etrn-20201231


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

IDRs – incentive distribution rights
IRS – United States Internal Revenue Service
NAAQS – National Ambient Air Quality Standards
NGA – Natural Gas Act of 1938
NGPA – Natural Gas Policy Act of 1978
NYMEX – New York Mercantile Exchange
NYSE – New York Stock Exchange
PHMSA – Pipeline and Hazardous Materials Safety Administration of the DOT
RCRA – Resource Conservation and Recovery Act
SEC – United States Securities and Exchange Commission

Disclosures in this Annual Report on Form 10-K contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and Section 27A of the Securities Act of 1933, as amended (the Securities Act). Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as "anticipate," "estimate," "could," "would," "will," "may," "forecast," "approximate," "expect," "project," "intend," "plan," "believe," "target" and other words of similar meaning in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this Annual Report on Form 10-K include the matters discussed in the sections captioned "Strategy" under "Developments, Market Trends and Competitive Conditions" in "Item 1. Business" and "Outlook" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," and the expectations of plans, strategies, objectives, and growth and anticipated financial and operational performance of Equitrans Midstream Corporation (together with its subsidiaries, Equitrans Midstream or the Company), including:

The forward-looking statements included in this Annual Report on Form 10-K involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The Company has based these forward-looking statements on management's current expectations and assumptions about future events. While the Company considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory, judicial and other risks and uncertainties, many of which are difficult to predict and are beyond the Company's control. The risks and uncertainties that may affect the operations, performance and results of the Company's business and forward-looking statements include, but are not limited to, those set forth under "Item 1A. Risk Factors," and elsewhere in this Annual Report on Form 10-K.

The Separation. On November 12, 2018, Equitrans Midstream, EQT and, for certain limited purposes, EQT Production Company, a wholly owned subsidiary of EQT, entered into a separation and distribution agreement (the Separation and Distribution Agreement), pursuant to which, among other things, EQT effected the separation of its midstream business, which was composed of the assets and liabilities of the separately-operated natural gas gathering, transmission and storage and water services operations of EQT (the Midstream Business), from EQT's upstream business, which was composed of the natural gas, oil and natural gas liquids development, production and sales and commercial operations of EQT (the Separation), to Equitrans Midstream, and distributed 80.1% of the then-outstanding shares of common stock, no par value, of Equitrans Midstream (Equitrans Midstream common stock) to EQT shareholders of record as of the close of business on November 1, 2018 (the Distribution). As part of the Separation, EQT retained the remaining 19.9% of the then-outstanding shares in Equitrans Midstream.

EQM IDR Transaction. On February 22, 2019, Equitrans Midstream completed a simplification transaction pursuant to that certain Agreement and Plan of Merger, dated as of February 13, 2019 (the IDR Merger Agreement), by and among Equitrans Midstream and certain related parties, pursuant to which, among other things, (i) Equitrans Merger Sub, LP merged with and into EQGP (the Merger) with EQGP continuing as the surviving limited partnership and a wholly owned subsidiary of EQM, and (ii) each of (a) the IDRs in EQM, (b) the economic portion of the general partner interest in EQM and (c) the issued and outstanding EQGP common units were canceled, and, as consideration for such cancellation, certain affiliates of the Company received on a pro rata basis 80,000,000 newly-issued common units representing limited partner interests in EQM (EQM common units) and 7,000,000 newly-issued Class B units representing limited partner interests in EQM (Class B units), and EQGP Services, LLC (the EQM General Partner) retained the non-economic general partner interest in EQM (such transactions, collectively, the EQM IDR Transaction). Additionally, as part of the EQM IDR Transaction, the 21,811,643 EQM common units held by EQGP were canceled and 21,811,643 EQM common units were issued pro rata to certain subsidiaries of the Company. As a result of the EQM IDR Transaction, the EQM General Partner replaced EQM Midstream Services, LLC as the general partner of EQM. See Note 2 to the consolidated financial statements for further information on the EQM IDR Transaction.

Preferred Restructuring Agreement. On February 26, 2020, the Company and EQM entered into a Preferred Restructuring Agreement (the Restructuring Agreement) with all of the Investors pursuant to which, at the effective time of the EQM Merger (the Effective Time): (i) EQM redeemed $600 million aggregate principal amount of the Investors' EQM Series A Preferred Units issued and outstanding immediately prior to the Restructuring Closing (defined below), which occurred substantially concurrent with the closing of the EQM Merger, for cash at 101% of the EQM Series A Preferred Unit purchase price of $48.77 per such unit (the EQM Series A Preferred Unit Purchase Price) plus any accrued and unpaid distribution amounts and partial period distribution amounts, and (ii) immediately following such redemption, each remaining issued and outstanding EQM Series A Preferred Unit was exchanged for 2.44 shares of a newly authorized and created series of preferred stock, without par value, of Equitrans Midstream, convertible into Equitrans Midstream common stock (the Equitrans Midstream Preferred Shares) on a one for one basis, in each case, in connection with the occurrence of the “Series A Change of Control” (as defined in the Fourth Amended and Restated Agreement of Limited Partnership of EQM (as amended, the Former EQM Partnership Agreement)) that occurred upon the closing of the EQM Merger (collectively, the Restructuring and, the closing of the Restructuring, the Restructuring Closing). See Note 2 to the consolidated financial statements for further information on the Restructuring Agreement and the Restructuring.

The EQT Global GGA. On February 26, 2020 (the EQT Global GGA Effective Date), the Company entered into a Gas Gathering and Compression Agreement (the EQT Global GGA) with EQT for the provision by the Company of certain gas gathering services to EQT in the Marcellus and Utica Shales of Pennsylvania and West Virginia. Pursuant to the EQT Global GGA, EQT is subject to an initial annual MVC of 3.0 Bcf per day that gradually steps up to 4.0 Bcf per day for several years following the full in-service date of the MVP. The EQT Global GGA runs from the EQT Global GGA Effective Date through December 31, 2035, and will renew annually thereafter unless terminated by EQT or the Company pursuant to its terms. Pursuant to the EQT Global GGA, the Company has certain obligations to build connections to connect EQT wells to its gathering system, which are subject to geographical limitations in relation to the dedicated area in Pennsylvania and West Virginia, as well as the distance of such connections to the Company's then-existing gathering system. In addition to the fees related to gathering services, the EQT Global GGA provides for potential cash bonus payments payable by EQT to the Company during the period beginning on the first day of the calendar quarter in which the MVP in-service date occurs through the earlier of the twelfth calendar quarter from that point or the calendar quarter ending December 31, 2024 (the Henry Hub cash bonus payment provision). The potential cash bonus payments are conditioned upon the quarterly average of certain Henry Hub natural gas prices exceeding certain price thresholds.

The gathering MVC fees payable by EQT to the Company set forth in the EQT Global GGA are subject to potential reductions for certain contract years as set forth in the EQT Global GGA, conditioned upon the in-service date of the MVP, which provide for estimated aggregate fee relief of approximately $270 million in the first year after the in-service date of the MVP, approximately $230 million in the second year after the in-service date of the MVP and approximately $35 million in the third year after the in-service date of the MVP. In addition, if the MVP in-service date has not occurred by January 1, 2022, EQT has an option, exercisable for a period of twelve months (or such shorter period if the in-service date of the MVP occurs), to forgo approximately $145 million of the gathering fee relief in the first year after the MVP in-service date and approximately $90 million of the gathering fee relief in the second year after the MVP in-service date in exchange for a cash payment from the Company to EQT in the amount of approximately $196 million (the EQT Cash Option). See Note 6 to the consolidated financial statements for further information on the EQT Global GGA.

Water Services Letter Agreement. On February 26, 2020, the Company entered into a letter agreement with EQT, pursuant to which EQT agreed to utilize the Company for the provision of water services in Pennsylvania under existing water services agreements and new water services agreements if negotiated between the parties (such letter agreement, the Water Services Letter Agreement). The Water Services Letter Agreement is effective as of the first day of the first month following the MVP in-service date and will expire on the fifth anniversary of such date. During each year of the Water Services Letter Agreement, EQT agreed that fixed MVC fees payable to the Company for water services in Pennsylvania incurred on a volumetric basis, provided in accordance with existing agreements and new agreements entered into between the parties pursuant to the Water Services Letter Agreement (or the related agreements), will be equal to or greater than $60 million per year.

Share Purchase Agreements. On February 26, 2020, the Company entered into two share purchase agreements (the Share Purchase Agreements) with EQT, pursuant to which the Company agreed to (i) purchase 4,769,496 shares of Equitrans Midstream common stock (the Cash Shares) from EQT in exchange for approximately $46 million in cash, (ii) purchase 20,530,256 shares of Equitrans Midstream common stock (the Rate Relief Shares and, together with the Cash Shares, the Share Purchases) from EQT in exchange for a promissory note in the aggregate principal amount of approximately $196 million (which EQT subsequently assigned to EQM as consideration for certain commercial terms under the EQT Global GGA), and (iii) pay EQT cash in the amount of approximately $7 million (the Cash Amount). On March 5, 2020, the Company completed the Share Purchases and paid the Cash Amount. The Company used proceeds from the EQM Credit Facility (defined in Note 11 to the consolidated financial statements) to fund the purchase of the Cash Shares and to pay the Cash Amount in addition to other uses of proceeds. After the closing of the Share Purchases, the Company retired the Cash Shares and the Rate Relief Shares. On September 29, 2020, the Company made a prepayment to EQM of all principal, interest, fees and other obligations outstanding under the promissory note EQT assigned to EQM and the promissory note was terminated.

As of December 31, 2020, the Company provided a majority of its natural gas gathering, transmission and storage services under long-term contracts that generally include fixed monthly reservation fees or MVCs. The Company maintains a stable cash flow profile, with approximately 66% of the Company's revenues for the year ended December 31, 2020 generated from firm reservation fees. The percentage of the Company's revenues that are generated by firm reservation fees is expected to increase in future years as a result of the 15-year term EQT Global GGA, which includes an MVC that became effective on April 1, 2020 of 3.0 Bcf per day and gradually steps up to 4.0 Bcf per day for several years following the full in-service date of the MVP project, and the Hammerhead gathering agreement (which is subject to a pending dispute with EQT), which includes a 1.2 Bcf per day firm capacity commitment. These contract structures enhance the stability of the Company's cash flows and limits its direct exposure to commodity price risk.

Gathering Customers. For the year ended December 31, 2020, EQT accounted for approximately 65% of Gathering's revenues. Subject to certain exceptions and limitations, as of December 31, 2020, Gathering had acreage dedications (inclusive of acreage dedications to Eureka Midstream Holdings, LLC (Eureka Midstream), a joint venture in which the Company has a 60% interest and that owns a 190-mile gathering header pipeline system in Ohio and West Virginia that services both dry Utica and wet Marcellus Shale production) through which the Company has the right to elect to gather all natural gas produced from wells under an area covering (i) approximately 475,000 gross acres in Pennsylvania pursuant to agreements with EQT, including the EQT Global GGA, and agreements with certain other third parties, (ii) approximately 344,000 gross acres in Ohio pursuant to agreements with EQT and other third parties and (iii) approximately 370,000 gross acres in West Virginia pursuant to the EQT Global GGA and agreements with certain other third parties.

The Company provides gathering services in two manners: firm service and interruptible service. Firm service contracts are typically long-term and can include firm reservation fees, which are fixed, monthly charges for the guaranteed reservation of pipeline access. Revenues under firm reservation fees also include fixed volumetric charges under MVCs. As of December 31, 2020, the gathering system had total contracted firm reservation capacity (including contracted MVCs) of approximately 7.0 Bcf per day (inclusive of Eureka Midstream contracted capacity), which included contracted firm reservation capacity of approximately 1.8 Bcf per day associated with the Company's high-pressure header pipelines (including 1.2 Bcf per day under the Hammerhead gathering agreement, which is currently subject to a dispute with EQT). Including future capacity expected from expansion projects that are not yet fully constructed for which the Company has executed firm contracts, the gathering system had total contracted firm reservation capacity (including contracted MVCs) of approximately 8.0 Bcf per day (inclusive of Eureka Midstream contracted capacity) as of December 31, 2020, which included contracted firm reservation capacity of approximately 1.8 Bcf per day associated with the Company's high-pressure header pipelines (including 1.2 Bcf per day under the Hammerhead gathering agreement, which is currently subject to a dispute with EQT). Volumetric-based fees can also be charged under firm contracts for each firm volume gathered as well as for volumes gathered in excess of the firm contracted volume, if system capacity exists. Based on total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed for which the Company has executed firm contracts, the Company's firm gathering contracts had a weighted average remaining term of approximately 15 years as of December 31, 2020.

The Company provides transmission and storage services in two manners: firm service and interruptible service. Firm service contracts are typically long-term and can include firm reservation fees, which are fixed, monthly charges for the guaranteed reservation of pipeline and storage capacity. Volumetric-based fees can also be charged under firm contracts for firm volume transported or stored as well as for volumes transported or stored in excess of the firm contracted volume, if there is system capacity. Customers are not assured capacity or service for volumes in excess of the firm contracted volume as such volumes have the same priority as interruptible service. Including future capacity expected from expansion projects that are not yet fully constructed for which the Company has executed firm transmission contracts, approximately 4.4 Bcf per day of transmission capacity, excluding, in the aggregate, 2.3 Bcf per day of firm capacity commitments associated with the MVP and MVP Southgate projects, and 30.5 Bcf of storage capacity were subscribed under firm transmission and firm storage contracts, respectively, as of December 31, 2020. Based on total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed for which the Company has executed firm contracts, the Company's firm transmission and storage contracts had a weighted average remaining term of approximately 14 years as of December 31, 2020.

As of December 31, 2020, approximately 97% of Transmission's contracted firm transmission capacity was subscribed by customers under negotiated rate agreements under its tariff, while the remainder was subscribed at discounted rates under its tariff, which are rates below the recourse rates and above a minimum level. As of December 31, 2020, Transmission did not have any contracted firm transmission capacity subscribed at recourse rates under its tariff, which are the maximum rates an interstate pipeline may charge for its services under its tariff. See also “FERC Regulation” under “Regulatory Environment” below and “Our natural gas gathering, transmission and storage services are subject to extensive regulation by federal, state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends.” included in "Item 1A. Risk Factors" for additional information.

Strategy. The Company's strategically-located assets overlay core acreage in the Appalachian Basin. The location of the Company's assets allows its producer customers to access major demand markets in the U.S. The Company is one of the largest natural gas gatherers in the U.S., and its largest customer, EQT, was the largest natural gas producer in the U.S. based on average daily sales volumes as of December 31, 2020. The Company maintains a stable cash flow profile, with approximately 66% of its revenue for the year ended December 31, 2020 generated from firm reservation fees. Further, as discussed above, the percentage of the Company's revenues that are generated by firm reservation fees is expected to increase in future years as a result of the 15-year term EQT Global GGA, which includes an MVC that became effective on April 1, 2020 of 3.0 Bcf per day and gradually steps up to 4.0 Bcf per day for several years following the full in-service date of the MVP project. This contract structure enhances the stability of the Company's cash flows and limits its direct exposure to commodity price risk.

•Mountain Valley Pipeline. The MVP is being constructed by a joint venture among the Company and affiliates of each of NextEra Energy, Inc., Consolidated Edison, Inc. (Con Edison), AltaGas Ltd. and RGC Resources, Inc. As of December 31, 2020, the Company owned an approximate 46.2% interest in the MVP project and will operate the MVP. The MVP is an estimated 300-mile, 42-inch diameter natural gas interstate pipeline with a targeted capacity of 2.0 Bcf per day that will span from the Company's existing transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia, providing access to the growing southeast demand markets. The MVP Joint Venture has secured a total of 2.0 Bcf per day of firm capacity commitments at 20-year terms. Additional shippers have expressed interest in the MVP project and the MVP Joint Venture is evaluating an expansion opportunity that could add approximately 0.5 Bcf per day of capacity through the installation of incremental compression. The MVP Joint Venture is also evaluating other future pipeline extension projects.

As discussed under "The regulatory approval process for the construction of new midstream assets is very challenging, and decisions by regulatory and judicial authorities in pending or potential proceedings could impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations necessary to complete certain projects on the targeted time frame or at all or our ability to achieve the expected investment returns on the projects." included in "Item 1A. Risk Factors", there are pending legal and regulatory challenges to or otherwise affecting certain aspects of the MVP project that must be resolved before the project can be completed, and the MVP Joint Venture is working to resolve these challenges. In order to complete the project in accordance with the targeted full in-service date and cost, the MVP Joint Venture must, among other things: (i) timely receive the Army Corps Individual Permit, which will require Section 401 water quality certification approvals or waivers from each of the West Virginia Department of Environmental Protection and the Virginia Department of Environmental Quality and certain other state-level approvals; (ii) maintain and, as applicable, timely receive required authorizations, including authorization to proceed with construction, related to the Jefferson National Forest from the Bureau of Land Management (BLM), the U.S. Forest Service (USFS) and the FERC; (iii) timely receive authorization from the FERC to utilize alternative trenchless construction methods for certain stream and wetland crossings; (iv) continue to have available the orders previously issued by the FERC modifying its prior stop work orders and extending the MVP Joint Venture’s prescribed time to complete the MVP project; (v) timely receive authorization from the FERC to complete construction work in the portion of the project route currently remaining subject to the FERC’s previous stop work order; and (vi) continue to be authorized to work under the Biological Opinion and Incidental Take Statement issued by the United States Department of the Interior’s Fish and Wildlife Service (FWS) for the MVP project, in each case including the continued effectiveness of any such foregoing or other authorizations notwithstanding any pending or future challenge thereto. See the discussion of litigation and regulatory related delays affecting the completion of the MVP project set forth in "Item 3. Legal Proceedings".

•MVP Southgate Project. In April 2018, the MVP Joint Venture announced the MVP Southgate project, a proposed 75-mile interstate pipeline that will extend from the MVP at Pittsylvania County, Virginia to new delivery points in Rockingham and Alamance Counties, North Carolina. The MVP Southgate project is backed by a 300 MMcf per day firm capacity commitment from Dominion Energy North Carolina. As designed, the MVP Southgate project has expansion capabilities that could provide up to 900 MMcf per day of total capacity. The MVP Southgate project is estimated to cost a total of approximately $450 million to $500 million, which is expected to be spent primarily in 2022. The Company expects to fund approximately $225 million of the overall project cost. During the year ended December 31, 2020, the Company made approximately $5 million of capital contributions to the MVP Joint Venture for the MVP Southgate project. For 2021, the Company expects to make capital contributions of approximately $20 million to the MVP Joint Venture for the MVP Southgate project. The Company will operate the MVP Southgate and, as of December 31, 2020, owned a 47.2% interest in the MVP Southgate project. The MVP Joint Venture submitted the MVP Southgate certificate application to the FERC in November 2018. The Final Environmental Impact Statement for the MVP Southgate project was issued on February 14, 2020. In June 2020, the FERC issued the Certificate of Public Convenience and Necessity for the MVP Southgate; however, the FERC, while authorizing the project, directed the Office of Energy Projects not to issue a notice to proceed with construction until necessary federal permits are received for the MVP project and the Director of the Office of Energy Projects lifts the stop work order and authorizes the MVP Joint Venture to continue constructing the MVP project. On August 11, 2020, North Carolina regulators denied the MVP Southgate project's application for a Clean Water Act Section 401 Individual Water Quality Certification and Jordan Lake Riparian Buffer Authorization due to uncertainty surrounding the completion of the MVP project, which denial was appealed by the MVP Joint Venture on September 10, 2020. The MVP Southgate project is targeted to be placed in-service in 2022, which such targeted in-service date is based on, among other things, favorable and timely resolution of this and other regulatory and legal decisions and processes. See the discussion of litigation and regulatory related delays affecting the completion of the MVP Southgate project set forth in "Item 3. Legal Proceedings".

Interstate pipelines may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust or unreasonable, unduly discriminatory or preferential. Rate design and the allocation of costs also can affect a pipeline's profitability. While the ratemaking process establishes the maximum rate that can be charged, interstate pipelines such as the Company's transmission and storage system are permitted to discount their firm and interruptible rates without further FERC authorization down to a specified minimum level, provided they do not unduly discriminate. In addition, pipelines are allowed to negotiate different rates with their customers, under certain circumstances. Changes to rates or terms and conditions of service, and contracts can be proposed by a pipeline company under Section 4 of the NGA, or the existing interstate transmission and storage rates or terms and conditions of service, and contracts may be challenged by a complaint filed by interested persons including customers, state agencies or the FERC under Section 5 of the NGA. Rate increases proposed by a pipeline may be allowed to become effective subject to refund and/or a period of suspension, while rates or terms and conditions of service that are the subject of a complaint under Section 5 of the NGA are subject to prospective change by the FERC. Rate increases proposed by a regulated interstate pipeline may be challenged and such increases may ultimately be rejected by the FERC.

The Company's interstate pipeline may also use negotiated rates that could involve rates above or below the recourse rate or rates that are subject to a different rate structure than the rates specified in the Company's interstate pipeline tariffs, provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement. A prerequisite for allowing the negotiated rates is that negotiated rate customers must have had the option to take service under the pipeline's recourse rates. As of December 31, 2020, approximately 97% of the system's contracted firm transmission capacity was subscribed by customers under negotiated rate agreements under its tariff. Some negotiated rate transactions are designed to fix the negotiated rate for the term of the firm transportation agreement and the fixed rate is generally not subject to adjustment for increased or decreased costs occurring during the contract term.

The FERC’s 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.

FERC Regulation of Gathering Rates and Terms of Service. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC under the NGA. While the FERC does not generally regulate the rates and terms of service over facilities determined to be performing a natural gas gathering function, it has traditionally regulated rates charged by interstate pipelines for gathering services performed on the pipeline's own gathering facilities when those gathering services are performed in connection with jurisdictional interstate transmission services. The Company currently maintains rates and terms of service in its tariff for unbundled gathering services performed on its gathering facilities in connection with the transmission service. Just as with rates and terms of service for transmission and storage services, the Company's rates and terms of service for its FERC-regulated low-pressure gathering system may be challenged by complaint and are subject to prospective change by the FERC. The Company has submitted an application to the FERC requesting authorization to abandon these low-pressure gathering facilities and services. As of December 31, 2020, the application remained pending before the FERC.

Notwithstanding the investigatory and preventative maintenance costs incurred in the Company's performance of customary pipeline management activities, the Company may incur significant additional expenses if anomalous pipeline conditions are discovered or more stringent pipeline safety requirements are implemented. For example, in April 2016, PHMSA published a notice of proposed rulemaking addressing several integrity management topics and proposing new requirements to address safety issues for natural gas transmission and gathering lines (the Mega Rule). The proposed Mega Rule would strengthen existing integrity management requirements, expand assessment and repair requirements to pipelines in areas with medium population densities and extend regulatory requirements to onshore gas gathering lines that are currently exempt. Part one of the Mega Rule was finalized on July 1, 2020. Two remaining parts of the Mega Rule are awaiting finalization. Dates for finalization have not been updated or released by PHMSA due to COVID-19.

Further, in June 2016, then-President Obama signed the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the 2016 Pipeline Safety Act), extending PHMSA's statutory mandate under prior legislation through 2019. Although a reauthorization bill extending PHMSA’s statutory mandate until 2023 was introduced in 2019, Congress did not pass the bill in 2019 or 2020 and PHMSA is operating under a continuing resolution until a new bill is passed. In addition, the 2016 Pipeline Safety Act empowered PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing and also required PHMSA to develop new safety standards for natural gas storage facilities by June 2018. Pursuant to those provisions of the 2016 Pipeline Safety Act, PHMSA issued two separate Interim Final Rules in October 2016 and December 2016 that expanded the agency's authority to impose emergency restrictions, prohibitions and safety measures and strengthened the rules related to underground natural gas storage facilities, including well integrity, wellbore tubing and casing integrity. The December 2016 Interim Final Rule, relating to underground gas storage facilities, went into effect in January 2017. PHMSA determined, however, that it would not issue enforcement citations to any operators for violations of provisions of the December 2016 Interim Final Rule that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issued a final rule. The final rule related to underground gas storage facilities became effective as of March 13, 2020.

Following the October 2016 Interim Final Rule, PHMSA also published two final rules on pipeline safety applicable to the Company: "Enhanced Emergency Order Procedures;" and "Safety of Gas Transmission Pipelines: Maximum Allowable Operating Pressure Reconfirmation, Expansion of Assessment Requirements." The Enhanced Emergency Order Procedures rule, which became effective on December 2, 2019, implements an existing statutory authorization for PHMSA to issue emergency orders related to pipeline safety if an unsafe condition or practice, or a combination of unsafe conditions and practices, constitutes, or is causing an imminent hazard. The Safety of Gas Transmissions Pipelines rule, which went into effect on July 1, 2020, requires operators of certain gas transmission pipelines that have been tested or that have inadequate records to determine the material strength of their lines by reconfirming the Maximum Allowable Operating Pressure, and establishes a new Moderate Consequence Area for determining regulatory requirements for gas transmission pipeline segments outside of high consequence areas. The rule also establishes new requirements for conducting baseline assessments, incorporates into the regulations industry standards and guidelines regarding design, construction and in-line inspections, and new requirements for data integration and risk analysis in integrity management programs, including seismicity, manufacturing and construction defects, and crack and crack-like defects, and includes several requirements that allow operators to notify PHMSA of proposed alternative approaches to achieving the objectives of the minimum safety standards. In 2020, the Company did not incur material compliance costs in connection with complying with the PHMSA rules applicable to the Company, and it is in the process of assessing the impact of these rules on its future costs of operations and revenue from operations.

Should the Company fail to comply with DOT regulations adopted under authority granted to PHMSA, it could be subject to penalties and fines. PHMSA has the statutory authority to impose civil penalties for pipeline safety violations up to a maximum of approximately $220,000 per day for each violation and approximately $2.2 million for a related series of violations. This maximum penalty authority established by statute will continue to be adjusted periodically to account for inflation. In addition, the Company could be required to make additional maintenance capital expenditures in the future for the above described or similar regulatory compliance initiatives that are not reflected in its forecasted maintenance capital expenditures. The Company believes that its operations are in substantial compliance with all existing federal, state and local pipeline safety laws and regulations. However, the adoption of new laws and regulations, such as those proposed by PHMSA, could result in significant added costs or delays in service or the termination of projects, which could have a material adverse effect on the Company in the future.

On December 27, 2020, then-President Trump signed the “Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES Act) of 2020.” The PIPES Act identifies areas where Congress believed additional oversight, research, or regulations was needed. The PIPES Act includes new mandates for PHMSA to require operators to update, as needed, their emergency response plans and operating and maintenance plans. The PIPES Act also requires operators to manage records and update, as necessary, their existing district regulator stations to eliminate a common mode of failure. PHMSA will also require that leak detection and repair programs consider the environment, the use of advance lead detection practices and technologies, and for operators to be able to locate and categorize all leaks that are hazardous to human safety, the environment, or can become hazardous. The Company does not anticipate incurring material capital expenditures in connection with complying with the PIPES Act.

The Company has implemented programs and policies designed to keep its pipelines and other facilities in compliance with existing environmental laws and regulations, and the Company does not believe that its compliance with such legal requirements will have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to pay dividends to its shareholders. Nonetheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment (and such trend will likely increase under the Biden Administration). Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be significantly in excess of the amounts the Company currently anticipates. For example, in October 2015, the EPA revised the National Ambient Air Quality Standards (NAAQS) for ozone from 75 parts per billion for the current eight-hour primary and secondary ozone standards to 70 parts per billion for both standards. The EPA may designate

the areas in which the Company operates as nonattainment areas. States that contain any areas designated as nonattainment areas will be required to develop implementation plans demonstrating how the areas will attain the applicable standard within a prescribed period of time. These plans may require the installation of additional equipment to control emissions. In addition, in May 2016, the EPA finalized rules that impose volatile organic compound and methane emissions limits (and collaterally reduce methane emissions) on certain types of compressors and pneumatic pumps, as well as requiring the development and implementation of leak monitoring plans for compressor stations. The EPA finalized amendments to some requirements in these standards in March 2018, September 2018 and September 2020, including rescission of certain requirements and revisions to other requirements such as fugitive emissions monitoring frequency. In September 2020, the EPA issued a correction to the regulations, removing transmission and storage segments from the source category subject to the rule and removing the methane emissions limits from the rule. President Biden has ordered the EPA to review these rules. Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of the Company's equipment, result in longer permitting timelines, and significantly increase the Company's capital expenditures and operating costs, which could adversely affect the Company's business. The Company tries to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. While the Company believes that it is in substantial compliance with existing environmental laws and regulations, there is no assurance that the current conditions will continue in the future.

Hazardous Substances and Waste. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include current and prior owners or operators of the site where a release of hazardous substances occurred and companies that transported, disposed or arranged for the transportation or disposal of the hazardous substances found at the site. Under CERCLA, these "responsible persons" may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. The Company generates materials in the course of its ordinary operations that are regulated as "hazardous substances" under CERCLA or similar state laws and, as a result, may be jointly and severally liable under CERCLA, or such laws, for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

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

Air Emissions. The federal Clean Air Act and comparable state laws and regulations restrict the emission of air pollutants from various industrial sources, including the Company's compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that the Company obtain pre-approval for the construction or modification of certain projects or facilities, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. The Company's failure to comply with these requirements could subject it to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. The Company may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining permits and approvals for air emissions. These types of capital expenditures could also be required in areas that are nonattainment for the ozone national ambient air quality standards depending on the design of the relevant state’s implementation plan to meet the air quality standards. Compliance with these requirements may require modifications to certain of the Company's operations, including the installation of new equipment to control emissions from the Company's compressors that could result in significant costs, including increased capital expenditures and operating costs, and could adversely affect the Company's business.

The U.S. Congress, along with federal and state agencies, has considered measures to reduce the emissions of GHGs. Legislation or regulation that restricts carbon emissions could increase the Company's cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or, depending on any future legislation, purchase emission allowances. The effect of climate change legislation or regulation on the Company's business is currently uncertain. If the Company incurs additional costs to comply with such legislation or regulations, it may not be able to pass on the higher costs to its customers or recover all the costs related to complying with such requirements and any such recovery may depend on events beyond the Company's control, including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or implementing regulations. The Company's future results of operations, cash flows or financial condition could be adversely affected if such costs are not recovered through regulated rates or otherwise passed on to its customers. Additionally, the Company's producer customers may also be affected by legislation or regulation, which may, directly or indirectly, adversely impact their ability and willingness to produce natural gas and accordingly affect such producers' financial health or reduce the volumes delivered to the Company and demand for its services. Climate change and GHG legislation or regulation could delay or otherwise negatively affect efforts to obtain and maintain permits and other regulatory approvals for existing and new facilities, impose additional monitoring and reporting requirements or adversely affect demand for the natural gas the Company gathers, transports and stores. The effect on the

Water Discharges. The federal Clean Water Act and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants or dredged and fill material into state waters as well as waters of the United States, including adjacent wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of permits issued by the EPA, the Army Corps or an analogous state agency. In September 2015, new EPA and Army Corps rules defining the scope of the EPA's and the Army Corps' jurisdiction became effective (the 2015 Clean Water Rule). But the 2015 Clean Water Rule was promptly challenged in courts and was enjoined by judicial action in some states. Further, in October 2019 the EPA issued a rule repealing the 2015 Clean Water Rule and recodifying the preexisting regulations. In June 2020, new EPA and Army Corps regulations narrowing the regulatory scope of the Clean Water Act became effective (the 2020 Navigable Waters Protection Rule). Like the 2015 Clean Water Rule, the 2020 Navigable Water Protection Rule was promptly challenged in courts and has been enjoined by judicial action in at least one state. To the extent that any future rules expand the scope of the Clean Water Act's jurisdiction, the Company could face increased costs and delays with respect to obtaining permits for activities in jurisdictional waters, including wetlands.

National Environmental Policy Act. The construction of interstate natural gas transportation pipelines pursuant to the NGA requires authorization from the FERC. The FERC actions are subject to the National Environmental Policy Act (NEPA). NEPA requires federal agencies, such as the FERC, to evaluate major federal actions having the potential to significantly affect the environment. In the course of such evaluations, an agency will either prepare an environmental assessment that examines the potential direct, indirect and cumulative effects of a proposed project or, if necessary, a more detailed Environmental Impact Statement. Any proposed plans for future construction activities that require FERC authorization will be subject to the requirements of NEPA. This process has the potential to significantly delay or limit, and significantly increase the cost of, development of midstream infrastructure. In September 2020, new Council on Environmental Quality regulations intended to streamline the NEPA evaluation process went into effect. These rules have been challenged in courts, although initial efforts to enjoin enforcement of the rule were unsuccessful.

Endangered Species Act. The federal Endangered Species Act (ESA) restricts activities that may adversely affect endangered and threatened species or their habitats. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of the Company's facilities are located in areas that are designated as habitats for endangered or threatened species, the Company is confident that it is in substantial compliance with the ESA. The designation of previously unprotected species as being endangered or threatened, or the designation of previously unprotected areas as a critical habitat for such species, could cause the Company to incur additional costs, result in delays in construction of pipelines and facilities, or cause the Company to become subject to operating restrictions in areas where the species are known to exist. For example, the FWS continues to receive hundreds of petitions to consider listing additional species as endangered or threatened and is being regularly sued or threatened with lawsuits to address these petitions. Some of these legal actions may result in the listing of species located in areas in which the Company operates. Throughout 2020, the United States Department of Interior narrowed the ESA regulations and their applicability. These regulations have been challenged in the courts.

In July 2019, the Company formed a Culture Champions Group, which consists of a diverse representation of employees across the organization below the director level, with the objective of soliciting suggestions from employees on ways to enhance the Company's culture. In early 2020, the Company also conducted an anonymous culture survey to seek feedback from employees on a variety of topics, including understanding of the Company's strategy, vision, departmental coordination, employee development, and empowerment. Based on the results of the survey, as well as feedback provided to the Culture Champions Group, the Company has implemented a number of actions within the organization to improve and enhance employee recognition, leadership visibility and communication, and integration and collaboration between departments, including but not limited to coffee talks (informational sessions on various topics), peer networking initiatives, lunches with leaders, and employee communication sessions.

Diversity and Inclusion. The Company believes each employee is essential to its continued success and the Company seeks to provide every employee with the foundation and environment needed to achieve the employee’s goals. This objective begins with the Company's commitment to diversity and inclusion. In July 2020, the Company formally launched its Inclusion program, which focuses on the Company's core value of Collaboration through cultivating an inclusive, respectful work environment that values differing perspectives and encourages the power of teamwork and accountability. The Company's program is composed of four pillars – Accountability, External Recruitment Outreach, Internal Outreach, and External Partnerships. Through each of these pillars, the Company seeks to touch every aspect of its business. During 2020, under this program, the Company launched a micro-learning platform providing employees with inclusion-related content on a bi-weekly basis; conducted manager inclusion training; completed a review of human resources policies in support of an inclusive work environment; created an Inclusion scorecard to capture relevant employee demographics for discussion with leadership; and began the steps to establish the Company's first gender neutral restroom in its headquarters location.

Safety. Above all else, safety is the Company's main priority – this includes the safety of its employees, contractors, and communities – always. The Company is committed to maintaining a strong safety culture and to emphasizing the importance of its employees’ role in identifying, mitigating and communicating safety risks. The Company's Board of Directors (Board) provides oversight for the Company's safety initiatives through the Health, Safety, Security and Environmental (HSSE) Committee of the Board. The Company tracks numerous safety-related metrics to evaluate its safety performance and has incorporated safety metrics into the Company's annual incentive plan. By linking these metrics to employees’ compensation, the Company believes it can more effectively and proactively address safety issues, increase the safety of the Company's worksites and offices, and achieve employee buy-in. Additionally, the Company's President and Chief Operating Officer distributes monthly comprehensive safety memorandums to all employees and members of the Board keeping them abreast of the Company’s safety performance. In 2020, the Company experienced the following safety highlights:

In connection with the COVID-19 pandemic, the Company has proactively undertaken a number of company-wide measures intended to promote the safety of field and office-based employees and contractors (including, among other things, establishing an Infectious Disease Response Team, instituting enhanced self-protection and office sanitation measures, eliminating non-essential business travel, implementing a mandatory work-from-home protocol for a substantial majority of the Company’s employees through at least June 1, 2021, instituting face covering protocols, providing certain medical benefit enhancements, practicing social distancing in field operations where possible, sharing the Company’s infectious disease response plan with suppliers and contractors, and timely communicating updates to employees and other relevant parties). In addition, the Company has implemented additional mitigation efforts in connection with the remobilization of certain field employees and contractors. The Company’s Infectious Disease Response Team continues to monitor and assist in implementing mitigation efforts in respect of potential areas of risk for the Company and its stakeholders.

On February 17, 2021, EQT announced a projected 2021 capital expenditure forecast of $1.10 billion to $1.20 billion compared to 2020 actual capital expenditures of $1.08 billion. EQT may reduce its capital spending in the future based on commodity prices or other factors. Unless we are successful in attracting significant new customers, our ability to maintain or increase the capacity subscribed and volumes transported or gathered under service arrangements on our gathering, transmission and storage and water systems will depend on receiving consistent or increasing commitments from EQT. While EQT has dedicated a significant amount of its acreage to us, and executed long-term contracts with substantial firm reservation and MVCs on our systems, it may determine in the future that drilling in areas outside of our current areas of operations is strategically more attractive to it, and other than the firm reservations and MVCs, it is under no contractual obligation to maintain its production dedicated to us. Moreover, EQT’s publicly-disclosed strategy continues to focus on capital efficiency, reducing indebtedness and free cash flow generation as opposed to volume growth. On February 17, 2021, EQT publicly disclosed that its development program is expected to result in approximately flat sales volumes for 2021 relative to EQT's pro-forma 2020 levels (reflecting acreage acquired by EQT from Chevron U.S.A. Inc. in 2020 (the Chevron Acquisition)). A reduction in the capacity subscribed or volumes transported or gathered on our systems by EQT (or lack of growth in respect of such volumes) could have a material adverse effect on our business, financial condition, results of operations, liquidity and our ability to pay dividends to our shareholders.

EQT may also elect to reduce its drilling activity or curtail production if commodity prices, including natural gas prices in the Appalachian Basin, do not improve to levels EQT determines to be sufficient to justify drilling and production or if such prices decrease below EQT's preferred levels. Fluctuations in energy prices can also greatly affect the development of EQT’s and other producers’ respective reserves and declining prices could have a negative impact on EQT’s and other producers’ development and production activity which could be material depending on the severity of the downturn in prices. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide political and economic conditions, the length and severity of the COVID-19 outbreak and its effect on oil, NGLs and natural gas prices (and the positive impact lower oil prices have had and are expected to have on natural gas prices in the near- and medium-term, primarily as a result of corresponding declines in the production of associated gas in the United States), weather conditions and seasonal trends, the levels of domestic production and consumer demand, new exploratory finds of natural gas, the levels of imported and exported natural gas, oil and LNG, the availability of transportation systems with adequate capacity, the volatility and uncertainty of regional pricing differentials, the price and availability of (and adoption rate of) alternative fuels, the effect of energy conservation measures, the nature and extent of governmental regulation and taxation, and the anticipated future prices of natural gas, oil, LNG and other commodities. Due to these and other factors, even if reserves are known to exist in areas serviced by our assets, producers have chosen, and may choose in the future, not to develop those reserves. Sustained reductions in development or production activity in our areas of operation could lead to reduced utilization of our services, including our water services which are directly associated with producers’ well completion activities and fresh and produced water needs (which are partially driven by horizontal lateral lengths and the number of completion stages per well).

Additionally, the execution of the EQT Global GGA was based upon assumptions, including regarding EQT’s forecasted drilling and production levels and volumes on our system, that our management believed appropriate at the time of execution. If any of the assumptions fail to be realized, or if actual results differ from these assumptions, we may not achieve anticipated benefits associated with the EQT Global GGA. Failure to achieve anticipated benefits associated with the EQT Global GGA may have a negative impact on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Further, if EQT's volumes on our systems do not meet levels we assumed at the time of executing the EQT Global GGA and, during the period of such lower volumes, gathering fee reductions take effect following the in-service date of the MVP as required under the EQT Global GGA, our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders may be adversely affected. See “EQT Global GGA” in Note 6 to the consolidated financial statements for additional information.

Our business is dependent on the continued availability of natural gas production and reserves in our areas of operation. A sustained low-price environment for natural gas or regulatory limitations has adversely affected and could in the future adversely affect development of additional reserves and production that is accessible by our pipeline and storage assets and fresh water sources. Production from natural gas wells naturally declines over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, producers may determine in the future that drilling activities in areas outside of our current areas of operations are strategically more attractive to them due to the price environment for natural gas, including locally, or other reasons. A further reduction, or lack of growth, in the natural gas volumes supplied by producers could result in reduced throughput on our systems and adversely impact our ability to sustain and/or grow our operations and pay dividends to our shareholders. Accordingly, maintaining or increasing the contracted capacity or the volume of natural gas gathered, transported and stored on our systems and cash flows associated therewith is substantially dependent on our customers continually accessing additional reserves of natural gas in or accessible to our current areas of operations.

The primary factors affecting our ability to obtain non-dedicated sources of natural gas include the level of successful drilling activity near our systems and our ability to compete for volumes from successful new wells, and most development areas in our areas of operation are already dedicated to us or one of our competitors. While EQT has dedicated production from a substantial portion of its leased properties to us, we have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering and transmission systems or the rate at which production from a well declines. In addition, we have no control over EQT or other producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, producers’ focus on generating free cash flow and/or de-levering, prevailing and projected energy prices, hedging strategies, demand for hydrocarbons, levels of reserves, the producers’ contractual obligations to us and other midstream companies, geological considerations, environmental or other governmental regulations, the availability of drilling permits, the availability of drilling rigs and crews, and other production and development costs.

Fluctuations in energy prices can also greatly affect the development of new natural gas reserves. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to certain factors such as those described under the heading “We depend on EQT for a substantial majority of our revenues and future growth. Therefore, we are subject to the business and liquidity risks of EQT, and any further decrease in EQT’s drilling or completion activity (or significant production curtailments) could adversely affect our business and operating results.” Henry Hub spot and local spot natural gas prices, which were under pressure prior to the COVID-19 outbreak due primarily to a warmer than normal 2019 - 2020 winter heating season, a temperate spring 2020 season and an oversupply of natural gas (caused in part by the significant increase in production of associated gas from the Permian Basin and similar basins in recent years), were further pressured by a reduction in global demand for natural gas during 2020 (for which the COVID-19 outbreak was a contributing factor), lack of available natural gas storage and the continued significant supplies of natural gas produced, particularly from the Appalachian Basin. The Henry Hub natural gas price ranged from $1.33 per MMbtu to $3.03 per MMbtu between January 1, 2020 and December 31, 2020, with some prices reflecting the lowest natural gas prices in more than 20 years. Further, market prices for natural gas in the Appalachian Basin continue to be lower than Henry Hub natural gas prices and were significantly lower during portions of 2020. Natural gas prices have improved since the spring of 2020 and are expected to further improve during 2021, as reflected by the natural gas forward price strip as of February 19, 2021, primarily due to demand, such as in the winter months, for natural gas potentially exceeding available supply (as a result of, in part, the decrease in associated gas production from the Permian Basin given the dramatic decrease in oil production caused by historical low oil prices during the first half of 2020). However, the length and extent of that price recovery (if any) and its effect on the development plans of our customers, which impact both our ability to execute new commercial agreements with our customers as well as the volumetric-based fee revenues we earn under existing contracts, will be impacted by global demand for natural gas, the length and severity of the 2020-2021 winter heating season, rates of natural gas production (including amounts of associated gas from the Permian Basin, which certain analysts are projecting will increase in 2021 and later years), and the length and severity of the COVID-19 outbreak. There is no assurance that the elevated natural gas prices indicated by the forward natural gas price strip as of February 19, 2021 will be realized or be realized for any particular length of time or that producers will increase production volume as a result of any particular price level.

In addition, significant delays in the regulatory approval process for growth projects, including the MVP and MVP Southgate projects, have significantly increased costs and negatively impacted the targeted in-service dates for the projects, and further delays, such as because of a stay or loss of a critical authorization, may cause similar adverse effects, including to the MVP project’s targeted full in-service date in late 2021 and the MVP Southgate project’s targeted in-service date in 2022. Significant delays and cost increases in turn could adversely affect our ability, and, in the case of the MVP and MVP Southgate projects, the ability for the MVP Joint Venture and its owners, including us, to achieve the expected investment returns and/or cause other-than-temporary declines in value associated with the projects. The MVP and MVP Southgate projects in particular are subject to several agency actions and judicial challenges (and will likely become subject to further actions and challenges) that must be resolved before the MVP and MVP Southgate projects can be completed, as described in more detail in “Item 3. Legal Proceedings” and “Outlook” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

As the MVP project nears completion and in light of the abandonment by third parties of certain other similar pipeline projects, we have experienced and may further experience increased opposition from activists in the form of lawsuits, intervention in regulatory proceedings and otherwise, which has been and/or may be focused on the few remaining portions of the project. Such focused opposition may make it increasingly difficult to complete the project and place it in service within the targeted time frame or at all and may also affect the ability to effect extensions and/or expansions of the project. We also expect that as pre-construction activity in respect of the MVP Southgate project increases (or if construction were to commence), the MVP Southgate project may be subject to similar heightened opposition. These and other challenges to our internal growth projects, particularly the MVP project, could adversely affect our business (including by increasing the possibility of investor activism), financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

The gathering fees payable by EQT to us set forth in the EQT Global GGA are subject to potential reductions for certain contract years set forth in the EQT Global GGA, conditioned upon the in-service date of the MVP, which provide for estimated aggregate fee relief of $270 million in the first year after the in-service date of the MVP, $230 million in the second year after the in-service date of the MVP and $35 million in the third year after the in-service date of the MVP. In addition, if the MVP in-service date has not occurred by January 1, 2022, EQT has an option, exercisable for a period of twelve months, to forgo approximately $145 million of the gathering fee relief in the first year after the MVP in-service date and approximately $90 million of the gathering fee relief in the second year after the MVP in-service date in exchange for a cash payment from us to EQT in the amount of approximately $196 million. In addition, among the other benefits to us pursuant to the EQT Global GGA, EQT is subject to an initial annual MVC of 3.0 Bcf per day that gradually steps up to 4.0 Bcf per day for several years following the in-service date of the MVP. Any further delay in the MVP in-service date may prevent us from achieving a portion of the anticipated benefits associated with the execution of the EQT Global GGA. See “EQT Global GGA” in Note 6 to the consolidated financial statements for additional information.

We may perform either a qualitative or quantitative assessment of potential impairment. Our qualitative assessment of potential impairment may result in the determination that a quantitative impairment analysis is not necessary. Under this elective process, we assess qualitative factors to determine whether the existence of events or circumstances leads us to determine that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If after assessing the totality of events or circumstances, we determine that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing a quantitative analysis is not required. However, if we conclude otherwise, then we perform a quantitative impairment analysis. If we choose not to perform a qualitative assessment, or if we choose to perform a qualitative assessment but are unable to qualitatively conclude that no impairment has occurred, then we will perform a quantitative assessment. In the case of a quantitative assessment, we estimate the fair value of the reporting unit with which the goodwill is associated and compare it to the carrying value. If the estimated fair value of a reporting unit is less than its carrying value, an impairment charge is recognized for the excess of the reporting unit’s carrying value over its fair value.

Assessing goodwill for potential impairment requires significant judgments and estimates by management. Fair value of the reporting unit to which goodwill is recorded is estimated using a combination of an income and market approach which, in the case of the income approach, applies significant inputs not observable in the public market (Level 3), including estimates and assumptions related to the use of an appropriate discount rate, future throughput volumes, operating costs, capital spending and changes in working capital, and, in the case of the market approach, applies metrics and multiples derived from comparable companies and reference transactions. All of our goodwill as of December 31, 2020 relates to a business that was acquired and valued by EQT’s management in the November 2017 acquisition by EQT of Rice Energy Inc. The reporting unit to which goodwill is recorded as of December 31, 2020 is the EQM Opco reporting unit (defined and discussed in Note 4 to the consolidated financial statements). See Note 4 to the consolidated financial statements for additional information on our reporting units and impairment previously recognized.

We evaluate long-lived assets and equity method investments for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable (meaning, in the case of equity method investments, that such investments have suffered other-than-temporary declines in value). With respect to property, plant and equipment and finite lived assets, asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, commencement of operations, resolution of relevant legal and regulatory matters, and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of carrying value over fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to evaluations of recoverability and the recognition of additional impairments. The evaluation and measurement of impairments for equity method investments involves similar uncertainties, judgments and estimates as those applicable to other long-lived assets. If the equity method investment carrying value exceeds the fair value and it is determined that the decline in value is other-than-temporary, we will recognize an impairment equal to the excess of the carrying value over fair value. The fair value of equity method investments is generally estimated using an income approach

If the operations or projected operating results of our businesses decline, we could incur additional goodwill, property, plant and equipment and intangible asset impairment charges. Further, if we determine that the carrying value of long-lived assets is not recoverable or the value associated with our equity method investment in the MVP Joint Venture has suffered an other-than-temporary decline, we would incur additional impairment charges. Future impairment charges could be significant and could have a material adverse impact on our financial condition and results of operations for the period in which the impairment is recorded. As of the filing of this Annual Report on Form 10-K, we cannot predict the likelihood or magnitude of any future impairment. However, our closing stock price decreased by approximately 17% between January 15, 2021 and January 20, 2021. If our stock price does not recover before the end of the first quarter of 2021, such change in our market value during the first quarter may trigger a quantitative assessment for impairment for the first quarter of 2021, which may result in our realizing impairments, the magnitude of which we are unable to estimate as of the filing of this Annual Report on Form 10-K.

See Note 11 to the consolidated financial statements for a discussion of the Amended EQM Credit Facility and the Eureka Credit Facility. The Amended EQM Credit Facility contains certain negative covenants, that, among other things, establish for EQM a maximum consolidated leverage ratio that varies over the course of the term ranging from not more than 5.75 to 1.00 to not more than 5.00 to 1.00, tested as of the end of each fiscal quarter (which in limited circumstances is increased for certain measurement periods following the consummation of certain acquisitions). EQM's consolidated leverage ratio is derived from a number of components, including the amount of projected Consolidated EBITDA (as defined in the Amended EQM Credit Facility) from certain approved projects, including the MVP project, that is available to be included in the consolidated leverage ratio calculation under the Amended EQM Credit Facility. If the targeted in-service date for the MVP project is further delayed, such delay could result in a decrease in the amount of projected Consolidated EBITDA for future quarters, which, absent other actions which may be available to the Company to reduce its then-leverage, may further limit the Company's ability to borrow under the Amended EQM Credit Facility. Under the Eureka Credit Facility, Eureka is required to maintain a consolidated leverage ratio of not more than 4.75 to 1.00 (which in limited circumstances is increased for certain measurement periods following the consummation of certain acquisitions). Additionally, as of the end of any fiscal quarter, Eureka may not permit the ratio of consolidated EBITDA (as defined in the Eureka Credit Facility) for the four fiscal quarters then ending to

Organic and greenfield growth projects are a significant component of our growth strategy. The development and construction of pipelines and storage facilities involves numerous regulatory, environmental, political and legal uncertainties that are beyond our control and require the expenditure of significant amounts of capital. The development and construction of pipeline infrastructure and storage facilities exposes us to risks such as the failure to meet customer contractual requirements, delays caused by landowners, advocacy groups or activists opposed to the natural gas industry in the form of lawsuits, intervention in regulatory proceedings, environmental hazards, vandalism, adverse weather conditions, the performance of third-party contractors, the lack of available skilled labor, equipment and materials and the inability to obtain necessary rights-of-way or approvals and permits from regulatory agencies on a timely basis or at all (and maintain such rights-of-way, approvals and permits once obtained). These types of projects may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase for some time after completion of a particular project. For instance, we are required to pay construction costs generally as they are incurred but construction typically occurs over an extended period of time, and we will not receive revenues or material increases in revenues until the project is placed into service. Moreover, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Our systems compete primarily with other interstate and intrastate pipelines and storage facilities in the gathering, transmission and storage of natural gas. Some of our competitors have greater financial resources and may be better positioned to compete as the midstream industry moves towards greater consolidation; further, some of such competitors may now, or in the future, have access to greater supplies of natural gas or water than we do. Some of these competitors may expand or construct gathering systems, transmission and storage systems and water systems that would create additional competition for the services we provide to our customers. In addition, our customers may develop or acquire their own gathering, transmission or storage, or water services instead of using ours.

We are exposed to the risk of loss resulting from the nonpayment and/or nonperformance of our customers, suppliers, joint venture partners and other counterparties as further described in “Credit Risk” under “Item 7A. Quantitative and Qualitative Disclosure About Market Risk.” We extend credit to our customers as a normal part of our business. While we have established credit policies, including assessing the creditworthiness of our customers as permitted by our FERC-approved natural gas tariffs, and may require appropriate terms or credit support from them based on the results of such assessments, including in the form of prepayments, letters of credit, or guaranties, we may not have adequately assessed the creditworthiness of our existing or future customers. Pursuant to the EQT Global GGA and the Credit Letter Agreement, amongst other things, (a) we agreed to relieve certain credit posting requirements for EQT, in an amount up to approximately $250 million under its commercial agreements with us, subject to EQT maintaining a minimum credit rating from two of three rating agencies of (i) Ba3 with Moody’s, (ii) BB- with S&P and (iii) BB- with Fitch. As of February 22, 2021, EQT’s public debt had sub-investment grade credit ratings of BB with a stable outlook at S&P, Ba2 with a stable outlook at Moody’s, and BB with a positive outlook at Fitch. We cannot predict the extent to which the businesses of our counterparties would be impacted if commodity prices decline, commodity prices are depressed for a sustained period of time, or other conditions in the energy industry were to further deteriorate, nor can we estimate the impact such conditions would have on the abilities of our customers to perform under their gathering, transmission and storage and water services agreements with us. The recent low commodity price environment negatively impacted natural gas producers causing some producers significant economic stress including, in certain cases, to file for bankruptcy protection or to renegotiate contracts. To the extent one or more of our counterparties, including EQT, is in financial distress or commences bankruptcy proceedings (such as the bankruptcy proceedings commenced by Gulfport on November 13, 2020), contracts with these counterparties may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code (Bankruptcy Code). On November 24, 2020, Gulfport moved to reject its gas gathering agreements with certain of our subsidiaries and made certain related court filings attempting to reject the agreements, which motions we have opposed. For the year ended December 31, 2020, Gulfport accounted for approximately 9% of the Company's operating revenues. Nonpayment and/or nonperformance by our counterparties occurring as a result of changes in the conditions in energy industry and/or any unfavorable renegotiation or rejection of contracts under the Bankruptcy Code could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

On September 23, 2020, EQT and certain of its affiliates instituted arbitration proceedings against us relating to the Hammerhead gathering agreement, pursuant to which we agreed to construct the Hammerhead pipeline and related facilities and gather gas for EQT. See “Hammerhead Pipeline” under “Outlook” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information. The dispute, during its pendency, could adversely affect our business and operating results, including by causing us to incur expenses in arbitration or additional proceedings in excess of those currently expected and by diverting management time and resources. Also, while the dispute is ongoing, we believe the market price of our common stock may continue to be adversely affected by the perception that the dispute is negatively affecting our overall commercial relationship with EQT. In addition, if the dispute is resolved in a manner adverse to us, such resolution could result in EQT’s acquisition of Hammerhead assets in exchange for a reimbursement payment or otherwise affect or negate our ability to recognize revenue and generate operating cash flows in the future from such assets.

Our water services business includes fresh water distribution for use in our customers’ natural gas, NGL and oil exploration and production activities. Water is an essential component of natural gas, NGL and oil production during the drilling and the hydraulic fracturing process. As a result, the demand for our fresh water distribution and produced water handling services is tied to the level of drilling and completion activity of our customers, including EQT (which is currently and anticipated to continue to be our primary customer for such services). More specifically, the demand for our water distribution and produced water handling services has been and could be further adversely affected by any further reduction in or slowing of EQT’s or other customers’ well completions, any reduction in produced water attributable to completion activity, or the extent to which EQT or other customers complete wells with shorter lateral lengths, which would lessen the volume of fresh water required for completion activity, and may also be affected by other companies that provide water services. In addition, increased regulation of hydraulic fracturing could result in reductions or delays in natural gas, NGL and oil production by our water service customers, which could reduce the number of wells for which we provide water services.

It is possible that costs to perform services under “negotiated rate” contracts will exceed the negotiated rates we have agreed to provide to our customers. If this occurs, it could decrease the cash flow realized by our systems and, therefore, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Under FERC policy, a regulated service provider and a customer may mutually agree to a “negotiated rate,” and that contract must be filed with and accepted by the FERC. As of December 31, 2020, approximately 97% of the contracted firm transmission capacity on our system was subscribed under such “negotiated rate’’ contracts. Unless the parties to these “negotiated rate” contracts agree otherwise, the contracts generally may not be adjusted to account for increased costs that could be caused by inflation or other factors relating to the specific facilities being used to perform the services.

We have entered into joint ventures to construct the MVP and MVP Southgate projects and a joint venture relating to Eureka Midstream and may in the future enter into additional joint venture arrangements with third parties. Joint venture arrangements may restrict our operational and corporate flexibility. Joint venture arrangements and dynamics can also divert management and operating resources in a manner that is disproportionate to our ownership percentage in such ventures. Because we do not control all of the decisions of the MVP Joint Venture or the joint venture relating to Eureka Midstream, it may be difficult or impossible for us to cause these joint ventures to take actions that we believe would be in our or the joint venture’s best interests. For example, we cannot unilaterally cause the distribution of cash by the MVP Joint Venture or Eureka Midstream. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing that we fund operating and/or capital expenditures, the timing and amount of which we may not control, and our joint venture partners may not act in a manner that we believe would be in our or the joint venture’s best interests or satisfy their financial obligations to the joint venture. In addition, the operations of the MVP Joint Venture, Eureka Midstream and any joint ventures we may enter into in the future are subject to many of the same operational risks to which we are subject.

In order to fund our capital expenditures and capital contributions, we may use cash from our operations, incur borrowings under our subsidiaries’ credit facilities or through debt capital market transactions, enter into our own credit arrangements or sell additional shares of our equity or a portion of our assets. Using cash from operations will reduce the cash we have available to pay dividends to our shareholders. Our and our subsidiaries’ ability to obtain bank financing or to access the capital markets for debt offerings, or our ability to access the capital markets for future equity offerings, may be limited by, among other things, our and our subsidiaries’ financial condition at the time of any such financing or offering, our and our subsidiaries’ credit ratings, as applicable, the covenants in our subsidiaries’ debt agreements, the rights and preferences governing the Equitrans Midstream Preferred Shares, general economic conditions, including related to the COVID-19 outbreak, market conditions in our industry, changes in law (including tax laws), and other contingencies and uncertainties that are beyond our control. Additionally, market forces are affecting (and are expected to continue to affect) the availability of capital to energy industry participants. For example, activists concerned about the potential effects of climate change continue to direct their attention towards, among other things, sources of funding for fossil fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investments in energy-related activities. Further, such institutions are increasingly allocating funds to those industries and companies perceived as having better growth opportunities and/or stronger ESG metrics and practices. Such market forces may adversely affect our ability to obtain financing in the future or achieve increases in our stock price.

As of February 22, 2021, EQM and EQT had sub-investment grade credit ratings at each of Moody’s, S&P and Fitch. See “A further downgrade of EQM’s credit ratings, including in connection with the MVP project or customer credit ratings changes, including EQT’s, which are determined by independent third parties, could impact our liquidity, access to capital, and costs of doing business.” Global financial markets and economic conditions have been, and continue to be, volatile, especially for companies involved in the oil and gas industry. Furthermore, as a result of concerns about the stability of financial markets generally, the solvency of counterparties specifically and general market trends favoring funding non-fossil fuel industries and companies (or fossil fuel industry companies with stronger ESG metrics and practices), the cost of obtaining money from the bank markets generally has increased as many lenders and institutional investors have increased rates, enacted tighter lending standards, refused to refinance existing debt at maturity or at all or on terms similar to the borrower’s current debt, and reduced, or in some cases, ceased to provide funding to borrowers, particularly those in the fossil fuel industry. The repricing of credit risk, concern regarding funding fossil fuel companies given climate change, and the relatively weak economic conditions in the oil and gas industry, compounded by the global economic downturn caused by the COVID-19 outbreak, have made, and will likely continue to make, it difficult for some entities to obtain funding on favorable terms or at all. As a result, even if we or our subsidiaries are successful in obtaining funds for capital expenditures and capital contributions through debt or equity financings, as applicable, the terms thereof could limit our ability to pay dividends to our shareholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage thereby limiting our ability to further borrow, and issuing additional equity may result in significant common shareholder dilution and increase the aggregate amount of cash required to maintain the then-current dividend rates, which could materially decrease our ability to pay dividends at the then-current dividend rates. If funding is not available to us or our subsidiaries when needed, or is available only on unfavorable terms, we may be unable to execute our business plans, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which (or actions taken to attempt to address any such funding issue) could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

These risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, regulatory investigations and penalties and substantial losses to us. The location of certain segments of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. Despite any precautions taken, an event such as those described above could cause considerable harm to people, property or the environment and could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our systems. Potential customer impacts arising from service interruptions on segments of our systems could include, but are not limited to, limitations on our ability to satisfy customer contractual requirements, obligations to provide reservation charge credits to customers in times of constrained capacity and solicitation of our existing customers by third parties for potential new projects that would compete directly with our existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Negative public perception regarding us, the MVP, MVP Southgate, other of our expansion projects, other industry participants and their projects and actions, the midstream industry and/or the natural gas industry in general resulting from, among other things, climate change, oil spills, the explosion of natural gas transmission and gathering lines and other facilities, erosion and sedimentation issues, unpopular expansion projects, and general concerns raised by advocacy groups about hydraulic fracturing and pipeline projects (as well as specific concerns raised by such groups in respect of particular pipeline projects), has led to, and may in the future lead to, increased regulatory scrutiny, which may, in turn, lead to new local, state and federal safety and environmental laws, regulations, guidelines, enforcement interpretations and/or adverse judicial rulings or regulatory actions. See “Item 3. Legal Proceedings.” These actions have caused, and may continue to cause, operational delays or restrictions, increased construction and operating costs, penalties under construction contracts, additional regulatory burdens and increased litigation. As discussed under “The regulatory approval process for the construction of new midstream assets is very challenging, and decisions by regulatory and judicial authorities in pending or potential proceedings could impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations necessary to complete certain projects on the targeted time frame or at all or our ability to achieve the expected investment returns on the projects,” there are several pending challenges to certain aspects of the MVP project and the MVP Southgate project that must be resolved before the MVP project and the MVP Southgate project, as applicable, can be completed. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we and the MVP Joint Venture need to complete the expansion projects, including the MVP and MVP Southgate projects, and conduct our and its respective operations to be denied, removed, withheld, delayed, stayed or burdened by requirements that restrict our and its respective abilities to profitably conduct business or make it more difficult to obtain the real property interests needed in order to operate

Most of our insurance is subject to deductibles or self-insured retentions. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations, business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. We may not be able to maintain or obtain insurance of the types and in the amounts we desire at reasonable rates, and we may elect to self-insure a portion of our asset portfolio. The insurance coverage we have obtained or may obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses. In addition, for pre-Distribution losses, we share insurance coverage with EQT, and we will remain responsible for payment of any deductible or self-insured amounts under those insurance policies. To the extent we experience a pre-Distribution loss that would be covered under EQT’s insurance policies, our ability to collect under those policies may be reduced to the extent EQT erodes the limits under those policies.

Our business has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications, to operate our assets, and the maintenance of our financial and other records has long been dependent upon such technologies. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Deliberate attacks on, or unintentional events affecting, our systems or infrastructure, the systems or infrastructure of third parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in delivery of natural gas and NGLs, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, personal injury, property damage and other operational disruptions, as well as damage to our reputation, financial condition and cash flows. Further, as cyber incidents continue to evolve, we may be required to expend additional resources beyond those currently budgeted to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. In addition, new U.S. laws and regulations governing data privacy and the unauthorized disclosure of personal information may potentially elevate our compliance costs. Any failure by us to comply with these laws and regulations, including as a result of a cyber incident, could result in significant penalties and liability to us. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.

For the years ended December 31, 2020, 2019 and 2018, approximately 66%, 58% and 54%, respectively, of our revenues were generated from firm reservation fees. Although our goal is to execute long-term firm reservation fee and MVC contracts with new or existing customers in the future, our efforts to obtain such contractual terms may not be successful. As of December 31, 2020, most of our water service agreements are volumetric in nature and therefore are more sensitive to fluctuations in commodity prices and downturns in hydraulic fracturing by our customers in the future. In addition, we may acquire or develop additional midstream assets in the future that do not provide services primarily based on capacity reservation charges or other fixed fee arrangements and therefore have a greater exposure to fluctuations in commodity price risk than our current operations. Exposure to the volatility of natural gas prices, including regional basis differentials with regard to natural gas prices, as a result of our contracts could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Additionally, the EQT Global GGA provides for potential cash bonus payments payable by EQT to us during the period beginning on the first day of the calendar quarter in which the MVP in-service date occurs through the earlier of the twelfth calendar quarter from that point or the calendar quarter ending December 31, 2024 (the Henry Hub cash bonus payment provision). The fair value of the Henry Hub cash bonus payment provision is largely determined by estimates of the NYMEX Henry Hub natural gas forward price curve, and payments are conditioned upon the quarterly average of certain Henry Hub natural gas prices exceeding certain price thresholds. Based on the Henry Hub natural gas forward strip prices as of February 19, 2021 and the terms of the Henry Hub cash bonus payment provision, delays in the in-service date for the MVP project, including beyond the most recent targeted full in-service of late 2021, may decrease the estimated fair value of the derivative asset attributable to the Henry Hub cash bonus payment provision. Such changes in estimated fair value, if any, would be recognized in other income on our statements of consolidated comprehensive income and could have an adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

We do not own all of the land on which our pipelines, storage systems and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms, and/or increased costs or delays, to retain necessary land use if we do not have valid rights-of-way or easements, if such rights-of-way or easements lapse or terminate or if our facilities are not properly located within the boundaries of such rights-of-way or easements. Although many of these rights are perpetual in nature, we occasionally obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. If we were to be unsuccessful in negotiating or renegotiating rights-of-way or easements, we might have to institute condemnation proceedings on our FERC-regulated assets or relocate our facilities for non-regulated assets. It is possible that the U.S. Congress may amend Section 7 of the NGA to require that condemnation authority not be exercised and construction may not begin until a FERC certificate order has been reviewed on rehearing. A loss of rights-of-way or easements or a relocation could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Additionally, even when we own an interest in the land on which our pipelines, storage systems and facilities have been constructed, agreements with correlative rights owners may require that we relocate pipelines and facilities or shut in storage systems and facilities to facilitate the development of the correlative rights owners’ estate, or pay the correlative rights owners the lost value of their estate if they are not willing to accommodate development.

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

Amounts drawn under our subsidiaries’ respective credit facilities may bear interest at rates based on U.S. dollar LIBOR (USD LIBOR). On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. On November 30, 2020, ICE Benchmark Administration (IBA), the administrator of LIBOR, announced plans to consult on ceasing publication of USD LIBOR on December 31, 2021 for only the one-week and two-month USD LIBOR tenors, and on June 30, 2023 for all other LIBOR currency-tenor pairs. U.S. regulators, including the U.S. Federal Reserve, published a concurrent statement supporting the IBA’s plans but also urging banks to phase out LIBOR as soon as practicable. On December 4, 2020, the IBA published its consultation on the potential cessation of LIBOR, consistent with its earlier announcement. In light of these recent announcements, the future of USD LIBOR at this time is uncertain and any changes in the methods by which USD LIBOR is determined or regulatory activity related to USD LIBOR’s phase-out could cause USD LIBOR to perform differently than in the past or cease to exist. The Amended EQM Credit Facility provides for mechanisms to amend the facility to reflect the establishment of an alternative rate of interest upon the occurrence of certain events related to the phase-out of LIBOR, while the Eureka Credit Facility requires USD LIBOR based loans to be converted to base rate borrowings.

We have not yet pursued any technical amendments or other contractual alternatives to address this matter. We are evaluating the potential impact of the cessation of USD LIBOR; however, we are not able to predict whether USD LIBOR will cease to be available or cease to be used, when such cessation may occur, whether SOFR or any other rate will become a widely accepted replacement for LIBOR, or the terms on which we may be able to renegotiate our credit facilities and the eventual impact of such developments on our interest expense. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial markets could have a material adverse impact on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Pursuant to the NGA, existing interstate transmission and storage rates, terms and conditions of service, and contracts may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases, changes to terms and conditions of service and contracts proposed by a regulated interstate pipeline may be protested and such actions can be delayed and may ultimately be rejected by the FERC. We currently hold authority from the FERC to charge and collect (i) “recourse rates,” which are the maximum rates an interstate pipeline may charge for its services under its tariff, (ii) “discount rates,” which are rates below the “recourse rates” and above a minimum level, (iii) “negotiated rates,” which involve rates above or below the “recourse rates,” provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement, and (iv) market-based rates for some of our storage services from which we derive a small portion of our revenues. As of December 31, 2020, approximately 97% of our contracted firm transmission capacity was subscribed by customers under negotiated rate agreements under our tariff, rather than recourse, discount or market-based rate contracts. There can be no guarantee that we will be allowed to continue to operate under such rate structures for the remainder of those assets’ operating lives. Customers, the FERC or other interested stakeholders, such as state regulatory agencies, may challenge our rates offered to customers or the terms and conditions of service included in our tariffs. We do not have an agreement in place that would prohibit customers, including EQT or its affiliates, from challenging our tariffs. Any successful challenge against rates charged for our transmission and storage services could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.

Our operations are regulated extensively at the federal, state and local levels. Laws, regulations and other legal requirements have increased the cost to plan, design, install, operate and abandon gathering, transmission and water systems and pipelines, as well as storage systems. Legal requirements relating to the environment, health and safety govern discharges of substances into the air, water and ground; the management and disposal of hazardous substances and wastes; the clean-up of contaminated sites; groundwater quality and availability; plant and wildlife protection; locations available for pipeline construction; environmental impact studies and assessments in connection with permitting; restoration of properties after construction or operations are completed; pipeline safety (including replacement requirements); and work practices related to employee health and safety. Compliance with the laws, regulations and other legal requirements applicable to our business, including delays in obtaining (or challenges maintaining) permits or other government approvals, may increase our cost of doing business, result in delays or restrictions in the performance of operations due to the need to pursue alternative construction methods or obtain additional or more detailed permits or other governmental approvals or even cause us to abandon an existing project or not to pursue a new project. For example, the FWS continues to receive hundreds of petitions to consider listing of additional species as endangered or threatened and is being regularly sued or threatened with lawsuits to address these petitions. Some of these legal actions have resulted in, and may in the future result in, listing of species located in areas in which we operate. Such designations of previously unprotected species as being endangered or threatened, or the designation of previously unprotected areas as a critical habitat for such species, can result in increased costs, construction delays, restrictions in our operations or abandonment of projects. Listing of aquatic species could potentially affect water supplies or delay related infrastructure development. As discussed under “The regulatory approval process for the construction of new midstream assets is very challenging, and decisions by regulatory and judicial authorities in pending or potential proceedings could impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations necessary to complete certain projects on the targeted time frame or at all or our ability to achieve the expected investment returns on the projects,” there are several pending challenges to certain aspects of the MVP project and the MVP Southgate project that must be resolved before the MVP project and the MVP Southgate project, as applicable, can be completed, including those litigation and regulatory-related delays discussed in “Item 3. Legal Proceedings.” In addition, lack of compliance with laws, regulations or other legal requirements could subject us to claims for personal injuries, property damage and other damages. Our failure to comply with the laws, regulations and other legal requirements applicable to our business, even if as a result of factors beyond our control, could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages.

The EPA regulates GHG emissions from new and modified facilities that are potential major sources of criteria pollutants under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs and has adopted regulations that require, among other things, preconstruction and operating permits for certain large stationary sources and the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis. Laws, regulations and other legal requirements are constantly changing, and implementation of compliant processes in response to such changes could be costly and time consuming. For additional information on laws, regulations and other legal requirements applicable to us, see “Regulatory Environment—Environmental Matters” under “Item 1. Business.” Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. In addition to periodic changes to air, water and waste laws, as well as anticipated EPA initiatives to impose climate change-based air regulations on industry, which we expect to increase under the Biden Administration, the U.S. Congress and various states have been evaluating and/or implemented climate-related legislation and other regulatory initiatives that would further restrict emissions of GHGs, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of burning natural gas). Several states are also pursuing similar measures to regulate emissions of GHGs from new and existing sources. Many states and regions have adopted GHG initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities. For example, ten northeastern states and Virginia participate in the Regional Greenhouse Gas Initiative agreement (RGGI) aimed at reducing carbon dioxide emissions from power plants. RGGI imposes a cap on emissions of carbon dioxide on all fossil-fuel fired electric generating facilities that are 25 MW or larger and allows for trades of carbon dioxide emissions in the participating states. Pennsylvania has taken steps to join RGGI. It is likely that these regional efforts will continue. If implemented, GHG restrictions may result in additional compliance obligations with respect to, or taxes on the release, capture and use of, GHGs that could have an adverse effect on our business, financial condition, results of operations, liquidity or ability to pay dividends to our shareholders. Further, initiatives such as RGGI may adversely affect demand for natural gas and accordingly our producer customers, which could

There is a risk that we may incur costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of wastes and potential emissions and discharges related to our operations. Private parties, including the owners of the properties through which our gathering system or our transmission and storage system pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to require remediation of contamination or enforce compliance with environmental requirements as well as to seek damages for personal injury or property damage. In addition, changes in environmental law that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to pay dividends to our shareholders. We may not be able to recover all or any of these costs from insurance.

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

local governments have adopted, and others may adopt, ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Further, several federal governmental agencies are conducting reviews and studies on the environmental aspects of hydraulic fracturing, including the EPA. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report, contrary to several previously published draft reports issued by the EPA, found instances in which impacts to drinking water may occur. However, the report also noted significant data gaps that prevented the EPA from determining the extent or severity of these impacts. The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing.

State and federal regulatory agencies recently have focused on a possible connection between hydraulic fracturing-related activities and the increased occurrence of seismic activity (induced seismicity). In a few instances, operators of injection disposal wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their regulations to account for induced seismicity. While Pennsylvania is not one of the states where such regulation has been enacted, regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. These developments could result in additional regulation and restrictions on the use of injection disposal wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on our customers.

Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to EQM’s income tax return for tax years beginning after 2017, the IRS (and some states) may assess and collect any resulting taxes (including any applicable interest and penalties) directly from EQM. EQM will have a limited ability to shift any such tax liability to its general partner and unitholders, including us, in accordance with their interests in EQM during the year under audit, but there can be no assurance that EQM will be able to do so under all circumstances, or that EQM will be able to effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which EQM does business in the year under audit or in the adjustment year. As a result of the EQM Merger, we own all of the EQM common units. If EQM makes payments of taxes, penalties and interest resulting from audit adjustments with respect to tax periods beginning in 2017 and before 2021, we may be and potentially former unitholders may be required to reimburse it for such payment or, if EQM is required to bear such payments, our cash available to pay dividends to our shareholders might be substantially reduced.

We are not required to declare and pay dividends to our common shareholders, and our Board may decide to reduce the amount of the cash dividend that we pay on our common stock or may decide not to declare any dividends in the future. Although we have in the past paid regular cash dividends, any payment of future dividends will be at the sole discretion of our Board and will depend upon many factors, including the financial condition, earnings, liquidity and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, our leverage, regulatory constraints and other factors deemed relevant by our Board. We are also not entitled to pay any dividends on any junior securities, including any shares of our common stock, prior to paying the quarterly dividends payable to the holders of Equitrans Midstream Preferred Shares, including any previously accrued and unpaid dividends.

As more fully described under “As part of the EQM Merger and the related Restructuring, we issued Equitrans Midstream Preferred Shares in exchange for a portion of the then-outstanding EQM Series A Preferred Units, which Equitrans Midstream Preferred Shares by virtue of their terms and preferences present a number of risks to current and future holders of our common stock”, at the effective time of the EQM Merger, we created and issued the Equitrans Midstream Preferred Shares in exchange for a portion of the then-outstanding EQM Series A Preferred Units. Upon the occurrence of certain events or the passage of time, the Equitrans Midstream Preferred Shares may be converted by the holder or us, as applicable, initially on a one-for-one basis in the case of certain conversions by holders, subject to certain anti-dilution adjustments and an adjustment for any dividends that have accrued but not been paid when due and partial period dividends. If we or a holder of the Equitrans Midstream Preferred Shares convert Equitrans Midstream Preferred Shares into common stock, the conversion will have a dilutive effect on our earnings per share of common stock, which could adversely affect the market price of our common stock.

Our Second Amended and Restated Bylaws provide that, unless our Board otherwise determines, the state and federal courts sitting in the judicial district of the Commonwealth of Pennsylvania, County of Allegheny, will be the sole and exclusive forum for any derivative action or proceeding brought on behalf of us, any action asserting a claim of breach of a fiduciary duty owed by any director or officer or other employee of ours to us or our shareholders, any action asserting a claim against us or any director or officer or other employee of us arising pursuant to any provision of the PBCL or our Amended and Restated Articles of Incorporation or Second Amended and Restated Bylaws or any action asserting a claim against us or any director or officer or other employee of ours governed by the internal affairs doctrine. The choice of forum provision set forth in our Second Amended and Restated Bylaws does not apply to actions arising under the Securities Act or the Exchange Act.

We are in the process of implementing a new enterprise resource planning (ERP) system. We are committing significant resources to implementation activities and the system software. Our ERP system is critical to our financial reporting and ability to establish effective controls and execute critical business processes. The transition to our new ERP system may be disruptive to our business if the ERP system, which is being done in phases, does not work as planned or if we experience issues relating to the implementation. Such disruptions could impact our ability to provide important information to our management, send invoices and track payments, fulfill contractual obligations, accurately maintain books and records, provide accurate, timely and reliable reports on our financial and operating results or otherwise operate our business. In addition, we may experience periodic or prolonged disruption of our financial functions arising out of the implementation and conversion, general use of the system, other periodic upgrades or updates, or other external factors that are outside of our control. Additionally, if the system does not operate as intended, the effectiveness of our internal control over financial reporting could be adversely affected or ability to assess it adequately could be delayed. This ERP system and our other information technology systems may be vulnerable to data breaches, cyber-attacks or fraud.

At the effective time of the EQM Merger, we created and issued the Equitrans Midstream Preferred Shares in exchange for a portion of the then-outstanding EQM Series A Preferred Units. The creation and issuance of the Equitrans Midstream Preferred Shares present a number of risks to current and future holders of our common stock, including a preference in favor of holders of Equitrans Midstream Preferred Shares in the payment of dividends on our common stock, the risk of dilution occurring as a result of the conversion of the Equitrans Midstream Preferred Shares into our common stock and the ability of the holders of the Equitrans Midstream Preferred Shares to vote with the holders of our common stock on most matters, as well as the risk that the holders of the Equitrans Midstream Preferred Shares will have certain other class voting rights with respect to any amendment to our organizational documents that would be adverse (other than in a de minimis manner) to any of the rights, preferences or privileges of the Equitrans Midstream Preferred Shares.

Pursuant to the terms of the Restructuring Agreement, in connection with the closing of the Restructuring, we entered into a registration rights agreement with certain holders of the Equitrans Midstream Preferred Shares pursuant to which, among other things, we gave the Investors certain rights to require us to file and maintain one or more registration statements with respect to the resale of the Equitrans Midstream Preferred Shares and the shares of our common stock that are issuable upon conversion of the Equitrans Midstream Preferred Shares, and which, upon request by certain Investors party to the Registration Rights Agreement, will require us to initiate underwritten offerings for the Equitrans Midstream Preferred Shares and the shares of our common stock that are issuable upon conversion of the Equitrans Midstream Preferred Shares and use our best efforts to cause the Equitrans Midstream Preferred Shares to be listed on the securities exchange on which the shares of our common stock are then listed. See Note 2 to the consolidated financial statements for further information on the Equitrans Midstream Preferred Shares.

It was a condition to the Distribution that (i) a private letter ruling from the IRS regarding the qualification of the Distribution, together with certain related transactions, as a transaction that is generally tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code and certain other U.S. federal income tax matters relating to the Separation and Distribution shall not have been revoked or modified in any material respect and (ii) EQT received an opinion of counsel with respect to certain tax matters relating to the qualification of the Distribution, together with certain related transactions, as a transaction described in Sections 355 and 368(a)(1)(D) of the Code. The IRS private letter ruling is based upon and relies on, and the opinion of counsel is based upon and relies on, among other things, various facts and assumptions, as well as certain representations, statements and undertakings of EQT and us, including those relating to the past and future conduct of EQT and us. If any of these representations, statements or undertakings is, or becomes, inaccurate or incomplete, or if any representations or covenants contained in any of the Separation-related agreements and documents or in any documents relating to any IRS private letter ruling or opinion of counsel are breached, such IRS private letter ruling and/or opinion of counsel may be invalid and the conclusions reached therein could be jeopardized.

Notwithstanding receipt of the IRS private letter ruling and opinion of counsel, the IRS could determine that the Distribution and/or certain related transactions should be treated as taxable transactions for U.S. federal income tax purposes if it determines that any of the representations, assumptions or undertakings upon which such IRS private letter ruling or the opinion of counsel was based are false or have been violated. In addition, the IRS private letter ruling does not address all of the issues that are relevant to determining whether the Distribution, together with certain related transactions, continues to qualify as a transaction that is generally tax-free for U.S. federal income tax purposes, and the opinion of counsel represented the judgment of such counsel and is not binding on the IRS or any court and the IRS or a court may disagree with the conclusions in any opinion of counsel. Accordingly, notwithstanding receipt of an IRS private letter ruling or opinion of counsel, there can be no assurance that the IRS will not assert that the Distribution and/or certain related transactions do not qualify for the intended tax treatment or that a court would not sustain such a challenge. In the event the IRS were to prevail with such challenge we, EQT, and our respective shareholders could be subject to material U.S. federal income tax liability.

Even if the Distribution otherwise qualifies as generally tax-free for U.S. federal income tax purposes under Section 355 and Section 368(a)(1)(D) of the Code, it would result in a material U.S. federal income tax liability to EQT (but not to its shareholders) under Section 355(e) of the Code if one or more persons acquire, directly or indirectly, a 50-percent or greater interest (measured by either vote or value) in EQT’s stock or in the stock of us as part of a plan or series of related transactions that includes the Distribution, and we may be required to indemnify EQT for any such liability under the tax matters agreement entered into by EQT and us in connection with the Distribution. The process for determining whether an acquisition is part of a plan under these rules is complex, inherently factual in nature and subject to a comprehensive analysis of the facts and circumstances of the particular case. Notwithstanding the IRS private letter ruling and opinion of counsel described above, a sufficient change in ownership of EQT or our common stock may occur which could result in a material tax liability to EQT.

There are several significant areas where the liabilities of EQT may become our obligations. For example, under the Code and the related rules and regulations, each corporation that was a member of the EQT consolidated U.S. federal income tax return group during a taxable period or portion of a taxable period ending on or before the effective date of the Distribution is jointly and severally liable for the U.S. federal income tax liability of the EQT consolidated U.S. federal income tax return group for that taxable period. Consequently, if EQT is unable to pay the consolidated U.S. federal income tax liability for a pre-Separation period, we could be required to pay the amount of such tax, which could be substantial and in excess of the amount allocated to us under the tax matters agreement. For a discussion of the tax matters agreement, see Note 8 to the consolidated financial statements. Other provisions of federal law establish similar liability for other matters, including laws governing tax-qualified pension plans, as well as other contingent liabilities.

In connection with the Separation, we and EQT entered into a Separation and Distribution Agreement as well as various other agreements, including a tax matters agreement, an employee matters agreement and a shareholder and registration rights agreement with respect to EQT’s continuing ownership of our common stock. The Separation and Distribution Agreement, the tax matters agreement and the employee matters agreement determined the allocation of assets and liabilities between the companies following the Separation for those respective areas and include indemnification related to liabilities and obligations. If EQT is unable or unwilling to satisfy its obligations under these agreements, including its indemnification obligations, our business, results of operations and financial condition could be materially and adversely affected. For a description of these agreements with EQT, see Note 8 to the consolidated financial statements.

The Separation and Distribution Agreement with EQT provides for, among other things, provisions governing the relationship between us and EQT with respect to and resulting from the Separation. For a description of the Separation and Distribution Agreement, see Note 8 to the consolidated financial statements. Among other things, the Separation and Distribution Agreement provides for indemnification obligations designed to make us financially responsible for substantially all liabilities that may exist relating to our business activities, whether incurred prior to or after the Separation, as well as those obligations of EQT assumed by us pursuant to the Separation and Distribution Agreement. If we are required to indemnify EQT under the circumstances set forth in the Separation and Distribution Agreement, we may be subject to substantial liabilities. See also the discussion of potential indemnification obligations under “If the Separation and Distribution, together with certain related transactions, does not continue to qualify as a transaction that is generally tax-free for U.S. federal income tax purposes, we, EQT, and our respective shareholders could be subject to significant tax liabilities and, in certain circumstances, we could be required to indemnify EQT for material taxes and other related amounts pursuant to indemnification obligations under the tax matters agreement.”

The Company's real property falls into two categories: (i) parcels that it owns in fee and (ii) parcels in which its interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the Company's operations. Certain lands on which the Company's pipelines and facilities are located are owned by the Company in fee title, and the Company believes that it has satisfactory title to these lands. The remainder of the lands on which the Company's pipelines and facilities are located are held pursuant to surface leases or easements between the Company, as lessee or grantee, and the respective fee owners of the lands, as lessors or grantors. The Company has held, leased or owned many of these lands for many years without any material challenge known to the Company relating to the title to the land upon which the assets are located, and the Company believes that it has satisfactory leasehold estates, easement interests or fee ownership to such lands. The Company believes that it has satisfactory title to all of its material leases, easements, rights-of-way, permits and licenses, and the Company has no knowledge of any material challenge to its title to such assets or their underlying fee title.

As discussed under, “We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations and future development," included in "Item 1A. Risk Factors," there are, however, certain lands within the Company's storage pools as to which it may not currently have vested real property rights, some of which are subject to ongoing acquisition negotiations or inverse condemnation proceedings. In accordance with Equitrans, L.P.'s FERC certificates, the geological formations within which its permitted storage facilities are located cannot be used by third parties in any way that would detrimentally affect its storage operations, and the Company has the power of eminent domain with respect to the acquisition of necessary real property rights to use such storage facilities. Certain property owners have initiated legal proceedings against the Company and its affiliates for trespass, inverse condemnation and other claims related to these matters, and there is no assurance that other property owners will not initiate similar legal proceedings against the Company and its affiliates prior to final resolution.

Pratt Storage Field. On October 31, 2018, a gas explosion occurred in Morgan Township, Greene County, Pennsylvania (the Incident). Following the explosion, the Pennsylvania Department of Environmental Protection (the PADEP), the Pennsylvania Public Utilities Commission and the PHMSA began investigating the Incident. In January 2020, the PADEP notified the Company that it was required to submit an investigation report pursuant to the state’s gas migration regulations due to the Incident's proximity to the Company's Pratt Storage Field assets. The Company, while disputing the applicability of the regulations, submitted a report to the PADEP in March 2020. In September 2020, the PADEP responded to the Company’s investigation report with a request for additional information. The Company responded to the September 2020 request, but cannot predict whether any action will ultimately be brought by the PADEP or what the outcome of such an action would be. If a penalty is imposed, it could result in monetary sanctions in excess of $300,000. However, the Company does not believe that the penalty, if imposed, will have a material impact on the financial condition, results of operations or liquidity of the Company.

PADEP Consent Agreement I/M/O Swarts Storage Field – Stipulated Penalty Assessment. On September 2, 2020, the PADEP notified the Company that it was assessing a stipulated penalty in the amount of $490,000 due to the alleged failure of the Company to submit information required pursuant to an October 29, 2019 Consent Order and Agreement. The Company disputed the PADEP’s claim and sought initial dispute resolution proceedings based on the Company’s position that it had submitted the information multiple times since October 2019. On September 29, 2020, the PADEP notified the Company that it was no longer pursuing penalties arising from the alleged violation referenced in the September 2, 2020 letter, but it did not officially withdraw the stipulated penalty. Despite the PADEP’s notification that it was no longer pursuing the stipulated penalty, as a result of the PADEP not officially withdrawing the stipulated penalty, the PADEP could pursue the stipulated penalty in the future. If penalties are pursued and ultimately imposed, these penalties could result in monetary sanctions in excess of $300,000. However, the Company does not believe that the penalties, if imposed, would have a material impact on the financial condition, results of operations or liquidity of the Company.

(which covers all but the northernmost area of West Virginia) for the MVP project. The crux of Sierra Club's position was that the MVP Joint Venture, pursuant to its FERC license, planned to use a certain methodology (dry open cut creek crossing methodology) to construct the pipeline across streams in West Virginia that would take considerably longer than the 72 hours allowed for such activities pursuant to the terms of West Virginia's Clean Water Act Section 401 certification for Nationwide Permit 12. A three-judge panel of the Fourth Circuit agreed with the Sierra Club and on October 2, 2018, issued a preliminary order stopping the construction in West Virginia of that portion of the pipeline that is subject to Nationwide Permit 12. In August 2018, the West Virginia Department of Environmental Protection (WVDEP) initiated an administrative process to revise its 401 Water Quality Certification for the Army Corps Nationwide Permits and requested public comment to, among other things, specifically revise the 72-hour limit for stream crossings noted as problematic by the Fourth Circuit as well as other conditions (the WVDEP 401 Rulemaking Proceedings). Pending the resolution of the West WVDEP 401 Rulemaking Proceedings, the Army Corps' Pittsburgh District and Norfolk District (each of which had also verified use of Nationwide Permit 12 by the MVP Joint Venture) suspended their verifications that allowed the MVP Joint Venture to use Nationwide Permit 12 for stream and wetlands crossings in northern West Virginia and Virginia, respectively. On April 24, 2019, the WVDEP submitted a modification to its 401 Water Quality Certification developed in the WVDEP 401 Rulemaking Proceedings to the EPA for approval, which approval was received in August 2019. The Army Corps approved the WVDEP's modification on January 24, 2020, and the MVP Joint Venture submitted a new permit application to the Army Corps on January 28, 2020. On September 25, 2020, the Huntington and Pittsburgh districts approved MVP Joint Venture’s Nationwide Permit 12 and the Norfolk district lifted its suspension of the MVP Joint Venture's Nationwide Permit 12. On September 28, 2020, Appalachian Mountain Advocates, on behalf of Sierra Club and certain other petitioners, filed a petition for review of the Huntington and Norfolk permits. On October 5, 2020, Appalachian Mountain Advocates requested from the Fourth Circuit an administrative stay of the Army Corps' verifications to the MVP Joint Venture's Nationwide Permit 12. On November 9, 2020, the Court entered an order granting the motion to stay the verifications and issued a written opinion on December 1, 2020 on the issuance of the stay. While the case was scheduled to be fully briefed and argued by March 31, 2021, on February 19, 2021, the MVP Joint Venture, as part of its initiated broader strategy to obtain authorization for stream and wetland crossings discussed above under "Developments, Market Trends and Competitive Conditions" under "Item 1. Business" requested that the Army Corps' Huntington, Pittsburgh, and Norfolk Districts administratively revoke the previously-issued Nationwide Permit 12 verifications for the project. After receiving confirmation from the Army Corps, the MVP Joint Venture accordingly will seek dismissal of the existing litigation challenging those verifications as moot.

•Jefferson National Forest Crossing and Associated Authorizations. In a different Fourth Circuit appeal, Sierra Club, et al. v. U.S. Forest Service, et al., consolidated under Case No. 17-2399, Fourth Circuit Court of Appeals, filed in December 2017, the Sierra Club challenged a BLM decision to grant a right-of-way to the MVP Joint Venture and a USFS decision to amend its management plan to accommodate the MVP, both of which affect the MVP's approximate 3.5-mile segment in the Jefferson National Forest (JNF) in Virginia. On July 27, 2018, agreeing in part with the Sierra Club, the Fourth Circuit vacated the BLM and USFS decisions, finding fault with the BLM's analysis of the practicality of alternate routes and the USFS' analysis of erosion and sedimentation effects. The USFS published a draft Supplemental Environmental Impact Statement (SEIS) to the 2017 FERC Final Environmental Impact Statement for MVP in the Federal Register on September 25, 2020 with a public comment period that closed on November 9, 2020. On December 11, 2020, the USFS published a Final Supplemental Environmental Impact Statement that addressed the issues raised in the prior proceedings and evaluated the most recent sedimentation analysis submitted to the agency consistent with the findings presented in MVP’s Biological Opinion and Incidental Take Statement issued by the FWS on September 4, 2020. See Appalachian Voices, et al. v. U.S. Dep’t of Interior below for additional information. On January 11, 2021, the MVP Joint Venture received final approval of the Record of Decision from the USFS and the BLM on January 15, 2021 issued the required right-of-way permit for the MVP’s 3.5-mile segment in the JNF in Virginia (the JNF Right-of-Way). Sierra Club, et al. subsequently filed a petition with the Fourth Circuit to reverse the USFS approval of the Record of Decision and BLM’s grant of the JNF Right-of-Way in Sierra Club, et. V. U.S. Bureau of Land Management, Case No. 21-108, Fourth Circuit Court of Appeals.

On August 3, 2018, citing the court's vacatur and remand in Sierra Club, et al. v. U.S. Forest Service, et al., consolidated under Case No. 17-2399, the FERC issued a stop work order for the entire pipeline pending the agency actions on remand. The FERC modified its stop work order on August 29, 2018 to allow work to continue on all but approximately 25 miles of the project (the Exclusion Zone). On October 10, 2018, the Fourth Circuit granted a petition for rehearing filed by the MVP Joint Venture for the limited purpose of clarifying that the July 27, 2018 order did not vacate the portion of the BLM's Record of Decision authorizing a right-of-way and temporary use permit for the MVP to cross the Weston and Gauley Bridge Turnpike Trail in Braxton County, West Virginia. On October 15, 2018, the MVP Joint Venture filed with the FERC a request to further modify the August 3, 2018 stop work order to allow the MVP Joint Venture to complete the bore and install the pipeline under the Weston and Gauley Bridge Turnpike

Trail. On October 24, 2018, the FERC granted the MVP Joint Venture's request to further modify the stop work order and authorize construction. Additionally, on October 9, 2020, the FERC authorized construction to resume project-wide (as it had been stopped by the FERC on October 15, 2019 in relation to a separate matter discussed below), other than with respect to the Exclusion Zone, which requires additional authorization. On December 17, 2020, the FERC again modified the stop work order and authorized construction to resume in 17 miles of the Exclusion Zone. The Company cannot guarantee whether or when the FERC will act in respect of any or all of the remaining portions of the Exclusion Zone (although the MVP Joint Venture anticipates seeking FERC authorization to lift the Exclusion Zone stop work order should water body crossing authorizations be received as discussed above under "Developments, Market Trends and Competitive Condition" under "Item 1. Business"). The FERC's October 9, 2020 and December 17, 2020 actions are the subject of challenges filed by the Sierra Club in Sierra Club, et al. v. FERC, Case No. 20-1512 (consolidated with No. 21-1040), D.C. Circuit Court of Appeals on December 22, 2020 and January 25, 2021, respectively (a stay request filed by the Sierra Club on January 29, 2021 was denied by the Court of Appeals for the D.C. Circuit (DC Circuit) on February 19, 2021). If any of the challenges to the JNF Right-of-Way or FERC's October 9, 2020 and December 17, 2020 orders are successful, it could result in the JNF Right-of-Way or the FERC's orders, as applicable, being vacated and/or additional agency proceedings (the outcome of which the Company cannot predict) and cause a delay in the targeted in-service date for the MVP project (and consequent impacts relating to such delay).

•Challenges to FERC Certificate, Court of Appeals for the DC Circuit. Multiple parties have sought judicial review of the FERC's order issuing a certificate of public convenience and necessity to the MVP Joint Venture and/or the exercise by the MVP Joint Venture of eminent domain authority. On February 19, 2019, the DC Circuit issued an order rejecting multiple consolidated petitions seeking direct review of the FERC order under the Natural Gas Act and certain challenges to the exercise by the MVP Joint Venture of eminent domain authority in Appalachian Voices, et al. v. FERC, et al., consolidated under Case No. 17-1271. No petitions for rehearing or petitions for rehearing en banc were filed by the April 5, 2019 deadline. The mandate was issued on April 17, 2019. Another group of parties filed a complaint in the U.S. District Court for the District of Columbia asserting that the FERC's order issuing certificates is unlawful on constitutional and other grounds in Bold Alliance, et al. v. FERC, et al., Case No. 17-1822. The district court plaintiffs sought declaratory relief as well as an injunction preventing the MVP Joint Venture from developing its project or exercising eminent domain authority. In December 2017 and January 2018, the FERC and the MVP Joint Venture, respectively, moved to dismiss the petitions for lack of subject matter jurisdiction. The court granted the motion and dismissed plaintiffs' complaint on September 28, 2018. On October 26, 2018, plaintiffs appealed the decision in Case No. 17-1822 to the DC Circuit in Bold Alliance, et al. v. FERC, et al., Case No. 18-5322. On December 3, 2018, the FERC, as appellee, filed a joint motion with the appellants to hold Case No. 18-5322 in abeyance pending completion of the appeals of the final agency orders related to the MVP certificate in consolidated Case No. 17-1271 and Atlantic Coast Pipeline’s (ACP) certificate. The MVP Joint Venture filed a motion to dismiss the case as to some of the plaintiffs. On February 15, 2019, the DC Circuit entered an order holding this appeal in abeyance pending rulings on the appeals from the ACP and MVP FERC proceedings. Although the members of the ACP project announced the cancellation of that project on July 5, 2020, ACP's proceeding remains pending. Case No. 18-5322 remains in abeyance. Similarly, another group of parties filed a complaint in the U.S. District Court for the District of Columbia in Bohon et al. v. FERC et al., Case No. 20-00006, asserting that the delegation of authority to FERC under the NGA violates the nondelegation doctrine and separation-of-powers principle of the U.S. Constitution. The MVP Joint Venture and FERC filed motions to dismiss which were granted by the court. On July 6, 2020, the landowners filed a notice of appeal to the DC Circuit in Case No. 20-5203. On November 30, 2020, appellants filed their brief, asking the DC Circuit to overturn the decision of the lower court. Oral arguments before the DC Circuit are scheduled for March 29, 2021. Due to the uncertainty regarding the timing of permitting and the outcome of legal challenges facing the MVP project, on August 25, 2020, the MVP Joint Venture filed a request with the FERC for and, on October 9, 2020, the FERC granted, an extension of time to complete the MVP project for an additional two years through October 13, 2022. On December 22, 2020, a challenge to the FERC’s action to grant an extension of time to complete the MVP project was filed in the DC Circuit in Sierra Club, et al. v. FERC, Case No. 20-1512 (consolidated with No. 21-1040, DC Circuit). On January 29, 2021, Sierra Club requested a stay of the FERC’s action to grant the MVP Joint Venture an extension of time to complete the MVP project from the DC Circuit, which stay request was denied by the DC Circuit on February 19, 2021. If any of these challenges were successful, it could result in the MVP Joint Venture's certificate of public convenience and necessity being vacated and/or additional proceedings before the FERC, the outcome of which the Company cannot predict.

holding the litigation in abeyance until January 11, 2020. On October 15, 2019, the FERC issued an order requiring the MVP Joint Venture to cease all forward-construction progress. The FERC modified this order on October 9, 2020 and December 17, 2020, which the Sierra Club has appealed to the DC Circuit as discussed above in Jefferson National Forest Crossing and Associated Authorizations. On September 4, 2020, FWS issued the MVP Joint Venture a new Biological Opinion and Incidental Take Statement (the New BiOp) for the MVP project and the Fourth Circuit subsequently dismissed the litigation regarding the Original BiOp. On October 27, 2020, Appalachian Voices et al. filed a petition with the Fourth Circuit challenging the New BiOp and filed a request for an administrative stay of the New BiOp with FWS, which FWS subsequently denied. On November 2, 2020, the petitioners filed a motion to stay the New BiOp with the Fourth Circuit. On November 18, 2020, the Fourth Circuit issued an order denying the requested stay. The matter is scheduled to be fully briefed and argued by June 30, 2021. If this challenge were successful, it could result in the New BiOp being vacated and/or additional proceedings (the outcome of which the Company cannot predict) and cause a delay in the targeted in-service date for the MVP project (and consequent impacts relating to such delay).

Grand Jury Subpoena. On January 7, 2019, the MVP Joint Venture received a letter from the U.S. Attorney's Office for the Western District of Virginia stating that it and the EPA are investigating potential criminal and/or civil violations of the Clean Water Act and other federal statutes as they relate to the construction of the MVP. The January 7, 2019 letter requested that the MVP Joint Venture and its members, contractors, suppliers and other entities involved in the construction of the MVP preserve documents related to the MVP generated from September 1, 2018 to the present. In a telephone call on February 4, 2019, the U.S. Attorney's Office confirmed that it had opened a criminal investigation. On February 11, 2019, the MVP Joint Venture received a grand jury subpoena from the U.S. Attorney's Office for the Western District of Virginia requesting certain documents related to the MVP from August 1, 2018 to the present. The MVP Joint Venture is complying with the letter and subpoena but cannot predict whether any action will ultimately be brought by the U.S. Attorney's Office or what the outcome of such an action would be. The MVP Joint Venture began a rolling production of documents responsive to the subpoena after the U.S. Attorney’s office narrowed its subpoena inquiry to five farms in Virginia containing twenty streams or wetlands.

•Sierra Club et al. v. FERC; Case No. 20-1427, DC Circuit. On June 18, 2020, the FERC issued an order granting a certificate of public convenience and necessity for the MVP Southgate project. However, the FERC, while authorizing the project, directed the Office of Energy Projects not to issue a notice to proceed with construction until necessary federal permits are received for the MVP project and the Director of the Office of Energy Projects lifts the stop-work order and authorizes the MVP Joint Venture to continue constructing the MVP project. Certain opposition parties subsequently requested rehearing of the certificate order. On August 20, 2020, the FERC issued an order denying requests for rehearing of that certificate order, and on September 17, 2020, the FERC issued an order addressing the arguments raised on rehearing. On October 9, 2020, Sierra Club, among other petitioners, filed an appeal of these orders with the DC Circuit. On December 23, 2020, the Court set a revised briefing schedule for the proceeding and the matter is scheduled to be fully briefed by August 2, 2021. If this challenge were successful, it could result in the MVP Southgate project’s certificate of public convenience and necessity being vacated and/or additional proceedings before the FERC, the outcome of which the Company cannot predict.

Mr. Karam was appointed Chief Executive Officer and Chairman of the Board of Equitrans Midstream in July 2019. Prior to that, Mr. Karam served as President and Chief Executive Officer of Equitrans Midstream since September 2018 and a Director since November 2018. Prior to his service at Equitrans Midstream, he served as senior vice president, EQT and president, midstream from August 2018, serving in those capacities until the Separation. Mr. Karam served as chief executive officer and chairman of the EQM General Partner from July 2019 until the EQM Merger in June 2020, chairman, president and chief executive officer, from October 2018 to July 2019, and as president, chief executive officer and director, from August 2018 to October 2018. Additionally, he served as chairman, president and chief executive officer of the general partner of EQGP from October 2018 through the consummation of the EQGP Buyout, as well as president, chief executive officer and director from August 2018 to October 2018. Mr. Karam served on EQT’s board of directors from November 2017 until the Separation. Mr. Karam is the founder and served as chairman of Karbon Partners, LLC, which invests in, owns, constructs, and operates midstream energy assets, from April 2017 to August 2018. Mr. Karam previously served as the founder, chairman and chief executive officer of the general partner of PennTex Midstream Partners, LP (PennTex), a publicly traded master limited partnership with operations in North Louisiana and the Permian Basin from 2014 until its sale to Energy Transfer Partners in 2016. Preceding PennTex, he was the founder, chairman and chief executive officer of Laser Midstream Partners, LLC, one of the first independent natural gas gathering systems in the northeast Marcellus Shale, from 2010 until 2012 when it was acquired by Williams Partners.

Ms. Charletta was appointed President and Chief Operating Officer of Equitrans Midstream in July 2019. She was appointed Executive Vice President and Chief Operating Officer of Equitrans Midstream in September 2018. She also served as executive vice president, chief operating officer and a director of the EQM General Partner from October 2018 through July 2019, when she was promoted to president and chief operating officer. She served as president, chief operating officer and director of the EQM General Partner through the EQM Merger. Ms. Charletta served as the executive vice president, chief operating officer and as a director of EQGP's general partner from October 2018 through the consummation of the EQGP Buyout. Ms. Charletta joined EQT in 2002 as a senior pipeline engineer and from that time held various management positions with increasing responsibility. She assumed the role of senior vice president of midstream operations of a subsidiary of EQT in December 2013 and was promoted to senior vice president of midstream engineering and construction in July 2017, a position she held until the Separation.

As discussed under "We cannot guarantee the timing, amount or payment of dividends on our common stock, and we may further reduce the amount of the cash dividend that we pay on our common stock or may not pay any cash dividends at all to our shareholders. Our ability to declare and pay cash dividends to our shareholders, if any, in the future will depend on various factors, many of which are beyond our control.” included in "Item 1A. Risk Factors," the amount and timing of dividends is subject to the discretion of the Board and depends upon business conditions, including, but not limited to, the financial condition, results of operations, liquidity and capital requirements of the Company's operating subsidiaries, covenants associated with certain debt obligations, legal requirements and strategic direction and other factors deemed relevant by the Board. The Board has the discretion to change the dividend at any time for any reason.

In years prior to 2020, the total shareholder return of the Company’s common stock was compared to the total returns of the S&P 500 index and a customized group of peer companies. In recent years, several companies deemed to be the Company’s peers have been acquired or have merged with other companies in the midstream energy industry. This has caused fluctuations in the companies comprising the Company’s customized peer group year-to-year. To mitigate the impact of these fluctuations and provide more consistency to the performance graph disclosure year after year, and to better align with the Company’s simplified organizational structure and broadened investor base following the EQM Merger, for 2020, the Company elected to replace its customized peer group with the Alerian US Midstream Energy Index, which is also used by the Management Development and Compensation Committee of the Board for purposes of establishing peer groups for the Company’s long-term incentive compensation programs. The Peer Group, which includes Antero Midstream Corp., Cheniere Energy Partners, L.P., Crestwood Equity Partners LP, DCP Midstream LP, Enable Midstream Partners LP, Energy Transfer LP, EnLink Midstream, LLC, Enterprise Products Partners L.P., Kinder Morgan, Inc., Magellan Midstream Partners, L.P., MPLX LP, ONEOK, Inc., Phillips 66 Partners LP, Plains All American Pipeline LP, Plains GP Holdings LP, Targa Resources Corp., Western Midstream Partners, LP and The Williams Companies, Inc., is presented for comparative purposes.

Net income attributable to Equitrans Midstream common shareholders was $364.4 million in 2020 compared with a net loss attributable to Equitrans Midstream common shareholders of $203.7 million in 2019. The increase resulted primarily from a decrease in impairment charges associated with long-lived assets on Gathering (as discussed in Note 4 to the consolidated financial statements), higher equity income from the Company's investment in the MVP Joint Venture, increased revenue from firm reservation fees primarily on Water and Gathering and unrealized gains on derivative instruments associated with the Henry Hub cash bonus payment provision, partially offset by lower volumetric-based fee revenues primarily due to the impacts of the EQT Global GGA, higher net income attributable to noncontrolling interests, higher income tax expense, preferred dividends associated with the Equitrans Midstream Preferred Shares, higher net interest expense, higher depreciation expense, higher selling, general and administrative expense and a loss on early extinguishment of debt.

The ongoing COVID-19 outbreak has resulted in a severe global economic downturn and a recession of unknown duration and has caused increased volatility in and intermittent disruptions to the global financial and credit markets. The outbreak has directly resulted in a significant decrease in demand for oil and NGLs, at least in the short term, which caused extreme volatility in oil and other liquids prices and a significant negative impact to, at a minimum, the short- and medium-term outlook for oil prices. The downward pressure on oil prices was further exacerbated by the failure, in March 2020, of Saudi Arabia and Russia to agree to cut oil production, which contributed to a sharp drop in the price of oil (and at one point negative prices for oil) and an imbalance between the supply and demand for oil. The revised outlook for oil and other liquids prices caused a significant reduction in the number of operating drilling rigs in the United States, with a substantial portion of this reduction in rigs accounted for in shale plays targeted primarily at developing oil resources, including the Permian Basin. According to Baker Hughes, the average U.S. rig count fell to approximately 367 during January 2021, compared to an average rig count of approximately 791 during January 2020. This dramatic decrease in the number of operating drilling rigs has positively impacted the natural gas forward price strip based on the market expectation that the reduced or curtailed production of associated gas from basins such as the Permian Basin will at least in the near- and medium-term cause a reduction in the overall supply of natural gas which will more than offset reduced demand for natural gas as a result of the COVID-19 outbreak. See “Commodity Prices” under “Outlook” below for a further discussion of the current commodity price environment for the Company and its producer customers.

Future disruptions to the global financial and credit markets from the COVID-19 outbreak and related economic impacts could, both directly and indirectly, negatively impact the Company’s financial condition and results of operations. The Company closed EQM’s offerings of the 2021 Senior Notes (defined in Note 18 to the consolidated financial statements) and the 2020 Senior Notes (defined in Note 11 to the consolidated financial statements) in January 2021 and June 2020, respectively; however, there can be no guarantee that future disruptions to the financial and credit markets as a result of the COVID-19 outbreak and related economic impacts would not affect the Company’s ability to again access such markets, if needed, on acceptable terms or at all. Further, certain of the Company’s producer customers have significant capital needs, primarily to refinance existing indebtedness that matures during the next several years, and further disruptions or instability in financial and credit markets as a result of the COVID-19 outbreak and the economic disruptions therefrom may have a significant, negative impact on such producers’ abilities to access the financial and credit markets and refinance existing indebtedness as it becomes due. If such producer customers have difficulty refinancing such indebtedness on acceptable terms or at all (or undertaking other transactions to generate cash for debt service), the Company’s exposure to risk of nonpayment and/or nonperformance by its customers would increase. Additionally, the ability of the Company’s producer customers to maintain or grow their production would likely be adversely affected as a result of such refinancing challenges, which would have a negative impact on demand for the Company’s current services as well as the prospect of future pipeline expansion projects that would enhance the Company’s business.

From an operational perspective, while the COVID-19 outbreak has significantly impacted the manner in which the Company’s employees and contractors perform their job functions, the outbreak has had, and continues to have, a minimal impact on the Company’s overall operations. However, the situation surrounding COVID-19 remains fluid, and the Company continues to actively manage its response in collaboration with relevant parties, including its employees, contractors, customers and suppliers. As a midstream energy company, during applicable state-issued stay-at-home orders, the Company has been recognized as an essential business under various regulations related to the COVID-19 outbreak and continued to operate as permitted under these regulations. The Company has proactively undertaken a number of companywide measures intended to promote the safety of field and office-based employees and contractors. These measures include, among other things, establishing an Infectious Disease Response Team, instituting enhanced self-protection and office sanitation measures, eliminating non-essential business travel, implementing a mandatory work-from-home protocol for a substantial majority of the Company’s employees through at least June 1, 2021, instituting face covering protocols, providing certain medical benefit enhancements, practicing social distancing in the field where possible, sharing the Company’s infectious disease response plan with suppliers and contractors, and timely communicating updates to employees and other relevant parties. In addition, the Company has implemented additional mitigation efforts in connection with the remobilization of certain field employees and contractors. The Company’s Infectious Disease Response Team continues to monitor and assist in implementing mitigation efforts in respect of potential areas of risk for the Company and its stakeholders. Additionally, the Company has provided support to local communities through corporate giving and the Equitrans Midstream Foundation. The Company's operations have been able to maintain a consistent level of effectiveness through the measures taken. The Company believes that it is following best practices under COVID-19 guidance and intends to continue to refine its practices as additional guidance is released and assess potential impacts from COVID-19 to its financial position and operating results, as well as any regulatory and legislative activities relating to COVID-19 that could impact its business.

The Company is unable to predict, in light of the ongoing and dynamic nature of the circumstances related to COVID-19 and the continued growth in COVID-19 infections in the United States (including in certain of the Company’s areas of operation) and globally, any additional impact the outbreak may have on the Company’s business, results of operations and financial condition. The extent of COVID-19’s impact on the Company will depend on future developments, which are highly uncertain and cannot be predicted with any reasonable degree of certainty, including new information that may emerge concerning the severity of COVID-19, the duration of the outbreak, spikes in infection rates (including in the Company's areas of operation) and related economic effects and after effects (including on the natural gas industry), and actions taken to contain COVID-19 or its impact, including vaccine acceptance, distribution and effectiveness, among others. For further information regarding the potential impact of COVID-19, see "The outbreak of COVID-19 (or any future pandemic), and related declines in economic output and demand for natural gas, could harm our business, results of operations and financial condition." under "Item 1A. Risk Factors."

Operating segments are revenue-producing components of an enterprise for which separate financial information is produced internally and is subject to evaluation by the chief operating decision maker in deciding how to allocate resources. Headquarters costs consist primarily of transaction costs and other unallocated corporate expenses. Net interest expense, components of other income and income tax expense are managed on a consolidated basis. The Company has presented each segment's operating income (loss), unrealized gain on derivative instruments, equity income and various operational measures in the following sections. Management believes that the presentation of this information is useful to management and investors regarding the financial condition, results of operations and trends of its segments. The Company has reconciled each segment's operating income (loss) to the Company's consolidated operating income (loss) and net income (loss) in Note 5 to the consolidated financial statements.

GATHERING RESULTS OF OPERATIONS


	Years Ended December 31,
	2020		2019		% Change	2018		% Change
FINANCIAL DATA	(Thousands, except per day amounts)
Firm reservation fee revenues(a)	$	595,720	$	581,118	2.5	$	447,360	29.9
Volumetric-based fee revenues	416,561		578,813		(28.0)	549,710		5.3
Total operating revenues	1,012,281		1,159,931		(12.7)	997,070		16.3
Operating expenses:
Operating and maintenance	87,388		96,740		(9.7)	79,735		21.3
Selling, general and administrative	93,070		80,822		15.2	84,001		(3.8)
Separation and other transaction costs	4,104		19,344		(78.8)	7,761		149.2
Depreciation	172,967		144,310		19.9	98,678		46.2
Amortization of intangible assets	63,195		53,258		18.7	41,547		28.2
Impairments of long-lived assets	55,581		854,307		(93.5)	261,941		226.1
Total operating expenses	476,305		1,248,781		(61.9)	573,663		117.7
Operating income (loss)	$	535,976	$	(88,850)	703.2	$	423,407	(121.0)

Unrealized gain on derivative instruments(b)	$	16,460	$	—	100.0	$	—	—

OPERATIONAL DATA
Gathering volumes (BBtu per day)
Firm capacity(c)	4,652		3,351		38.8	2,044		63.9
Volumetric-based services	3,553		4,493		(20.9)	4,445		1.1
Total gathered volumes	8,205		7,844		4.6	6,489		20.9

Capital expenditures(d)	$	344,873	$	834,712	(58.7)	$	717,251	16.4

Gathering operating expenses decreased by $772.5 million for the year ended December 31, 2020 compared to the year ended December 31, 2019, primarily as a result of a $798.7 million decrease in impairment charges (as discussed in Note 4 to the consolidated financial statements), a $15.2 million decrease in separation and other transaction costs primarily given acquisition-related costs associated with the Bolt-on Acquisition and a $9.4 million decrease in operating and maintenance expense primarily associated with a decrease in repairs and maintenance expense, partially offset by an increase in non-income tax reserves. The decrease in such operating expenses was partly offset by a $28.7 million increase in depreciation expense as a result of additional assets placed in-service, including a full year of depreciation on assets acquired in the Bolt-on Acquisition, and a $9.9 million increase in amortization of intangible assets as a result of intangible assets acquired in the Bolt-on Acquisition and a corresponding adjustment to the useful lives of these intangibles (as discussed in Note 3 to the consolidated financial statements). Selling, general and administrative expense increased by $12.2 million primarily due to higher personnel costs.

See "Outlook" and Note 4 to the consolidated financial statements for further discussion of the impairment of long-lived assets. See also “Outlook” for discussions of certain customer production curtailments during the second and third quarters of 2020 and Note 6 to the consolidated financial statements for discussions of the EQT Global GGA and the transactions related thereto, including the potential cash fee relief to EQT in connection with a further delay in the targeted MVP in-service date. The Company expects that the revenues resulting from the MVCs under the EQT Global GGA will increase the proportion of the Company's total operating revenues that are firm reservation fee revenues, and correspondingly decrease the portion of the Company's total operating revenues that are volumetric-based fee revenues, in future periods. Firm reservation fee revenues under the Company’s Hammerhead gathering agreement with EQT (which is subject to a pending dispute with EQT) are also expected to contribute to an increase in the Company’s firm reservation fee revenues. See also “Outlook” for discussions of the Hammerhead dispute with EQT and the Gulfport bankruptcy.

TRANSMISSION RESULTS OF OPERATIONS


	Years Ended December 31,
	2020		2019		% Change	2018		% Change
FINANCIAL DATA	(Thousands, except per day amounts)
Firm reservation fee revenues	$	364,533	$	356,569	2.2	$	356,725	—
Volumetric-based fee revenues	29,303		33,951		(13.7)	30,076		12.9
Total operating revenues	393,836		390,520		0.8	386,801		1.0
Operating expenses:
Operating and maintenance	37,635		33,989		10.7	39,563		(14.1)
Selling, general and administrative	26,292		26,865		(2.1)	31,936		(15.9)
Depreciation	54,540		51,935		5.0	49,723		4.4
Total operating expenses	118,467		112,789		5.0	121,222		(7.0)
Operating income	$	275,369	$	277,731	(0.9)	$	265,579	4.6

Equity income	$	233,833	$	163,279	43.2	$	61,778	164.3

OPERATIONAL DATA
Transmission pipeline throughput (BBtu per day)
Firm capacity reservation	2,932		2,823		3.9	2,903		(2.8)
Volumetric-based services	16		90		(82.2)	59		52.5
Total transmission pipeline throughput	2,948		2,913		1.2	2,962		(1.7)

Average contracted firm transmission reservation commitments (BBtu per day)	4,087		3,966		3.1	3,909		1.5

Capital expenditures(a)	$	45,219	$	59,313	(23.8)	$	114,450	(48.2)

All of Eureka Midstream's income is, for the period prior to the closing of the EQM Merger, all of EQM's income was, and for the period prior to the EQGP Buyout, all of EQGP's income was included in the Company's pre-tax income; however, the Company does not record income tax expense on the portions of its income attributable to the noncontrolling member of Eureka Midstream and did not record income tax expense on the portions of its income attributable to the noncontrolling limited partners of EQM and EQGP for the periods prior to the closings of the EQM Merger and the EQGP Buyout, respectively. This reduces the Company's effective tax rate in periods when the Company has consolidated pre-tax income. The Company expects its effective tax rate for periods following the EQM Merger to generally be higher than the pre-EQM Merger periods due to the decrease in net income attributable to noncontrolling interests as a result of the Company's acquisition of the outstanding EQM common units not held by the Company and its subsidiaries and related Restructuring in connection with the closing of the EQM Merger.

The Company's strategically-located assets overlay core acreage in the Appalachian Basin. The location of the Company's assets allows its producer customers to access major demand markets in the U.S. The Company is one of the largest natural gas gatherers in the U.S., and its largest customer, EQT, was the largest natural gas producer in the U.S. based on average daily sales volumes as of December 31, 2020. The Company maintains a stable cash flow profile, with approximately 66% of its revenue for the year ended December 31, 2020 generated by firm reservation fees. Further, the percentage of the Company's revenues that are generated by firm reservation fees is expected to increase in future years as a result of the 15-year term EQT Global GGA, which includes an MVC that became effective on April 1, 2020 of 3.0 Bcf per day and gradually steps up to 4.0 Bcf per day for several years following the full in-service date of the MVP project. This contract structure enhances the stability of the Company's cash flows and limits its direct exposure to commodity price risk.

Under the EQT Global GGA, the performance obligation is to provide daily MVC capacity and as such the total consideration is allocated proportionally to the daily MVC over the life of the contract. In periods that the gathering MVC revenue billed will exceed the allocated consideration, the excess will be deferred to the contract liability and recognized in revenue when the performance obligation has been satisfied. Assuming a full in-service date in late 2021 for the MVP, the deferral to the contract liability is expected to increase by approximately $295 million and $6 million during 2021 and 2022, respectively. While the 3.0 Bcf per day MVC capacity became effective on April 1, 2020, additional daily MVC capacity and the associated gathering MVC fees payable by EQT to the Company as set forth in the EQT Global GGA are conditioned upon the in-service date of the MVP. There are ongoing legal and regulatory matters that must be resolved favorably before the MVP project can be completed which could have a material effect on the performance obligation and the allocation of the total consideration over the life of the contract and the gathering MVC fees payable by EQT under the contract.

Hammerhead Pipeline. On September 23, 2020, EQT and certain affiliates of EQT instituted arbitration proceedings against the Company by filing a Demand for Arbitration with the American Arbitration Association. The arbitration arises out of the Hammerhead gathering agreement, pursuant to which the Company agreed to construct the Hammerhead pipeline and gather gas for EQT. EQT sought a declaratory judgment that it may exercise an early termination right and purchase the Hammerhead pipeline and related facilities under the terms of the Hammerhead gathering agreement. With its Demand for Arbitration, EQT also sought emergency relief, asking that an emergency arbitrator: (i) resolve the parties’ dispute on the merits by October 1, 2020; or (ii) alternatively, toll the contractual deadline for EQT’s exercise of its termination right, which was set to expire on October 11, 2020, until after the parties’ dispute was resolved. On October 6, 2020, the emergency arbitrator issued an order denying EQT’s request for emergency resolution on the merits but tolling the early termination deadline until the arbitration has been resolved. The Company’s answer to the Notice of Arbitration was filed on October 8, 2020, and the parties are currently engaged in arbitration. The Company will vigorously defend against EQT’s claims and litigate its rights, including the assertion of appropriate counterclaims.

Henry Hub spot and local spot natural gas prices, which were under pressure prior to the COVID-19 outbreak due primarily to a warmer than normal 2019 - 2020 winter heating season, a temperate spring 2020 season and an oversupply of natural gas (caused in part by the significant increase in production of associated gas from the Permian Basin and similar basins in recent years), were further pressured by a reduction in global demand for natural gas during 2020 (for which the COVID-19 outbreak was a contributing factor), lack of available natural gas storage and the continued significant supplies of natural gas being produced, particularly from the Appalachian Basin. The Henry Hub natural gas price ranged from $1.33 per MMbtu to $3.03 per MMbtu between January 1, 2020 and December 31, 2020, with some prices reflecting the lowest natural gas prices in more than 20 years. Further, market prices for natural gas in the Appalachian Basin continue to be lower than Henry Hub natural gas prices and were significantly lower during portions of 2020. Natural gas prices have improved since the spring of 2020 and are expected to further improve during 2021, as reflected by the natural gas forward price strip as of February 19, 2021, primarily due to demand, such as in the winter months, for natural gas potentially exceeding available supply (as a result of, in part, the decrease in associated gas production from the Permian Basin given the dramatic decrease in oil production caused by historical low oil prices during the first half of 2020). However, the length and extent of that price recovery (if any) and its effect on the development plans of the Company’s customers, which impact both the Company’s ability to execute new commercial agreements with its customers as well as the volumetric-based fee revenues the Company earns under existing contracts, will be impacted by global demand for natural gas, the length and severity of the 2020-2021 winter heating season, rates of natural gas production (including amounts of associated gas from the Permian Basin, which certain analysts are projecting will increase in 2021 and later years), and the length and severity of the COVID-19 outbreak. There is no assurance that the elevated natural gas prices indicated by the current forward natural gas price strip will be realized or be realized for any particular length of time, or that producers will increase production volume as a result of any particular price level.

Lower natural gas prices have caused certain producers, including customers of the Company, to determine to reduce their rig count (and thereby delay production), temporarily shut in portions of their production or otherwise take actions to slow production growth and/or reduce production, which when effected by the Company's producer customers reduces the demand for, and usage of, the Company’s services. For instance, in May 2020 and September 2020, EQT publicly disclosed that it had made the strategic decision to temporarily curtail significant portions of its production, and certain other Company customers also curtailed portions of their production during the second and/or third quarters of 2020. The temporary production curtailments in 2020 resulted in a decrease in the Company's volumetric-based fee revenues for portions of 2020, and an extended period of low natural gas prices and/or a slow recovery of natural gas prices in 2021 could cause EQT or other

Certain of the Company’s customers reduced their capital spending forecasts in 2020 as compared to 2019 capital expenditures and 2021. For example, EQT's 2020 capital expenditures were approximately $694 million, or 39%, lower than EQT's 2019 capital expenditures. Although EQT announced a modest increase in its 2021 capital expenditure forecast compared to EQT's 2020 actual capital expenditures, EQT's 2021 sales volume forecast is approximately flat relative to its pro-forma 2020 sales volume (adjusted for the Chevron Acquisition). Price declines and sustained periods of low natural gas and NGL prices could continue to have an adverse effect on the creditworthiness of the Company's customers and related ability to pay firm reservation fees under long-term contracts and/or affect activity levels and, accordingly, volumetric-based fees, which could affect the Company’s results of operations, liquidity or financial position. Each of S&P, Moody's and Fitch took negative ratings actions on a number of Appalachian exploration and production companies during 2020, including EQT, Range Resources and Gulfport, citing, among other things, lower natural gas price assumptions and current and future financing needs (although all three ratings agencies have since taken positive action on EQT citing, among other things, subsequent debt reduction and improvements in natural gas fundamentals). On November 13, 2020, Gulfport filed for Chapter 11 bankruptcy protection, as further described above under "Gulfport Bankruptcy." Many of the Company’s customers, including EQT, have entered into long-term firm reservation transmission and gathering contracts or contracts with MVCs on the Company's systems. However, approximately 34% of the Company’s operating revenues for 2020 were volumetric-based fee revenues. For more information, see "Decreases in production of natural gas in our areas of operation have adversely affected, and future decreases could further adversely affect, our business and operating results and reduce our cash available to pay cash dividends to our shareholders." included in "Item 1A. Risk Factors."

The accounting estimates related to impairments are susceptible to change, including estimating fair value which requires considerable judgment. For goodwill, management’s estimate of a reporting unit’s future financial results is sensitive to changes in assumptions, such as changes in stock prices, weighted-average cost of capital, terminal growth rates and industry multiples. Similarly, cash flow estimates utilized for purposes of evaluating long-lived assets and equity method investments (such as in the MVP Joint Venture) require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, commencement of operations, resolution of relevant legal and regulatory matters, and other factors. The Company evaluates long-lived assets and equity method investments for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable (meaning, in the case of equity method investments, that such investments have suffered other-than-temporary declines in value under ASC 323). For the Company’s equity investment in the MVP Joint Venture, management must evaluate the Company’s investment for other-than-temporary declines in fair value under ASC 323. The Company believes the estimates and assumptions used in estimating its reporting units’, long-lived assets' and its equity investment's fair values as of December 31, 2020 are reasonable and appropriate; however, assumptions and estimates are inherently subject to significant business, economic, competitive, regulatory, judicial and other risks that could materially affect the calculated fair values and the resulting conclusions regarding impairments, which could materially affect the Company’s results of operations and financial position. Additionally, actual results could differ from these estimates and assumptions may not be realized. The Company also continues to evaluate and monitor the ongoing legal and regulatory matters related to the MVP and MVP Southgate projects that affect project completion, as further described in “Item 3. Legal Proceedings.” Adverse or delayed developments with respect to such matters or other adverse developments could require that the Company modify assumptions reflected in the probability-weighted scenarios of discounted future net cash flows (including with respect to the probability of success) utilized to estimate fair value of its equity investment in the MVP Joint Venture, which could result in an other-than-temporary impairment of that investment. See also Note 4 to the consolidated financial statements, “Reviews of our goodwill, intangible and other long-lived assets have resulted in significant impairment charges and reviews of our goodwill, intangible and other long-lived assets could result in future significant impairment charges, including with respect to our investment in the MVP Joint Venture.” included in “Item 1A. Risk Factors," and the Company's discussion of "Critical Accounting Policies and Estimates" included in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation."

The Company's liquidity requirements are to finance its operations, its capital expenditures, potential acquisitions and other strategic transactions and capital contributions to joint ventures, including the MVP Joint Venture, to pay cash dividends and to satisfy any indebtedness obligations. The Company's ability to meet these liquidity requirements depends on the Company's cash flow from operations, the continued ability of the Company to borrow under its credit facilities and the Company's ability to raise capital in banking, capital and other markets (including refinancing existing credit facilities as they mature). Cash flow and capital raising activities (including the ability in refinancings to obtain similar terms to those currently present in existing credit facilities) may be affected by prevailing economic conditions in the natural gas industry and other financial and business factors (including market forces causing shifts in investor sentiment and credit allocations to industries and companies perceived as having better growth opportunities and/or stronger ESG metrics and practices, as well as the COVID-19 outbreak), some of which are beyond the Company's control. The Company's available sources of liquidity include cash from operations, cash on hand, borrowings under its subsidiaries' revolving credit facilities, issuances of additional debt and issuances of additional equity securities. As of December 31, 2020, pursuant to the terms of the Amended EQM Credit Facility and Amended 2019 EQM Term Loan Agreement, the Company would have been able to borrow approximately $2.0 billion under the Amended EQM Credit Facility. The amount the Company is able to borrow under the Amended EQM Credit Facility is bounded by a maximum consolidated leverage ratio specified in the Amended EQM Credit Facility, which ratio varies over the course of the term of the Amended EQM Credit Facility from not more than 5.75 to 1.00 to not more than 5.00 to 1.00 tested as of the end of each fiscal quarter. The Company’s consolidated leverage ratio is derived from a number of components, including the amount of projected Consolidated EBITDA (as defined in the Amended EQM Credit Facility) from certain approved projects, including the MVP project, that is available to be included in the consolidated leverage ratio calculation under the Amended EQM Credit Facility. If the targeted in-service date for the MVP project is further delayed, such delay could result in a decrease in the amount of projected Consolidated EBITDA for future quarters, which, absent other actions which may be available to the Company to reduce its then-leverage, may further limit the Company’s availability to borrow under the Amended EQM Credit Facility. See also Note 11 to the consolidated financial statements.

See “Security Ratings” below for a discussion of the downgrades of EQM’s credit ratings during 2020. The non-investment grade ratings from Moody's, S&P and Fitch have caused the Company to incur higher borrowing costs under the Amended EQM Credit Facility and, prior to its termination, the Amended 2019 EQM Term Loan Agreement. As a result of the February 2020 downgrades (discussed below), EQM was also obligated to deliver additional credit support to the MVP Joint Venture in the form of letters of credit, which, in the case of the MVP project (based on the midpoint of the targeted cost for the project), is in the amount of approximately $231.2 million and is, in the case of the MVP Southgate, $14.2 million, in each case as of the filing date of this Annual Report on Form 10-K. Additionally, pursuant to the EQT Global GGA, if EQM does not maintain minimum credit ratings from two of three credit rating agencies of at least Ba3 with respect to Moody's and BB- with respect to S&P and Fitch, EQM will be obligated to provide additional credit support in an amount equal to approximately $196 million to EQT in support of the potential payment obligation related to the EQT Cash Option (the Cash Option Letter of Credit). See "A further downgrade of EQM’s credit ratings, including in connection with the MVP project or customer credit ratings changes, including EQT’s, which are determined by independent third parties, could impact our liquidity, access to capital, and costs of doing business." included in "Item 1A. Risk Factors."

Net cash flows used in financing activities were $291.4 million for the year ended December 31, 2020 compared to net cash flows provided by financing activities of $1,392.2 million for the year ended December 31, 2019. For the year ended December 31, 2020, the primary source of financing cash flows was net proceeds from the 2020 Senior Notes issuance, while the primary uses of financing cash flows were the redemption of the EQM Series A Preferred Units, payment to retire the ETRN Term Loans, the payments of dividends and distributions to shareholders and unitholders and net payments of borrowings on the Amended EQM Credit Facility. The net proceeds from the 2020 Senior Notes were primarily used to repay borrowings on the Amended EQM Credit Facility. For the year ended December 31, 2019, the primary sources of financing cash flows were borrowings on the Company's and EQM's credit facilities, proceeds from the issuance of the term loans under the 2019 EQM Term Loan Agreement (defined in Note 11 to the consolidated financial statements), which were used primarily to pay down borrowings under the EQM Credit Facility, and the net proceeds from the issuance of the EQM Series A Preferred Units, which were used in part to fund the purchase price of the Bolt-on Acquisition and to pay certain fees and expenses related to the Bolt-on Acquisition, while the primary uses of financing cash flows were payments on the Company's and EQM's credit facility borrowings, the payment of dividends, the payments of distributions to noncontrolling interest unitholders, the Company's purchase of EQGP common units and the payment of distributions to holders of EQM Series A Preferred Units.

project and the increase to EQM's financial leverage resulting from actions in connection with the EQM Merger and the Share Purchases. On April 2, 2020, Moody's further downgraded EQM's credit rating from Ba2, with a negative outlook, to Ba3, with a negative outlook, following Moody's downgrade of EQT's credit rating. On April 7, 2020, S&P further downgraded EQM's credit rating from BB, with a stable outlook, to BB-, with a negative outlook, following S&P's further downgrade of EQT's credit rating. On September 2, 2020, S&P, following its upgrade of EQT's outlook from negative to stable (based on EQT's reduced debt and improved leverage and maturity profile), lifted EQM's outlook from negative to stable, citing primarily the change in EQT's outlook. In January 2021, each of Moody's, S&P and Fitch affirmed EQM's credit ratings in connection with the issuance of the 2021 Senior Notes. The ETRN Term Loans were paid off on March 3, 2020 with proceeds from the EQM Credit Facility and the ETRN Term Loan Credit Agreement was terminated; therefore, the Company no longer has any credit ratings assigned to its debt.

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. The Company cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in its judgment, circumstances so warrant, including in connection with the MVP project or the creditworthiness of EQM's customers, including EQT. As of December 31, 2020, EQT's public debt had credit ratings of BB from S&P (with a stable outlook), Ba3 from Moody's (with a positive outlook) (which was subsequently upgraded to BA2 with a stable outlook on February 2, 2021) and BB from Fitch (with a positive outlook). As of December 31, 2019, EQT's credit ratings with each of S&P, Moody's and Fitch were considered investment grade. If any credit rating agency further downgrades or withdraws EQM's ratings, including for reasons relating to the MVP project (such as future delays in the targeted full in-service date of the MVP project or increases in such project’s costs), EQM’s leverage or credit ratings of our customers (including EQT), the Company's access to the capital markets could become more challenging, borrowing costs will likely increase, the Company may be required to provide additional credit assurances (the amount of which may be substantial), including the Cash Option Letter of Credit, in support of commercial agreements such as joint venture agreements, and the potential pool of investors and funding sources may decrease. In order to be considered investment grade, a company must be rated Baa3 or higher by Moody's, BBB- or higher by S&P, or BBB- or higher by Fitch. Anything below these ratings, including all of EQM's credit ratings, are considered non-investment grade.

The Company has federal and state net operating loss (NOL) carryforwards related to federal and various state jurisdictions. The federal and states of Virginia and West Virginia NOL carryforwards have no expiration, but utilization is limited to 80% of taxable income in the year of utilization. The Company's Pennsylvania NOL carryforwards expire in 2038 and 2040. The Company believes that it is more likely than not that the benefit from certain federal and state NOL carryforwards will be realized. In addition to the NOL carryforwards, the Company has recorded deferred tax liabilities principally resulting from its investment in partnerships. No valuation allowances have been established on the Company's deferred tax assets because the Company believes that future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize these deferred tax assets. Any determination to change the valuation allowance would impact the Company's income tax expense in the period in which such a determination is made.

Impairments of Long-Lived Assets and Equity Method Investments. The Company evaluates long-lived assets and equity method investments for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. With respect to property, plant and equipment and finite lived intangibles, asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. Any accounting estimate related to impairment of property, plant and equipment, finite-lived intangible assets, goodwill or an investment in an unconsolidated entity may require the Company's management to make assumptions about future cash flows, discount rates, the fair value of investments and whether losses in the value of its investments are other than temporary. Management's assumptions about future cash flows require significant judgment because, among other things, actual operating levels have fluctuated in the past and are expected to fluctuate in the future.

Revenue Recognition. Revenue from the gathering, transmission and storage of natural gas is generally recognized when the service is provided. Revenue from water services is generally recognized when water is delivered. Contracts often contain fixed and variable consideration. Fixed consideration primarily relates to firm reservation payments including MVCs. Variable consideration is generally dependent on volumes and recognized in the period they occur. For all contracts, the Company allocates the transaction price to each performance obligation based on the judgment determined relative standalone selling price. When applicable, the excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units of production or straight-line methodology as these methods appropriately match the consumption of services provided to the customer. The units of production methodology requires the use of production estimates that are uncertain and the use of judgment when developing estimates of future production volumes, thus impacting the rate of revenue recognition. Production estimates are monitored as circumstances and events warrant. Certain of the Company's gas gathering and water agreements have MVCs. If a customer under such an agreement fails to meet its MVC for a specified period (thus not exercising all the contractual rights to gathering and water services within the specified period, herein referred to as “breakage”), it is obligated to pay a contractually determined fee based upon the shortfall between the actual gathered or water volumes and the MVC for the period contained in the contract. When management determines it is probable that the customer will not exercise all or a portion of its remaining rights, the Company recognizes revenue associated with such breakage amount in proportion to the pattern of exercised rights within the respective MVC period.

The Company records an allowance for credit losses on a quarterly basis in order to estimate uncollectible receivables. The Company's current expected credit loss (CECL) methodology considers risks of collection based on a customer’s current credit status. The standard requires an entity to assess whether financial assets share similar risk characteristics and, if so, group such assets in a pool. Customer balances are aggregated for evaluation based on their credit risk rating, which takes into account changes in economic factors that impact a customer’s ability to meet its financial obligations. The Company's CECL methodology assigns a reserve, even if remote, to each customer based on credit risk and the reserve is evaluated on a quarterly basis. In order to calculate the appropriate provision, the Company utilizes an estimated loss rate factor based on a customer's credit rating for receivables and a risk-adjusted reserve based on the receivable aging schedule in order to account for the receivables which may be at a greater risk of collection. Customer credit risk ratings are updated quarterly and management has enabled a risk-responsive approach to changes in customer and economic factors. While the Company has not historically experienced material losses on uncollected receivables, declines in the market price for natural gas affecting producer activity combined with the increase in customers on the Company's systems may result in a greater exposure to potential losses than management's current estimates.

purchase price accounting estimates. Accounting for the acquisition of a business requires a company to record the acquired identifiable assets and liabilities at fair value. The estimated fair value of midstream facilities and equipment, which generally consist of pipeline systems and compression stations, was estimated using the cost approach. Significant unobservable inputs in the estimate of fair value include management's assumptions about the replacement costs for similar assets, the relative age of the acquired assets and any potential economic or functional obsolescence associated with the acquired assets. The fair value of intangible assets was determined using the income approach, which requires a forecast of the expected future cash flows generated and an estimated market-based weighted average cost of capital. Significant unobservable inputs in the determination of fair value include future revenue estimates, future cost assumptions and estimated customer retention rates.

Performance-based awards expected to be satisfied in cash are treated as liability awards and remeasured at fair value at the end of each reporting period, recognizing a proportionate amount of the expense for each period over the vesting period of the award. Performance-based awards expected to be satisfied in Company common stock are treated as equity awards and recorded based on an estimated grant date fair value over the vesting period of the award. Determination of the fair value of the awards requires judgments and estimates regarding, among other things, the appropriate methodologies to follow in valuing the awards and the related inputs required by those valuation methodologies. Most often, the Company obtains a valuation at the grant date for equity awards and at each remeasurement date for liability awards based upon assumptions regarding risk-free rates of return, expected volatilities, the expected term of the award and dividend yield, as applicable. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of valuation. Expected volatilities are based on historical volatility of the Company's common stock and, where applicable, the common stock of the peer group members at the time of valuation. The expected term represents the period of time elapsing during the applicable performance period. The dividend yield is based on the historical dividend yield of the Company's common stock adjusted for any expected changes and, where applicable, of the common stock of the peer group members at the time of valuation.

Interest Rate Risk. Changes in interest rates affect the amount of interest the Company earns on cash, cash equivalents and short-term investments and the interest rates EQM and Eureka pay on borrowings under their respective revolving credit facilities and term loans, as applicable. As of December 31, 2020, the Amended 2019 EQM Term Loan Agreement provided for, and the Amended EQM Credit Facility and the Eureka Credit Facility provide for, variable interest rates and thus expose the Company, through EQM and Eureka, to fluctuations in market interest rates. In addition, EQM's interest rates under the Amended 2019 EQM Term Loan Agreement were impacted by and the Amended EQM Credit Facility are impacted by changes in EQM's credit ratings (which may be caused by factors outside of EQM's control). Eureka's interest rates under the Eureka Credit Facility are also impacted by changes in Eureka's Consolidated Leverage Ratio (as defined in the Eureka Credit Facility) which may fluctuate based on Eureka Midstream's liquidity needs. Such changes in interest rates may accordingly impact the Company's results of operations and liquidity. Further, changes in interest rates may affect the dividend payable on Equitrans Midstream Preferred Shares after March 31, 2024, which could affect the amount of cash the Company has available to make quarterly cash dividends to its shareholders. Additionally, on March 30, 2020, EQM executed amendments to the EQM Credit Facility and the 2019 EQM Term Loan Agreement, which, among other things, increased the interest rates applicable to the borrowings under such facilities. EQM's senior notes are fixed rate and thus do not expose the Company to fluctuations in market interest rates. Changes in interest rates do affect the fair value of EQM's fixed rate debt. See Note 11 to the consolidated financial statements for discussion of borrowings and Note 1 to the consolidated financial statements for discussion of fair value measurements. See Note 18 to the consolidated financial statements for discussion of the prepayment and termination of the Amended 2019 EQM Term Loan Agreement. EQM and Eureka may from time to time hedge the interest on portions of borrowings under their respective revolving credit facilities in order to manage risks associated with floating interest rates (however, there may be no assurance that such hedges will fully mitigate interest rate risk).

Credit Risk. The Company is exposed to credit risk, which is the risk that it may incur a loss if a counterparty fails to perform under a contract. The Company actively manages its exposure to credit risk associated with customers through credit analysis, credit approval and monitoring procedures. For certain transactions, the Company requests letters of credit, cash collateral, prepayments or guarantees as forms of credit support. Equitrans, L.P.'s FERC tariffs require tariff customers that do not meet specified credit standards to provide three months of credit support; however, the Company is exposed to credit risk beyond this three-month period when its tariffs do not require its customers to provide additional credit support. For some of the Company's more recent long-term contracts associated with system expansions, it has entered into negotiated credit agreements that provide for other credit support if certain credit standards are not met. The Company has historically experienced only minimal credit losses in connection with its receivables.

gas production during portions of 2020. A sustained period of low prices could adversely affect development of additional reserves and production that is accessible by the Company's pipeline and storage assets, or result in lower drilling activity or additional curtailments, which would decrease demand for the Company's services. Lower regional natural gas prices could also cause producers to determine in the future that drilling activities in areas outside of the Company's current areas of operation are strategically more attractive to them. Certain of the Company's customers, including EQT, reduced capital spending for 2020 compared to 2019, and may announce lower capital spending in the future based on commodity prices, access to capital, investor expectations regarding free cash flow, a desire to reduce or refinance leverage (including the perceived ability to do so) or other factors. Unless the Company is successful in attracting and retaining new customers, the Company's ability to maintain or increase the capacity subscribed and volumes transported under service arrangements on its transmission and storage system, the volumes gathered on its gathering systems, or the volumes of water provided by its water services business will be dependent on receiving consistent or increasing commitments and production from its existing customers. While EQT has dedicated a substantial portion of its core acreage to the Company and has entered into long-term firm gathering and transmission contracts and contracts with MVCs on certain of the Company's systems, EQT may determine in the future that drilling or continuing to produce gas from existing wells in the Company's areas of operations is not economical above the amount to fulfill its required MVCs. For example, in May 2020 and September 2020, EQT publicly disclosed that it had made the strategic decision to temporarily curtail significant portions of its production, and certain other Company customers also curtailed portions of their production during the second and/or third quarters of 2020. See "Commodity Prices" under "Outlook" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional discussion. Other than with respect to its MVCs and other firm commitments under existing contracts, EQT is under no contractual obligation to continue to develop its acreage dedicated to the Company. See also Note 6 to the consolidated financial statements for a discussion of the EQT Global GGA and the Water Services Letter Agreement.

The Company's cash flow profile is underpinned by both firm reservation fee revenues and volumetric-based fees, with approximately 66% of its revenue for the year ended December 31, 2020 generated by firm reservation fee revenues. Accordingly, the Company believes that the effect of short- and medium-term declines in volumes of gas gathered, transported or stored on its systems may be mitigated because firm reservation fee revenues are paid regardless of volumes supplied to the system by customers. Sustained periods of low commodity prices could however have a further adverse effect on customer creditworthiness and related ability to pay firm reservation fees under long-term contracts and/or affect activity levels and accordingly volumetric-based fees, all of which could affect the Company's results of operations, liquidity or financial position. Significant declines in gas production in the Company's areas of operations would adversely affect the Company's results of operations, financial condition and liquidity. Additionally, the Company’s exposure to commodity price risk may increase in future periods. See "Our exposure to direct commodity price risk may increase in the future." under "Item 1A. Risk Factors."


			Accounting for the EQT global gas gathering agreement and share purchase agreements

Description of the Matter			As more fully described in Note 6 to the consolidated financial statements, on February 26, 2020, the Company entered into a Gas Gathering and Compression Agreement (the EQT Global GGA) with EQT Corporation. Additionally, on February 26, 2020, the Company entered into two share purchase agreements (the Share Purchase Agreements) with EQT Corporation (EQT), pursuant to which the Company agreed to (i) purchase shares of Equitrans Midstream common stock from EQT in exchange for cash and (ii) purchase shares of Equitrans Midstream common stock from EQT as consideration for certain commercial terms under the EQT Global GGA (the Rate Relief Shares). The EQT Global GGA also provides for potential cash bonus payments payable by EQT conditioned upon the quarterly average of the NYMEX Henry Hub Natural Gas price exceeding certain price thresholds. The Company’s initial accounting for the execution of the EQT Global GGA and Share Purchase Agreements included recognition of a contract liability consisting of deferred revenue associated with the EQT Global GGA in the form of advance payments from EQT associated with the Rate Relief Shares and the initial fair value of the Henry Hub cash bonus payment provision. Auditing the Company's accounting for the initiation of the EQT Global GGA and the Share Purchase Agreements was complex due to the judgment that was required in determining the balance sheet classification of the elements of the EQT Global GGA and Share Purchase Agreements. Additionally, a detailed analysis of the terms of the relevant agreements was required to determine the existence of any derivatives that may require separate accounting under applicable accounting guidance.

How We Addressed the Matter in Our Audit			We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s initial accounting for the EQT Global GGA and Share Purchase Agreements. For example, we tested controls over the initial recognition of the EQT Global GGA and Share Purchase Agreements, including management’s evaluation of the EQT Global GGA and the identification and evaluation of specific features and the related accounting. To test the initial accounting for the EQT Global GGA and Share Purchase Agreements, our audit procedures included, among others, inspection of the agreements underlying those transactions and testing management’s application of the relevant accounting guidance, including the determination of the balance sheet classification of each transaction component and the identification of any derivatives included in the arrangements. Our testing of the Company’s initial accounting included, among other procedures, evaluating the contractual provisions and testing the completeness and accuracy of the underlying data. We involved professionals with specialized skill and knowledge to assist in evaluating the appropriateness of the accounting for the EQT Global GGA and Share Purchase Agreements, including conclusions reached with respect to identification and bifurcation of embedded features. Our procedures also included evaluating the sufficiency of the Company’s disclosures with respect to the accounting for the EQT Global GGA and Share Purchase Agreements described in Note 6 to the consolidated financial statements.


			Valuation of EQM OpCo Reporting Unit Goodwill

Description of the Matter			At December 31, 2020, the Company had goodwill of approximately $486.7 million related to the EQM OpCo reporting unit. As discussed in Notes 1 and 4 to the consolidated financial statements, goodwill is evaluated for impairment at least annually and whenever events or changes in circumstance indicate that the fair value of a reporting unit is less than its carrying amount. If after assessing the totality of events or circumstances, the Company determines it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then a quantitative assessment is not required. However, if the Company concludes otherwise, a quantitative impairment analysis is performed. If the Company chooses not to perform a qualitative assessment, or if it chooses to perform a qualitative assessment but is unable to qualitatively conclude that no impairment has occurred, then the Company will perform a quantitative assessment. In the case of a quantitative impairment test, the Company estimates the fair value of the reporting unit with which the goodwill is associated and compares it to the carrying value. If the estimated fair value of a reporting unit is less than its carrying value, an impairment charge is recognized for the excess of the reporting unit's carrying value over its fair value. Auditing management’s quantitative goodwill impairment tests for the EQM OpCo reporting unit was complex due to the significant estimation required to determine the fair value of that reporting unit. In particular, the fair value estimates of that reporting unit were sensitive to significant assumptions, including assumptions regarding future throughput volumes and operating costs, and discount rates, among others. These assumptions could be affected by factors such as unexpected future production curtailments by the Company’s customers that have contracts with volumetric-based fees or future market or economic conditions and industry and company-specific qualitative factors.

How We Addressed the Matter in Our Audit			We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s goodwill impairment review process, including controls over management’s review of the significant assumptions described above. To test the estimated fair value of the Company’s EQM OpCo reporting unit for which quantitative impairment tests were performed, we performed audit procedures that included, among others, evaluating methodologies used and testing the significant assumptions discussed above and testing the underlying data used by the Company in its analyses for completeness and accuracy. We compared the significant assumptions used by management to current industry and economic trends and evaluated whether changes in those trends would affect the significant assumptions. We assessed the historical accuracy of management’s estimates and performed sensitivity analyses of significant assumptions to evaluate the changes in the fair value of the reporting unit that would result from changes in the assumptions. We involved our valuation specialists to assist in reviewing the valuation methodology and testing the discount rate assumption. Our procedures also included evaluating the sufficiency of the Company’s disclosures with respect to the valuation of EQM OpCo reporting unit goodwill described in Note 4 to the consolidated financial statements.


			Valuation of Equity Method Investment in Mountain Valley Pipeline, LLC (MVP Joint Venture)

Description of the Matter			At December 31, 2020, the Company has an investment in the MVP Joint Venture of approximately $2.8 billion. As discussed in Notes 1 and 9 to the consolidated financial statements, the Company accounts for its interests in the MVP Joint Venture under the equity method because it has the ability to exercise significant influence, but not control, over the MVP Joint Venture's operating and financial policies. The Company reviews the carrying value of its investments in unconsolidated entities for impairment whenever events or changes in circumstances indicate that the fair value may have declined in value. When there is evidence of loss in value that is other than temporary, the Company compares the investment's carrying value to its estimated fair value to determine whether impairment has occurred. If the carrying value exceeds the estimated fair value, the Company estimates and recognizes an impairment loss equal to the difference between the investment's carrying value and fair value. During the year ended December 31, 2020, the Company evaluated its investment in the MVP Joint Venture for impairment and determined the fair value of its investment continued to exceed the carrying value at December 31, 2020. Accordingly, no impairment losses with respect to its equity investment in the MVP Joint Venture were recorded for the year ended December 31, 2020. The Company used probability-weighted scenarios of discounted future cash flows to estimate the fair value of the investment. The use of probability-weighted, discounted cash flows requires management to make significant estimates regarding the likelihood of various scenarios utilized to determine the fair value estimate. Changes in the probability-weighted assumptions could have a significant impact on the fair value estimate, which is used to determine the amount of any impairment. Auditing management’s evaluation of impairment of the equity investment in the MVP Joint Venture was complex due to the significant judgment required to determine the fair value of the investment. In particular, the fair value estimates of the investment in the MVP Joint Venture were sensitive to significant assumptions, including assumptions regarding the probability-weighted, discounted cash flows. These assumptions could be affected by factors such as adverse macroeconomic conditions or other adverse factors such as permit and litigation matters impacting the MVP Joint Venture. The audit procedures to evaluate the reasonableness of management’s estimates and assumptions related to the likelihood of various probability-weighted scenarios required a high degree of auditor judgement and an increased extent of effort.

How We Addressed the Matter in Our Audit			We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s equity method investment impairment evaluation process, including controls over management’s review of the significant assumptions described above. To test the Company’s impairment evaluation related to its investment in the MVP Joint Venture, we performed audit procedures that included evaluating the methodologies used and testing significant assumptions and underlying data used by the Company in its analyses for completeness and accuracy. We involved our valuation specialists to assist in reviewing the valuation methodology and testing the discount rate assumption. Our audit procedures related to the probability-weighted forecasts of discounted future cash flows included, among others, procedures to evaluate the reasonableness of the probabilities assigned by management to various outcomes. We also performed procedures to assess management’s consideration of potential changes in legal or regulatory trends and how such developments could impact significant assumptions that influence the in-service dates or viability of the project. We performed procedures to evaluate the reasonableness of key assumptions based upon management’s plans to resolve outstanding permitting issues and performed reviews to identify any potential contrary evidence through reading information included in the Company’s press releases, regulatory filings, analyst and industry reports, internal communications to management and the Board of Directors, among others. Our procedures also included evaluating the sufficiency of the Company’s disclosures with respect to the valuation of the investment in the MVP Joint Venture described in Note 9 to the consolidated financial statements.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.


	2020		2019		2018
	(Thousands, except per share amounts)
Operating revenues (a)	$	1,510,825	$	1,630,242	$	1,495,098
Operating expenses:
Operating and maintenance (a)	154,109		165,367		163,451
Selling, general and administrative (a)	129,969		112,915		123,810
Separation and other transaction costs (a)	23,797		26,080		85,444
Depreciation	259,613		227,364		175,821
Amortization of intangible assets	63,195		53,258		41,547

Impairments of long-lived assets (b)	55,581		969,258		261,941
Total operating expenses	686,264		1,554,242		852,014
Operating income	824,561		76,000		643,084
Equity income (c)	233,833		163,279		61,778
Other income (d)	17,225		2,661		5,011
Loss on early extinguishment of debt (e)	24,864		—		—
Net interest expense (a)	307,380		256,195		115,454
Income (loss) before income taxes	743,375		(14,255)		594,419
Income tax expense	105,331		50,704		83,142
Net income (loss)	638,044		(64,959)		511,277
Net income attributable to noncontrolling interests	214,912		138,784		292,879
Net income (loss) attributable to Equitrans Midstream	423,132		(203,743)		218,398
Preferred dividends (f)	58,760		—		—
Net income (loss) attributable to Equitrans Midstream common shareholders	$	364,372	$	(203,743)	$	218,398

Earnings (loss) per share of common stock attributable to Equitrans Midstream common shareholders - basic (g)	$	1.06	$	(0.80)	$	0.86
Earnings (loss) per share of common stock attributable to Equitrans Midstream common shareholders - diluted (g)	$	1.06	$	(0.80)	$	0.86

Weighted average common shares outstanding - basic	343,935		254,884		254,432
Weighted average common shares outstanding - diluted	343,975		254,884		255,033

Net income (loss)	$	638,044	$	(64,959)	$	511,277
Other comprehensive loss, net of tax:
Pension and other post-retirement benefits liability adjustment, net of tax expense of $70, $70 and $638	(203)		(517)		(1,509)
Other comprehensive loss	(203)		(517)		(1,509)
Comprehensive income (loss)	637,841		(65,476)		509,768
Less: Comprehensive income attributable to noncontrolling interests	214,912		138,784		292,879
Less: Comprehensive income attributable to preferred dividends (f)	58,760		—		—
Comprehensive income (loss) attributable to Equitrans Midstream common shareholders	$	364,169	$	(204,260)	$	216,889

Dividends declared per common share	$	0.60	$	1.80	$	0.41

YEARS ENDED DECEMBER 31,


	2020		2019		2018
	(Thousands)
Cash flows from operating activities:
Net income (loss)	$	638,044	$	(64,959)	$	511,277
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	259,613		227,364		175,821
Amortization of intangible assets	63,195		53,258		41,547

Impairment of long-lived assets	55,581		969,258		261,941
Deferred income taxes	102,718		50,704		25,246
Equity income	(233,833)		(163,279)		(61,778)
Other income	(17,278)		(5,716)		(5,570)
Loss on early extinguishment of debt	24,864		—		—
Non-cash long-term compensation expense	12,301		2,786		4,190
Changes in other assets and liabilities:
Accounts receivable	(37,810)		17,523		(36,225)
Accounts payable	(7,922)		(90,301)		(90,502)


Deferred revenue	225,746		—		—

Other assets and other liabilities	55,667		(20,151)		(104,237)
Net cash provided by operating activities	1,140,886		976,487		721,710
Cash flows from investing activities:
Capital expenditures	(462,031)		(967,369)		(865,882)
Capital contributions to the MVP Joint Venture	(272,801)		(774,593)		(913,195)
Bolt-on Acquisition (defined in Note 3), net of cash acquired	—		(837,231)		—
Purchase of interests in the MVP Joint Venture	—		—		(11,302)
Principal payments received on the Preferred Interest (defined in Note 1)	5,003		4,661		4,406
Net cash used in investing activities	(729,829)		(2,574,532)		(1,785,973)
Cash flows from financing activities:

Proceeds from revolving credit facility borrowings	1,965,000		2,484,000		3,446,500
Payments on revolving credit facility borrowings	(2,080,000)		(2,495,500)		(3,271,000)
Proceeds from the issuance of long-term debt	1,600,000		1,400,000		3,100,000
Debt discounts, debt issuance costs and credit facility origination fees	(26,720)		(2,870)		(73,467)
Payments for retirement of long-term debt	(594,000)		(34,325)		—
Redemption of EQM Series A Preferred Units (defined in Note 1)	(617,338)		—		—
Proceeds from issuance of EQM Series A Preferred Units, net of offering costs	—		1,158,313		—
Distributions paid to noncontrolling interest unitholders	(128,770)		(382,360)		(380,651)
Distributions paid to holders of EQM Series A Preferred Units	(61,931)		(48,480)		—
Dividends paid to holders of Equitrans Midstream Preferred Shares	(16,879)		—		—
Dividends paid to common shareholders	(278,395)		(448,128)		—
Net distributions to EQT	—		—		(1,117,577)
Cash Shares and Cash Amount (defined in Note 6)	(52,323)		—		—
Net payments on EQGP's (defined in Note 1) working capital loan with EQT	—		—		(168)
Acquisition of 25% of Strike Force Midstream LLC	—		—		(175,000)
Purchases of EQGP common units	—		(238,455)		(291,206)
Net cash (used in) provided by financing activities	(291,356)		1,392,195		1,237,431

Net change in cash and cash equivalents	119,701		(205,850)		173,168
Cash and cash equivalents at beginning of year	88,322		294,172		121,004
Cash and cash equivalents at end of year	$	208,023	$	88,322	$	294,172


	2020		2019
	(Thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	208,023	$	88,322
Accounts receivable (net of allowance for credit losses of $4,699 and allowance for doubtful accounts of $285 as of December 31, 2020 and 2019, respectively) (a)(b)	290,446		255,344
Other current assets (a)(b)	63,268		31,546
Total current assets	561,737		375,212

Property, plant and equipment	8,835,652		8,583,124
Less: accumulated depreciation	(1,007,756)		(859,157)
Net property, plant and equipment	7,827,896		7,723,967

Investments in unconsolidated entity	2,796,316		2,324,108
Goodwill	486,698		486,698
Net intangible assets	716,590		797,439
Deferred income taxes	—		90,597
Other assets (a)	336,615		243,688
Total assets	$	12,725,852	$	12,041,709

LIABILITIES, MEZZANINE EQUITY AND SHAREHOLDERS' EQUITY
Current liabilities:
Current portion of revolving credit facility borrowings and long-term debt (c)	$	302,500	$	6,000
Accounts payable	72,098		128,114
Capital contributions payable to the MVP Joint Venture	10,723		45,150
Accrued interest	126,191		73,455
Accrued liabilities	83,366		83,238
Total current liabilities	594,878		335,957

Revolving credit facility borrowings (d)	485,000		902,500
Long-term debt	6,443,312		5,421,983
Contract liability (a)(e)	398,750		—
Deferred income taxes	345,896		—
Regulatory and other long-term liabilities	94,902		99,189
Total liabilities	8,362,738		6,759,629

Mezzanine equity:
Equitrans Midstream Preferred Shares, 30,018 and 0 shares issued and outstanding as of December 31, 2020 and 2019, respectively (f)	681,842		—

Shareholders' equity:

Common stock, no par value, 432,470 and 254,745 shares issued and outstanding as of December 31, 2020 and 2019, respectively	3,941,295		1,292,804
Retained deficit	(728,959)		(618,062)
Accumulated other comprehensive loss	(2,229)		(2,026)
Total common shareholders' equity	3,210,107		672,716
Noncontrolling interests	471,165		4,609,364
Total shareholders' equity	3,681,272		5,282,080
Total liabilities, mezzanine equity and shareholders' equity	$	12,725,852	$	12,041,709


														Mezzanine
			Common Stock											Equity
								Accumulated Other						Equitrans
						Retained								Midstream
	Parent Net		Shares	No		Earnings		Comprehensive		Noncontrolling		Total		Preferred
	Investment		Outstanding	Par Value		(Deficit)		Loss		Interests		Equity		Shares
	(Thousands, except per unit and share amounts)
Balance at January 1, 2018	$	1,143,769	—	$	—	$	—	$	—	$	5,094,995	$	6,238,764	$	—
Other comprehensive income (net of tax):
Net income	184,466		—	—		33,932		—		292,879		511,277		—
Pension and other post-retirement benefits liability adjustment, net of tax expense of $638	—		—	—		—		(1,509)		—		(1,509)		—
Purchase of Strike Force Midstream LLC noncontrolling interests	1,818		—	—		—		—		(176,818)		(175,000)		—
Net changes in ownership of consolidated entities	(159,255)		—	—		—		—		214,924		55,669		—
Share-based compensation plans	340		2	2,897		—		—		953		4,190		—
Issuance of Equitrans Midstream common stock	—		254,269	—		—		—		—		—		—
Net distributions to EQT	(701,901)		—	—		—		—		—		(701,901)		—
Separation-related adjustments	(469,237)		—	469,237		—		—		—		—		—
Distributions paid to noncontrolling interest unitholders ($4.295, $1.123 and $0.5966 per common unit for EQM, EQGP and RMP, respectively)	—		—	—		—		—		(380,651)		(380,651)		—
Purchase of EQGP common units	—		—	(46,764)		—		—		(244,442)		(291,206)		—
Balance at December 31, 2018	$	—	254,271	$	425,370	$	33,932	$	(1,509)	$	4,801,840	$	5,259,633	$	—
Other comprehensive income (net of tax):
Net (loss) income	—		—	—		(203,743)		—		138,784		(64,959)		—
Pension and other post-retirement benefits liability adjustment, net of tax expense of $70	—		—	—		316		(517)		—		(201)		—
Dividends on common shares ($1.76 per share)	—		—	—		(448,567)		—		—		(448,567)		—
Share-based compensation plans, net	—		474	2,531		—		—		255		2,786		—
Separation-related adjustments	—		—	(93,666)		—		—		—		(93,666)		—
Distributions paid to noncontrolling interest unitholders ($4.595 per common unit for EQM)	—		—	—		—		—		(382,360)		(382,360)		—
Issuance of EQM Series A Preferred Units, net of offering costs	—		—	—		—		—		1,158,313		1,158,313		—
Distributions paid to holders of EQM Series A Preferred Units ($1.9703 per EQM Series A Preferred Unit)	—		—	—		—		—		(48,480)		(48,480)		—
Bolt-on Acquisition (as defined in Note 3)	—		—	—		—		—		478,460		478,460		—

Purchase of EQGP common units	—		—	(38,648)		—		—		(199,807)		(238,455)		—
Net changes in ownership of consolidated entities	—		—	997,217		—		—		(1,337,641)		(340,424)		—
Balance at December 31, 2019	$	—	254,745	$	1,292,804	$	(618,062)	$	(2,026)	$	4,609,364	$	5,282,080	$	—
Other comprehensive income (net of tax):
Net income	—		—	—		391,625		—		214,912		606,537		31,507
Pension and other post-retirement benefits liability adjustment, net of tax expense of $70	—		—	—		—		(203)		—		(203)		—
Dividends on common shares ($0.90 per share)	—		(178)	—		(280,559)		—		—		(280,559)		—
Share-based compensation plans	—		66	12,786		—		—		285		13,071		—
Distributions paid to noncontrolling interest unitholders ($1.5475 per common unit for EQM)	—		—	—		—		—		(128,770)		(128,770)		—
Distributions paid to holders of EQM Series A Preferred Units ($2.0728 per EQM Series A Preferred Unit)	—		—	—		—		—		(51,002)		(51,002)		—
Dividends paid to holders of Equitrans Midstream Preferred Shares ($0.5623 per share)	—		—	—		—		—		—		—		(16,879)

Equitrans Midstream has a written Code of Business Conduct and Ethics that applies to Equitrans Midstream's Chief Executive Officer (Principal Executive Officer), Chief Financial Officer (Principal Financial Officer), Chief Accounting Officer (Principal Accounting Officer) and others. The Code of Business Conduct and Ethics is available on Equitrans Midstream's website at www.equitransmidstream.com (accessible by clicking on the "About" link on the main page followed by the "Governance" link), and a printed copy will be delivered free of charge on request by writing to the corporate secretary at Equitrans Midstream Corporation, c/o Corporate Secretary, 2200 Energy Drive, Canonsburg, Pennsylvania 15317. Any amendments to, or waivers from, a provision of the Company's Code of Business Conduct and Ethics that applies to the Company's Principal Executive Officer, Principal Financial Officer and Principal Accounting Officer and that relates to any element of the code of ethics enumerated in paragraph (b) of Item 406 of Regulation S-K shall be disclosed by posting such information on the Company's website at www.equitransmidstream.com.

In reviewing any agreements incorporated by reference in this Form 10-K or filed with this Form 10-K, please remember that such agreements are included to provide information regarding their terms. They are not intended to be a source of financial, business or operational information about the Company or any of its subsidiaries or affiliates. The representations, warranties and covenants contained in these agreements are made solely for purposes of the agreements and are made as of specific dates; are solely for the benefit of the parties; may be subject to qualifications and limitations agreed upon by the parties in connection with negotiating the terms of the agreements, including being made for the purpose of allocating contractual risk between the parties instead of establishing matters as facts; and may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors or security holders. Investors and security holders should not rely on the representations, warranties and covenants or any description thereof as characterizations of the actual state of facts or condition of the Company or any of its subsidiaries or affiliates or, in connection with acquisition agreements, of the assets to be acquired. Moreover, information concerning the subject matter of the representations, warranties and covenants may change after the date of the agreements. Accordingly, these representations and warranties alone may not describe the actual state of affairs as of the date they were made or at another time.

Exhibit No.

Document Description

Method of Filing

2.1

Separation and Distribution Agreement, dated as of November 12, 2018, by and among EQT Corporation, Equitrans Midstream Corporation and, solely for certain limited purposes therein, EQT Production Company.

Incorporated herein by reference to Exhibit 2.1 to Form 8-K (#001-38629) filed on November 13, 2018.

2.2

Tax Matters Agreement, dated as of November 12, 2018, by and between EQT Corporation and Equitrans Midstream Corporation.

Incorporated herein by reference to Exhibit 2.3 to Form 8-K (#001-38629) filed on November 13, 2018.

2.3

Employee Matters Agreement, dated as of November 12, 2018, by and between EQT Corporation and Equitrans Midstream Corporation.

Incorporated herein by reference to Exhibit 2.4 to Form 8-K (#001-38629) filed on November 13, 2018.

2.4**

Agreement and Plan of Merger, dated as of April 25, 2018, by and among EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP), EQM Midstream Services, LLC (formerly known as EQT Midstream Services, LLC), EQM Acquisition Sub, LLC, EQM GP Acquisition Sub, LLC, RM Partners LP (formerly known as Rice Midstream Partners LP), EQM Midstream Management LLC (formerly known as Rice Midstream Management LLC) and, solely for purposes of certain provisions therein, EQT Corporation.

Incorporated herein by reference to Exhibit 2.1 to EQGP Holdings, LP's Form 8-K (#001-37380) filed on April 26, 2018.

2.5

Incentive Distribution Rights Purchase and Sale Agreement, dated as of April 25, 2018, by and among EQGP Holdings, LP (formerly known as EQT GP Holdings, LP), Rice Midstream GP Holdings LP and EQT Corporation.

Incorporated herein by reference to Exhibit 2.3 to EQGP Holdings, LP's Form 8-K (#001-37380) filed on April 26, 2018.

2.6**

Contribution and Sale Agreement, dated as of April 25, 2018, by and among EQT Corporation, Rice Midstream Holdings LLC, EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP) and EQM Gathering Holdings, LLC.

Incorporated herein by reference to Exhibit 2.2 to EQGP Holdings, LP's Form 8-K (#001-37380) filed on April 26, 2018.

2.7**

Purchase and Sale Agreement, dated as of March 13, 2019, by and between EQM Midstream Partners, LP and North Haven Infrastructure Partners II Buffalo Holdings, LLC.

Incorporated herein by reference to Exhibit 2.1 to Form 8-K (#001-38629) filed on March 15, 2019.

2.8**

Agreement and Plan of Merger, dated as of February 26, 2020, by and among Equitrans Midstream Corporation, EQM LP Corporation, LS Merger Sub, LLC, EQM Midstream Partners, LP and EQGP Services, LLC.

Incorporated herein by reference to Exhibit 2.1 to Form 8-K (#001-38629) filed on February 28, 2020.

3.1

Amended and Restated Articles of Incorporation of Equitrans Midstream Corporation.

Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-38629) filed on November 13, 2018.

3.2

Second Amended and Restated Bylaws of Equitrans Midstream Corporation.

Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-38629) filed on October 10, 2019.

3.3

Statement with Respect to Shares of Series A Junior Participating Preferred Stock.

Incorporated herein by reference to Exhibit 3.3 to Form 8-K (#001-38629) filed on November 13, 2018.

3.4

Statement with Respect to Shares of Series A Preferred Stock, dated as of June 17, 2020.

Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-38629) filed on June 17, 2020.

4.1

Indenture, dated as of August 1, 2014, by and among EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP), as issuer, the subsidiaries of EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP) party thereto, and The Bank of New York Mellon Trust Company, N.A., as trustee.

Incorporated herein by reference to Exhibit 4.1 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on August 1, 2014.

4.2

First Supplemental Indenture, dated as of August 1, 2014, by and among EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP), as issuer, the subsidiaries of EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP) party thereto, and The Bank of New York Mellon Trust Company, N.A., as trustee.

Incorporated herein by reference to Exhibit 4.2 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on August 1, 2014.

4.3

Second Supplemental Indenture, dated as of November 4, 2016, by and between EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP), as issuer, and The Bank of New York Mellon Trust Company, N.A., as trustee.

Incorporated herein by reference to Exhibit 4.2 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on November 4, 2016.

4.4

Third Supplemental Indenture, dated as of June 25, 2018, by and between EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP), as issuer, and The Bank of New York Mellon Trust Company, N.A., as trustee.

Incorporated herein by reference to Exhibit 4.2 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on June 25, 2018.

4.5

Fourth Supplemental Indenture, dated as of June 25, 2018, by and between EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP), as issuer, and The Bank of New York Mellon Trust Company, N.A., as trustee.

Incorporated herein by reference to Exhibit 4.4 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on June 25, 2018.

4.6

Fifth Supplemental Indenture, dated as of June 25, 2018, by and between EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP), as issuer, and The Bank of New York Mellon Trust Company, N.A., as trustee.

Incorporated herein by reference to Exhibit 4.6 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on June 25, 2018.

4.7

Shareholder and Registration Rights Agreement, dated as of November 12, 2018, by and between EQT Corporation and Equitrans Midstream Corporation.

Incorporated herein by reference to Exhibit 4.1 to Form 8-K (#001-38629) filed on November 13, 2018.

4.8

Description of Certain of Registrants' Securities.

Incorporated hereby by reference to Exhibit 4.8 to Form 10-K (#001-38629) for the year ended December 31, 2019.

4.9

Registration Rights Agreement, dated as of June 17, 2020, by and among Equitrans Midstream Corporation and the Investors party thereto.

Incorporated herein by reference to Exhibit 4.1 to Form 8-K (#001-38629) filed on June 17, 2020.

4.10

Indenture, dated as of June 18, 2020, by and between EQM Midstream Partners, LP and The Bank of New York Mellon Trust Company, N.A., as trustee.

Incorporated herein by reference to Exhibit 4.1 to Form 8-K (#001-38629) filed on June 18, 2020.

4.11

Indenture, dated as of January 8, 2021, by and between EQM Midstream Partners, LP and The Bank of New York Mellon Trust Company, N.A., as trustee.

Incorporated herein by reference to Exhibit 4.1 to Form 8-K (#001-38629) filed on January 8, 2021.

10.1(a)

Third Amended and Restated Credit Agreement, dated as of October 31, 2018, by and among EQM Midstream Partners, LP, Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and an L/C Issuer, and the other lenders party thereto.

Incorporated herein by reference to Exhibit 10.1 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on October 31, 2018.

10.1(b)

First Amendment to Third Amended and Restated Credit Agreement, dated as of March 30, 2020, by and among EQM Midstream Partners, LP, the lender parties thereto and Wells Fargo Bank, National Association, as administrative agent.

Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-38629) filed on March 30, 2020.

10.2(a)

Term Loan Agreement, dated as of August 16, 2019, by and among EQM Midstream Partners, LP, as borrower, Toronto Dominion (Texas) LLC, as administrative agent, and the lenders party thereto.

Incorporated herein by reference to Exhibit 10.1 to EQM Midstream Partners, LP’s Form 8-K (#001-35574) filed on August 19, 2019.

10.2(b)

First Amendment to Term Loan Agreement, dated as of March 30, 2020, by and among EQM Midstream Partners, LP, the lender parties thereto and Toronto Dominion (Texas) LLC, as administrative agent.

Incorporated herein by reference to Exhibit 10.2 to Form 8-K (#001-38629) filed on March 30, 2020.

10.3

Sublease Agreement, effective as of March 1, 2011, by and between Equitrans, L.P. and EQT Production Company.

Incorporated herein by reference to Exhibit 10.12 to Amendment No. 2 to EQM Midstream Partners, LP's Form S-1/A Registration Statement (#333-179487) filed on May 10, 2012.

10.4

Amendment of Sublease Agreement, dated as of April 5, 2012, by and between Equitrans, L.P. and EQT Production Company.

Incorporated herein by reference to Exhibit 10.13 to Amendment No. 2 to EQM Midstream Partners, LP's Form S-1/A Registration Statement (#333-179487) filed on May 10, 2012.

10.5

Transportation Service Agreement Applicable to Firm Transportation Service Under Rate Schedule FTS, Contract No. CW2250463-1296, dated as of January 8, 2016, as amended through December 20, 2017, by and between Equitrans, L.P. and EQT Energy, LLC.

Incorporated herein by reference to Exhibit 10.13 to EQM Midstream Partners, LP's Form 10-K (#001-35574) for the year ended December 31, 2017.

10.6

Second Amended and Restated Gas Gathering and Compression Agreement, dated as of March 31, 2017, by and between Rice Drilling D LLC and EQM Olympus Midstream LLC (formerly known as Rice Olympus Midstream LLC). Specific items in this exhibit have been redacted, as marked by three asterisks [***], because confidential treatment for those items has been granted by the SEC. The redacted material has been separately filed with the SEC.

Incorporated herein by reference to Exhibit 10.3 to EQM Midstream Partners, LP's Form 10-Q (#001-35574) for the quarterly period ended June 30, 2018.

10.7

Amended and Restated Water Services Agreement, dated as of November 4, 2015, by and between Rice Drilling D LLC and Rice Water Services (PA) LLC.

Incorporated herein by reference to Exhibit 10.2 to Rice Midstream Partners LP's Form 8-K (#001-36789) filed on November 5, 2015.

10.8

Amended and Restated Water Services Agreement, dated as of November 4, 2015, by and between Rice Drilling B LLC and Rice Water Services (OH) LLC.

Incorporated herein by reference to Exhibit 10.3 to Rice Midstream Partners, LP's Form 8-K (#001-36789) filed on November 5, 2015.

10.9(a)

Third Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline, LLC, dated as of April 6, 2018, by and among MVP Holdco, LLC, US Marcellus Gas Infrastructure, LLC, WGL Midstream, Inc., Con Edison Gas Pipeline and Storage, LLC, RGC Midstream, LLC and Mountain Valley Pipeline, LLC. Specific items in this exhibit have been redacted, as marked by three asterisks [***], because confidential treatment for those items has been granted by the SEC. The redacted material has been separately filed with the SEC.

Incorporated herein by reference to Exhibit 10.1 to EQM Midstream Partners, LP's Form 10-Q/A (#001-35574) for the quarterly period ended March 31, 2018.

10.9(b)

First Amendment to Third Amended and Restated Limited Liability Company Agreement of Mountain Valley Pipeline, LLC, dated as of February 5, 2020, by and among MVP Holdco, LLC, US Marcellus Gas Infrastructure, LLC, WGL Midstream, Inc., Con Edison Gas Pipeline and Storage, LLC, RGC Midstream, LLC and Mountain Valley Pipeline, LLC.

Incorporated hereby by reference to Exhibit 10.21(b) to Form 10-K (#001-38629) for the year ended December 31, 2019.

10.10

Amended and Restated Omnibus Agreement, dated November 13, 2018, among EQT Corporation, EQM Midstream Partners, LP and EQM Midstream Services, LLC.

Incorporated herein by reference to Exhibit 10.1 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on November 13, 2018.

10.11

Second Amended and Restated Omnibus Agreement, dated November 13, 2018, among EQT Corporation, RM Partners LP, EQM Midstream Management LLC, and EQM Poseidon Midstream LLC.

Incorporated herein by reference to Exhibit 10.2 to EQM Midstream Partners, LP's Form 8-K (#001-35574) filed on November 13, 2018.

10.12

Transportation Service Agreement Applicable to Firm Transportation Service Under Rate Schedule FTS, Contract No. EQTR 20242-852, dated as of September 24, 2014 and amended through April 1, 2019, by and between Equitrans, L.P. and EQT Energy, LLC.

Incorporated herein by reference to Exhibit 10.5 to Form 10-Q (#001-38629) for the quarterly period ended June 30, 2019.

10.13

Transportation Service Agreement Applicable to Firm Transportation Service Under Rate Schedule FTS, Contract No. EQTR19837-1296, dated as of January 8, 2016 and amended through January 9, 2020, by and between Equitrans, L.P. and EQT Energy, LLC.

Incorporated hereby by reference to Exhibit 10.37 to Form 10-K (#001-38629) for the year ended December 31, 2019.

10.14*

Equitrans Midstream Corporation Amended and Restated Directors’ Deferred Compensation Plan.

Incorporated herein by reference to Exhibit 10.18 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2020.

10.15(a)*

Equitrans Midstream Corporation 2018 Long-Term Incentive Plan.

Incorporated herein by reference to Exhibit 4.3 to Registration Statement on Form S-8 (File No. 333-228337) filed on November 9, 2018.

10.15(b)*

First Amendment to the Equitrans Midstream Corporation 2018 Long-Term Incentive Plan.

Incorporated herein by reference to Exhibit 10.2 to Form 8-K (#001-38629) filed on June 17, 2020.

10.16*

Letter Agreement, dated as of August 9, 2018, with Thomas F. Karam.

Incorporated herein by reference to Exhibit 10.57 to Registration Statement on Form 10-12B/A (#001-38629) filed on October 18, 2018.

10.17*

Letter Agreement, dated as of September 4, 2018, with Kirk R. Oliver.

Incorporated herein by reference to Exhibit 10.58 to Registration Statement on Form 10-12B/A (#001-38629) filed on October 18, 2018.

10.18*

Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement, dated as of January 15, 2019, with Diana M. Charletta

Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-38629) filed on January 22, 2019.

10.19*

Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement, dated as of November 13, 2018, by and between Equitrans Midstream Corporation and Thomas F. Karam.

Incorporated herein by reference to Exhibit 10.9 to Form 8-K (#001-38629) filed on November 13, 2018.

10.20*

Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement, dated as of November 13, 2018, by and between Equitrans Midstream Corporation and Kirk R. Oliver.

Incorporated herein by reference to Exhibit 10.10 to Form 8-K (#001-38629) filed on November 13, 2018.

10.21*

Letter Agreement, dated April 2, 2019, with Stephen M. Moore.

Incorporated herein by reference to Exhibit 10.12 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2019.

10.22*

Confidentiality, Non-Solicitation and Non-Competition Agreement, dated April 15, 2019, with Stephen M. Moore.

Incorporated herein by reference to Exhibit 10.13 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2019.

10.23*

Form of Agreement of Assignment of Confidentiality, Non-Solicitation and Non-Competition Agreement.

Incorporated herein by reference to Exhibit 10.11 to Form 8-K (#001-38629) filed on November 13, 2018.

10.24*##

Confidentiality, Non-Solicitation and Change of Control Agreement, dated as of April 14, 2020, by and between Equitrans Midstream Corporation and Brian P. Pietrandrea.

Incorporated herein by reference to Exhibit 10.17 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2020.

10.25*

Form of Equitrans Midstream Corporation Director and/or Executive Officer Indemnification Agreement.

Incorporated herein by reference to Exhibit 10.16 to Registration Statement on Form 10-12B/A (#001-38629) filed on October 18, 2018.

10.26*

Equitrans Midstream Corporation 2019 Performance Share Unit Program.

Incorporated herein by reference to Exhibit 10.7(a) to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2019.

10.27*

Form of Equitrans Midstream Corporation Restricted Stock Award Agreement (Standard) under 2018 Long-Term Incentive Plan (2019 grants).

Incorporated herein by reference to Exhibit 10.7(b) to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2019.

10.28*

Form of Participant Award Agreement under the 2019 Performance Share Unit Program.

Incorporated herein by reference to Exhibit 10.7(c) to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2019.

10.29*

Amendment to 2018 EQT Incentive Performance Share Unit Program.

Incorporated herein by reference to Exhibit 10.8 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2019.

10.30*

Amended and Restated Equitrans Midstream Corporation Short-Term Incentive Plan.

Incorporated herein by reference to Exhibit 10.16 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2020.

10.31*

Form of Equitrans Midstream Corporation Director Participant Award Agreement.

Incorporated herein by reference to Exhibit 10.10 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2019.

10.32*

Equitrans Midstream Corporation 2020 Performance Share Unit Program.

Incorporated herein by reference to Exhibit 10.13 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2020.

10.33*

Form of Participant Award Agreement under 2020 Performance Share Unit Program.

Incorporated herein by reference to Exhibit 10.14 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2020.

10.34*

Form of Equitrans Midstream Corporation Restricted Stock Award Agreement (2020 Awards).

Incorporated herein by reference to Exhibit 10.15 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2020.

10.35**

Preferred Restructuring Agreement, dated as of February 26, 2020, by and among Equitrans Midstream Corporation, EQM Midstream Partners, LP and the Investors party thereto.

Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-38629) filed on February 28, 2020.

10.36(a)#

Gas Gathering and Compression Agreement, dated as of February 26, 2020, by and among EQT Corporation, EQT Production Company, Rice Drilling B LLC, EQT Energy, LLC and EQM Gathering Opco, LLC.

Incorporated herein by reference to Exhibit 10.4 to Form 8-K/A (#001-38629) filed on March 13, 2020.

10.36(b)#

First Amendment to Gas Gathering and Compression Agreement, dated as of August 26, 2020, by and among EQT Production Company, Rice Drilling B LLC, EQT Energy, LLC and EQM Gathering Opco, LLC.

Incorporated herein by reference to Exhibit 10.1 to Form 10-Q (#001-38629) for the quarterly period ended September 30, 2020.

10.37#

Credit Letter Agreement, dated as of February 26, 2020, by and between EQM Midstream Partners, LP and EQT Corporation.

Incorporated herein by reference to Exhibit 10.5 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2020.

10.38

Water Services Letter Agreement, dated as of February 26, 2020, by and among EQT Production Company, Rice Drilling B LLC, EQM Gathering Opco, LLC and Equitrans Water Services (PA) LLC.

Incorporated herein by reference to Exhibit 10.6 to Form 8-K/A (#001-38629) filed on March 13, 2020.

10.39

Loan Agreement, dated as of March 3, 2020, by and between EQM Midstream Partners, LP and Equitrans Midstream Corporation.

Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-38629) filed on March 6, 2020.

10.40

Promissory Note, dated as of March 5, 2020, by and between Equitrans Midstream Corporation and EQM Midstream Partners, LP (as assignee of EQT Corporation).

Incorporated herein by reference to Exhibit 10.2 to Form 8-K (#001-38629) filed on March 6, 2020.

10.41

Share Purchase Agreement, dated as of February 26, 2020, by and between Equitrans Midstream Corporation and EQT Corporation.

Incorporated herein by reference to Exhibit 10.2 to Form 8-K (#001-38629) filed on February 28, 2020.

10.42

Share Purchase Agreement, dated as of February 26, 2020, by and between Equitrans Midstream Corporation and EQT Corporation.

Incorporated herein by reference to Exhibit 10.3 to Form 8-K (#001-38629) filed on February 28, 2020.

10.43

Purchase Agreement, dated June 16, 2020, by and between EQM Midstream Partners, LP and J.P. Morgan Securities LLC, as representative of the several initial purchasers named on Schedule 1 thereto.

Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-38629) filed on June 18, 2020.

10.44

Purchase Agreement, dated January 4, 2021, by and among EQM Midstream Partners, LP, Equitrans Midstream Corporation (for certain limited purposes) and Barclays Capital Inc., as representative of the several initial purchasers named on Schedule 1 thereto.

Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-38629) filed on January 5, 2021.

10.45#

Letter Agreement, dated as of November 1, 2020, by and among EQM Gathering Opco, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC and EQT Energy, LLC.

Filed herewith as Exhibit 10.45.

10.46*

Equitrans Midstream Corporation Executive Short-Term Incentive Plan.

Filed herewith as Exhibit 10.46.

10.47*

Equitrans Midstream Corporation 2021 Performance Share Unit Program.

Filed herewith as Exhibit 10.47.

10.48*

Form of Participant Award Agreement under 2021 Performance Share Unit Program.

Filed herewith as Exhibit 10.48.

10.49*

Form of Equitrans Midstream Corporation Restricted Stock Award Agreement (2021 Awards).

Filed herewith as Exhibit 10.49.

21.1

Schedule of Subsidiaries.

Filed herewith as Exhibit 21.1.

23.1

Consent of Independent Registered Public Accounting Firm.

Filed herewith as Exhibit 23.1.

23.2

Consent of Independent Registered Public Accounting Firm (Mountain Valley Pipeline, LLC - Series A).

Filed herewith as Exhibit 23.2.

31.1

Rule 13(a)-14(a) Certification of Principal Executive Officer.

Filed herewith as Exhibit 31.1.

31.2

Rule 13(a)-14(a) Certification of Principal Financial Officer.

Filed herewith as Exhibit 31.2.

Section 1350 Certification of Principal Executive Officer and Principal Financial Officer.

Furnished herewith as Exhibit 32.

99.1

Mountain Valley Pipeline, LLC (Series A) financial statements.

Filed herewith as Exhibit 99.1.

101

Inline Interactive Data File.

Filed herewith as Exhibit 101.

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

Filed herewith as Exhibit 104.




☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


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


		Page No.
Glossary of Commonly Used Terms, Abbreviations and Measurements		3
Cautionary Statement		6
PART I
Item 1.	Business	9
Item 1A.	Risk Factors	29
Item 1B.	Unresolved Staff Comments	59
Item 2.	Properties	59
Item 3.	Legal Proceedings	60
Item 4.	Mine Safety Disclosures	63
	Information About Our Executive Officers	64
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	65
Item 6.	Selected Financial Data	66
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	67
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	84
Item 8.	Financial Statements and Supplementary Data	86
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	150
Item 9A.	Controls and Procedures	150
Item 9B.	Other Information	150
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	151
Item 11.	Executive Compensation	151
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	151
Item 13.	Certain Relationships and Related Transactions and Director Independence	151
Item 14.	Principal Accounting Fees and Services	151
PART IV
Item 15.	Exhibits and Financial Statement Schedules	152

Signatures		159


	11/13/2018		12/31/2018		12/31/2019		12/31/2020
Equitrans Midstream Corporation	$	100.00	$	95.84	$	71.75	$	47.88
S&P 500	100.00		92.82		122.05		144.51
Alerian U.S. Midstream Energy	100.00		89.60		103.54		77.70
Peer Group	100.00		91.00		105.27		76.30


	Years Ended December 31,
	2020		2019		% Change	2018		% Change
FINANCIAL DATA	(Thousands)
Firm reservation fee revenues	$	41,798	$	11,190	273.5	$	—	100.0
Volumetric-based fee revenues	62,910		68,601		(8.3)	111,227		(38.3)
Total operating revenues	104,708		79,791		31.2	111,227		(28.3)
Operating expenses:
Operating and maintenance	29,131		34,638		(15.9)	44,152		(21.5)
Selling, general and administrative	5,941		2,933		102.6	5,895		(50.2)
Depreciation	30,880		26,915		14.7	23,513		14.5
Total operating expenses	65,952		64,486		2.3	73,560		(12.3)
Operating income	$	38,756	$	15,305	153.2	$	37,667	(59.4)

OPERATIONAL DATA
Water services volumes (MMgal)
Firm capacity reservation(a)	697		249		179.9	—		100.0
Volumetric-based services	1,219		1,559		(21.8)	2,088		(25.3)
Total water volumes	1,916		1,808		6.0	2,088		(13.4)

Capital expenditures	$	11,905	$	37,457	(68.2)	$	23,537	59.1


or

FOR THE TRANSITION PERIOD FROM ___________ TO __________

COMMISSION FILE NUMBER			001-38629


Name	Age	Year Initially Elected as Executive Officer	Title
Thomas F. Karam	62	2018	Chief Executive Officer
Diana M. Charletta	48	2018	President and Chief Operating Officer
Kirk R. Oliver	63	2018	Senior Vice President and Chief Financial Officer
Stephen M. Moore	61	2019	Senior Vice President and General Counsel
Brian P. Pietrandrea	46	2019	Vice President and Chief Accounting Officer


	Years Ended December 31,
	2020		2019(a)		2018		2017(a)		2016
	(Thousands, except per share amounts)
Operating revenues	$	1,510,825	$	1,630,242	$	1,495,098	$	895,558	$	732,272

Net income (loss) attributable to Equitrans Midstream common shareholders	364,372		(203,743)		218,398		(27,156)		65,153

Earnings (loss) per share of common stock attributable to Equitrans Midstream


Basic	$	1.06	$	(0.80)	$	0.86	$	(0.11)	$	0.26


Diluted	$	1.06	$	(0.80)	$	0.86	$	(0.11)	$	0.26

Dividends declared per common share	$	0.60	$	1.80	$	0.41	$	—	$	—


	December 31,
	2020		2019		2018		2017		2016
	(Thousands)
Total assets	$	12,725,852	$	12,041,709	$	10,523,835	$	8,328,796	$	4,392,155
Long-term debt, including credit facilities (a)	7,230,812		6,324,483		4,660,244		1,453,352		985,732


	Total		2021		2022 – 2023		2024 – 2025		2026 +
	(Thousands)
Long-term debt (a)	$	6,500,000	$	—	$	2,500,000	$	1,200,000	$	2,800,000

Credit facility borrowings (b)	787,500		302,500		485,000		—		—
Interest payments on senior notes (c)	2,232,938		275,875		527,802		397,917		1,031,344
Purchase obligations (d)	10,340		6,083		2,766		1,491		—

Operating lease obligations (e)	66,981		12,508		17,833		10,948		25,692
Other liabilities (f)	13,970		3,674		10,296		—		—
Total contractual obligations	$	9,611,729	$	600,640	$	3,543,697	$	1,610,356	$	3,857,036


			Page No.
Reports of Independent Registered Public Accounting Firm			87
Statements of Consolidated Comprehensive Income for the Years Ended December 31, 2020, 2019 and 2018			92
Statements of Consolidated Cash Flows for the Years Ended December 31, 2020, 2019 and 2018			94
Consolidated Balance Sheets as of December 31, 2020 and 2019			95
Statements of Consolidated Equity for the Years Ended December 31, 2020, 2019 and 2018			97
Notes to Consolidated Financial Statements			99


/s/ Ernst & Young LLP
We have served as the Company's auditor since 2018.
Pittsburgh, Pennsylvania
February 23, 2021


Partial period distributions on EQM Series A Preferred Units converted in the EQM Merger (as defined in Note 1)	—		—	—		—		—		(10,929)		(10,929)		—
Redemption of EQM Series A Preferred Units	—		—	—		(27,253)		—		(590,085)		(617,338)		—
Restructuring Agreement (as defined in Note 1)	—		—	(100,524)		—		—		(579,157)		(679,681)		667,214
EQM Merger	—		203,137	2,736,229		—		—		(2,993,453)		(257,224)		—
Share Purchase Agreements (as defined in Note 6)	—		(25,300)	—		(190,992)		—		—		(190,992)		—
Adoption of Topic 326 (as defined in Note 1)	—		—	—		(3,718)		—		—		(3,718)		—
Balance at December 31, 2020	$	—	432,470	$	3,941,295	$	(728,959)	$	(2,229)	$	471,165	$	3,681,272	$	681,842


	Accounts Receivable		Contract Asset (a)		Other Assets (b)		Total
	(thousands)
Balance at December 31, 2019	$	(285)	$	—	$	—	$	(285)
Adoption of Topic 326	(2,708)		—		(1,010)		(3,718)


(Provision for) recovery of expected credit losses	(1,706)		(181)		81		(1,806)
Balance at December 31, 2020	$	(4,699)	$	(181)	$	(929)	$	(5,809)


(in thousands)	Preliminary Purchase Price Allocation (As initially reported)		Measurement Period Adjustments (a)		Purchase Price Allocation (As adjusted)
Consideration given:
Cash consideration (b)	$	861,250	$	(11,404)	$	849,846
Buyout of portion of Eureka Midstream Class B units and incentive compensation	2,530		—		2,530
Total consideration	863,780		(11,404)		852,376

Fair value of liabilities assumed:
Current liabilities	52,458		(9,857)		42,601
Long-term debt	300,825		—		300,825
Other long-term liabilities	10,203		—		10,203
Amount attributable to liabilities assumed	363,486		(9,857)		353,629

Fair value of assets acquired:
Cash	15,145		—		15,145
Accounts receivable	16,817		—		16,817
Inventory	12,991		(26)		12,965
Other current assets	882		—		882
Net property, plant and equipment	1,222,284		(8,906)		1,213,378
Intangible assets (c)	317,000		(6,000)		311,000
Deferred tax asset	5,773		(5,268)		505
Other assets	14,567		—		14,567
Amount attributable to assets acquired	1,605,459		(20,200)		1,585,259

Noncontrolling interests	(486,062)		7,602		(478,460)

Goodwill as of April 10, 2019	$	107,869	$	(8,663)	$	99,206
Impairment of goodwill (d)					(99,206)
Goodwill as of December 31, 2020					$	—


(in thousands)	December 31, 2020		April 10, 2019 Through December 31, 2019
Operating revenues	$	128,631	$	97,123
Operating loss attributable to Equitrans Midstream	$	(8,235)	$	(94,551)
Net income (loss) attributable to noncontrolling interests	$	13,996	$	(21,291)
Net loss attributable to Equitrans Midstream	$	(29,430)	$	(80,631)


	Years Ended December 31,
(in thousands, except per share data)	2019		2018
Pro forma operating revenues	$	1,661,822	$	1,616,821
Pro forma net (loss) income	$	(44,167)	$	552,291
Pro forma net income attributable to noncontrolling interests	$	126,558	$	357,264
Pro forma net (loss) income attributable to Equitrans Midstream	$	(170,725)	$	195,027
Pro forma (loss) income per share (basic)	$	(0.67)	$	0.77
Pro forma (loss) income per share (diluted)	$	(0.67)	$	0.77


	EQM Opco(a)		Rice Retained Midstream		Eureka/Hornet		Total
	(Thousands)
Goodwill as of January 1, 2018	$	1,346,918	$	37,954	$	—	$	1,384,872
Add: transfer of goodwill from EQT	3,803		112,535		—		116,338
Less: impairment of goodwill	(261,941)		—		—		(261,941)
Goodwill as of December 31, 2018	1,088,780		150,489		—		1,239,269
Add: goodwill associated with Bolt-on Acquisition	—		—		99,206		99,206
Less: impairment of goodwill	(602,082)		(150,489)		(99,206)		(851,777)
Goodwill as of December 31, 2019	486,698		—		—		486,698

Goodwill as of December 31, 2020	$	486,698	$	—	$	—	$	486,698


	Year Ended December 31, 2020
	Gathering		Transmission		Water		Total
	(Thousands)
Firm reservation fee revenues (a)	$	595,720	$	364,533	$	41,798	$	1,002,051
Volumetric-based fee revenues	416,561		29,303		62,910		508,774
Total operating revenues	$	1,012,281	$	393,836	$	104,708	$	1,510,825


	Year Ended December 31, 2019
	Gathering		Transmission		Water		Total
	(Thousands)
Firm reservation fee revenues	$	581,118	$	356,569	$	11,190	$	948,877
Volumetric-based fee revenues	578,813		33,951		68,601		681,365
Total operating revenues	$	1,159,931	$	390,520	$	79,791	$	1,630,242


	Year Ended December 31, 2018
	Gathering		Transmission		Water		Total
	(Thousands)
Firm reservation fee revenues	$	447,360	$	356,725	$	—	$	804,085
Volumetric-based fee revenues	549,710		30,076		111,227		691,013
Total operating revenues	$	997,070	$	386,801	$	111,227	$	1,495,098


	Unbilled Revenue
	(Thousands)
Balance as of January 1, 2020	$	—
Revenue recognized in excess of amounts invoiced (a)	28,446
Minimum volume commitments invoiced (b)	(9,828)
Balance as of December 31, 2020	$	18,618


	Contract Liability
	(Thousands)
Balance as of January 1, 2020	$	—
Amounts recorded during the period (a)	398,750
Amounts transferred during the period (b)	—
Balance as of December 31, 2020	$	398,750


	2021		2022		2023		2024		2025		Thereafter		Total
	(Thousands)
Gathering firm reservation fees	$	159,669	$	158,699	$	158,606	$	157,104	$	149,597	$	1,192,897	$	1,976,572
Gathering revenues supported by MVCs	508,468		575,437		607,671		568,341		562,622		4,818,885		7,641,424
Transmission firm reservation fees	357,730		381,314		341,046		279,493		246,408		2,371,249		3,977,240
Water revenues supported by MVCs	2,028		60,000		60,000		60,000		60,000		60,000		302,028
Total (a)	$	1,027,895	$	1,175,450	$	1,167,323	$	1,064,938	$	1,018,627	$	8,443,031	$	13,897,264


Incentive PSU Program	Settled In	Accounting Treatment	Fair Value (a)		Risk Free Rate		Vested/ Payment Date	Awards Paid	Value (Millions)		Unvested/ Expected Payment Date	Awards Outstanding as of December 31, 2020 (b)
2016	Stock	Equity	$	109.30	1.31	%	February 2019	569,290	$	62.2	N/A	N/A

2017	Stock	Equity	$	120.60	1.47	%	February 2020	66,822	8.1		N/A	N/A
2017	Cash	Liability	$	13.36	N/A		February 2020	146,387	2.0		N/A	N/A
2018	Stock	Equity	$	76.53	1.97	%	N/A	N/A	N/A		First Quarter of 2021	85,872
2018T1	Cash	Liability	$	8.04	N/A		N/A	N/A	N/A		First Quarter of 2021	29,049
2018T2	Cash	Liability	$	8.04	N/A		N/A	N/A	N/A		First Quarter of 2021	58,097
2019	Stock	Equity	$	15.03	2.54	%	N/A	N/A	N/A		First Quarter of 2022	483,555
2019	Cash	Liability	$	4.03	0.09	%	N/A	N/A	N/A		First Quarter of 2022	211,297
2020	Stock	Equity	$	5.59	0.39	%	N/A	N/A	N/A		First Quarter of 2023	731,115
2020	Cash	Liability	$	9.44	0.13	%	N/A	N/A	N/A		First Quarter of 2023	414,153


	For Incentive PSU Programs Issued During the Years Ended December 31,
	2020				2019				2018
Accounting Treatment	Liability (a)		Equity		Liability (a)		Equity		Equity
Risk-free rate	0.13	%	0.39	%	0.09	%	2.54	%	1.97	%
Dividend yield (b)	N/A		N/A		N/A		N/A		N/A
Volatility factor	63.0	%	53.0	%	63.0	%	30.0	%	32.6	%
Expected term	2 years		3 years		1 year		3 years		3 years


	Non-vested Shares (a)	Weighted Average Fair Value		Aggregate Fair Value
Outstanding at January 1, 2020	397,117	$	24.63	$	9,779,218

Granted	491,640	13.36		6,568,310
Vested	(28,375)	57.73		(1,638,044)
Forfeited	(19,314)	17.77		(343,138)
Outstanding at December 31, 2020	841,068	$	17.08	$	14,366,346


	December 31, 2020						December 31, 2019
	Principal		Carrying Value(a)		Fair Value(b)		Principal		Carrying Value(a)		Fair Value(b)
	(Thousands)


Amended EQM Credit Facility	$	485,000	$	485,000	$	485,000	$	610,000	$	610,000	$	610,000
Eureka Credit Facility	302,500		302,500		302,500		292,500		292,500		292,500
Total credit facility borrowings	$	787,500	$	787,500	$	787,500	$	902,500	$	902,500	$	902,500

ETRN Term Loan Credit Agreement	$	—	$	—	$	—	$	600,000	$	568,484	$	594,743
Amended 2019 EQM Term Loan Agreement(c)	1,400,000		1,397,768		1,400,000		1,400,000		1,397,491		1,400,000
EQM 4.00% Senior Notes due 2024	500,000		497,245		515,455		500,000		496,476		486,905
EQM 4.125% Senior Notes due 2026	500,000		494,966		512,285		500,000		494,115		471,770
EQM 4.75% Senior Notes due 2023(d)	1,100,000		1,094,235		1,162,590		1,100,000		1,091,988		1,104,961
EQM 5.50% Senior Notes due 2028	850,000		841,538		933,980		850,000		840,420		839,035
EQM 6.50% Senior Notes due 2048	550,000		539,393		582,995		550,000		539,009		518,678
EQM 6.00% Senior Notes due 2025	700,000		690,565		767,375		—		—		—
EQM 6.50% Senior Notes due 2027	900,000		887,602		1,020,060		—		—		—
Total debt	6,500,000		6,443,312		6,894,740		5,500,000		5,427,983		5,416,092
Less current portion of debt	—		—		—		6,000		6,000		6,000
Total long-term debt(e)	$	6,500,000	$	6,443,312	$	6,894,740	$	5,494,000	$	5,421,983	$	5,410,092


	Year Ended December 31,
	2020				2019				2018
	Basic		Diluted		Basic		Diluted		Basic		Diluted
	(In thousands, except per share data)
Net income (loss)	$	638,044	$	638,044	$	(64,959)	$	(64,959)	$	511,277	$	511,277
Less: Net income attributable to noncontrolling interests (excluding EQM Series A Preferred Units)	167,553		167,553		64,803		64,803		292,879		292,879
Less: EQM Series A Preferred Units interest in net income	47,359		47,359		73,981		73,981		—		—

Less: Preferred dividends	58,760		58,760		—		—		—		—

Net income (loss) attributable to Equitrans Midstream common shareholders	$	364,372	$	364,372	$	(203,743)	$	(203,743)	$	218,398	$	218,398

Basic weighted average common shares outstanding	343,935		343,935		254,884		254,884		254,432		254,432
Dilutive securities (a)	—		40		—		—		—		601
Diluted weighted average common shares outstanding	343,935		343,975		254,884		254,884		254,432		255,033

Earnings (loss) per share of common stock attributable to Equitrans Midstream common shareholders	$	1.06	$	1.06	$	(0.80)	$	(0.80)	$	0.86	$	0.86


	Three Months Ended
	March 31 (a)		June 30		September 30		December 31
	(Thousands, except per share amounts)
2020
Operating revenues	$	453,113	$	340,590	$	350,000	$	367,122
Operating income	242,082		175,297		200,509		206,673
Net income	189,560		143,458		168,439		136,587
Net income attributable to Equitrans Midstream common shareholders	69,732		26,990		149,838		117,812

Earnings per share of common stock attributable to Equitrans Midstream common shareholders(b)


Basic and diluted	$	0.28	$	0.10	$	0.35	$	0.27


	Three Months Ended
	March 31		June 30 (a)		September 30 (a)		December 31 (a)
	(Thousands, except per share amounts)
2019
Operating revenues	$	389,782	$	406,167	$	408,434	$	425,859
Operating income (loss)	260,041		166,175		(38,453)		(311,763)
Net income (loss)	199,566		130,480		(61,489)		(333,516)
Net income (loss) attributable to Equitrans Midstream common shareholders	56,299		74,521		(65,825)		(268,738)

Earnings (loss) per share of common stock attributable to Equitrans Midstream common shareholders (b)


Basic and diluted	$	0.22	$	0.29	$	(0.26)	$	(1.05)


1	Financial Statements	Page Reference
	Statements of Consolidated Comprehensive Income for the Years Ended December 31, 2020, 2019 and 2018	92
	Statements of Consolidated Cash Flows for the Years Ended December 31, 2020, 2019 and 2018	94
	Consolidated Balance Sheets as of December 31, 2020 and 2019	95
	Statements of Consolidated Equity for the Years Ended December 31, 2020, 2019 and 2018	97
	Notes to Consolidated Financial Statements	99

2	Financial Statement Schedules
	All schedules are omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedules.
	The financial statements of the MVP Joint Venture, Series A are included in this filing as Exhibit 99.1 pursuant to Rule 3-09 of Regulation S-X.

3	Exhibits
	The exhibits referenced below are filed (or, as applicable, furnished) as part of this Annual Report on Form 10-K.


			Equitrans Midstream Corporation
			(Registrant)


			By:			/s/ KIRK R. OLIVER
						Kirk R. Oliver
						Senior Vice President and Chief Financial Officer
						February 23, 2021


	Threshold	Target	Maximum
Performance Goal	At 25th percentile	50th percentile	At or above 75th percentile
Payout Factor	50%	100%	200%


Antero Midstream Corporation Cheniere Energy Inc. Crestwood Equity Partners LP DCP Midstream LP Enable Midstream Partners LP EnLink Midstream LLC Hess Midstream LP Kinder Morgan Inc. Magellan Midstream Partners LP National Fuel Gas Company ONEOK Inc. Plains All American Pipeline LP Targa Resources Corp The Williams Companies Inc. Western Midstream Partners LP