EDGAR 10-K Filing

Company CIK: 1747009
Filing Year: 2023
Filename: 1747009_10-K_2023_0001747009-23-000011.json

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ITEM 1. BUSINESS
Item 1. Business
Overview of Operations
Equitrans Midstream is one of the largest natural gas gatherers in the U.S. and holds a significant transmission footprint in the Appalachian Basin. Equitrans Midstream, a Pennsylvania corporation, became an independent, publicly traded company on November 12, 2018. The Company provides midstream services to its customers in Pennsylvania, West Virginia and Ohio through its three primary assets: the gathering system, which includes predominantly dry gas gathering systems of high-pressure gathering lines; the transmission system, which includes FERC-regulated interstate pipelines and storage systems; and the water network, which primarily consists of water pipelines and other facilities that support well completion and produced water handling activities.
As of December 31, 2022, the Company provided a majority of its natural gas gathering, transmission and storage services and water services under long-term contracts that generally include firm reservation fee revenues. For the year ended December 31, 2022, approximately 71% of the Company's operating revenues were generated from firm reservation fee revenues. Generally, the Company is focused on utilizing contract structures reflecting long-term firm capacity, MVC or ARC commitments which are intended to provide support to its cash flow profile. The percentage of the Company's operating revenues that are generated by firm reservation fees (as well as the Company's revenue generally) may vary year to year depending on various factors, including customer volumes and the rates realizable under the Company's contracts, including the EQT Global GGA (defined below) which provides for periodic gathering MVC fee declines through January 1, 2028 (with the fee then remaining fixed throughout the remaining term), even if MVP would not achieve full in-service. Additionally, as discussed in Note 5 to the consolidated financial statements, in connection with MVP full in-service the EQT Global GGA provides for more significant potential gathering MVC fee declines in certain contract years.
The Company's operations are focused primarily in southwestern Pennsylvania, northern West Virginia and southeastern Ohio, which are prolific resource development areas in the natural gas shale plays known as the Marcellus and Utica Shales. These regions are also the primary operating areas of EQT, which was one of the largest natural gas producers in the United States based on average daily sales volumes as of December 31, 2022 and the Company's largest customer as of December 31, 2022. EQT accounted for approximately 61% of the Company's revenues for the year ended December 31, 2022.
EQT Global GGA. On February 26, 2020 (the EQT Global GGA Effective Date), the Company entered into a Gas Gathering and Compression Agreement (as subsequently amended, the EQT Global GGA) with EQT and certain affiliates of EQT for the provision by the Company of certain gas gathering services to EQT in the Marcellus and Utica Shales of Pennsylvania and West Virginia. The EQT Global GGA is intended to, among other things, incentivize combo and return-to-pad drilling by EQT. Pursuant to the EQT Global GGA, EQT is subject to an initial annual MVC of 3.0 Bcf per day that gradually steps up to 4.0 Bcf per day through December 2031 following the full in-service date of the MVP (should it be placed in-service) and the dedication of a substantial majority of EQT's core acreage in southwestern Pennsylvania and West Virginia. The EQT Global GGA runs from the EQT Global GGA Effective Date through December 31, 2035, and will renew annually thereafter unless terminated by EQT or the Company pursuant to its terms. Pursuant to the EQT Global GGA, the Company has certain obligations to build connections to connect EQT wells to its gathering system, which are subject to limitations, including geographical in relation to the dedicated area, as well as the distance of such connections to the Company's then-existing gathering system, which could provide capital efficiencies to EQM. In addition to the fees related to gathering services, the EQT Global GGA provides for potential cash bonus payments payable by EQT to the Company during the period beginning on the first day of the calendar quarter in which the MVP full in-service date occurs through the calendar quarter ending December 31, 2024 (the Henry Hub cash bonus payment provision). The potential cash bonus payments are conditioned upon the quarterly average of certain Henry Hub natural gas prices exceeding certain price thresholds.
Under the EQT Global GGA, the performance obligation is to provide daily MVC capacity and as such the total consideration is allocated proportionally to the daily MVC over the life of the contract. In periods that the gathering MVC revenue billed will exceed the allocated consideration, the excess will be deferred to the contract liability and recognized in revenue when the performance obligation has been satisfied. While the 3.0 Bcf per day MVC capacity became effective on April 1, 2020, additional daily MVC capacity and the associated gathering MVC fees payable by EQT to the Company as set forth in the EQT Global GGA are conditioned upon the full in-service date of the MVP. There are ongoing (and potentially future) legal and regulatory matters that affect the MVP project which have had and/or could have (as applicable) a material effect on the performance obligation, the allocation of the total consideration over the life of the contract and the gathering MVC fees payable by EQT under the contract.
Under the EQT Global GGA, the gathering MVC fees periodically decline through January 1, 2028 (with the fee then remaining fixed throughout the remaining term), even if MVP would not achieve full in-service. Before January 1, 2026, beginning the first day of the quarter in which the full in-service date of the MVP occurs, the gathering MVC fees payable by EQT to the Company are subject to more significant potential declines for certain contract years as set forth in the EQT Global GGA, which, prior to EQT's exercise of the EQT Cash Option (defined below), provided for estimated aggregate fee relief of up to approximately $270 million in the first twelve-month period, up to approximately $230 million in the second twelve-month period and up to approximately $35 million in the third twelve-month period. Given that the MVP full in-service date did not occur by January 1, 2022, on July 8, 2022, EQT irrevocably elected under the EQT Global GGA to forgo up to approximately $145 million of the potential gathering MVC fee relief in such first twelve-month period and up to approximately $90 million of the potential gathering MVC fee relief in such second twelve-month period in exchange for a cash payment from the Company to EQT in the amount of approximately $195.8 million (the EQT Cash Option). As a result of EQT exercising the EQT Cash Option, the maximum aggregate potential fee relief applicable under the EQT Global GGA in such first twelve-month period and such second twelve-month period was reduced to be up to approximately $125 million and $140 million, respectively. The Company utilized borrowings under the Amended EQM Credit Facility to effect payment of the EQT Cash Option to EQT on October 4, 2022. Additionally, the EQT Global GGA provides for a fee credit to the gathering rate for certain gathered volumes that also receive separate transmission services under certain transmission contracts.
Credit Letter Agreement. On February 26, 2020, in connection with the execution of the EQT Global GGA, the Company and EQT entered into a letter agreement (the Credit Letter Agreement) pursuant to which, among other things, (a) the Company agreed to relieve certain credit posting requirements for EQT, in an amount up to approximately $250 million, under its commercial agreements with the Company, subject to EQT maintaining a minimum credit rating from two of three rating agencies of (i) Ba3 with Moody's Investors Service (Moody's), (ii) BB- with S&P Global Ratings (S&P) and (iii) BB- with Fitch Investor Services (Fitch) and (b) the Company agreed to use commercially reasonable good faith efforts to negotiate similar credit support arrangements for EQT in respect of its commitments to the MVP Joint Venture. See Note 14 to the consolidated financial statements for further information on EQT's credit ratings.
Water Services Letter Agreement and 2021 Water Services Agreement. On February 26, 2020, the Company entered into a letter agreement with EQT relating to the provision of water services in Pennsylvania (such letter agreement, the Water Services Letter Agreement). Subject to the effect of the 2021 Water Services Agreement (as defined below), the Water Services Letter Agreement would have been effective as of the first day of the first month following the MVP full in-service date and would have expired on the fifth anniversary of such date. During each year of the Water Services Letter Agreement, EQT had agreed to pay the Company a minimum $60 million per year annual revenue commitment (ARC) for volumetric water services provided in Pennsylvania, all in accordance with existing water service agreements and new water service agreements entered into between the parties pursuant to the Water Services Letter Agreement (or the related agreements).
On October 22, 2021, the Company and EQT entered into a new 10-year, mixed-use water services agreement covering operations within a dedicated area in southwestern Pennsylvania (as subsequently amended, the 2021 Water Services Agreement). The 2021 Water Services Agreement became effective on March 1, 2022 and replaced the Water Services Letter Agreement and certain other existing Pennsylvania water services agreements. Pursuant to the 2021 Water Services Agreement, EQT has agreed to pay the Company a minimum ARC for water services equal to $40 million in each of the first five years of the 10-year contract term and equal to $35 million per year for the remaining five years of the contract term.
Share Purchase Agreements. On February 26, 2020, the Company entered into two share purchase agreements (the Share Purchase Agreements) with EQT, pursuant to which the Company agreed to (i) purchase 4,769,496 shares of Equitrans Midstream common stock (the Cash Shares) from EQT in exchange for approximately $46 million in cash, (ii) purchase 20,530,256 shares of Equitrans Midstream common stock (the Rate Relief Shares and, together with the Cash Shares, the Share Purchases) from EQT in exchange for a promissory note in the aggregate principal amount of approximately $196 million (which EQT subsequently assigned to EQM as consideration for certain commercial terms under the EQT Global GGA), and (iii) pay EQT cash in the amount of approximately $7 million (the Cash Amount). On March 5, 2020, the Company completed the Share Purchases and paid the Cash Amount. The Company used proceeds from the Amended EQM Credit Facility (as
defined in Note 10) 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.
Overview of the Company
The Separation. On November 12, 2018, the Company, 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). For periods prior to April 22, 2022, although they operated separately, the Company and EQT were characterized for certain purposes as related parties. Based solely on information reported by EQT in a Schedule 13G/A filed with the SEC on April 28, 2022, EQT was no longer a related party of the Company as of April 22, 2022.
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 incentive distribution rights (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.
EQM Series A Preferred Units. On March 13, 2019, EQM entered into a Convertible Preferred Unit Purchase Agreement, together with Joinder Agreements entered into on March 18, 2019, with certain investors (such investors, collectively, the Investors) to issue and sell in a private placement (the Private Placement) an aggregate of 24,605,291 Series A Perpetual Convertible Preferred Units (EQM Series A Preferred Units) representing limited partner interests in EQM for a cash purchase price of $48.77 per EQM Series A Preferred Unit, resulting in total gross proceeds of approximately $1.2 billion.
Preferred Restructuring Agreement. On February 26, 2020, the Company and EQM entered into a Preferred Restructuring Agreement (the Restructuring Agreement) with all of the Investors pursuant to which, at the effective time of the EQM Merger (the Effective Time): (i) EQM redeemed $600 million aggregate principal amount of the Investors' EQM Series A Preferred Units issued and outstanding immediately prior to the Restructuring Closing (as defined below), which occurred substantially concurrent with the closing of the EQM Merger (defined below), 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.
EQM Merger. On June 17, 2020, pursuant to that certain Agreement and Plan of Merger, dated as of February 26, 2020 (the EQM Merger Agreement), by and among the Company, EQM LP Corporation, a wholly owned subsidiary of the Company (EQM LP), LS Merger Sub, LLC, a wholly owned subsidiary of EQM LP (Merger Sub), EQM and the EQM General Partner, Merger Sub merged with and into EQM (the EQM Merger), with EQM continuing and surviving as an indirect, wholly owned subsidiary of the Company. Upon consummation of the EQM Merger, the Company acquired all of the outstanding EQM common units that the Company and its subsidiaries did not already own. Following the closing of the EQM Merger, EQM was
no longer a publicly traded entity. See Note 2 to the consolidated financial statements for further information on the EQM Merger.
The following diagram depicts the Company's organizational and ownership structure as of December 31, 2022:
The following is a map of the Company's gathering, transmission and storage and water services operations as of December 31, 2022. Also included is the MVP route, which project is discussed in "Strategy" under "Developments, Market Trends and Competitive Conditions" in Part I, "Item 1. Business" of this Annual Report on Form 10-K.
Business Segments
The Company reports its operations in three segments that reflect its three lines of business: Gathering, Transmission and Water. These segments include all of the Company's operations. For discussion of the composition of the three segments, see Notes 1 and 4 to the consolidated financial statements.
The Company's three business segments correspond to the Company's three primary assets: the gathering system, transmission and storage system and water service system. The following table summarizes the composition of the Company's operating revenues by business segment.
Years Ended December 31,
2022 2021 2020
Gathering operating revenues 66 % 66 % 67 %
Transmission operating revenues 30 % 30 % 26 %
Water operating revenues 4 % 4 % 7 %
The Company's largest customer, EQT, accounted for approximately 61%, 59% and 64% of the Company's total revenues for the years ended December 31, 2022, 2021 and 2020, respectively.
Gathering Customers. For the year ended December 31, 2022, EQT accounted for approximately 63% of Gathering's revenues. Subject to certain exceptions and limitations, as of December 31, 2022, Gathering (inclusive of acreage dedications to Eureka Midstream Holdings, LLC (Eureka Midstream), a joint venture in which the Company is the operator and has a 60% interest) had significant acreage dedications through which the Company has the right to elect to gather all natural gas produced from wells under dedicated areas in (i) Pennsylvania pursuant to agreements with EQT, including the EQT Global GGA, and agreements with certain other third parties, (ii) West Virginia pursuant to agreements with EQT, including the EQT Global GGA, and agreements with certain other third parties, and (iii) Ohio pursuant to agreements with various third parties.
The Company provides gathering services in two manners: firm service and interruptible service. Firm service contracts are typically long-term and often include firm reservation fees, which are fixed, monthly charges for the guaranteed reservation of pipeline access. Revenues under firm reservation fees also include fixed volumetric charges under MVCs. As of December 31, 2022, the gathering system had total contracted firm reservation capacity (including contracted MVCs) of approximately 7.4 Bcf per day (inclusive of Eureka Midstream contracted capacity), which included contracted firm reservation capacity of approximately 1.8 Bcf per day associated with the Company's high-pressure header pipelines. Including future capacity expected from expansion projects that are not yet fully constructed or not yet fully in-service for which the Company has executed firm contracts, the gathering system had total contracted firm reservation capacity (including contracted MVCs) of approximately 8.5 Bcf per day (inclusive of Eureka Midstream contracted capacity) as of December 31, 2022, which included contracted firm reservation capacity of approximately 1.9 Bcf per day associated with the Company's high-pressure header pipelines. Volumetric-based fees can also be charged under firm contracts for each firm volume gathered, as well as for volumes gathered in excess of the firm contracted volume. Based on total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed or not yet fully in-service for which the Company has executed firm contracts, the Company's firm gathering contracts had a weighted average remaining term of approximately 14 years as of December 31, 2022.
Interruptible service contracts include volumetric-based fees, which are charges for the volume of natural gas gathered and generally do not guarantee access to the pipeline. These contracts can be short- or long-term. To the extent that capacity reserved by customers with firm service contracts is not fully used or excess capacity exists, the gathering system can allocate capacity to interruptible services.
The Company generally does not take title to the natural gas gathered for its customers but retains a percentage of wellhead gas receipts to recover natural gas used to fuel certain of its compressor stations and meet other requirements on the Company's gathering systems.
Transmission Customers. For the year ended December 31, 2022, EQT accounted for approximately 61% of Transmission's throughput and approximately 52% of Transmission's revenues. As of December 31, 2022, Transmission had an acreage dedication from EQT through which the Company had the right to elect to transport all gas produced from wells drilled by EQT under dedicated areas in Allegheny, Washington and Greene Counties in Pennsylvania and Wetzel, Marion, Taylor, Tyler, Doddridge, Harrison and Lewis Counties in West Virginia. The Company's other customers include LDCs, marketers, producers and commercial and industrial users. The Company's transmission and storage system provides customers with
access to markets in Pennsylvania, West Virginia and Ohio and to the Mid-Atlantic, Northeastern, Midwestern and Gulf Coast markets through interconnect points with major interstate pipelines.
The Company provides transmission and storage services in two manners: firm service and interruptible service. Firm service contracts are typically long-term and often include firm reservation fees, which are fixed, monthly charges for the guaranteed reservation of pipeline and storage capacity. Volumetric-based fees can also be charged under firm contracts for firm volume transported or stored, as well as for volumes transported or stored in excess of the firm contracted volume. As of December 31, 2022, the Company had firm capacity subscribed under firm transmission contracts of approximately 5.7 Bcf per day, which includes future capacity expected from expansion projects that are not yet fully constructed or not yet fully in-service for which the Company has executed firm transmission contracts and excludes 2.3 Bcf per day of firm capacity commitments associated with the MVP and MVP Southgate projects. As of December 31, 2022, the Company had firm storage capacity of approximately 27.8 Bcf subscribed under firm storage contracts. Based on total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed or not yet fully in-service for which the Company has executed firm contracts, the Company's firm transmission and storage contracts had a weighted average remaining term of approximately 12 years as of December 31, 2022.
Interruptible service contracts include volumetric-based fees, which are charges for the volume of natural gas transported or stored and generally do not guarantee access to the pipeline or storage facility. These contracts can be short- or long-term. To the extent that capacity reserved by customers with firm service contracts is not fully used or excess capacity exists, the transmission and storage systems can allocate capacity to interruptible services.
The Company generally does not take title to the natural gas transported or stored for its customers but retains a percentage of gas receipts to recover natural gas used to fuel its compressor stations and meet other requirements of the Company's transmission and storage systems.
As of December 31, 2022, approximately 97% of Transmission's contracted firm transmission capacity was subscribed by customers under negotiated rate agreements under its tariff. As of December 31, 2022, Transmission had minimal contracted firm transmission capacity subscribed at discounted rates and recourse rates under its tariff. See also "FERC Regulation" under "Regulatory Environment" below and "Our natural gas gathering, transmission and storage services are subject to extensive regulation by federal, state and local regulatory authorities. Changes in or additional regulatory measures adopted by such authorities, and related litigation, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends.” included in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K for additional information.
Water Customers. For the year ended December 31, 2022, EQT accounted for approximately 94% of Water's revenues. The Company has the exclusive right to provide fluid handling services to certain EQT-operated wells through 2029 (and thereafter such right will continue on a month-to-month basis) within areas of dedication in Belmont County, Ohio, including the delivery of fresh water for well completion operations and the collection and recycling or disposal of flowback and produced water. The Company also provides water services to other customers operating in the Marcellus and Utica Shales. Given commencement of the 2021 Water Services Agreement, the majority of the Company's water service revenues are subject to an ARC with EQT.
See also "Water Services Letter Agreement" and "2021 Water Services Agreement" above for additional information.
The Company's Assets
Gathering Assets. As of December 31, 2022, the gathering system, inclusive of Eureka Midstream's gathering system, included approximately 1,180 miles of high-pressure gathering lines, 135 compressor units with compression of approximately 493,000 horsepower and multiple interconnect points with the Company's transmission and storage system and to other interstate pipelines.
Transmission and Storage Assets. As of December 31, 2022, the transmission and storage system included approximately 940 miles of FERC-regulated, interstate pipelines that have interconnect points to seven interstate pipelines and multiple LDCs. As of December 31, 2022, the transmission and storage system was supported by 43 compressor units, with total throughput capacity of approximately 4.4 Bcf per day and compression of approximately 136,000 horsepower, and 18 associated natural gas storage reservoirs, which had a peak withdrawal capacity of approximately 820 MMcf per day and a working gas capacity of approximately 43 Bcf.
Water Assets. As of December 31, 2022, the fresh water systems included approximately 201 miles of pipeline that deliver fresh water from local municipal water authorities, the Monongahela River, the Ohio River, local reservoirs and several regional waterways. In addition, as of December 31, 2022, the fresh water system assets included 21 fresh water impoundment facilities. The mixed water system, upon completion, is designed to include approximately 70 miles of buried pipeline and two water
storage facilities with 350,000 barrels of capacity, as well as two interconnects with the Company’s existing Pennsylvania fresh water systems and provides services to producers in southwestern Pennsylvania. The Company expects the remaining portions of the mixed water system to be substantially complete in 2023.
Developments, Market Trends and Competitive Conditions
The Company's strategically located assets overlay core acreage in the Appalachian Basin. The location of the Company's assets allows its producer customers to access major demand markets in the U.S. The Company is one of the largest natural gas gatherers in the U.S., and its largest customer, EQT, was one of the largest natural gas producers in the U.S. based on average daily sales volumes as of December 31, 2022 and EQT's public senior debt had investment grade credit ratings from Standard & Poor's Global Ratings (S&P) and Fitch Ratings (Fitch) as of that date. For the year ended December 31, 2022, approximately 71% of the Company's operating revenues were generated from firm reservation fee revenues. Generally, the Company is focused on utilizing contract structures reflecting long-term firm capacity, MVC or ARC commitments which are intended to provide support to its cash flow profile. The percentage of the Company's operating revenues that are generated by firm reservation fees (as well as the Company's revenue generally) may vary year to year depending on various factors, including customer volumes and the rates realizable under the Company's contracts, including the EQT Global GGA which provides for periodic gathering MVC fee declines through January 1, 2028 (with the fee then remaining fixed throughout the remaining term), even if MVP would not achieve full in-service. Additionally, as discussed in Note 5 to the consolidated financial statements, in connection with MVP full in-service the EQT Global GGA provides for more significant potential gathering MVC fee declines in certain contract years.
The Company's principal strategy is to achieve greater scale and scope, enhance the durability of its financial strength and to continue to work to position itself for a lower carbon economy, which the Company expects will drive future growth and investment. The Company is implementing its strategy by continuing to pursue its organic growth projects, including particularly the MVP given the Company's belief that the MVP will, among other benefits, help to promote greater natural gas production in the Appalachian Basin given production levels have been limited by regional takeaway capacity limitations (including the lack of completion of the MVP), focusing on opportunities to use its existing assets to deepen and grow its customer relationships at optimized levels of capital spending and taking into account the Company's leverage, and continuing to prudently invest resources in its sustainability-oriented initiatives. The Company is also continuing to focus on maintaining and strengthening its balance sheet. Additionally, the Company also periodically evaluates strategically-aligned inorganic growth opportunities (whether within its existing footprint or to extend the Company's reach into the southeast United States and to become closer to key demand markets, such as the Gulf of Mexico LNG export market).
As part of its approach to organic growth, the Company is focused on its projects and assets outlined below, many of which are supported by contracts with firm capacity, MVC or ARC commitments.
The Company expects that the MVP (should it be placed in-service), together with the Hammerhead pipeline and Equitrans, L.P. Expansion Project (EEP), will primarily drive the Company's organic growth, as discussed in further detail below. In addition, the Company continues to focus on de-levering its balance sheet (which the Company views as a critical strategic objective), including in connection with the MVP (should it be placed in-service).
•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, 2022, the Company owned an approximate 47.2% 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 is designed to span from the Company's existing transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia, which will provide access to the growing southeast demand markets. The MVP Joint Venture has secured a total of 2.0 Bcf per day of firm capacity commitments at 20-year terms. Additional shippers have expressed interest in the MVP project and the MVP Joint Venture is evaluating an expansion opportunity that could add approximately 0.5 Bcf per day of capacity through the installation of incremental compression.
In October 2017, the FERC issued the Certificate of Public Convenience and Necessity (the Certificate) for the MVP. In the first quarter of 2018, the MVP Joint Venture received limited notice to proceed with certain construction activities from the FERC and commenced construction. However, as discussed in "The regulatory approval process for the construction of new midstream assets is very challenging, has significantly increased costs and delayed then-targeted in-service dates, and decisions by regulatory and judicial authorities in pending or potential proceedings, particularly with respect to litigation in the Fourth Circuit regarding MVP, are likely to impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations necessary to complete certain projects in a timely manner or at all, or our ability to achieve the expected investment returns on
the projects." included in Part I, "Item 1A. Risk Factors", as well as in Part I, "Item 3. Legal Proceedings" of this Annual Report on Form 10-K, the MVP project has been subject to repeated, significant delays and cost increases because of legal and regulatory setbacks, particularly in respect of litigation in the U.S. Court of Appeals for the Fourth Circuit (Fourth Circuit), including, the Fourth Circuit's vacatur and remanding on specific issues of the MVP Joint Venture's authorizations related to the Jefferson National Forest (JNF) received from the Bureau of Land Management (BLM) and the U.S. Forest Service (USFS) and the Fourth Circuit's vacatur and remanding on specific issues of 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 on January 25, 2022 and February 2, 2022, respectively.
Given ongoing litigation and regulatory matters, on June 24, 2022, the MVP Joint Venture filed a request with the Federal Energy Regulatory Commission (FERC) for an extension of time to complete the MVP project for an additional four years (relative to a prior obtained extension) through October 13, 2026, which request was granted on August 23, 2022.
The MVP Joint Venture has sought new authorizations relating to the JNF, a new Biological Opinion and Incidental Take Statement, and an Individual Permit from the Huntington, Pittsburgh and Norfolk Districts of the U.S. Army Corps of Engineers (Army Corps) to effect approximately 300 water crossings utilizing open cut techniques. In April 2022, the MVP obtained the FERC’s authorization to amend the Certificate to utilize alternative trenchless construction methods to effect approximately 120 water crossings. In order to complete the project, in addition to the authorizations with respect to water crossings and other relevant regulatory matters, the MVP Joint Venture needs to continue to have available the orders previously issued by the FERC that are necessary to complete the MVP project and receive authorization from the FERC to complete construction work in the portion of the project route currently remaining subject to the FERC’s previous stop work order and in the JNF. The MVP Joint Venture also is participating in the defense of Section 401 water quality certification approvals received in December 2021 from each of the West Virginia Department of Environmental Protection (WVDEP) and the Virginia Department of Environmental Quality (VADEQ) (the State 401 Approvals), which are the subject of ongoing litigation in the Fourth Circuit and the MVP Joint Venture is awaiting rulings from the Fourth Circuit.
For further information regarding litigation and regulatory related delays and risks affecting the completion of the MVP project, see Part I, "Item 3. Legal Proceedings" of this Annual Report on Form 10-K. See also "The regulatory approval process for the construction of new midstream assets is very challenging, has significantly increased costs and delayed then-targeted in-service dates, and decisions by regulatory and judicial authorities in pending or potential proceedings, particularly with respect to litigation in the Fourth Circuit regarding MVP, are likely to impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations necessary to complete certain projects in a timely manner or at all or our ability to achieve the expected investment returns on the projects.” and "Expanding our business by constructing new midstream assets subjects us to construction, regulatory, environmental, political and legal uncertainties that are beyond our control." included in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.
On October 25, 2022 and January 24, 2023, oral argument was held in the Fourth Circuit relating to the WVDEP State 401 Approval and VADEQ State 401 Approval, respectively, which oral arguments were conducted by the same panel of Fourth Circuit judges as have appeared, and overruled permitting agencies, in numerous prior matters relating to the MVP Joint Venture. The Company perceives continued hostility to and risk posed by the Fourth Circuit panel to the MVP Joint Venture’s State 401 Approvals (and, based upon the oral arguments, particularly with respect to WVDEP State 401 Approval) and more generally to those potential future authorizations and permits within the Fourth Circuit’s jurisdiction, including any new authorizations for the JNF and new Biological Opinion and Incidental Take Statement.
However, notwithstanding prior setbacks and ongoing risks, the MVP Joint Venture continues to engage in pursuing the requisite authorizations necessary under applicable law from the relevant agencies to complete the MVP project and the Company believes that the agencies are working to issue such authorizations over the next several months and to produce authorizations, for the third time in certain cases, that address points raised by the Fourth Circuit and exceed legal and regulatory standards for the issuance of such authorizations. Further, the Company continues to urge the United States Congress to expeditiously pass, and for there to be enacted, federal energy infrastructure permitting reform legislation that specifically requires the completion of the MVP project, similar to MVP-specific aspects of legislation proposed in 2022 by each of United States Senators Joseph Manchin and Shelley Moore Capito and ideally in sufficient time for the MVP Joint Venture to complete construction in 2023. The Company previously indicated that such legislation was the best path to complete the MVP in accordance with the Company’s previously-communicated targeted full in-service date for the project during the second half of 2023 and at a targeted total project cost of approximately $6.6 billion (excluding AFUDC). However, while as of the date of the filing of this Annual Report on
Form 10-K, the Company believes there remains continuing significant bipartisan support for federal energy infrastructure permitting reform legislation and that the MVP continues to be a prominent part of related discussions, the Company recognizes that to such date attempts to enact such legislation have failed and that differences between and within the Republican and Democratic parties continue to exist as to the scope and terms of any such reform, and such differences could impede the prospect of legislation being enacted in sufficient time for the MVP Joint Venture to complete construction in 2023.
The Company continues to pursue the requisite authorizations to complete the MVP project, understanding that they will be subject to the risk of challenge, including in the Fourth Circuit, and believes that there remain prospects for federal energy infrastructure permitting reform legislation favorable to the MVP project. Given that, the Company recognizes that there are a number of upcoming regulatory and litigation (and potential legislative) milestones and the timing thereof that will determine whether the MVP Joint Venture may commence forward construction with the goal of completing the project in 2023 or that will prevent such construction and completion in 2023. The Company believes that the MVP Joint Venture will complete the four to five months of remaining construction activity as promptly as practicable once authorized and fully mobilized and that the total project cost would be approximately $6.6 billion (excluding AFUDC) if that completion is achieved in 2023.
On November 4, 2019, Con Edison exercised an option to cap its investment in the construction of the MVP project at approximately $530 million (excluding AFUDC). The Company and NextEra Energy, Inc. are obligated, and RGC Resources, Inc., another member of the MVP Joint Venture owning an interest in the MVP project, has opted, to fund the shortfall in Con Edison's capital contributions on a pro rata basis. Such funding by the Company and funding by other members has and will correspondingly increase the Company's and such other members' respective interests in the MVP project and decrease Con Edison's interest in the MVP project. If the project were to be completed in 2023 at a total project cost of approximately $6.6 billion (excluding AFUDC), the Company's equity ownership in the MVP project would progressively increase from approximately 47.2% to approximately 48.1%.
Through December 31, 2022, the Company had funded approximately $2.7 billion to the MVP Joint Venture for the MVP project. If the MVP project were to be completed in 2023, the Company expects it would make total capital contributions to the MVP Joint Venture in 2023 of approximately $610 million to $660 million primarily related to forward construction for a total of approximately $3.4 billion over the project's construction, inclusive of approximately $180 million in excess of the Company's ownership interest. If no forward construction were to occur in 2023, the Company expects it would make total capital contributions to the MVP Joint Venture in 2023 of approximately $150 million to $200 million, primarily related to right-of-way maintenance and environmental compliance measures.
•Wellhead Gathering Expansion Projects and Hammerhead Pipeline. During the year ended December 31, 2022, the Company invested approximately $266 million in gathering projects (inclusive of capital expenditures related to the noncontrolling interest in Eureka Midstream). For 2023, the Company expects to invest approximately $250 million to $300 million in gathering projects (inclusive of expected capital expenditures of approximately $15 million related to the noncontrolling interest in Eureka Midstream). The primary projects include infrastructure expansion and optimization in core development areas in the Marcellus and Utica Shales in southwestern Pennsylvania, southeastern Ohio and northern West Virginia for EQT, Range Resources Corporation (Range Resources) and other producers. The Company expects that it will continue to see the benefits of return-to-pad drilling and system integrations in 2023, and accordingly estimates gathering capital expenditures required to maintain flat gathered volumes in a given year would be approximately $200 million for 2023.
The Hammerhead pipeline is a 1.6 Bcf per day gathering header pipeline that is primarily designed to connect natural gas produced in Pennsylvania and West Virginia to the MVP, Texas Eastern Transmission and Dominion Transmission, is supported by a 20-year term, 1.2 Bcf per day, firm capacity commitment from EQT, and cost approximately $540 million. The Company expects Hammerhead pipeline full commercial in-service to commence in conjunction with full MVP in-service.
During the second quarter of 2022, the Company entered into an agreement with a producer customer to install approximately 32,000 horsepower booster compression to existing facilities. The project is backed by a long-term commitment and is targeted to be in-service in mid-2024. The Company expects to invest approximately $70 million, with a majority of the capital spend in 2023 and 2024.
•Transmission Projects and Equitrans Expansion Project. During the year ended December 31, 2022, the Company invested approximately $36 million in transmission projects. The EEP is one of the Company's transmission projects and is designed to provide north-to-south capacity on the mainline Equitrans, L.P. system, including primarily for
deliveries to the MVP. A portion of the EEP commenced operations with interruptible service in the third quarter of 2019. The EEP provides capacity of approximately 600 MMcf per day and offers access to several markets through interconnects with Texas Eastern Transmission, Dominion Transmission and Columbia Gas Transmission. Once the MVP is fully placed in service, firm transportation agreements for 550 MMcf per day of capacity will commence under 20-year terms.
For 2023, the Company expects to invest approximately $90 million to $100 million in transmission projects. This includes an estimate of $5 million of capital expenditures related to the Rager Mountain natural gas storage field incident based on current information (however, such estimate is not an estimate of all potential capital expenditures from the incident as some items are not able to be estimated as of the filing of this Annual Report on Form 10-K). The $90 million to $100 million of expected investment in transmission projects also includes capital expenditures expected for 2023 associated with the Company's Ohio Valley Connector expansion project (OVCX). OVCX will increase deliverability on the Company's existing Ohio Valley Connector pipeline (OVC) by approximately 350 MMcf per day, create new receipt and delivery transportation paths, and enhance long-term reliability. The project is supported by new long-term firm capacity commitments of 330 MMcf per day, as well as an extension of approximately 1.0 Bcf per day of existing contracted mainline capacity for EQT. OVCX is designed to meet growing demand in key markets in the mid-continent and gulf coast through existing interconnects with long-haul pipelines in Clarington, Ohio. On July 7, 2022, the FERC issued a Notice of Intent to Prepare an Environmental Impact Statement for OVCX, and on January 20, 2023 issued the Final Environmental Impact Statement for the project. Based on the Company's expectation to receive all necessary approvals in the first half of 2023, the incremental OVC capacity is expected to be placed in-service during the first half of 2024. The Company expects to invest approximately $160 million in the project. The project is consistent with the Company's ongoing efforts to optimize existing assets and achieve capital efficiency.
•MVP Southgate Project. In April 2018, the MVP Joint Venture announced the MVP Southgate project, which is a contemplated interstate pipeline that was approved by the FERC to extend approximately 75 miles from the MVP at Pittsylvania County, Virginia to new delivery points in Rockingham and Alamance Counties, North Carolina. The MVP Southgate project is backed by a 300 MMcf per day firm capacity commitment from Dominion Energy North Carolina, and, as currently designed, reflects potential expansion capabilities that could provide up to 900 MMcf per day of total capacity. The Company is expected to operate the MVP Southgate project and owned a 47.2% interest in the MVP Southgate project as of December 31, 2022. The MVP Southgate project, as originally designed, was estimated to cost a total of approximately $450 million to $500 million, a portion of which the Company expected to fund.
The MVP Joint Venture submitted the MVP Southgate certificate application to the FERC in November 2018. In June 2020, the FERC issued the Certificate of Public Convenience and Necessity (MVP Southgate Certificate) 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. The FERC conditioned its authorization on the MVP Southgate project being built and made available for service by June 18, 2023. The Company anticipates that an extension of such construction deadline would be sought from the FERC prior to such deadline. In addition, there have been certain other litigation and regulatory-related delays affecting completion of the MVP Southgate project, including on August 11, 2020, the North Carolina Department of Environmental Quality 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 reissued in April 2021 following an appellate proceeding. On December 3, 2021, the Virginia State Air Pollution Control Board denied the permit for the MVP Southgate project’s Lambert compressor station, which decision the MVP Joint Venture initially appealed before withdrawing its request to review the denial.
Given the continually evolving regulatory and legal environment for greenfield pipeline construction projects, as well as factors specific to the MVP and MVP Southgate projects, the MVP Joint Venture continues to evaluate the MVP Southgate project and is focused on its ongoing discussions and negotiations with Dominion Energy North Carolina and other prospective customers regarding refining the MVP Southgate project’s design, scope and/or timing for the benefit of such customers in lieu of pursuing the project as originally contemplated. Dominion Energy North Carolina’s obligations under the precedent agreement in support of the original project are subject to certain conditions, including that the MVP Joint Venture would have completed construction of the project facilities by June 1, 2022, which deadline is subject to extension to June 1, 2023 by virtue of previously declared events of force majeure. The Company is unable to ensure the results of the discussions and negotiations between the MVP Joint
Venture and Dominion Energy North Carolina and other prospective customers, including the ultimate design, scope, timing, undertaking or completion of the project.
•Water Operations. During the year ended December 31, 2022, the Company invested approximately $67 million in its water infrastructure, primarily to construct the initial mixed-use water system buildout. This includes approximately $10 million to replace certain previously installed water lines that the Company believes do not meet their prescribed quality standards. The Company is pursuing recoupment of such replacement and related costs. The Company placed portions of the initial mixed-use water system in service in 2022. The Company expects the remaining portions of the mixed water system to be substantially complete in 2023. For 2023, the Company expects to invest approximately $35 million to $45 million, primarily related to the continued construction of its mixed-use water system buildout.
See "Sustainability and Corporate Responsibility" in Part II, "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" of this Annual Report on Form 10-K for a discussion of the Company's continued focus on ESG and sustainability matters which the Company believes will distinctively position the Company and create value.
Competitive Conditions. Key competitors for new natural gas gathering systems include companies that own major natural gas pipelines, independent gas gatherers and integrated energy companies. When compared to the Company or its customers, some of the Company's competitors have operations in multiple natural gas producing basins, have greater capital resources and access to, or control of, larger natural gas supplies. Natural gas producers that develop their own gas gathering systems or acquire such systems may also compete with the Company depending on the location of such systems relative to the Company's assets and existing agreements.
Competition for natural gas transmission and storage is primarily based on rates, customer commitment levels, timing, performance, commercial terms, reliability, service levels, location, reputation and fuel efficiencies. The Company's principal competitors in its transmission and storage market include companies that own major natural gas pipelines in the Marcellus and Utica Shales. In addition, the Company competes with companies that are building high-pressure gathering facilities that are able to transport natural gas to interstate pipelines without being subject to FERC jurisdiction. Major natural gas transmission companies that compete with the Company also have storage facilities connected to their transmission systems that compete with certain of the Company's storage facilities.
Key competition for water services includes natural gas producers that develop their own water distribution systems in lieu of employing the Company's water services assets and other natural gas midstream companies that offer water services. The Company's ability to attract customers to its water service business depends on its ability to evaluate and select suitable projects and to consummate transactions in a highly competitive environment.
Further, natural gas as a fuel competes with other forms of energy available to end-users, including coal, liquid fuels and, increasingly, renewable and alternative energy. Demand for renewable and alternative energy is increasing generally with changes in consumer preferences, governmental clean energy policies, and as renewable and alternative energy becomes more cost competitive with traditional fuels (including by technological advancement, legislation or government subsidies, as well as traditional supply and demand dynamics) and more widely available. Continued increases in the demand for renewable and alternative energy at the expense of natural gas (or increases in the demand for other sources of energy, particularly if prices for natural gas are elevated relative to other forms of energy as fuel) could lead to a reduction in demand for natural gas gathering, transmission and storage, and water services.
Regulatory Environment
FERC Regulation. The Company's interstate natural gas transmission and storage operations are regulated by the FERC under the Natural Gas Act of 1938, as amended (NGA), the Natural Gas Policy Act of 1978, as amended (NGPA), and the regulations, rules and policies promulgated under those and other statutes. Certain portions of the Company's gathering operations are also currently rate-regulated by the FERC in connection with its interstate transmission operations. The Company's FERC-regulated operations are pursuant to tariffs approved by the FERC that establish rates (other than market-based rate authority), cost recovery mechanisms and terms and conditions of service to its customers. Generally, the FERC's authority extends to:
•rates and charges for the Company's natural gas transmission and storage services and FERC-regulated gathering services;
•certification and construction of new interstate transmission and storage facilities;
•abandonment of interstate transmission and storage services and facilities and certificated gathering facilities;
•maintenance of accounts and records;
•relationships between pipelines and certain affiliates;
•terms and conditions of services and service contracts with customers;
•depreciation and amortization policies;
•acquisitions and dispositions of interstate transmission and storage facilities; and
•initiation and discontinuation of interstate transmission and storage services.
The FERC regulates the rates and charges for transmission and storage in interstate commerce. Unless market-based rates have been approved by the FERC, the maximum applicable recourse rates and terms and conditions for service are set forth in the pipeline's FERC-approved tariff. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of providing service, including the recovery of a return on the pipeline's actual and prudent historical investment costs. Key determinants in the ratemaking process include the depreciated capital costs of the facilities, the costs of providing service, the allowed rate of return and income tax allowance, as well as volume throughput and contractual capacity commitment assumptions.
Interstate pipelines may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust or unreasonable, unduly discriminatory or preferential. Rate design and the allocation of costs also can affect a pipeline's profitability. While the ratemaking process establishes the maximum rate that can be charged, interstate pipelines such as the Company's transmission and storage system are permitted to discount their firm and interruptible rates without further FERC authorization down to a specified minimum level, provided they do not unduly discriminate. In addition, pipelines are allowed to negotiate different rates with their customers, under certain circumstances. Changes to rates or terms and conditions of service, and contracts can be proposed by a pipeline company under Section 4 of the NGA, or the existing interstate transmission and storage rates, terms and conditions of service and/or contracts may be challenged by a complaint filed by interested persons including customers, state agencies or the FERC under Section 5 of the NGA. Rate increases proposed by a pipeline may be allowed to become effective subject to refund and/or a period of suspension, while rates or terms and conditions of service that are the subject of a complaint under Section 5 of the NGA are subject to prospective change by the FERC. Rate increases proposed by a regulated interstate pipeline may be challenged and such increases may ultimately be rejected by the FERC.
The Company's interstate pipeline may also use negotiated rates that could involve rates above or below the recourse rate or rates that are subject to a different rate structure than the rates specified in the Company's interstate pipeline tariffs, provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement. A prerequisite for allowing the negotiated rates is that negotiated rate customers must have had the option to take service under the pipeline's recourse rates. As of December 31, 2022, approximately 97% of the system's contracted firm transmission capacity was subscribed by customers under negotiated rate agreements under its tariff. Some negotiated rate transactions are designed to fix the negotiated rate for the term of the firm transportation agreement and the fixed rate is generally not subject to adjustment for increased or decreased costs occurring during the contract term.
The FERC’s regulations also extend to the terms and conditions set forth in agreements for transmission and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the form of service agreements set forth in the pipeline's FERC-approved tariff. Non-conforming agreements must be filed with and accepted by the FERC. In the event that the FERC finds that an agreement is materially non-conforming, in whole or in part, it could reject, or require the Company to seek modification of, the agreement, or alternatively require the Company to modify its tariff so that the non-conforming provisions are generally available to all customers or class of customers.
The FERC’s jurisdiction also extends to the certification and construction of new interstate transmission and storage facilities, including, but not limited to, acquisitions, facility replacements and upgrades, expansions, and abandonment of facilities and services. While the FERC currently exercises jurisdiction over the rates and terms of service for the Company’s FERC-regulated gathering services, these gathering facilities may not be subject to the FERC’s certification and construction authority. Prior to commencing construction of new or existing interstate transmission and storage facilities, an interstate pipeline must obtain (except in certain circumstances, such as where the activity is permitted under the FERC’s regulations or is authorized under the operator’s existing blanket certificate issued by the FERC) a certificate authorizing the construction, or file to amend its existing certificate, from the FERC.
On April 19, 2018, the FERC issued a Notice of Inquiry (2018 Notice of Inquiry) seeking information regarding whether, and if so how, it should revise its approach under its currently effective policy statement on the certification of new natural gas transportation facilities (Certificate Policy Statement). The formal comment period in this proceeding closed on June 25, 2018.
On February 18, 2021, the FERC issued another Notice of Inquiry in the same proceeding that modified and expanded the inquiry and renewed its request for public comment (together with the 2018 Notice of Inquiry, the Certificate Policy Statement NOI). The formal comment period closed May 26, 2021. On February 18, 2022, the FERC issued an Updated Certificate Policy Statement. On February 18, 2022, the FERC issued an interim GHG policy. On March 24, 2022, the FERC issued an order suspending the effectiveness of the Updated Certificate Policy Statement and the interim GHG policy and has taken no further action to date.
In 2022, Congress did not pass legislation revising the NGA or other statutes that may impact the Company's existing facilities and operations or the ability to construct new facilities, though that remains a possibility in 2023. Potential areas of revision include, but are not limited to, (i) amending Section 5 of the NGA to allow the FERC to require a pipeline to make refunds from the date that a NGA Section 5 complaint was filed with the FERC if rates are later found to be unjust and unreasonable; (ii) amending Section 7 of the NGA affecting the ability of companies to exercise eminent domain; and (iii) amending Section 19(b) of the NGA to provide the FERC additional time to act on requests for rehearing.
FERC had a full complement of five commissioners in 2022. However, Chairman Richard Glick left FERC at the end of 2022 after the Senate did not reconfirm him to serve an additional term. On January 3, 2023, President Biden named Willie Phillips to be Acting Chairman of the FERC. President Biden has not yet nominated a fifth commissioner or appointed a permanent Chair.
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. On June 17, 2022 and December 16, 2022, the FERC issued orders authorizing Equitrans, L.P. to abandon these low-pressure gathering facilities, subject to certain conditions. Equitrans, L.P. has abandoned certain of these assets and is working to complete the abandonments of the remaining facilities in 2023.
The Company believes that its high-pressure gathering systems meet the traditional tests the FERC has used to establish a pipeline's status as an exempt gatherer not subject to regulation as a jurisdictional natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is often the subject of litigation in the industry, so the classification and regulation of these systems are subject to change based on future determinations by the FERC, the courts or the U.S. Congress.
Safety and Maintenance. The Company's interstate natural gas pipeline system and natural gas storage assets are subject to regulation by PHMSA. PHMSA has established safety requirements pertaining to the design, installation, testing, construction, operation and maintenance of gas pipeline and storage facilities, including requirements that pipeline and storage operators develop a written qualification program for individuals performing covered tasks on pipeline facilities and implement pipeline and storage well integrity management programs. These integrity management plans require more frequent inspections and other preventive measures to ensure safe operation of oil and natural gas transportation pipelines and storage facilities in high population areas or facilities that are hard to evacuate and areas of daily concentrations of people.
Notwithstanding the investigatory and preventative maintenance costs incurred in the Company's performance of customary pipeline and storage management activities, the Company may incur significant additional expenses if anomalous pipeline or storage conditions are discovered or more stringent safety requirements are implemented. For example, in April 2016, PHMSA published a notice of proposed rulemaking addressing several integrity management topics and proposing new requirements to address safety issues for natural gas transmission and gathering lines, along with certain storage facilities (the Mega Rule). PHMSA intended the Mega Rule to strengthen existing integrity management requirements, expand assessment and repair requirements to pipelines in areas with medium population densities, and extend regulatory requirements to onshore gas gathering lines that are currently exempt. Part I of the Mega Rule was promulgated on October 1, 2019, with an effective date of July 1, 2020 (see discussion below). Part II was promulgated on November 15, 2021, with an effective date of May 16, 2022 (see discussion below). Finally, Part III of the Mega Rule was promulgated on August 24, 2022, and has an effective date of May 24, 2023 (see discussion below).
Further, in June 2016, then-President Obama signed the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the 2016 Pipeline Safety Act), extending PHMSA's statutory mandate under prior legislation through 2019. In addition,
the 2016 Pipeline Safety Act empowered PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing and also required PHMSA to develop new safety standards for natural gas storage facilities by June 2018. Pursuant to those provisions of the 2016 Pipeline Safety Act, PHMSA issued a final rule effective December 2, 2019 that expanded the agency's authority to impose emergency restrictions, prohibitions and safety measures and issued a final rule effective March 13, 2020 that strengthened the rules related to underground natural gas storage facilities, including well integrity, wellbore tubing and casing integrity
Following the October 2016 Interim Final Rule, PHMSA also published five final rules on pipeline safety applicable to the Company: "Enhanced Emergency Order Procedures;" "Safety of Gas Transmission Pipelines: Maximum Allowable Operating Pressure Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments" (also known as the Mega Rule Part I); and "Safety of Gas Gathering Pipelines: Extension of Reporting Requirements, Regulation of Large, High-Pressure Lines, and Other Related Amendments" (also known as the Mega Rule Part II); and "Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments" (also known as the Mega Rule Part III); and “Pipeline Safety: Requirement of Valve Installation and Minimum Rupture Detection Standards” (the valve rule). The Enhanced Emergency Order Procedures rule, which became effective on December 2, 2019, implements an existing statutory authorization for PHMSA to issue emergency orders related to pipeline safety if an unsafe condition or practice, or a combination of unsafe conditions and practices, constitutes, or is causing an imminent hazard. Mega Rule Part I, which went into effect on July 1, 2020, requires operators of certain gas transmission pipelines that have been tested or that have inadequate records to determine the material strength of their lines by reconfirming the Maximum Allowable Operating Pressure (MAOP), and establishes a new Moderate Consequence Area for determining regulatory requirements for gas transmission pipeline segments outside of high consequence areas. The rule also establishes new requirements for conducting baseline assessments, incorporates into the regulations industry standards and guidelines regarding design, construction and in-line inspections (ILI), and new requirements for data integration and risk analysis in integrity management programs, including seismicity, manufacturing and construction defects, and crack and crack-like defects, and includes several requirements that allow operators to notify PHMSA of proposed alternative approaches to achieving the objectives of the minimum safety standards. Mega Rule Part II, which was finalized on November 15, 2021 and went into effect on May 16, 2022, extends existing design, operational and maintenance, and reporting requirements to onshore natural gas gathering pipelines in rural areas. The rule requires operators of onshore gas gathering pipelines to report incidents and file annual reports (with the first annual reports due in Spring 2023), and creates new safety requirements that vary based on pipeline diameter and potential consequences of a failure. Mega Rule Part III, which was finalized on August 24, 2022, is not effective until May 24, 2023. The rule requires operators of certain transmission pipelines to assess their integrity management practices, and comply with enhanced corrosion control and mitigation timelines. It also establishes new requirements for pipeline inspections following an extreme weather event or natural disaster, and provides enhanced guidance for pipeline repairs. The valve rule requires the installation of remote operated rupture mitigation valves on new or entirely replaced transmission, storage and certain gathering lines when valves are installed to meet valve spacing requirements. In addition the valve rule includes requirements for operator actions to be taken when notified of a potential rupture that include notifying emergency response agencies and closing valves within a specified timeframe. In 2022, the Company did not incur material compliance costs in connection with complying with the PHMSA rules applicable to the Company. However, as discussed below, the Company does expect certain compliance costs to increase in the near future, and the Company continues to assess the impact of compliance with these rules which could materially impact its future costs of operations and revenue from operations. For example, Mega Rule Part I requires MAOP reconfirmation of certain previously untested transmission pipeline segments, which are commonly referred to as ‘‘grandfathered’’ pipelines. The Company’s grandfathered pipeline MAOP reconfirmation efforts, which the Company has initiated, may result in unanticipated testing and/or replacement costs. When reconfirming MAOP on certain of the Company’s grandfathered pipeline segments the Company may be required to remove portions of pipelines for testing, shut in certain pipelines, and/or may face significant operational or technical challenges when performing either a pressure test or an ILI examination, which could result in substantial costs related thereto, or to repairs, remediation, or replacing existing pipelines, and/or other mitigating actions that may be determined to be necessary as a result of the tests, as well as lost cash flows resulting from shutting down the Company's pipelines during the pendency of any such actions, which could be material to capital expenditures, earnings and the Company's competitive position. Additionally, ensuring complete compliance with the applicable Mega Rule compliance deadlines may cause the Company to incur significant additional expenses if anomalous pipeline conditions are discovered.
States are generally preempted by federal law in the area of pipeline safety, but state agencies may qualify to assume responsibility for enforcing federal regulations over intrastate pipelines. They may also promulgate additive pipeline safety regulations provided that the state standards are at least as stringent as the federal standards. Although many of the Company's natural gas facilities fall within a class that is not subject to integrity management requirements, the Company may incur significant costs and liabilities associated with repair, remediation, preventive or mitigation measures associated with its non-exempt transmission pipelines. The costs, if any, for repair, remediation, preventive or mitigating actions that may be
determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down the Company's pipelines during the pendency of any such actions, could be material to capital expenditures, earnings and the Company's competitive position.
Should the Company fail to comply with 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, unforeseen maintenance capital expenditures in the future for its regulatory compliance initiatives. Additionally, the adoption of new laws and regulations, such as the Mega Rule discussed above, could result in significant added costs or delays to in service or the termination of projects, which could have a material adverse effect on the Company in the future.
On December 27, 2020, then-President Trump signed the "Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES Act) of 2020," which reauthorized the federal pipeline safety program that expired in 2019. The PIPES Act identifies areas where Congress believed additional oversight, research, or regulations was needed. The PIPES Act includes new mandates for PHMSA to require operators to update, as needed, their emergency response plans and operating and maintenance plans. The PIPES Act also requires operators to manage records and update, as necessary, their existing district regulator stations to eliminate a common mode of failure. PHMSA will also require that leak detection and repair programs consider the environment, the use of advance lead detection practices and technologies, and that operators be able to locate and categorize all leaks that are hazardous to human safety, the environment, or that can become hazardous. The Company has not incurred and does not anticipate incurring material capital expenditures in connection with complying with the PIPES Act.
Cybersecurity. The U.S. government has continued to issue public warnings that indicate that energy assets might be specific targets of cyberattacks and, in May and July 2021, the U.S. Department of Homeland Security's Transportation Safety Administration (the TSA) issued security directives (as well as subsequent revisions thereto) applicable to certain midstream companies requiring such companies to comply with mandatory reporting measures and undertake a number of specific cybersecurity enhancements for both information technology (IT) and operational technology (OT) systems. The Company continues to work with the TSA to ensure compliance with the security directives and is implementing the requirements of those security directives, as needed. While such implementation is utilizing significant internal resources, as of the filing date of this Annual Report on Form 10-K, implementation of the CIP and security directives have not materially adversely affected the Company's business and operations.
In March 2022, President Biden signed into law the Cyber Incident Reporting for Critical Infrastructure Act of 2022 (CIRCIA). CIRCIA directs the U.S. Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) to promulgate regulations requiring certain entities to report to CISA certain cyber incidents. The Company expects that it will be subject to such regulations after they are promulgated and continues to monitor regulatory developments to ensure future compliance and assess the impact the compliance with these rules on its future costs of operations. It is not possible at this time to predict the ultimate impact such regulations may have on the Company’s business or operations.
In March 2022, the U.S. Securities and Exchange Commission published a proposed rule requiring, among other things, registrants to disclose certain information regarding cybersecurity governance and certain information about material cybersecurity incidents within four business days of the incident. The proposed rule has not yet been finalized. The Company will be subject to such regulations should they be made final, which may result in additional costs for compliance.
The regulatory environment surrounding cybersecurity continues to evolve in ways that are frequently difficult to predict. We have been required and may further be required to expend additional resources as a result of current or new laws, regulations, directives or other requirements, or changes in the interpretation or enforcement practices thereof, related to cybersecurity, which could result in material compliance costs. Additionally, as discussed above, we may become subject to multiple incident reporting requirements and other cybersecurity obligations that could overlap or conflict with each other, resulting an increased risk of non-compliance or in different responses to the same incident. Any failure to remain in compliance with laws or regulations governing cybersecurity, including the requirements contained in the Company’s CIP, may result in penalties, fines, enforcement actions, or mandated changes in our practices, which may have a material adverse effect on our business and operations.
For further information, see also "Cyberattacks aimed at us or third parties, as well as any noncompliance by us with applicable laws and regulations governing cybersecurity and/or data privacy, could materially adversely affect us." under Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.
OSHA Regulation.
U.S. Department of Labor’s Occupational Safety and Health Administration (OSHA) is focusing on hazards posed to workers by extreme heat. The Biden Administration has indicated that it considers heat-related illnesses to be a growing hazard because of climate change, has identified this area of policy as a priority for the Administration because of its disproportionate impact on communities of color. To combat this hazard, on September 1, 2021, OSHA implemented an enforcement initiative prioritizing inspections of work activities when the heat index exceeds 80 degrees Fahrenheit. OSHA is also developing a National Emphasis Program for heat inspections and, on October 27, 2021, OSHA issued an Advanced Notice of Proposed Rulemaking on heat injury and illness prevention in outdoor and indoor work settings. This notice signals OSHA’s intent to issue a rule requiring employers to take certain precautions to avoid heat-related illnesses amongst their employees. These programs will not likely impact the Company’s remote employees, but could result in increased inspections and fines at the Company’s outdoor worksites.
Employee Health and Safety. As noted above, the Company is subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community "right-to-know" regulations and comparable state laws and regulations require that information be maintained concerning hazardous materials used or produced in the Company's operations and that this information be provided to employees, state and local government authorities and citizens.
Environmental Matters
General. The Company's operations are subject to stringent federal, state and local laws and regulations relating to the protection of the environment, which may have the following effects on the Company:
•requiring that the Company obtains various permits to conduct regulated activities;
•requiring the installation of pollution-control equipment or otherwise regulating the way the Company can handle or dispose of its wastes;
•limiting or prohibiting construction activities in sensitive areas, such as wetlands, water sources, or areas inhabited by endangered or threatened species; and
•requiring investigatory and remedial actions to mitigate or eliminate pollution conditions caused by the Company's operations or attributable to former operations.
In addition, the Company's operations and construction activities may be subject to county and local ordinances that restrict the time, place or manner in which those operations and activities may be conducted.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations and the issuance of orders enjoining future operations or imposing additional compliance requirements. Also, certain environmental statutes impose strict, and in some cases joint and several, liability for the cleanup and restoration of sites where hydrocarbons or wastes have been disposed or otherwise released regardless of the fault of the current site owner or operator. Consequently, the Company may be subject to environmental liability at its currently owned or operated facilities for conditions caused by others prior to the Company's involvement.
The Company has implemented programs and policies designed to keep its pipelines and other facilities in compliance with existing environmental laws and regulations, and the Company does not believe that the cost of its compliance with such legal requirements will have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to pay dividends to its shareholders. Nonetheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and it is generally expected that such trend will likely increase under the Biden Administration. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be significantly in excess of the amounts the Company currently anticipates. For example, the Biden Administration has announced that it will be reviewing the National Ambient Air Quality Standards (NAAQS) for ozone and may make these standards more stringent. This could result in the areas in which the Company operates being designated as nonattainment areas. States that contain any areas designated as nonattainment areas will be required to develop implementation plans demonstrating how the areas will attain the applicable standard within a prescribed period of time. These plans may require the installation of additional equipment to control emissions. The EPA did not make the ozone NAAQS more stringent when it reviewed them in 2020, but the Biden Administration has indicated that it will reconsider that decision. In addition, in November 2021, the EPA issued a proposed rule that would make more stringent the
volatile organic compound (VOC) and methane emissions limits on certain new and modified equipment in the oil and gas source category, including certain types of compressors and pneumatic pumps. The proposed rule would also extend these requirements to existing sources for the first time. Some states are also enacting methane reduction programs. For example, Pennsylvania has a methane reduction framework for the oil and gas industry that will result in an existing source VOC regulation with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines.
Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of the Company's equipment, result in longer permitting timelines, and significantly increase the Company's capital expenditures and operating costs, which could adversely affect the Company's business. The Company continuously attempts to anticipate future regulatory requirements that might be imposed and works to remain in compliance with changing environmental laws and regulations.
Additionally, on January 20, 2021, President Biden signed an executive order on "Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis," under which President Biden directed the heads of all federal agencies to review "all existing regulations, orders, guidance documents, policies, and any other similar agency actions (agency actions) promulgated, issued, or adopted" during the Trump Administration for consistency with the policies established in the Biden Administration order. Regulatory actions resulting from this review could adversely affect the Company’s business and results of operations, including by requiring additional capital expenditures and increasing operating costs.
The following is a discussion of several of the material environmental laws and regulations, as amended from time to time, that relate to the Company's business.
Hazardous Substances and Waste. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include current and prior owners or operators of the site where a release of hazardous substances occurred and companies that transported, disposed or arranged for the transportation or disposal of the hazardous substances found at the site. Under CERCLA, these "responsible persons" may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties, to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. The Company generates materials in the course of its ordinary operations that are regulated as "hazardous substances" under CERCLA or similar state laws. The Company may be jointly and severally liable under CERCLA, or such laws, for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
In the ordinary course of the Company's operations, the Company generates wastes constituting solid wastes, and in some instances hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act (RCRA) and comparable state statutes. While the RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. While certain petroleum production wastes are excluded from RCRA's hazardous waste regulations, it is possible that these wastes will in the future be designated as "hazardous wastes" and be subject to more rigorous and costly disposal requirements, which could have a material adverse effect on the Company's maintenance capital expenditures and operating expenses.
The Company owns, leases or operates properties where petroleum hydrocarbons are being or have been handled for many years. The Company has generally utilized operating and disposal practices that are standard in the industry at the time, although petroleum hydrocarbons or other wastes may have been disposed of or released on or under the properties owned, leased or operated by the Company, or on or under the other locations where these petroleum hydrocarbons and wastes have been transported for treatment or disposal. Petroleum hydrocarbons or other wastes may have been disposed or released on certain of these properties by third parties that previously operated, owned or leased these properties and whose treatment and disposal or release of petroleum hydrocarbons and other wastes were not under the Company's control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.
Air Emissions. The federal Clean Air Act and comparable state laws and regulations restrict the emission of air pollutants from various industrial sources, including the Company's compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that the Company obtain pre-approval for the construction or modification
of certain projects or facilities, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. The Company's failure to comply with these requirements could subject it to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. The Company may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining permits and approvals for air emissions.
These types of capital 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. The EPA did not make the ozone NAAQS more stringent when it reviewed them in 2020, but the Biden Administration has indicated that it will reconsider that decision. The EPA has indicated that it expects to issue a proposed rule on this reconsideration in 2023. If the ozone NAAQS are made more stringent, this could result in additional nonattainment areas being designated, which could in turn result in the Company being required to install additional pollution control equipment. Moreover, with regard to the 2015 ozone NAAQS, the EPA also released a proposed rule in February 2022 called the Good Neighbor Plan that would impose a federal implementation plan in 26 states to address air pollution from those states that is contributing to downwind nonattainment of the 2015 ozone NAAQS in other states. The rule would establish limitations on emissions of nitrogen oxides (NOx) for certain industrial stationary sources in 23 states, including states in which the Company operates. The EPA expects to finalize the Good Neighbor Plan in March 2023, which may result in the Company being required to install additional pollution control equipment.
Future compliance with these requirements may require modifications to certain of the Company's operations, including the installation of new equipment to control emissions from the Company's compressors, that could result in significant costs, including increased capital expenditures and operating costs, and could adversely affect the Company's business.
Climate Change. The Company has announced an aspiration of becoming net zero for scope 1 and 2 carbon emissions by 2050. The Company’s climate policy includes two interim emission reduction targets: (i) a 50 percent reduction of its Scope 1 and Scope 2 methane emissions by 2030; and (ii) a 50 percent reduction of its total Scope 1 and Scope 2 greenhouse gas (GHG) emissions by 2040.
Legislative and regulatory measures to address climate change and GHG emissions are in various phases of discussion or implementation and are a major focus of the Biden Administration. On January 27, 2021, President Biden signed an executive order on "Tackling the Climate Crisis at Home and Abroad." This executive order contains sweeping direction to the executive branch to address climate issues. As discussed further below, the construction of interstate natural gas transportation pipelines pursuant to the NGA requires authorization from FERC, and FERC actions are subject to review under NEPA. NEPA requires federal agencies, such as the FERC, to evaluate major federal actions having the potential to significantly affect the environment. On January 9, 2023, the White House Council on Environmental Quality published new interim guidance entitled “National Environmental Policy Act Guidance on Consideration of Greenhouse Gas Emissions and Climate Change.” Generally, the interim guidance calls for increased scrutiny of the GHG effects of proposed federal action, including requiring agencies to quantify the proposed action’s GHG emissions and relevant climate impacts. The interim guidance and increased review of the GHG impacts of federal action has the potential to significantly delay or limit, and significantly increase the cost of, development of midstream infrastructure.
The EPA regulates GHG emissions from new and modified facilities that are potential major sources of criteria pollutants under the Clean Air Act's Prevention of Significant Deterioration and Title V programs and has adopted regulations that require, among other things, preconstruction and operating permits for certain large stationary sources and the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis.
The EPA regulates methane and VOCs from the oil and gas sector through its new source performance standard program under the Clean Air Act. In May 2016, the EPA finalized rules (Subpart OOOOa) that impose methane and VOC emissions limits on certain types of new and modified compressors and pneumatic pumps. The EPA finalized amendments to some technical 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 November 2021, the EPA issued a proposed rule that proposes to do three things: (i) modify Subpart OOOOa to, among other things, increase fugitive emissions monitoring frequency; (ii) promulgate a new Subpart OOOOb that would impose more stringent requirements on new and modified oil and gas sources; and (iii) promulgate an emissions guideline (a new Subpart OOOOc) that would provide direction to the states to regulate VOC and methane emissions from existing sources in the sector for the first time. The proposed Subpart OOOOc would largely regulate existing sources in the same manner in which new and modified sources are regulated. In November 2022, the EPA issued a supplemental proposed rule that responded to comments it received on the initial proposed rule, modified and clarified some of the proposed requirements, and provided proposed regulatory text. If the proposal is finalized, the Company will be required to incur certain capital expenditures in the future for air pollution control
equipment, increased fugitive emissions monitoring, and other requirements that could result in significant costs and could adversely affect the Company's business.
In addition, in 2015, the U.S., Canada, and the U.K. participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the U.S. in April 2016, requires countries to review and "represent a progression" in their intended nationally determined contributions (which set GHG emission reduction goals) every five years beginning in 2020. The United States withdrew from the Paris Agreement in 2020; however, President Biden signed an executive order on January 20, 2021, for the United States to rejoin the Paris Agreement. The United States participated in the United Nations Conference on Climate Change in Glasgow, Scotland in November 2021 and was one of the countries entering into a Global Methane Pledge. One of the key pieces of the U.S. Methane Emissions Reduction Action Plan that was announced is the EPA’s proposed methane rules for the oil and gas sector. In April 2021, the United States announced its commitment to reduce its greenhouse gas emissions by 50 to 52 percent from 2005 levels by 2030. Depending on how this reduction is to be achieved, the Company could be required to reduce its GHG emissions, which would increase the Company’s cost of environmental compliance. The United States also participated in the November 2022 United Nations Conference on Climate Change in Sharm el-Sheikh, Egypt, but the focus of the nations was on assisting countries with a shift away from coal-fired power generation, with natural gas generation continuing and replacing coal-fired generation.
In August 2022, the Inflation Reduction Act (IRA) was enacted. Among other provisions, the IRA includes a methane fee that is imposed on certain types of facilities, including certain ones owned and/or operated by the Company. The IRA exempts from the methane fee those facilities that are subject to the EPA’s proposed methane rule, provided that the final rule results in emission reductions that are at least equivalent to those that would be achieved under the November 2021 proposed rule. At this time, the Company does not anticipate that the methane fee will have a material effect on the Company, but this could change if EPA’s final methane rule, which is expected in August 2023, is more stringent than the proposal.
The U.S. Congress, along with federal and state agencies, has also considered other measures to reduce the emissions of GHGs. Legislation or regulation that imposes a carbon tax on carbon emissions or that restricts those emissions could increase the Company's cost of environmental compliance through the Company's incurrence of increased non-income taxes or by requiring the Company to install new equipment to reduce emissions from larger facilities and/or, depending on any future legislation, purchase emission allowances. The effect of climate change legislation or regulation on the Company's business is currently uncertain. If the Company incurs additional costs to comply with such legislation or regulations, it may not be able to pass on the higher costs to its customers or recover all the costs related to complying with such requirements and any such recovery may depend on events beyond the Company's control, including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or implementing regulations. The Company's future results of operations, cash flows or financial condition could be adversely affected if such costs are not recovered through regulated rates or otherwise passed on to its customers. Additionally, the Company's producer customers may also be affected by legislation or regulation, which may, directly or indirectly, adversely impact their ability and willingness to produce natural gas and accordingly affect such producers' financial health or reduce the volumes delivered to the Company and demand for its services. Climate change and GHG legislation or regulation could delay or otherwise negatively affect efforts to obtain and maintain permits and other regulatory approvals for existing and new facilities, impose additional monitoring and reporting requirements or adversely affect demand for the natural gas the Company gathers, transports and stores. The effect on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.
See also "Our business is subject to climate change-related transitional risks (including evolving climate-focused regulation and climate change-driven trends, emphasizing financing non-fossil fuel businesses and prompting pursuit of emissions reductions, lower-carbon technologies and alternative forms of energy) and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers' development plans, and reduce demand for our products and services." under Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K for the year ended December 31, 2022.
Water Discharges. The federal Clean Water Act and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants or dredged and fill material into federal and state waters as well as waters of the United States, including adjacent wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of permits issued by the EPA, the Army Corps or an analogous state agency. In September 2015, new EPA and Army Corps rules defining the scope of the EPA's and the Army Corps' jurisdiction became effective (the 2015 Clean Water Rule), however, the 2015 Clean Water Rule was promptly challenged in courts and was enjoined by judicial action in some states. Further, in October 2019 the EPA issued a rule repealing the 2015 Clean Water Rule and recodifying the preexisting regulations. In June 2020, new EPA and Army Corps regulations narrowing the regulatory scope of the Clean Water Act became effective (the 2020 Navigable Waters Protection Rule). Like the 2015 Clean Water Rule, the 2020 Navigable Water Protection Rule was promptly challenged in courts and has been enjoined by judicial action in at least one state. On December 7, 2021, EPA and the Army Corps published a proposed rule that would reinstate the pre-2015 definition of waters of the United States, updated to reflect
recent Supreme Court decisions. On December 30, 2022, EPA and the Army Corps announced the final revised rule, which will become effective 60 days after it is published in the Federal Register. The final rule was published in the Federal Register on January 18, 2023, and is expected to take effect on March 20, 2023. Separately, in October 2022, the Supreme Court heard arguments in Sackett v. EPA, Supreme Court Docket No. 21-454, which could affect the potential reach of the Clean Water Act and regulation of waters of the United States. A decision has not been issued in that case at this time. To the extent that any future rules expand the scope of the Clean Water Act's jurisdiction, the Company could face increased costs and delays with respect to obtaining permits for activities in jurisdictional waters, including wetlands.
Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws. The Company believes that compliance with existing permits and foreseeable new permit requirements will not have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to pay dividends to its shareholders.
Nationwide Permits (NWPs) are issued by the Army Corps under the Clean Water Act and the Rivers and Harbors Act of 1899 and act as a type of general permit to minimize delays and paperwork for certain activities and discharges in federal jurisdictional waters and wetlands. NWPs are typically reviewed and reissued (or modified) every five years. One such permit, NWP 12, authorizes certain “Oil or Natural Gas Pipeline Activities” and was most recently modified and reissued in January 2021. On March 28, 2022, reportedly at the request of the Biden Administration, the Army Corps initiated an early review of NWP 12 to determine whether any future actions may be appropriate to modify NWP 12 prior to its expiration in 2026. The Army Corps solicited public and stakeholder comments through public meetings held in May 2022, but has not provided any additional updates on the status of its review. To the extent future revisions to NWP 12 modify its provisions with respect to oil and natural gas pipeline activities, the Company could face increased costs and delays with respect to obtaining permits for activities in jurisdictional waters, including wetlands.
National Environmental Policy Act. The construction of interstate natural gas transportation pipelines pursuant to the NGA requires authorization from the FERC. The FERC actions are subject to 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. On January 20, 2020, President Biden issued an Executive Order requiring a review of certain federal regulations, and in response the Council on Environmental Quality has initiated a two-phase process to review NEPA regulations. Phase 1 of that process resulted in new regulations taking effect in May 2022, partially reverting NEPA regulations to rules that were in effect at the end of the Obama administration. The proposed Phase 2 of that process will review whether broader revisions to the NEPA regulations are appropriate, but no proposed rule has been published at this time.
Endangered Species Act. The federal Endangered Species Act (ESA) restricts activities that may adversely affect endangered and threatened species or their habitats. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. The designation of previously unprotected species as being endangered or threatened, or the designation of previously unprotected areas as a critical habitat for such species, has caused and could in the future cause the Company to incur additional costs, resulted in and could in the future result in delays in construction of pipelines and facilities, or cause the Company to become subject to operating restrictions in areas where the species are known to exist. For example, the FWS continues to receive hundreds of petitions to consider listing additional species as endangered or threatened and is being regularly sued or threatened with lawsuits to address these petitions. Some of these legal actions may result in the listing of species located in areas in which the Company operates. Throughout 2020, the United States Department of Interior narrowed the ESA regulations and their applicability. These regulations have been challenged in the courts. In new regulations taking effect in August 2022, the United States Department of the Interior rescinded certain aspects of the 2020 changes to the ESA regulations. Some or all of these rules could be subject to additional rulemaking to revise or rescind the rules currently in effect.
Environmental Justice. The federal government has made advancing environmental justice a priority and has announced a number of new initiatives in the area. Some of those initiatives could have impacts on the business of oil and gas companies, although the ultimate form of the federal government’s approach to these issues is unknown and the impact to the oil and gas
industry remains uncertain. The Biden Administration announced a renewed commitment to environmental justice in a day one executive order, Executive Order 13990: Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis, and followed up that action with Executive Order 14008: Tackling the Climate Crisis at Home and Abroad, which further solidified the administration’s commitment to addressing climate change and advancing environmental justice. Since that time, numerous federal agencies have announced initiatives to prioritize environmental justice as they fulfill their missions.
On May 5, 2022, the Department of Justice (DOJ) launched a comprehensive environmental justice enforcement strategy designed to guide the Justice Department’s work and ensure use of all available tools to promote environmental justice. The strategy provides a roadmap for using DOJ’s civil and criminal enforcement authorities to advance environmental justice through prioritizing enforcement of environmental and civil rights violations in overburdened communities. On the same day, DOJ also launched the Office of Environmental Justice, which has the mission of protecting overburdened and underserved communities from the harm caused by environmental crimes, pollution and climate change. The office serves as a central hub for implementing DOJ’s comprehensive environmental justice enforcement strategy and engages with all department entities to carry out this task.
Further, on September 24, 2022, the Environmental and Protection Agency (EPA) launched the Office of Environmental Justice and External Civil Rights. In addition to providing resources and technical assistance on civil rights and environmental justice, the Office of Environmental Justice and External Civil Rights enforces federal civil rights laws, including Title VI of the Civil Rights Act of 1964, which prohibits discrimination by federal funding recipients.
In addition, the FERC increased its focus on environmental justice issues in its processes and analyses in 2022. For example, in April 2022, the FERC issued a two-year Equity Action Plan to promote equity and remove barriers that underserved communities, including environmental justice communities, face in the context of FERC’s processes and policies in five focus areas. As another example, in March 2022, FERC emphasized the importance of environmental justice considerations in its Strategic Plan for fiscal years 2022-2026.
Equitrans Midstream is aware of these changes regarding environmental justice-related policy and enforcement and is in the process of assessing whether and how they may affect the Company. Equitrans Midstream will continue to monitor new developments and actions taken by each of these offices.
States are also in the process of reexamining environmental justice law and policy. Pennsylvania’s then governor signed Executive Order 2021-07 in October 2021. The executive order permanently created an Office of Environmental Justice within the Pennsylvania Department of Environmental Protection, formally established the existent Environmental Justice Advisory Board, and created an Environmental Justice Interagency Council. On March 12, 2022, the Pennsylvania Department of Environmental Protection published for public comment a proposed update to the state’s Environmental Justice Public Participation Policy, which has been in effect since 2004. Under the proposed policy, applications for certain Department of Environmental Protection permits in environmental justice areas would be subject to specified enhanced public participation requirements, and the agency would prioritize inspections and enforcement in environmental justice areas. The public comment period closed on May 11, 2022. Finalization of the updated policy remains pending. In Virginia, the legislature enacted the Environmental Justice Act of 2020, which requires state agencies to examine the environmental justice impacts of their actions and creates a council to recommend new environmental justice policies. Ohio and West Virginia appear to be monitoring developments at the EPA and other federal agencies. Many of the key issues before the states appear to be focused on enhancing public participation in permitting and other project development-related decisions. State agencies also appear to be considering new approaches to environmental justice in permitting decisions, potentially denying permits or other authorizations on environmental justice grounds. The Company will continue to monitor state legal and regulatory developments in this area and respond as appropriate.
The majority of environmental justice litigation matters appear focused on whether state or federal agencies with permitting or other decision-making responsibility have adequately considered environmental justice issues during the decision-making process. These kinds of litigation, even if unsuccessful, present risks to the underlying project’s timeline and budget. Equitrans Midstream will continue to monitor these litigation-related developments.
Equitrans Midstream takes environmental justice issues seriously and is committed to supporting the communities in which the Company operates. In July 2022, the Company published its Environmental Justice Policy that reaffirms our commitment to providing reliable energy infrastructure in a safe and responsible manner while treating all people fairly. Additionally, one of the Company’s pillars of sustainability is stakeholder engagement, including engagement with the communities where Equitrans Midstream operates. For example, Equitrans Midstream has adopted a Stakeholder Engagement and Community Investment Policy, which emphasizes early and consistent community engagement throughout project development and operation, and it specifically prioritizes environmental justice and environmental stewardship. The Company has also adopted a
Human Rights Policy committing the Company to safeguarding dignity and respect for all people throughout the Company’s value chain, including through community engagement and the prevention of discrimination.
Seasonality
Weather affects natural gas demand for power generation and heating purposes. Peak demand for natural gas typically occurs during the winter months as a result of the heating load.
Human Capital Management
To ensure that we are well positioned to provide innovative solutions and reliable energy infrastructure services in a safe, efficient, and responsible manner and in a changing economic landscape focused on long-term, sustainable operations, the Company seeks to employ a team of highly accomplished people who are dedicated to the Company’s success and to foster an engaging workplace environment that provides for competitive pay and benefits, attractive career development opportunities, and a collaborative, respectful culture. In July 2022, in connection with reflecting on areas of increasing board focus, the Board of Directors of the Company (Board) renamed the Management Development and Compensation Committee the Human Capital and Compensation Committee and amended its charter to highlight the scope of its responsibilities beyond compensation to encompass other key factors which influence our human capital programs relevant to our workforce. This includes workplace health and wellness, talent attraction and retention, pay equity, diversity and inclusion, corporate culture initiatives and employee engagement initiatives, some of which are described below.
As of December 31, 2022, the Company had 766 employees. During 2022, the Company's overall turnover was 8% (with approximately 7% being voluntary turnover) of the total employee population.
Company Culture. The Company’s five core values of Safety, Integrity, Collaboration, Transparency, and Excellence shape its culture and identity and provide the framework for employee conduct and the Company’s relationships with its stakeholders.
The Company continues to utilize a cross-functional Culture and Inclusion Council which solicits employee feedback on ways to further enhance corporate culture. In 2022, in response to the Company’s 2021 anonymous culture survey, the Company took actions with respect to employee capability, including the creation of career ladders and training for both managers and individual contributors on having effective career conversations, and held employee meetings to discuss Company strategy. Additionally, the Company focused on enhancing internal customer service and encouraged employees to recognize and demonstrate their appreciation of their top internal customers, as well as attend learning opportunities oriented toward further developing internal customer service. The Company believes that this focus on employee development and internal customer service helps to further drive operating efficiency and promote a stronger corporate culture long-term.
Safety. Above all else, safety is the Company's main priority - this includes the safety of its employees, contractors, and communities - always. The Company is committed to maintaining a strong safety culture and continuing to identify and mitigate safety risks. The Health, Safety, Sustainability and Environmental Committee of the Board provides oversight for the Company's safety initiatives. The Company tracks numerous safety-related metrics to evaluate its safety performance and has incorporated safety metrics into the Company's annual incentive plan.
Diversity and Inclusion. The Company believes that diversity of thought and perspective and a team-based approach are essential to its continued success and is committed, through its Inclusion Program and other initiatives, to continuing to build a diverse, inclusive, respectful, and safe workplace. During 2022, the Company hosted, and more than 200 employees attended, five educational sessions on inclusion topics, including a training on disability awareness; published a process for employees to create Employee Network Groups with an affinity- or inclusion-related focus; invited employees to voluntarily participate in a self-identification survey on ethnicity, sexual orientation/gender identity/gender expression, veteran status, and disability status; launched a pilot mentor program for high potential underrepresented employees; and continued to publish an Inclusion Scorecard to capture relevant employee demographics for discussion with leadership and for all employees to review.
The Company also partners with several diverse organizations to broaden and extend its recruitment efforts, including HBCUConnect.com (Historically Black Colleges and Universities Connect), DiversityJobs.com, and GettingHired.com (representing individuals with disabilities).
Total Rewards. The Company believes its employees are critical to its success and its total rewards and benefits are structured to attract and retain a talented and engaged workforce. These benefits include comprehensive health insurance for full- and part-time employees; a robust wellness program; annual flu immunizations and paid time off for COVID-19 vaccinations; access to an Employee Assistance Program; tuition reimbursement; adoption assistance and paid new parent leave; paid time off for holidays, vacation, bereavement, jury duty, military and volunteer time; paid short- and long-term disability, life insurance, and business travel insurance; medical spending accounts for eligible retirees; competitive base salaries and an annual incentive
plan and long-term incentive opportunities; and a robust retirement plan with generous company matching and non-elective contributions. In addition, the Company offers flexible work arrangements based on job duties, which the Company believes will increasingly enable it to compete for talent on a broad geographic basis.
Talent Development. The Company believes it has a robust talent and leadership development framework. The Human Capital and Compensation Committee of the Board reviews and discusses with management the human capital management matters relevant to the Company’s work force, including talent attraction and retention. The Company provides leadership training to multiple levels of Company leaders and managers, as well as customized, executive-level assessment and development programs for senior leaders. Employees at all levels within the Company are encouraged to participate in relevant developmental opportunities through Company partnerships with external learning organizations and all employees are encouraged to complete an annual development plan.
Additional Information. The Company publishes an annual Corporate Sustainability Report (CSR), which contains the most recent available data on a variety of topics, including those discussed above under the heading "Human Capital Management." Copies of the 2022 CSR are available free of charge on the Company’s website (www.equitransmidstream.com) by selecting the "Sustainability" tab on the main page and then the "Sustainability Reporting" link. Information included in the CSR or our website is not incorporated into this Annual Report on Form 10-K.
Availability of Reports
The Company makes certain filings with the SEC, including its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through its website, www.equitransmidstream.com, as soon as reasonably practicable after they are filed with or furnished to the SEC. Reports filed with, or furnished to, the SEC are also available on the SEC's website at www.sec.gov.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
In addition to the other information contained in this Annual Report on Form 10-K, the following risk factors (and related summary) should be considered in evaluating our business and future prospects. The following discussion of risk factors, including the summary, contains forward-looking statements. The summary below is not exhaustive and is qualified by reference to the full set of risk factors set forth in this section.
The risk factors may be important for understanding any statement in this Annual Report on Form 10-K or elsewhere. The following information, including the full set of risk factors set forth in this section, should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and the financial statements and accompanying notes included in "Item 8. Financial Statements and Supplementary Data" in Part II of this Annual Report on Form 10-K. Note that additional risks not presently known to us or that are currently considered immaterial may also have a negative impact on our business and operations. If any of the events or circumstances described below actually occurs, our business, financial condition, results of operations, liquidity or ability to pay dividends could suffer and the trading price of our common stock could decline.
Because of the following factors, as well as other variables affecting our results of operations, past performance may not be a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods.
Summary of Risk Factors
The following is a summary of the most significant risks relating to our business activities that we have identified. If any of these risks actually occur, our business could be materially adversely affected. For a more complete understanding of our material risk factors, this summary should be read in conjunction with the detailed description of our risk factors which follows this section.
Risks Related to Our Operations
•We generate a substantial majority of our revenues from EQT and therefore are subject to the business and liquidity risks of EQT, and any decrease in EQT's drilling or completion activity or a greater focus of such activity on acreage not dedicated to us could adversely affect us. Various factors have affected and may further affect our ability to realize the benefits we believed associated with the EQT Global GGA at the time of its execution.
•The regulatory approval process, including judicial review, for the construction of new midstream assets is very challenging and has significantly impacted, and in the future could impact, our and the MVP Joint Venture's ability to obtain or maintain all approvals necessary to complete certain projects in a timely manner or at all or our ability to achieve the expected investment returns on the projects. Also, the prospect of federal legislation to promote energy infrastructure development, including the MVP, remains uncertain. If we do not complete organic growth projects and/or identify and complete inorganic growth opportunities, our future growth may be limited.
•Decreases or a lack of growth in production of natural gas in our areas of operation, and the lack of diversification of our assets and geographic locations, could further adversely affect us.
•We face and will continue to face opposition to and negative public perception regarding the development of our projects and the operation of our pipelines and facilities from various groups.
•Impairments of our assets, including property, plant, and equipment, intangible assets, goodwill and our equity method investment in the MVP Joint Venture, previously have reduced, and in the future could reduce, our earnings.
•Cyberattacks aimed at us and/or third parties, as well as any noncompliance by us with applicable laws and regulations governing cybersecurity and/or data privacy, could materially adversely affect us.
•Increasing scrutiny and changing stakeholder expectations for ESG matters and sustainability practices may adversely affect us.
•Our business is subject to climate change-related transitional risks and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers’ development plans, and reduce demand for our products and services.
•Our subsidiaries' significant indebtedness, and any future indebtedness, as well as the restrictions under our subsidiaries' debt agreements, could adversely affect us.
•We or our joint ventures may be unable to obtain financing on satisfactory terms and financing transactions may increase our financial leverage or cause dilution to our shareholders. A further downgrade of EQM’s credit ratings could impact our liquidity, access to capital, and costs of doing business.
•Increased competition from other companies that provide gathering, transmission and storage, and water services, or from alternative fuel or energy sources, could have a negative impact on customer throughput and the demand for our services and could limit our ability to grow.
•We are exposed to the credit risk of our counterparties in the ordinary course of our business.
•We may not be able to realize the expected investment return under certain of our existing contracts, or renew or replace expiring contracts at favorable rates, on a long-term basis or at all, and we have in the past been and may become subject to disagreements with counterparties on the interpretation of existing or future contractual terms.
•Third-party pipelines and other facilities interconnected to our pipelines and facilities may become unavailable to transport or process natural gas.
•Joint ventures that we have entered into (or may in the future enter into) might restrict our operational and corporate flexibility and divert our management’s time and our resources. We do not exercise control over our joint ventures or
joint venture partners, and it may be difficult or impossible for us to cause these joint ventures or partners to take actions that we believe would be in our or the joint venture’s best interests.
•Strategic transactions could reduce, rather than increase, our results of operations and liquidity, and adversely affect our ability to pay dividends to our shareholders.
•Expanding our business by constructing new midstream assets subjects us to risk.
•The November 2022 Rager Mountain incident required that we incur costs and expenses, and investigate and respond to the incident. Activities and investigations responsive to the incident are ongoing, and, consequently, we are incurring and in the future we expect to incur further costs and expenses.
•We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.
•Significant portions of our pipeline systems have been in service for several decades, and we are subject to numerous hazards and operational risks.
•We do not own all of the land on which our assets are located, which could disrupt our operations and future development.
•The loss or disengagement of key personnel could adversely affect our ability to execute our plans.
•Our exposure to direct commodity price risk may increase in the future.
Legal and Regulatory Risk
•Our natural gas gathering, transmission and storage services are subject to extensive regulation. Changes in or additional regulatory measures, and related litigation, could have a material adverse effect on us.
•We may incur significant costs as a result of performance of our pipeline integrity management programs and compliance with increasingly stringent safety regulations.
Risks Related to an Investment in Us
•For the taxable years prior to January 1, 2021, the tax treatment of EQM depended on its status as a partnership for U.S. federal income tax purposes. If the IRS were to treat EQM as a corporation or if EQM becomes subject to additional amounts of entity-level taxation, it would reduce the amount of cash we have available to pay dividends to our shareholders.
•We face certain risks related to the tax treatment of EQM and any potential audit adjustment to EQM's income tax returns for tax years beginning after 2017.
•Our stock price has fluctuated and may further fluctuate significantly and our shareholders’ percentage of ownership in us may be diluted in the future.
•We cannot guarantee the timing, amount or payment of dividends on our common stock.
•Anti-takeover provisions contained in our governing documents and Pennsylvania law could impair an attempt to acquire us and our exclusive forum provision in our governing documents could discourage lawsuits against us and our directors and officers.
•Equitrans Midstream Preferred Shares issued present a number of risks to current and future holders of our common stock.
Risks Related to the Separation
•We continue to face risks related to the Separation, including among others, those related to U.S. federal income taxes, contingent liabilities allocated to us following the Separation, EQT's obligations under certain Separation-related agreements and potential indemnification liabilities.
Risk Factors
Risks Related to Our Operations
We generate a substantial majority of our revenues from EQT. Therefore, we are subject to the business and liquidity risks of EQT, and any decrease in EQT's drilling or completion activity (or significant production curtailments) or a shift in such activity away from our assets could adversely affect our business and operating results. Various factors have affected and may further affect our ability to realize the benefits associated with the EQT Global GGA at the time of its execution.
Historically, we have provided EQT a substantial percentage of its natural gas gathering, transmission and water services. EQT accounted for approximately 61% of our revenues for the year ended December 31, 2022. We expect to derive a substantial majority of our revenues from EQT for the foreseeable future, primarily associated with the EQT Global GGA.
Given the scope of our business relationship with EQT, any event, whether in our areas of operations or otherwise, that adversely affects EQT’s production, financial condition, leverage, results of operations or cash flows may adversely affect us. Accordingly, we are subject to the business risks of EQT, including the following:
•prevailing and projected commodity prices, primarily natural gas and natural gas liquids (NGLs), including their effect on EQT’s hedge positions;
•natural gas price volatility or periods of low commodity prices, which may have an adverse effect on EQT’s drilling operations, revenue, profitability, future rate of growth, creditworthiness and liquidity;
•decisions of EQT’s management in respect of natural gas production, which may be influenced by corporate capital allocation strategies, regional takeaway constraints, commodity prices, or other factors;
•EQT’s ability to realize the benefits associated with its “evolved well design”;
•a reduction in or slowing of EQT’s anticipated drilling and production schedule, which would directly and adversely impact demand for our services;
•the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;
•the costs of producing natural gas, including the availability and costs of drilling rigs and crews and other equipment, including as may have been affected by inflation;
•infrastructure takeaway capacity constraints and interruptions, which have adversely affected, and if not addressed are expected to continue to adversely affect, EQT’s production decisions for acreage dedicated to or serviced by our assets;
•geologic and reservoir risks and considerations;
•risks associated with the operation of EQT’s wells and facilities, including potential environmental liabilities;
•EQT’s ability to identify future exploration, development and production opportunities based on market conditions;
•uncertainties inherent in projecting future rates of production, levels of reserves, and demand for natural gas, NGLs and oil;
•EQT’s ability to develop additional reserves that are economically recoverable, to optimize existing well production and to sustain production, including by use of large-scale, sequential, highly choreographed drilling and hydraulic fracturing, including combo and return-to-pad development;
•EQT’s ability or intention to prioritize the development of additional reserves not covered by our assets or obligations to build;
•EQT’s ability to achieve anticipated efficiencies associated with its strategic plan and execute on additional strategic transactions, if any;
•adverse effects of governmental and environmental regulation, including the availability of drilling permits, the regulation of hydraulic fracturing (including limitations in respect of engaging in hydraulic fracturing in specific areas), the potential removal of certain federal income tax deductions with respect to natural gas and oil exploration and development or additional state taxes on natural gas extraction, and changes in tax laws, and negative public
perception, whether as a result of stakeholder focus on ESG and sustainability matters or otherwise, regarding EQT’s operations;
•the loss or disengagement of key personnel and/or the effectiveness of their replacements;
•EQT’s ability to achieve its ESG and sustainability targets; and
•risks associated with cybersecurity, environmental activists and other threats.
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. A substantial reduction in the capacity subscribed or volumes transported or gathered on our systems by EQT (or sustained lack of growth in respect of such volumes) could have a material adverse effect on our business, financial condition, results of operations, liquidity and our ability to pay dividends to our shareholders.
As discussed under the heading “Decreases or a lack of growth in production of natural gas in our areas of operation, whether as a result of regional takeaway constraints, producer corporate capital allocation strategies, lower regional natural gas prices, natural well decline, and/or other factors, have adversely affected, and in the future could adversely affect, our business and operating results and reduce our cash available to pay cash dividends to our shareholders.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K, there are a number of factors that could cause EQT and other producers to elect to reduce or maintain then-current levels of drilling activity or curtail production. Any sustained reductions in development or production activity in our areas of operation, particularly from EQT, or maintenance levels of production could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Additionally, the execution of the EQT Global GGA was based upon assumptions our management believed appropriate at the time of execution, including regarding EQT’s forecasted drilling and production levels and volumes on our system, along with the then-targeted in-service date for the MVP project. Certain of such assumptions, including that regarding MVP full in-service timing, have not been realized, which has adversely affected our ability to realize the full benefits we believed associated with the EQT Global GGA at the time of its execution, including, for example, with respect to the amount of potential Henry Hub cash bonus payments realizable. If additional assumptions, including MVP full in-service timing, fail to be realized or actual results differ from those assumptions, our ability to fully achieve the benefits we believed associated with the EQT Global GGA at the time of its execution, as well as our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders, may be further adversely affected. Similarly, we may be adversely affected as gathering fee declines take effect under the EQT Global GGA, including if EQT maintains sustained flat production or decreases production, or EQT's volumetric flow rates on our systems do not meet levels we assumed at the time of executing the EQT Global GGA and during such period such gathering fee declines take effect, or as periodic gathering fee decreases take effect without MVP in-service, and such adverse effects may be material. See “EQT Global GGA” in Note 5 to the consolidated financial statements for additional information.
The regulatory approval process for the construction of new midstream assets is very challenging, has significantly increased costs and delayed then-targeted in-service dates, and decisions by regulatory and judicial authorities in pending or potential proceedings, particularly with respect to litigation in the Fourth Circuit regarding MVP, are likely to impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations necessary to complete certain projects in a timely manner or at all, or our ability to achieve the expected investment returns on the projects.
Certain of our projects require regulatory approval from federal, state and/or local authorities prior to and/or in the course of construction, including any extensions from, expansions of or additions to our and the MVP Joint Venture’s gathering, transmission and storage systems, as applicable. The approval process for certain projects has become increasingly slower and more difficult, due in part to federal, state and local concerns related to exploration and production, transmission and gathering activities and associated environmental impacts, and the increasingly negative public perception regarding the oil and gas industry, including major pipeline projects like the MVP and MVP Southgate. Further, regulatory approvals and authorizations, even when obtained, have increasingly been subject to judicial challenge by activists requesting that issued approvals and authorizations be stayed and vacated.
Accordingly, authorizations needed for our or the MVP Joint Venture’s projects, including the MVP and MVP Southgate projects, may not be granted or, if granted, such authorizations may include burdensome or expensive conditions or may later
be stayed or revoked or vacated, as has been the case with the MVP project which has been subject to repeated, significant delays and cost increases because of legal and regulatory hurdles, particularly in respect of litigation in the Fourth Circuit.
In addition, significant delays in the regulatory approval process for projects, as well as stays and losses of critical authorizations and permits, including for the MVP and MVP Southgate projects, have significantly increased costs and delayed the then-targeted in-service dates for the projects, and further such delays or issues may cause similar adverse effects. Significant delays, such as that caused by the vacatur in January and February 2022 of certain approvals for the MVP project by the Fourth Circuit, and cost increases, as well as other adverse developments and uncertainties, in turn could adversely affect our ability, and, in the case of the MVP and MVP Southgate projects, the ability for the MVP Joint Venture and its owners, including us, to achieve expected investment returns, adversely affect our willingness or ability and/or that of our joint venture partners to continue to pursue projects, and/or cause a further impairment to our equity investment in the MVP Joint Venture. The MVP and MVP Southgate projects in particular are subject to several agency actions and judicial challenges (and will likely become subject to further actions and challenges), as described in more detail in, as applicable, Part I, “Item 3. Legal Proceedings” and “Strategy” under “Developments, Market Trends and Competitive Conditions” in Part I, “Item 1. Business” of this Annual Report on Form 10-K.
There is no guarantee that the MVP Joint Venture will ultimately (or timely) receive all necessary authorizations or that such authorizations will be maintained in effect following challenge, or even after projects are placed in service. For example, as of the filing of this Annual Report on Form 10-K, MVP-related permitting matters are again before the same panel of Fourth Circuit judges has appeared, and overruled permitting agencies, in numerous prior matters relating to the MVP Joint Venture. Even if the MVP Joint Venture does succeed in resolving challenges or restoring or obtaining the necessary permits and other authorizations, this may not occur in a timely fashion and may adversely affect project costs.
We have experienced and may further experience increased opposition from activists in the form of lawsuits, intervention in regulatory proceedings and otherwise, which has been and/or may be focused on the few remaining portions of the MVP project and which have resulted in significant, adverse decisions in respect of project authorizations. Such opposition has made it increasingly difficult to complete the project and place it in service and, following any in-service, may also affect the ability to continue operating or affect extensions and/or expansions of the project. Further, such opposition and/or adverse court rulings and regulatory determinations may have the effect of increasing the timeframe on necessary agency action to address actual or perceived concerns in prior adverse court rulings, or may have the effect of increasing the risk that at a future point joint venture partners may elect not to continue to pursue or fund the project, which would, absent additional project sponsors, significantly imperil the ability to complete the project. See “We have entered into joint ventures, and may in the future enter into additional or modify existing joint ventures, that might restrict our operational and corporate flexibility and divert our management’s time and our resources. In addition, we exercise no control over joint venture partners and it may be difficult or impossible for us to cause these joint ventures or partners to take actions that we believe would be in our or the joint venture’s best interests and these joint ventures are subject to many of the same operational risks to which we are subject.” in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K. We also expect that other projects, such as the MVP Southgate, may be subject to similar heightened opposition, such as in respect of any request to the FERC to extend the June 18, 2023 construction deadline in the Certificate of Public Convenience and Necessity for the MVP Southgate project prior to such deadline (and there cannot be assurance that any such extension request would be granted or upheld on appeal). These and other challenges to our projects, particularly the MVP project, have adversely affected and could adversely affect our business (including by increasing the possibility of investor activism), financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
As described in more detail in “Strategy” under “Developments, Market Trends and Competitive Conditions” in Part I, “Item 1. Business” of this Annual Report on Form 10-K, we continue to urge the United States Congress to expeditiously pass, and for there to be enacted, federal energy infrastructure permitting reform legislation that specifically requires the completion of the MVP project. As the durability of regulatory authorizations and overall permitting process applicable to infrastructure projects continues in our view to be uncertain, as evidenced by the perceived heightened judicial review in litigation related to the MVP project in the Fourth Circuit, we believe there remains, as of the date of the filing of this Annual Report on Form 10-K, continuing significant bipartisan support for federal energy infrastructure permitting reform legislation. However, we recognize that to such date attempts to enact such legislation have failed and that differences between and within the Republican and Democratic parties continue to exist as to the scope and terms of any such reform. There is no guarantee that such legislation will be enacted, and if enacted will include requirements for the completion of the MVP project. If such legislation is not enacted, particularly in respect of the MVP project, and we experience further significant issues in obtaining or maintaining the requisite authorizations necessary under applicable law to complete the MVP project, our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders would likely be adversely and, depending on circumstances, materially affected (see for example “Our subsidiaries’ significant indebtedness, and any future indebtedness, as well as the restrictions under our subsidiaries’ debt agreements, could adversely affect our operating flexibility, business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders." and, regarding the EQT
Global GGA, “We generate a substantial majority of our revenues from EQT. Therefore, we are subject to the business and liquidity risks of EQT, and any decrease in EQT's drilling or completion activity (or significant production curtailments) or a shift in such activity away from our assets could adversely affect our business and operating results. Various factors have affected and may further affect our ability to realize the benefits we believed associated with the EQT Global GGA at the time of its execution.", in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K).
Decreases or a lack of growth in production of natural gas in our areas of operation, whether as a result of regional takeaway constraints, producer corporate capital allocation strategies, lower regional natural gas prices, natural well decline, and/or other factors, have adversely affected, and in the future could adversely affect, our business and operating results and reduce our cash available to pay cash dividends to our shareholders.
Our business is dependent on continued natural gas production and the availability and development of reserves in our areas of operation. Although natural gas prices have increased during the past two calendar years, higher natural gas prices have not caused our largest customers to materially increase their production forecasts and, even if natural gas prices remain elevated, our customers may announce in the future (as has been the case in the past) lower, flat or modest increases to production forecasts based on various factors, which could include (and have in the past included) regional takeaway capacity limitations (including without limitation the lack of completion of MVP), access to capital, investor expectations regarding free cash flow, a desire to reduce or refinance leverage or other factors. See, for example, “We generate a substantial majority of our revenues from EQT. Therefore, we are subject to the business and liquidity risks of EQT, and any decrease in EQT’s drilling or completion activity (or significant production curtailments) or a shift in such activity away from our assets could adversely affect our business and operating results. Various factors have affected and may further affect our ability to realize the benefits we believed associated with the EQT Global GGA at the time of its execution” in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K. Such decisions by our customers affect production levels and, accordingly, demand for our services and therefore our results of operations. Additionally, regional takeaway constraints, corporate capital allocation strategies or lower regional natural gas prices have caused and could cause producers to determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. Further reduction, or continued lack of growth, in the natural gas volumes supplied by our producer customers could limit our ability to grow, reduce throughput on our systems and adversely impact our business, including our ability to pay dividends to our shareholders.
Prices for natural gas and NGLs, including regional basis differentials, have previously adversely affected, and may in the future adversely affect, the timing of development of additional reserves and production that is accessible by our pipeline and storage assets, which also negatively affects our water services business, and the creditworthiness of our customers. Lower natural gas prices, particularly in the Appalachian region, have in the past caused, and may in the future cause, certain producers, including certain of our customers, to determine to take actions to slow production growth and/or maintain or reduce production, which when effected by our producer customers reduces the demand for, and usage of, our services. For instance, temporary production curtailments have previously resulted in a decrease in our volumetric-based fee revenues. An extended period of low natural gas prices and/or instability in natural gas prices in future periods, especially in the Appalachian region, or other factors could cause EQT or other producers to curtail production in the future, which could have a significant negative effect on the demand for our services, our volumetric-based fee revenue, and therefore our results of operations.
Maintaining or increasing the contracted capacity or the volume of natural gas not subject to MVCs gathered, transported and stored on our systems and cash flows associated therewith is substantially dependent on our customers continually accessing additional reserves of natural gas in or accessible to our current areas of operations. For example, while EQT has dedicated production from a substantial portion of its leased properties to us, we have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering and transmission systems or the rate at which production from a well naturally declines over time. EQT and other producers may not develop the acreage they have dedicated to us for a variety of reasons, including, among other things, the availability and cost of capital, corporate capital allocation policies, producers’ focus on generating free cash flow and/or de-levering, prevailing and projected energy prices, hedging strategies and environmental or other governmental regulations. Our ability to obtain non-dedicated sources of natural gas is affected by the level of successful drilling activity near our systems and our ability to compete for volumes from successful new wells, and most development areas in our areas of operation are already dedicated to us or one of our competitors.
In addition, the amount of natural gas reserves underlying wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. We do not obtain independent evaluations of natural gas reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves connected to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our systems are less than we anticipated based upon publicly available data provided by our producer customers, or the timeline for the development of reserves is longer than we anticipate, and we are unable to secure additional sources of natural gas, there could
be a material adverse effect on our business, results of operations, financial condition, liquidity and ability to pay dividends to our shareholders.
Impairments of our assets, including property, plant, and equipment, intangible assets, goodwill and our equity method investment in the MVP Joint Venture, previously have significantly reduced our earnings, and additional impairments could further reduce our earnings.
GAAP requires us to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing previously has resulted in, and in the future could result in, impairments of our assets, including our property, plant, and equipment, intangible assets, goodwill and/or our equity method investment in the MVP Joint Venture. If we determine that an impairment has occurred, we would be required to take an immediate noncash charge to earnings, which, if significant, could have a material adverse effect on our results of operations and financial position. See Note 3 to the consolidated financial statements for a discussion of impairments previously recognized.
There is risk we may be subject to future impairments, whether based on factors such as those described in Note 3 to the consolidated financial statements or otherwise, including if our operations or projected operating results were to further decline. Additionally, there is a significant and continuing risk that our equity investment in the MVP Joint Venture may be further impaired in the future. There are ongoing and may be future legal and regulatory matters related to the MVP project which could affect the ability to complete or operate the project, as well as legal and regulatory matters related to the MVP Southgate project that must be resolved in connection with the project. Assumptions and estimates utilized in assessing the fair value of our investment in the MVP Joint Venture may change depending on the nature or timing of resolutions to the legal and regulatory matters or based on other relevant developments. Adverse changes in circumstances relevant to the likelihood of project or expansion completion could prompt us, in future assessments, to apply a lower probability of project or expansion completion and such changes in assumptions or estimates (including probability) could have a material adverse effect on the fair value of our investment in the MVP Joint Venture and potentially result in an additional impairment, which could have a material adverse effect on our results of operations and financial position.
Further, potential macroeconomic factors, including other than temporary market fluctuations, changes in interest rates, cost increases and other unanticipated events, have required and could require that we further modify assumptions reflected in the probability-weighted scenarios of discounted future net cash flows utilized to estimate the fair value of our equity investment in the MVP Joint Venture, which could result in an other-than-temporary decline in value, resulting in an incremental impairment of that investment. While macroeconomic factors in and of themselves may not be a direct indicator of impairment, should an impairment indicator be identified in the future, macroeconomic factors such as changes in interest rates could ultimately impact the size and scope of any potential impairment. Future impairment charges could be significant and could have a material adverse impact on our financial condition and results of operations for the period in which the impairment is recorded. As of the filing of this Annual Report on Form 10-K, we cannot predict the likelihood or magnitude of any future impairment.
See Note 3 to the consolidated financial statements and “Outlook-Potential Future Impairments” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II of this Annual Report on Form 10-K for additional information.
Cyberattacks aimed at us or third parties, as well as any noncompliance by us with applicable laws and regulations governing cybersecurity and/or data privacy, could materially adversely affect us.
We have become increasingly dependent upon digital technologies, including information systems, infrastructure, and cloud applications, to conduct our business, and the maintenance of our financial and other records has long been dependent upon such technologies. We depend on both our own systems, networks, and technology as well as the systems, networks and technology of our vendors, customers and other business partners. Our increasing reliance on digital technologies puts us at greater risk for system failures, disruptions, incidents, data breaches and cyberattacks, which could significantly impair our ability to conduct our business. For instance, energy industry participants, including midstream companies, have been the victims of high-profile ransomware attacks, and we expect to continue to be targeted by cyberattacks as a critical infrastructure company.
The U.S. government has continued to issue public warnings that indicate that energy assets might be specific targets of cyberattacks, and the TSA has issued security directives (and subsequent amendments/revisions thereto) applicable to certain midstream companies, including us, requiring such companies to comply with mandatory reporting measures and undertake a number of specific cybersecurity enhancements for both IT and OT systems. For additional information regarding laws or regulations governing cybersecurity applicable to us, including the CIP and the TSA security directives, see "Regulatory Environment" and "Cybersecurity" under Part I, “Item 1. Business” of this Annual Report on Form 10-K. We have been required and may further be required to expend additional resources as a result of current or new laws, regulations, directives or
other requirements related to critical infrastructure cybersecurity. Any failure to remain in compliance with laws or regulations governing cybersecurity, including the TSA security directives, may result in penalties, fines, enforcement actions, or mandated changes in our practices, which may have a material adverse effect on our business and operations.
While we and our third-party service providers commit resources to the design, implementation and monitoring of our IT and OT systems, there is no guarantee that our cybersecurity measures will provide absolute security. Despite these measures, we may not be able to anticipate, detect or prevent all cyberattacks or incidents, particularly because the methodologies used by attackers change frequently or may not be recognized until launched, and because attackers are increasingly using tactics, techniques, and procedures designed to circumvent controls and avoid detection. In April 2022, the cybersecurity authorities of the United States, Australia, Canada, New Zealand, and the United Kingdom issued a joint cybersecurity advisory warning of the increased risks of Russian state-sponsored cyberattacks following the international response to Russia’s invasion of Ukraine. Deliberate attacks on, or unintentional events or incidents affecting, our IT and OT systems or infrastructure or the systems or infrastructure of third parties could, depending on the extent or duration of the event, materially adversely affect us, including by leading to corruption, misappropriation or loss of our proprietary and sensitive data, delays (which could be significant) in the performance of services for our customers, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, regulatory scrutiny, personal injury or death, property damage and other operational disruptions, as well as damage to our reputation, financial condition and cash flows and potential legal claims and liabilities. Like other companies in the natural gas industry, we have identified and expect to continue to identify cyberattacks and incidents on our systems, but none of the cyberattacks and incidents we have identified to the filing date of this Annual Report on Form 10-K has had a material impact on our business or operations.
Further, as cyberattacks continue to evolve and increase in sophistication and volume, we have expended, and expect to continue to expend, additional resources relating to cybersecurity, including, as applicable, to continue to modify or enhance our preventive, protective, and response measures and/or to investigate and remediate potential vulnerabilities to or consequences of cyberattacks and incidents. There can be no assurance that any preventive, protective, response, or remedial measures will address or mitigate all threats that arise.
The regulatory landscape with regard to data privacy continues to develop. New laws and regulations governing data privacy, as well as any unauthorized disclosure of personal information, may potentially increase our compliance costs. Any failure by us, a company that we acquire, or one of our technology service providers, to comply with these laws and regulations, where applicable, could adversely affect us, including by resulting in reputational harm, penalties, regulatory scrutiny, liabilities, legal claims and/or mandated changes in our business practices.
Increasing scrutiny and changing stakeholder expectations and disclosures in respect of ESG and sustainability practices may adversely impact our business and our stock price and impose additional costs or expose us to new or additional risks.
Companies across all industries are facing increasing scrutiny from stakeholders related to their ESG and sustainability practices. Investor advocacy groups, proxy advisory firms, certain institutional investors and lenders, investment funds and other influential investors and rating agencies are also increasingly focused on ESG and sustainability practices and matters and on the implications and social cost of their investments and loans. Increased focus related to ESG and sustainability matters may adversely affect our business, financial condition, results of operations, and liquidity, as well as our stock price, and expose us to new or additional risks, including as described below.
Increased focus on ESG and sustainability matters, particularly with respect to climate change and related demand for renewable and alternative energy, may, among other things, hinder our access to capital given our fossil fuel-based operations and/or adversely affect demand for our services. See “Our business is subject to climate change-related transitional risks (including evolving climate-focused regulation and climate change-driven trends emphasizing financing non-fossil fuel businesses and prompting pursuit of emissions reductions, lower-carbon technologies and alternative forms of energy) and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers’ development plans, and reduce demand for our products and services.” and “Increased competition from other companies that provide gathering, transmission and storage, and water services, or from alternative fuel or energy sources, could negatively impact demand for our services, which could adversely affect our financial results.” in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K. Additionally, due to an increased focus on climate change and/or environmental justice policies, particularly as it relates to the fossil fuel industry, pipeline infrastructure companies and projects, such as our MVP project, face increased legal scrutiny and execution risk, including related to litigation and enhanced and lengthier regulatory reviews by federal, state and/or environmental regulators.
We recognize that our shareholders, employees, customers, regulators, and other stakeholders expect us to continue to focus on long-term sustainable performance, including by addressing significant, relevant ESG factors, further working to prioritize sustainable energy practices, reducing our carbon footprint and promoting sustainability. We have incurred and expect to
continue to incur costs and capital expenditures in doing so, and certain of such future costs and capital expenditures could be material. For example, on March 21, 2022, the SEC released proposed rule changes that would require new climate-related disclosure in SEC filings, including certain climate-related metrics and greenhouse gas emissions, information about climate-related targets and goals, transition plans, if any, and extensive attestation requirements. In addition to requiring filers to quantify and disclose direct emissions data, the new rules would also require disclosure of climate impact arising from the operations and uses by the filer’s business partners and contractors and end-users of the filer’s products and/or services. If adopted as proposed, the rule changes would cause us to incur additional compliance and reporting costs, certain of which could be material, including related to monitoring, collecting, analyzing and reporting new metrics and implementing systems and procuring additional internal and external personnel with the requisite skills and expertise to serve those functions and provide necessary attestation, as applicable. Such costs may adversely affect our future business, financial condition, results of operations, and liquidity.
Further, if we do not adapt to or comply with investor or other stakeholder expectations and standards, which are evolving, or if we are perceived not to have responded appropriately or quickly enough to growing concern for ESG and sustainability issues, our business could suffer, including from reputational damage (and negative public perception regarding us or our industry may lead to additional regulatory scrutiny or other adverse developments). We have disclosed aspirational goals, targets, cost estimates and other expectations and assumptions related to reducing our carbon footprint and promoting sustainability that are necessarily uncertain due to, among other things, long implementation timelines, and thus may not be realized. Failure to realize (or timely achieve progress on) such aspirational goals, targets, cost estimates, and other expectations or assumptions may adversely impact us. Our disclosures regarding aspirational goals, targets, cost estimates, and other expectations or assumptions, as applicable, could receive increased scrutiny by shareholders or regulators which may adversely impact us, including as a result of unforeseen events which may affect us.
Additionally, activist shareholders may submit proposals to promote an ESG-related position. Responding to such proposals, proxy contests and other actions by activist shareholders can be costly and time-consuming, disrupting our operations, causing reputational harm, and diverting the attention of our Board and senior management from the pursuit of business strategies. Further, a multitude of organizations that provide information to investors have developed ratings processes for evaluating companies on their approach to ESG and sustainability matters. Such ratings and reports are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings, or perceptions of us or our industry as a result of such ratings or our ESG and sustainability practices, may lead to increased negative investor and other stakeholder sentiment toward us or our customers, and to the allocation of investment capital to other industries and companies, which could negatively affect our stock price and access to and costs of capital.
The occurrence of any of the foregoing may adversely affect our business, financial condition, results of operations, liquidity and/or our stock price.
Our business is subject to climate change-related transitional risks (including evolving climate-focused regulation and climate change-driven trends emphasizing financing non-fossil fuel businesses and prompting pursuit of emissions reductions, lower-carbon technologies and alternative forms of energy) and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers’ development plans, and reduce demand for our products and services.
Combating the effects of climate change continues to attract considerable attention in the United States and internationally, including from regulators, legislators, companies in a variety of industries, financial market participants and other stakeholders. Numerous proposals have been made and will continue to be made to monitor and limit existing emissions of GHGs, as well as to restrict or eliminate future emissions. Accordingly, our business and operations, and those in our value chain, including our producer customers, are subject to executive, regulatory, political, litigation, and financial risks associated with natural gas and the emission of GHGs.
In the United States, there is no comprehensive federal regulatory statute addressing climate change, although Congress does periodically consider such measures when enacting legislation, such as in August 2022 with the passage of the Inflation Reduction Act of 2022 (IRA), which includes the largest federal investment for climate related initiatives in United States history. Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing risks and governmental actions that could have an adverse impact on our operations in the United States, including climate change related pledges made by the Biden Administration.
At the federal level, the United States has addressed climate change through legislative action, executive actions and regulatory initiatives pursuant to existing statutes. These include the enactment of the IRA, rejoining the Paris Agreement on climate change, the Biden Administration’s target for the United States to achieve a 50%-52% reduction from 2005 levels in economy-wide net GHG pollution in 2030, various executive orders, limiting land available for oil and gas leasing, the United States
Methane Emissions Reduction Action Plan, Clean Air Act rules (such as the November 2021 proposal and December 2022 supplemental proposal to regulate methane from the oil and gas sector), increased scrutiny of GHGs in NEPA analyses (including through January 2023 interim guidance released by the White House Council on Environmental Quality entitled “National Environmental Policy Act Guidance on Consideration of Greenhouse Gas Emissions and Climate Change”) and the FERC's ongoing evaluation of how to treat GHGs for purposes of its environmental and certificate reviews. Accordingly, federal GHG regulations and policies and guidance applicable to the oil and gas industry and legislation relating to climate change may be enacted in the future.
In addition, U.S. Congress, regulatory bodies, and various states have implemented or are considering programs to further restrict GHG emissions. These include market-based cap and trade or carbon pricing programs or imposition of fees or taxes based on the emission of GHGs by certain facilities.
In 2022, Pennsylvania, which is home to our headquarters and many of our assets, as well as assets of our customers, entered the Regional Greenhouse Gas Initiative (RGGI), which is a consortium of certain Northeastern and Mid-Atlantic states that set declining limits on CO2 emissions from fossil fuel plants. Pennsylvania has faced legal challenges relating to its joining the RGGI, and an injunction has delayed its enforcement in Pennsylvania until such challenges are resolved. Should Pennsylvania’s RGGI regulations become enforceable or should Pennsylvania take other measures relating to the RGGI, increased uncertainty regarding demand for natural gas used in the generation of electricity in Pennsylvania may occur. Beyond Pennsylvania, it is likely that such regional and state efforts will continue and may establish additional requirements in states in which our assets are located regardless of federal action. For example, with respect to the footprints of MVP and MVP Southgate projects, North Carolina has initiated the rule-making process to join the RGGI, passed energy-related legislation, and through executive order committed to better incorporate equity into climate solutions. Although Virginia currently is a member of RGGI, Virginia's Governor Glenn Youngkin’s administration has publicly indicated its intent to withdraw Virginia from the RGGI by the end of 2023, and has begun the process of withdrawing from RGGI and rescinding its RGGI regulations. Nationally, demand for natural gas used in the generation of electricity could also be affected by the EPA’s expected rulemaking to limit CO2 emissions from existing natural gas-fired plants. For additional information on GHG laws, regulations and other legal requirements applicable to us, see “Regulatory Environment” and “Environmental Matters” under Part I, “Item 1. Business” of this Annual Report on Form 10-K.
There remains considerable uncertainty surrounding the timing, scope and potential impact of future action in the United States and internationally with respect to GHG emissions, including methane in particular. Although we continue to monitor legislative, regulatory and judicial developments in this area to assess potential impacts on our operations and otherwise take efforts and invest funds proactively to limit and reduce GHG emissions from our facilities, we cannot predict what form future laws, regulations and legal requirements relating to climate change might take. Nor can we predict the stringency of any such requirements, when they might become effective or their exact effect on us. Further, laws, regulations and other legal requirements relating to climate change are constantly changing or being reinterpreted, and this may occur during the permitting and construction phases of our projects (which may last several years), as has been the case with our MVP and MVP Southgate projects, and may result in increased costs and delays. Generally, development and implementation of processes to comply with changing legal requirements are likely to be costly and time consuming. Laws, regulations and legal requirements designed to reduce GHG emissions also may: (i) make some of our activities, or those of our customers, uneconomic or less economically advantageous to maintain or operate, which may affect the estimated fair values of underlying assets and results of operations; (ii) reduce the number of attractive business opportunities available to us and discourage investments in our securities; (iii) impose additional compliance obligations such as new emission control requirements, taxes, fees or other costs on the release of GHGs, cause longer permitting timelines, require that we purchase allowances for emissions, expose us to regulatory penalties or affect our reputation; and (iv) adversely affect production of or demand for natural gas (such as by increasing the cost of producing natural gas, increasing the cost of producing electricity with natural gas, or prompting consumers to use renewable fuels).
If any of the foregoing events were to occur, it may have an adverse effect on our business, financial condition, results of operations, liquidity or ability to pay dividends to our shareholders. Although future laws, regulations and legal requirements relating to climate change could have a material impact on our industry and us, attempts at quantification are based on speculation of what may occur in the future which is inherently uncertain. For example, the potential cost of carbon varies in many marketplaces and online resources. Assuming the cost of carbon ranges from $1/metric ton CO2e up to $51/metric ton CO2e, which was based on the “Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide: Interim Estimates under Executive Order 13990” published by the United States Government’s Interagency Working Group on Social Cost of Greenhouse Gases in early 2021, and taking into account our estimated metric tons of carbon dioxide equivalent Scope 1 and 2 emissions for 2021, we preliminarily estimate the potential financial impact from the enactment of a carbon tax would range from approximately $2 million to approximately $98 million per year.
However, these and any other estimates we may make taking into account potential future laws, regulation or legal requirements are necessarily uncertain.
Litigation risks relating to climate change continue to increase. Parties have brought suit against certain large oil and natural gas exploration and production companies, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to climate change effects, such as rising sea levels, and therefore are responsible for resultant damages. Parties have also alleged that these companies have been aware of the adverse effects of climate change for some time but misled their investors and consumers by failing to adequately disclose those impacts. While we are not currently party to any such litigation, we or our customers could be named in future actions given that our business involves natural gas. Further, climate change-related factors may prompt governmental investigations or adversely affect the regulatory approval process for the construction and operation of midstream assets as, for example, opposition parties have cited and are likely in the future to cite our GHG emissions as a specific concern during comment periods for regulatory permit reviews.
Market forces driven by concern for climate change are also affecting (and are expected to continue to affect) the availability and cost of capital to companies in the fossil fuel sector. For example, climate change activists continue to direct their attention towards, among other things, sources of funding for fossil fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or adding more burdensome terms to or altogether eliminating their investments in, or lending with respect to, fossil fuel energy-related activities and companies. Further, such institutions are increasingly allocating funds to those industries and companies perceived as having better growth opportunities and/or stronger ESG metrics and practices. Certain financial institutions, including some that are lenders under the Amended EQM Credit Facility (as defined in Note 10), have voluntarily adopted policies that have the effect of reducing the funding provided to the fossil fuel sector, and there is also a risk that financial institutions will in the future be required to adopt such policies. These market forces may adversely affect our ability to obtain financing in the future (and thus our pursuit of initiatives, such as growth projects) or achieve increases in our stock price, and these forces may also adversely affect our customers, which could result in, among other things, increased counterparty risk and/or decreased demand for our services. Further, concern regarding climate change is increasing demand for lower carbon technologies and energy in the marketplace, which is driving innovation and investment in products that compete with natural gas. Continued momentum to develop and drive down the cost of competitive energy alternatives may adversely affect demand for natural gas and accordingly our producer customers.
In addition to such transitional risks, climate change also may create physical risks to our business. Climate impacts, such as increasing temperatures, changing weather patterns, and more frequent or intense floods and storms, can pose serious challenges for our facilities, supply chains, employees, contractors, current and potential customers, and the communities in which we operate. In particular, our operations are primarily focused in the Appalachian Basin, which is a rain-susceptible region. Severe and repeated rainfall events above and beyond historical estimates and magnitudes because of climate change could exceed the design of environmental controls in place on our construction projects, and/or cause pipeline slips or other damage to our physical assets, especially facilities located in low-lying areas near streams and riverbanks and pipelines situated in landslide-prone and rain-susceptible regions, which may adversely affect our operations. We may not be able to pass on resultant higher costs to our customers or recover all costs related to mitigating these physical risks or repairing damage due to such events. Further, our ability to mitigate the adverse impacts of these events depends in part on the resilience of our environmental controls, facilities and the effectiveness of planning for disaster preparedness and response and business continuity, which plans may not fully encompass every potential climate-driven eventuality. Additionally, changing climate patterns could impact the demand for energy in the regions we currently and plan to serve. For example, extreme warm weather in the winter months may lead to decreased natural gas usage, which may affect our results of operations and financial condition.
One or more of any such developments could have an adverse effect on our business, financial condition, results of operations, liquidity or ability to pay dividends to our shareholders.
Negative public perception regarding us, the MVP, MVP Southgate, other of our expansion projects, the midstream industry, and/or the natural gas industry in general have had and could continue to have an adverse effect on our operations and business, and negative public perception may increase the likelihood of governmental initiatives aimed at the natural gas industry.
Negative public perception regarding us, the MVP, MVP Southgate, other of our expansion projects and/or the our industry, resulting from, among other things, concerns raised by advocacy groups about climate change, oil or produced water spills, gas and other hydrocarbon leaks, the explosion or location of natural gas transmission and gathering lines and other facilities, erosion and sedimentation issues, hydraulic fracturing, environmental justice concerns and general and specific concerns relating to our pipeline and expansion projects, has led to, and may in the future lead to, increased regulatory scrutiny, which may, in turn, lead to new local, state and federal safety and environmental laws, regulations, guidelines, enforcement interpretations and/or adverse judicial rulings or regulatory actions. See the sections captioned "Regulatory Environment" and
"Environmental Matters" under Part I, "Item 1. Business" as well as Part I, “Item 3. Legal Proceedings” of this Annual Report on Form 10-K.
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 in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K under “The regulatory approval process for the construction of new midstream assets is very challenging, has significantly increased costs and delayed then-targeted in-service dates, and decisions by regulatory and judicial authorities in pending or potential proceedings, particularly with respect to litigation in the Fourth Circuit regarding the MVP, are likely to impact our or the MVP Joint Venture’s ability to obtain or maintain in effect all approvals and authorizations necessary to complete certain projects in a timely manner or at all or our ability to achieve the expected investment returns on the projects,” there are several pending challenges to certain aspects of the MVP project and the MVP Southgate project that affect the MVP project and the MVP Southgate project, as applicable. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could further cause the permits we and the MVP Joint Venture need to complete the expansion projects, including the MVP and MVP Southgate projects, and to conduct our and its respective operations to be denied, removed, withheld, delayed, stayed or burdened by requirements that restrict our and its respective abilities to profitably conduct business or make it more difficult to obtain the real property interests needed in order to operate relevant assets or complete planned growth projects, which could, among other adverse effects, affect project completion or subsequent operation, result in revenue loss or a reduction in our and the MVP Joint Venture’s customer bases.
Additionally, there have been certain initiatives at the federal, state and local levels aimed at the natural gas industry, including those to restrict the use of hydraulic fracturing as discussed in more detail in “The adoption of legislation relating to hydraulic fracturing and the enactment of new or increased severance taxes and impact fees on natural gas production could cause our current and potential customers to reduce the number of wells they drill in the Marcellus and Utica Shales or curtail production of existing wells connected to our assets. If reductions are significant for those or other reasons, the reductions could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K. Adoption of legislation or regulations (which may be prompted by negative public perception) placing restrictions on hydraulic fracturing activities or other limitations with respect to the natural gas industry could materially adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Our subsidiaries’ significant indebtedness, and any future indebtedness, as well as the restrictions under our subsidiaries’ debt agreements, could adversely affect our operating flexibility, business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Our subsidiaries have significant amounts of debt outstanding under the Amended EQM Credit Facility, the 2021 Eureka Credit Facility (as defined in Note 10) and the senior unsecured notes issued by EQM. The respective debt agreements of EQM and Eureka Midstream, LLC (Eureka), a wholly owned subsidiary of Eureka Midstream, contain various covenants and restrictive provisions that limit EQM’s and Eureka’s, as applicable, ability to, among other things: incur or guarantee additional debt, make distributions on or redeem or repurchase units, incur or permit liens on assets, enter into certain types of transactions with affiliates, enter into burdensome agreements, subject to certain specified exceptions, enter into certain mergers or acquisitions; and, dispose of all or substantially all of their respective assets.
See Note 10 to the consolidated financial statements for a discussion of the Amended EQM Credit Facility and the 2021 Eureka Credit Facility. The Amended EQM Credit Facility contains certain negative covenants, that, among other things, establish for EQM a maximum Consolidated Leverage Ratio (as defined in the Amended EQM Credit Facility) that cannot exceed 5.50 to 1.00; provided that, effective as of the MVP Mobilization Effective Date (as defined in the Amended EQM Credit Facility), the maximum Consolidated Leverage Ratio permitted with respect to the end of the fiscal quarter in which the MVP Mobilization Effective Date occurs and the end of each of the three consecutive fiscal quarters of EQM thereafter shall be 5.85 to 1.00, with the then-applicable ratio being tested as of the end of each fiscal quarter. Under the 2021 Eureka Credit Facility, Eureka is required to maintain a Consolidated Leverage Ratio (as defined in the 2021 Eureka Credit Facility) of not more than 4.75 to 1.00 (or not more than 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions). Additionally, as of the end of any fiscal quarter, Eureka may not permit the ratio of Consolidated EBITDA (as defined in the 2021 Eureka Credit Facility) for the four fiscal quarters then ending to Consolidated Interest Charges (as defined in the 2021 Eureka Credit Facility) to be less than 2.50 to 1.00. EQM’s and Eureka’s ability to meet these covenants can be affected by events beyond their respective control and we cannot assure our shareholders that EQM or Eureka will continue to meet these covenants. In particular, delays in the full in-service of the MVP project may, depending on then-current circumstances and delay duration, unless mitigating actions are available and if necessary are taken by management, adversely affect EQM’s
ability to meet its leverage ratio requirement. In addition, the Amended EQM Credit Facility and the 2021 Eureka Credit Facility each contain certain events of default, including the occurrence of a change of control.
The provisions of the debt agreements may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of these debt agreements could result in an event of default, which could enable creditors to, subject to the terms and conditions of the applicable agreement, declare any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of the debt is accelerated, our assets may be insufficient to repay such debt in full, and in turn our shareholders could experience a partial or total loss of their investments. The Amended EQM Credit Facility and the 2021 Eureka Credit Facility each contain a cross default provision that applies to a default related to any other indebtedness the applicable borrower may have with an aggregate principal amount in excess of $25 million as to EQM, and $10 million as to Eureka.
Our subsidiaries’ levels of debt could have important consequences to us, including that our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on favorable terms; our funds available for operations, future business opportunities and dividends to our shareholders may be reduced by that portion of our cash flow required to make interest payments on our or our subsidiaries’ debt; we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service our subsidiaries’ current, or our or our subsidiaries' future respective debts, will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. Further, we view de-levering our business as a critical strategic objective given that leverage levels affect the manner in which we may pursue strategic and organic initiatives, our ability to respond to market and competitive pressures, and the competition for investment capital. Our ability to de-lever and the pace thereof will depend on our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors (including particularly bringing the MVP in-service), some of which are beyond our control.
If our operating results are not sufficient to service our subsidiaries’ current, or our or our subsidiaries' future indebtedness, as applicable, or our operating results affect our ability to comply with covenants in our debt agreements, we will be forced to take actions such as seeking modifications to the terms of our debt agreements, including pledging assets as collateral, reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to timely effect any of these actions on satisfactory terms or at all. Further, if our operating results are not sufficient to enable de-levering or affect the pace of de-levering, the manner in which we may pursue strategic and organic initiatives, address market and competitive pressures, and compete for investment capital may be adversely affected, absent additional actions to de-lever, which may not be available to us on satisfactory terms or at all.
Our subsidiaries’ current substantial indebtedness and the additional debt we and/or our subsidiaries will incur in the future for, among other things, working capital, repayment of existing indebtedness, capital expenditures, capital contributions to the MVP Joint Venture, acquisitions or operating activities may adversely affect our liquidity and therefore our ability to pay dividends to our shareholders.
In addition, our subsidiaries’ significant indebtedness may be viewed negatively by credit rating agencies, which could cause our subsidiaries’ respective access to the capital markets to become more challenging. Any future additional downgrade of the debt issued by EQM could increase our capital costs or adversely affect our operating flexibility or ability to raise capital in the future. See “A further downgrade of EQM’s credit ratings, which are determined by independent third parties, could impact our liquidity, access to capital, and costs of doing business.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K.
Additionally, our ability to obtain financing in the future may be adversely affected by market forces driven by concern for climate change. See “Our business is subject to climate change-related transitional risks (including evolving climate-focused regulation and climate change-driven trends emphasizing financing non-fossil fuel businesses and prompting pursuit of emissions reductions, lower-carbon technologies and alternative forms of energy) and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers’ development plans, and reduce demand for our products and services.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K.
If we, our subsidiaries or our joint ventures are unable to obtain needed capital or financing on satisfactory terms, our ability to execute our business strategy and pay dividends to our shareholders may be diminished. Additionally, financing transactions may increase our financial leverage or could cause dilution to our shareholders.
In order to fund our capital expenditures and capital contributions so to grow and maintain our asset base and complete expansion projects, including the MVP and MVP Southgate projects, as well as to fund potential strategic transactions, if any, we may use cash from our operations, incur borrowings under our subsidiaries’ credit facilities or through debt capital market transactions, enter into new credit arrangements or sell additional shares of our equity or a portion of our assets. Using cash from operations will reduce the cash we have available to pay dividends to our shareholders. Our subsidiaries’ ability to obtain or maintain bank financing or to access the capital markets for debt offerings, or our ability to access the capital markets for future equity offerings, may be limited by, among other things, our subsidiaries’ financial condition at the time of any such financing or offering, our subsidiaries’ credit ratings, as applicable, the covenants in our subsidiaries’ debt agreements, the rights and preferences governing the Equitrans Midstream Preferred Shares, the status of the MVP project, general economic conditions, market conditions in our industry, changes in law (including tax laws), and other contingencies and uncertainties that are beyond our control. Additionally, market forces are affecting (and are expected to continue to affect) the availability and cost of capital to companies in the fossil fuel sector. See “Our business is subject to climate change-related transitional risks (including evolving climate-focused regulation and climate change-driven trends emphasizing financing non-fossil fuel businesses and prompting pursuit of emissions reductions, lower-carbon technologies and alternative forms of energy) and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers’ development plans, and reduce demand for our products and services.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K.
Even if we or our subsidiaries are successful in obtaining funds through debt or equity financings, as applicable, the terms thereof could limit our ability to pay dividends to our shareholders and otherwise adversely affect us, such as by requiring additional or more restrictive covenants that impose operating and financial restrictions or, in the case of debt, requiring that collateral be posted to secure such debt. In addition, incurring additional debt may significantly increase our interest expense and financial leverage thereby limiting our ability to further borrow, and issuing additional equity may result in significant common shareholder dilution and increase the aggregate amount of cash required to maintain the then-current dividend rates, which could materially decrease our ability to pay dividends at the then-current dividend rates. If funding is not available to us or our subsidiaries or joint ventures when needed, or is available only on unfavorable terms, we may be unable to execute our business plans, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which (or actions taken to attempt to address any such funding issue) could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. For example, our strategic plans reflect the potential to incur debt at the MVP Joint Venture assuming the in-service of the MVP project so to enhance our ability to delever and pace thereof. The MVP Joint Venture’s ability to incur debt is subject to many of the same factors and considerations, as applied to the MVP Joint Venture, as are described for us and our subsidiaries in this risk factor, as well as joint venture considerations described under “We have entered into joint ventures, and may in the future enter into additional or modify existing joint ventures, that might restrict our operational and corporate flexibility and divert our management’s time and our resources. In addition, we exercise no control over joint venture partners and it may be difficult or impossible for us to cause these joint ventures or partners to take actions that we believe would be in our or the joint venture’s best interests and these joint ventures are subject to many of the same operational risks to which we are subject.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K, and there is no assurance that debt at the MVP Joint Venture level, or related impacts or benefits, will be realized.
A further downgrade of EQM’s credit ratings, which are determined by independent third parties, could impact our liquidity, access to capital, and costs of doing business.
As of February 21, 2023, EQM’s credit ratings were Ba3 with a stable outlook, BB- with a negative outlook and BB with a negative outlook from Moody’s, S&P and Fitch, respectively. EQM’s credit ratings have fluctuated (and may further fluctuate) depending on, among other things, EQM’s leverage, uncertainty around the full in-service date and total project cost of the MVP project and the credit profile of our customers.
EQM’s credit ratings are subject to further revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. We cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in its judgment, circumstances so warrant, including in connection with the MVP project, EQM's leverage or the creditworthiness of EQM’s customers. Credit rating agencies perform an independent analysis when assigning credit ratings. This analysis includes a number of criteria such as business composition, market and operational risks, various financial tests, ESG matters, as well as analysis of various financial metrics. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time.
If any credit rating agency further downgrades or withdraws EQM’s ratings, including for reasons relating to the MVP project (such as for delays affecting the MVP project or increases in such project’s targeted costs), EQM’s leverage or credit ratings of our customers, our subsidiaries’ respective access to the capital markets could become more challenging, borrowing costs will
likely increase, our operating flexibility may be adversely affected, EQM may be required to provide additional credit assurance (the amount of which may be substantial) in support of commercial agreements such as joint venture agreements, and the potential pool of investors and funding sources may decrease.
In order to be considered investment grade, EQM must be rated Baa3 or higher by Moody’s, BBB- or higher by S&P and BBB- or higher by Fitch. EQM’s non-investment grade credit ratings have resulted in greater borrowing costs, including under the Amended EQM Credit Facility, and increased collateral requirements, including under the MVP Joint Venture’s limited liability company agreement, than if EQM’s credit ratings were investment grade.
In addition to causing, among other impacts, higher borrowing costs and/or more restrictive terms associated with modifications to existing debt instruments, any further downgrade could also require additional or more restrictive covenants on future indebtedness that impose operating and financial restrictions on us or our subsidiaries, certain of our subsidiaries to guarantee such debt and certain other debt, and certain of our subsidiaries to provide collateral to secure such debt.
Any increase in our financing costs resulting from a credit rating downgrade, and/or more restrictive covenants or the pledging of security, could adversely affect our ability to finance future operations and limit our operating flexibility. If a credit rating downgrade and/or a resultant collateral requirement were to occur at a time when we are experiencing significant working capital requirements or otherwise lack liquidity, our business, results of operations, liquidity and ability to pay dividends to our shareholders could be adversely affected.
The lack of diversification of our assets and geographic locations could adversely affect us.
We rely exclusively on revenues generated from our gathering, transmission and storage and water systems, substantially all of which are located in the Appalachian Basin in Pennsylvania, West Virginia and Ohio. Due to our lack of diversification in assets and geographic location and continuing challenges to completing expansion projects such as the MVP and MVP Southgate, an adverse development in these businesses or our areas of operations, including adverse developments due to catastrophic events, pandemics, epidemics, weather, regulatory action, local prices, producer liquidity or production determinations, decreases in demand for natural gas from the Appalachian Basin, takeaway capacity constraints from the Appalachian Basin or increases in supply of natural gas from other natural gas or oil producing basins (such as associated gas production from the Permian Basin) could have a more significant impact on our business, financial condition, results of operations, liquidity and our ability to pay dividends than if we maintained more diverse assets and locations.
We are exposed to the credit risk of our counterparties and our credit risk management cannot completely eliminate such risk.
We are exposed to the risk of loss resulting from the nonpayment and/or nonperformance of our customers, suppliers, joint venture partners and other counterparties as further described in “Credit Risk” under Part II, “Item 7A. Quantitative and Qualitative Disclosure About Market Risk” of this Annual Report on Form 10-K. We extend credit to our customers as a normal part of our business. While we have established credit policies, including assessing the creditworthiness of our customers as permitted by our FERC-approved natural gas tariffs, and may require appropriate terms or credit support from them based on the results of such assessments, including in the form of prepayments, letters of credit, or guaranties, we may not adequately assess the creditworthiness of our existing or future customers or any other party and our credit policies cannot completely eliminate credit risk. Pursuant to 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, however, there can be no assurance that EQT will maintain sufficient credit ratings or such rating thresholds are protective against all credit risk in the case of EQT.
Periods of natural gas price declines and sustained periods of low natural gas and NGL prices, previously have had, and could in the future have, an adverse effect on the creditworthiness of our customers, including their ability to pay firm reservation fees under long-term contracts. For example, the low commodity price environment in 2019 and 2020 negatively impacted natural gas producers causing some producers significant economic stress including, in certain cases (including for a customer of the Company), to file for bankruptcy protection or to seek renegotiated contracts. We cannot predict the extent to which the businesses of our counterparties would be impacted if commodity prices decline, commodity prices are depressed for a sustained period of time, or other conditions in the energy industry were to deteriorate, nor can we estimate the impact such conditions would have on the abilities of our customers to perform under their gathering, transmission and storage and water services agreements with us. To the extent one or more of our counterparties is in financial distress or commences bankruptcy proceedings, contracts with these counterparties may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code (Bankruptcy Code). Nonpayment and/or nonperformance by our counterparties and/or any unfavorable renegotiation or rejection of contracts under the Bankruptcy Code could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Our future growth may be limited if we do not complete organic growth projects and/or identify and complete suitable acquisitions and other strategic transactions and realize anticipated benefits therefrom, and we face and will continue to face staunch and protracted opposition to the development of our projects and the operation of our pipelines and facilities from various groups, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Our ability to grow organically depends primarily upon our ability to complete organic growth projects, such as the MVP and MVP Southgate projects (and related expansions thereof). Certain of our in-flight projects have been delayed and we may be unable to complete successful, accretive in-flight or future expansion projects for many reasons, including, but not limited to, the following:
•an inability to identify attractive organic growth projects;
•an inability to obtain and/or maintain necessary rights-of-way, real-estate rights or permits or other government approvals, including approvals by regulatory agencies;
•an inability to successfully integrate the infrastructure we build with our existing systems;
•an inability to obtain and/or maintain sources of fresh or produced water;
•an inability to raise financing for expansion projects on economically acceptable terms;
•incorrect assumptions about volumes, revenues, costs, producer turn-in-lines and in-service timing, as well as potential growth; or
•an inability to secure or maintain adequate customer commitments to use the newly expanded facilities.
Additionally, we face and expect to continue to face staunch and protracted opposition to the development of expansion projects (such as the MVP and MVP Southgate projects) and operation of our pipelines and facilities from environmental groups, certain landowners, local, regional and national groups opposed to the natural gas industry and/or fossil fuels generally, activists and other advocates. Such opposition has taken and will likely continue to take many forms, including organized protests, attempts to block, vandalize or sabotage our development or operations, intervention in regulatory or administrative proceedings involving our assets directly or indirectly, lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business.
Any event that delays or interrupts (or continues to delay or interrupt) the completion of expansion projects, and/or revenues generated, or expected to be generated, by our operations or that causes us to make significant expenditures associated with delayed construction completion or not covered by insurance, could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
We also periodically evaluate inorganic growth opportunities, including additional interests in existing joint ventures. There is no guarantee that we will be able to identify, compete for and/or complete, suitable strategic transactions, or, in the case of any such strategic transaction, achieve synergies or other potential benefits. See also “Strategic transactions that we enter into could reduce, rather than increase, our results of operations and liquidity, and adversely affect our ability to pay dividends to our shareholders.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K.
Failure to achieve growth could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Expanding our business by constructing new midstream assets subjects us to construction, regulatory, environmental, political and legal uncertainties that are beyond our control.
Our growth strategy includes organic optimization of our existing assets and greenfield growth projects. The development and construction of pipeline infrastructure and storage facilities and the optimization of such assets involve numerous business, regulatory, environmental, political and legal uncertainties that are beyond our control, require the expenditure of significant amounts of capital and expose us to risks. Those risks include, but are not limited to: (i) the failure to meet customer contractual requirements; (ii) delays caused by landowners; (iii) delays caused by advocacy groups or activists opposed to the natural gas industry through lawsuits or intervention in regulatory proceedings; (iv) environmental hazards; (v) vandalism; (vi) adverse weather conditions; (vii) unknown or unanticipated geological conditions; (viii) difficult construction terrain, including on steep slopes; (ix) construction site access logistics; (x) the performance of third-party contractors; (xi) delays caused by evolving regulatory or legal requirements; (xii) the lack of available skilled labor, equipment and materials (or escalating costs in respect thereof, including as a result of inflation); (xiii) issues regarding availability of connecting infrastructure; and (xiv) 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 projects may not be completed on schedule, within budgeted cost, (and, in the case of the MVP, may continue to be delayed and exceed the budgeted cost), or at all. For example, public participation, including by pipeline infrastructure opponents, in the review and permitting process of projects, through litigation or otherwise, has previously introduced, and in the future can, introduce uncertainty and adversely affect project timing, completion and cost. See also “The regulatory approval process for the construction of new midstream assets is very challenging, has significantly increased costs and delayed then-targeted in-service dates, and decisions by regulatory and judicial authorities in pending or potential proceedings, particularly with respect to litigation in the Fourth Circuit regarding the MVP, are likely to impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations necessary to complete certain projects in a timely manner or at all or our ability to achieve the expected investment returns on the projects.” in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K. Further, civil protests regarding environmental justice and social issues or challenges in project permitting processes related to such issues, including proposed construction and location of infrastructure associated with fossil fuels, poses an increased risk and may lead to increased litigation, legislative and regulatory initiatives and review at federal, state, tribal and local levels of government or permitting delays that can prevent or delay the construction of such infrastructure and realization of associated revenues. Risks inherent in the construction of these types of projects, such as unanticipated geological conditions or challenging terrain in certain of our construction areas, could adversely affect project timing, completion and cost, as well as increase the risk of loss of human life, personal injuries, significant damage to property or environmental pollution.
Additionally, construction expenditures on projects generally occur over an extended period, yet we will not receive revenues from, or realize any material increases in cash flow as a result of, the relevant project until it is placed into service. Moreover, our cash flow from a project may be delayed or may not meet our expectations. Furthermore, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return. Such issues in respect of the construction of midstream assets could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
The November 2022 incident involving the venting of natural gas from a well at Equitrans, L.P.’s Rager Mountain natural gas storage facility required that we incur costs and expenses to halt such venting, and investigate and respond to the incident, including undertaking ongoing reviews of other storage assets. Activities and investigations responsive to the incident are ongoing, and, consequently, we are incurring and in the future we expect to incur further costs and expenses, whether resulting from or arising out of the incident, which could, depending on their scope and timing, materially adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
On November 6, 2022, we became aware of natural gas venting from a storage well (well 2244) at Equitrans, L.P.’s Rager Mountain natural gas storage facility, located in Cambria County, Pennsylvania. Following our receiving notification of the incident, Equitrans, L.P., engaged a leading specialty well services company, and in coordination with representatives of the PADEP and the PHMSA, worked to flood and plug well 2244, which successfully halted the venting of natural gas on November 19, 2022. Equitrans, L.P. also retained Blade Energy Partners, a leading firm involved in analyzing other storage field incidents, to conduct an independent investigation of the incident’s root cause, which investigation is ongoing. Further, we initiated a comprehensive review of all of Equitrans, L.P.’s storage wells, including wells at the Rager Mountain facility, which review of storage field asset integrity is ongoing. As a result of our preliminary review, we proactively temporarily plugged two additional storage wells at the Rager Mountain facility while we conduct additional analyses on the condition of those wells. As of the date of the filing of this Annual Report on Form 10-K, the plugged wells at the Rager Mountain facility are not being utilized for natural gas withdrawal, and injection operations at the Rager Mountain facility are not permissible. The PADEP and the PHMSA are investigating the incident and we continue to work to cooperate in such investigations. As discussed in Part I, “Item 3. Legal Proceedings” of this Annual Report on Form 10-K, the PADEP has issued a series of compliance orders and notices of violation (NOVs), aspects of which we and Equitrans, L.P., as applicable, have appealed, relating to the Rager Mountain facility and the Rager Mountain natural gas storage field incident, which orders and NOVs allege violations of Pennsylvania statutory provisions arising from the incident, including related to the venting of natural gas in the incident and the discharge into the environment of other hazardous materials in connection with the incident response, and we and Equitrans, L.P., may continue to receive NOVs from the PADEP relating to the incident. As of the filing of this Annual Report on Form 10-K, the PADEP has not specified a penalty related to the alleged violations; however, certain of the statutory provisions cited by the PADEP in certain NOVs provide for a maximum penalty of up to $25,000 per day of violation. See also Part I, “Item 3. Legal Proceedings” of this Annual Report on Form 10-K for information related to the PHMSA investigation. Based on the results of testing to estimate the total change in natural gas inventory at the Rager Mountain storage reservoir, we estimate that the Rager Mountain storage inventory was reduced by approximately 1.29 Bcf. However, as part of ongoing post-incident
response activities, we continue to evaluate whether and to what extent all of the inventory loss was due to venting or whether some was due to potential migration.
As of December 31, 2022, we have recorded estimated costs of $8.1 million in connection with the incident. This consists of amounts paid to stop the venting of natural gas in the incident and expenses incurred during 2022 in undertaking certain post-incident response activities, including the root cause analysis and storage field asset integrity review, and the remainder of which is a reserve to our consolidated balance sheets for potential penalties that ultimately could be imposed by the PADEP based on the statutory provisions cited in the PADEP compliance orders and certain NOVs. However, there can be no assurance as to the outcome of any regulatory investigation or pending or future proceeding or the scope of any penalty or other sanction which ultimately could be imposed on us by reason of the PADEP compliance orders or otherwise. Post-incident response efforts are ongoing and we are incurring and expect to continue to incur costs and expenses in relation thereto. As more information becomes available, our estimates may not be realized and are subject to change, including increases, which may be material. We acknowledge that there may be other potential costs related to or arising out of the incident that we do not currently anticipate incurring or that it cannot reasonably estimate, including regarding any potential litigation or future investigations or proceedings (or related awards, fines, penalties or costs), environmental remediation efforts, unforeseen maintenance capital expenditures on storage assets generally or beyond those currently anticipated for assets at the Rager Mountain facility, or commercial impacts, such if we were to continue not to be permitted to inject natural gas into the Rager Mountain facility during the upcoming spring 2023 natural gas injection season or if we would be required at a future point to replace all or a substantial portion of natural gas lost in the incident or otherwise address customer or reputational impacts arising out of the incident. Such costs, depending on their scope and timing, individually or in the aggregate with other costs incurred, could have a material adverse effect on our business, reputation, cash flows, financial condition and results of operations. We have notified our insurance carriers of the event at the Rager Mountain facility and are working with them to determine the extent of insurance coverage, if any. See also “We do not insure against all potential losses and could be seriously harmed by unexpected liabilities or the inability of our insurers to satisfy our claims.” in Part I, “Item 1A. Risk Factors”, Note 15 to the consolidated financial statements, Part I, “Item 3. Legal Proceedings” and Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report on Form 10-K for further information regarding the Rager Mountain natural gas storage field incident.
We are subject to numerous operational risks and hazards, as well as unforeseen interruptions.
Our business operations are subject to the inherent hazards and risks normally incidental to the gathering, transmission and storage of natural gas and performance of water services. These operating risks, some of which we have experienced and/or could experience in the future, include but are not limited to:
•aging infrastructure and mechanical or structural problems;
•security risks, including cybersecurity;
•pollution and other environmental risks;
•operator error;
•damage to pipelines, wells and storage assets, facilities, equipment, environmental controls and surrounding properties, and pipeline blockages or other operational interruptions, caused or exacerbated by natural phenomena, weather conditions, acts of sabotage, vandalism and terrorism;
•inadvertent damage from construction, vehicles, and farm and utility equipment;
•uncontrolled releases of natural gas and other hydrocarbons or of fresh, mixed or produced water, or other hazardous materials;
•leaks, migrations or losses of natural gas as a result of issues regarding pipeline and/or storage equipment or facilities and, including with respect to storage assets, as a result of undefined boundaries, geologic anomalies, natural pressure migration and wellbore migration or other factors relevant to such storage assets;
•ruptures, fires, leaks and explosions; and
•other hazards that could also result in personal injury and loss of life, pollution to the environment and suspension of operations.
Any such events, certain of which we have experienced, and any of which we may experience in the future, could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment or interruption, which
could be significant, of our operations, regulatory investigations and penalties and substantial losses to us and could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders, particularly if the event is not fully covered by insurance. See also “We do not insure against all potential losses and could be seriously harmed by unexpected liabilities or the inability of our insurers to satisfy our claims.” and “The November 2022 incident involving the venting of natural gas from a well at Equitrans, L.P.’s Rager Mountain natural gas storage facility required that we incur costs and expenses to halt such venting, and investigate and respond to the incident, including undertaking ongoing reviews of other storage assets. Activities and investigations responsive to the incident are ongoing, and, consequently, we are incurring and in the future we expect to incur further costs and expenses, whether resulting from or arising out of the incident, which could, depending on their scope and timing, materially adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.” in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K. The location of certain segments of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. Accidents or other operating risks have resulted, and in the future could result, in loss of service available to our customers. Customer impacts arising from service interruptions on segments of our systems have included and/or may include, without limitation and as applicable, curtailments, limitations on our ability to satisfy customer contractual requirements, obligations to provide reservation charge credits to customers and solicitation of our existing customers by third parties for potential new projects that would compete directly with our existing services. Such circumstances could adversely impact our ability to retain customers and, as has been the case in certain instances in the past, negatively impact our business, financial condition, results of operations, liquidity and/or ability to pay dividends to our shareholders.
Increased competition from other companies that provide gathering, transmission and storage, and water services, or from alternative fuel or energy sources, could negatively impact demand for our services, which could adversely affect our financial results.
Our ability to renew or replace existing contracts or add new contracts at rates sufficient to maintain or grow current revenues and cash flows could be adversely affected by the activities of our competitors. Our systems compete primarily with other interstate and intrastate pipelines and storage facilities in the gathering, transmission and storage of natural gas. Some of our competitors have greater financial resources and may be better positioned to compete, including if the midstream industry moves towards greater consolidation; further, some of such competitors may now, or in the future, have access to greater supplies of natural gas or water than we do. Some of these competitors may expand or construct gathering systems, transmission and storage systems and water systems that would create additional competition for the services we provide to our customers. In addition, certain of our customers, including EQT, have developed or acquired their own gathering and water infrastructure, and may acquire or develop gathering, transmission or storage or water infrastructure in the future, which could have a negative impact on the demand for our services depending on the location of such systems relative to our assets and existing contracts.
The policies of the FERC promoting competition in natural gas markets continue to have the effect of increasing the natural gas transmission and storage options for our customer base. As a result, we have experienced, and in the future could experience, “turnback” of firm capacity as existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we may have to bear the costs associated with the turned back capacity. Increased competition could reduce the volumes of natural gas transported or stored on our systems or, in cases where we do not have long-term firm contracts, could force us to lower our transmission or storage rates. Increased competition could also adversely affect demand for our water services.
Further, natural gas as a fuel competes with other forms of energy available to end-users, including coal, liquid fuels and, increasingly, renewable and alternative energy. Demand for and development of renewable and alternative energy is increasing as a result of concern regarding climate change. Further, the availability of renewable and alternative energy is growing, and it continues to become more cost competitive with fossil fuels, including natural gas. Continued increases, whether driven by legislation, regulation or consumer preferences, in the availability and demand for renewable and alternative energy at the expense of natural gas (or increases in the demand for other sources of energy relative to natural gas based on price and other factors) could adversely affect our producer customers and lead to a reduction in demand for our natural gas gathering, transmission and storage, and water services.
In addition, competition, including from renewable and alternative energy, could intensify the negative impact of factors that decrease demand for natural gas in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.
All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers and/or additional volumes from existing customers as we seek to maintain and expand our business, which could
have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
We may not be able to renew or replace expiring contracts at favorable rates, on a long-term basis or at all, and disagreements have occurred and may arise with contractual counterparties on the interpretation of existing or future contractual terms.
One of our exposures to market risk occurs at the time our existing contracts expire and are subject to renegotiation and renewal. As these contracts expire, we may have to negotiate extensions or renewals with existing customers or enter into new contracts with existing customers or other customers. We may be unable to do so on favorable commercial terms, if at all. Further, we also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. The extension or renewal of existing contracts and entry into new contracts depends on a number of factors beyond our control, including, but not limited to: (i) the level of existing and new competition to provide services to our markets; (ii) macroeconomic factors affecting natural gas economics for our current and potential customers; (iii) the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets; (iv) the extent to which the customers in our markets are willing to contract on a long-term basis or require capacity on our systems; and (v) the effects of federal, state or local regulations on the contracting practices of our customers and us. For more information related to contracting practices applicable to certain of our services, see “Regulatory Environment - FERC Regulation” under Part I, “Item 1. Business” of this Annual Report on Form 10-K. Additionally, disagreements may arise with contractual counterparties on the interpretation of contractual provisions, as had been the case with EQT with the Hammerhead gathering contract, including during the negotiation, for example, of contract amendments required to be entered into upon the occurrence of specified events.
Based on total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed or not yet fully in-service for which we have executed firm contracts, our firm gathering contracts and firm transmission and storage contracts had weighted average remaining terms of approximately 14 years and 12 years, respectively, as of December 31, 2022.
Any failure to extend or replace a significant portion of our existing contracts or to extend or replace our significant contracts, or extending or replacing contracts at unfavorable or lower rates or with lower or no associated firm reservation fee revenues, or other disadvantageous terms relative to the prior contract structure, or disagreements or disputes on the interpretation of existing contractual terms, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
We may not be able to increase our customer throughput and resulting revenue due to competition and other factors, which could limit our ability to grow.
Our ability to increase our customer-subscribed capacity and throughput and resulting revenue is subject to numerous factors beyond our control, including competition from third-party producers’ existing contractual obligations to competitors, the location of our assets relative to those of competitors for potential producer customers (or such producer customers’ own midstream assets), takeaway capacity constraints out of the Appalachian Basin and the extent to which we have available capacity when and where shippers require it. To the extent that we lack available capacity on our systems for volumes, or we cannot economically increase capacity, we may not be able to compete effectively with third-party systems for additional natural gas production in our areas of operation.
Our efforts to attract new customers or larger commitments from existing customers may be adversely affected by our desire to provide services pursuant to long-term firm contracts and contracts with MVCs. Our potential customers may prefer to obtain services under other forms of contractual arrangements which could require volumetric exposure or potentially direct commodity exposure, and we may not be willing to agree to such other forms of contractual arrangements.
If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport or process natural gas, our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders could be adversely affected.
We depend on third-party pipelines and other facilities that provide receipt and delivery options to and from our transmission and storage system. For example, our transmission and storage system interconnects with the following interstate pipelines: Texas Eastern, Eastern Gas Transmission, Columbia Gas Transmission, Tennessee Gas Pipeline Company, Rockies Express Pipeline LLC, National Fuel Gas Supply Corporation and ET Rover Pipeline, LLC, as well as multiple distribution companies. Similarly, our gathering systems have multiple delivery interconnects to multiple interstate pipelines. In the event that our access to such systems is impaired, the amount of natural gas that our gathering systems can gather and transport has been, and in the future would be, adversely affected, which has reduced and could, as applicable, reduce revenues from our gathering
activities as well as transmission and storage activities. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these or any other pipeline connections or facilities were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to operate efficiently and continue shipping natural gas to end markets could be restricted, as has occurred in the past. Any temporary or permanent interruption at any key pipeline interconnect or facility could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
A substantial majority of the services we provide on our transmission and storage system are subject to long-term, fixed-price “negotiated rate” contracts that are subject to limited or no adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts, we could be unable to achieve the expected investment return under such contracts, and/or our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders could be adversely affected.
It is possible that costs to perform services under “negotiated rate” contracts could exceed the negotiated rates we have agreed to with our customers. If this occurs, it could decrease the cash flow realized by our systems and, therefore, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Under FERC policy, a regulated service provider and a customer may mutually agree to a “negotiated rate,” and that contract must be filed with and accepted by the FERC. As of December 31, 2022, approximately 97% of the contracted firm transmission capacity on our system was subscribed under such “negotiated rate’’ contracts. Unless the parties to these “negotiated rate” contracts agree otherwise, the contracts generally may not be adjusted to account for increased costs that could be caused by inflation, GHG emission cost (such as carbon taxes, fees, or assessments) or other factors relating to the specific facilities being used to perform the services.
We have entered into joint ventures, and may in the future enter into additional or modify existing joint ventures, that might restrict our operational and corporate flexibility and divert our management’s time and our resources. In addition, we exercise no control over joint venture partners and it may be difficult or impossible for us to cause these joint ventures or partners to take actions that we believe would be in our or the joint venture’s best interests and these joint ventures are subject to many of the same operational risks to which we are subject.
We have entered into joint ventures to construct the MVP and MVP Southgate projects and a joint venture relating to Eureka Midstream, and may in the future enter into additional joint venture arrangements with third parties. Joint venture arrangements may restrict our operational and corporate flexibility. Joint venture arrangements and dynamics can also divert management and operating resources in a manner that is disproportionate to our ownership percentage in such ventures. Because we do not control all of the decisions of our joint ventures or joint venture partners, it may be difficult or impossible for us to cause these joint ventures or partners to take actions that we believe would be in our or the joint venture’s best interests. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing that we fund operating and/or capital expenditures, the timing and amount of which we may not control, and our joint venture partners may not act in a manner that we believe would be in our or the joint venture’s best interests, may elect not to support further pursuit of projects, and/or may not satisfy their financial obligations to the joint venture. The loss of joint venture partner support in further pursuing or funding a project may, and would in the case of the MVP project, significantly adversely affect the ability to complete the project. In addition, the 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.
Strategic transactions that we enter into could reduce, rather than increase, our results of operations and liquidity, and adversely affect our ability to pay dividends to our shareholders.
We have, and may in the future, engage in acquisitions, dispositions, and other strategic transactions. These transactions involve risks that may impact our ability to realize a benefit from the transaction, such as: (i) an inability to obtain necessary regulatory and third-party approvals; (ii) the timing of and conditions imposed upon us by regulators in connection with such approvals; (iii) failure to realize assumptions about volumes, revenues, capital expenditures and costs, including synergies and potential growth; (iv) an inability to secure or maintain adequate customer commitments to use the acquired systems or facilities; (v) an inability to successfully integrate the assets or businesses we acquire; (vi) we could be required to contribute additional capital to support acquired businesses or assets, and we may assume liabilities that were not disclosed to us, for which we are not indemnified or insured or for which our indemnity or insurance is inadequate; (vii) the diversion of management’s and employees’ attention from other business concerns in a manner that is disproportionate to the relative size and impact of, or ownership percentage in, such acquired assets or entities; and (viii) unforeseen difficulties operating a larger organization or in new geographic areas, with new joint venture partners or new business lines.
If risks such as the above are realized, or if a strategic transaction fails to be accretive over the long term to our cash generated from operations on a per share basis, it could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities or the inability of our insurers to satisfy our claims.
We are not fully insured against all risks inherent in our business, including certain environmental accidents that might occur as well as many cyber events. We do not maintain insurance in the type to cover all possible risks of loss, including “wild well” coverage or damage caused by cyberattacks. In addition, we do not maintain business interruption insurance of the types and in amounts necessary to cover all possible risks of loss, like project delays caused by pandemics, cyberattacks, environmental accident, governmental action or inaction. The occurrence of any risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
In addition to requiring in many instances that we are named as additional insureds on policies maintained by vendors such as construction contractors, we currently maintain excess liability insurance that covers our and our affiliates’ legal and contractual liabilities arising out of bodily injury, personal injury or property damage, including resulting loss of use, to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability but excludes: release of pollutants subsequent to their disposal; release of substances arising from the combustion of fuels that result in acidic deposition; and testing, monitoring, clean-up, containment, treatment or removal of pollutants from property owned, occupied by, rented to, used by or in the care, custody or control of us and our affiliates. We also maintain coverage for us and our affiliates for physical damage to assets and resulting business interruption, including, in limited circumstances, certain damage caused by cyberattacks.
Most of our insurance is subject to deductibles or self-insured retentions. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations, business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. We may not be able to maintain or obtain insurance of the types and in the amounts we desire at reasonable rates, and we have elected and may elect in the future to self-insure a portion of our asset portfolio. The insurance coverage we have obtained or may obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses. In addition, for pre-Distribution losses, we share insurance coverage with EQT, and we will remain responsible for payment of any deductible or self-insured amounts under those insurance policies. To the extent we experience a pre-Distribution loss that would be covered under EQT’s insurance policies, our ability to collect under those policies may be reduced to the extent EQT erodes the limits under those policies.
Furthermore, any insurance company that provides coverage to us may experience negative developments that could impair its ability to pay any of our claims. As a result, we could be exposed to greater losses than anticipated and may have to obtain replacement insurance, if available, at a greater cost.
Significant portions of our assets have been in service for several decades. There could be unknown events or conditions, or increased maintenance or repair expenses and downtime, associated with our assets that could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Significant portions of our transmission and storage system and FERC-regulated gathering system have been in service for several decades. The age and condition of these systems has contributed to, and could result in, adverse events, or increased maintenance or repair expenditures, and downtime associated with increased maintenance and repair activities, as applicable. Any such adverse events or any significant increase in maintenance and repair expenditures or downtime, or related loss of revenue, due to the age or condition of our systems could adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. See also, “We may incur significant costs and liabilities as a result of performance of our pipeline and storage integrity management programs and compliance with increasingly stringent safety regulation.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K.
The loss or disengagement of key personnel or other workforce problems could adversely affect our ability to execute our strategic, operational and financial plans.
Our operations are dependent upon key management, technical and professional personnel, and one or more of these individuals could leave our employment or become unavailable due to, among other things, pandemics or epidemics, natural disaster, war, act of terrorism, sustained illness or injury. The unexpected loss of the services and skills of one or more of these individuals could have a detrimental effect on us. In addition, the success of our operations depends, in part, on our ability to identify, attract, develop and retain experienced personnel. There continues to be increased competition for experienced technical and other professionals, which could increase the costs associated with identifying, attracting and retaining such personnel.
Additionally, a lack of employee engagement could lead to increased employee burnout, loss of productivity, increased propensity for errors, increased employee turnover, increased absenteeism, increased safety incidents and decreased customer satisfaction, which may in turn negatively impact our results of operations and financial condition. If we cannot identify, attract, develop, retain and engage key management, technical and professional personnel, along with other qualified employees, to support the various functions of our business, our ability to compete could be harmed.
Our exposure to direct commodity price risk may increase in the future and NYMEX Henry Hub futures prices affect the fair value, and may affect the realizability, of potential cash payments to us by EQT pursuant to the EQT Global GGA.
For the years ended December 31, 2022, 2021 and 2020, approximately 71%, 64% and 66%, respectively, of our operating revenues were generated from firm reservation fee revenues. Consequently, cash flows generated from such revenues generally had limited exposure to direct commodity price risks. Although our goal is to continue to seek to contractually minimize our exposure to direct commodity price risk in the future by executing long-term firm reservation fee, MVC and ARC contracts with new or existing customers, our efforts to obtain such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in the future that do not provide services primarily based on capacity reservation charges, MVCs, ARCs or other fixed fee arrangements and therefore may have a greater exposure to fluctuations in customer volume variability driven by commodity price risk. Our exposure to the volatility of natural gas prices, including regional basis differentials with regard to natural gas prices, and any significant increase to such exposure could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Additionally, the EQT Global GGA provides for potential cash bonus payments payable by EQT to us during the period beginning on the first day of the calendar quarter in which the MVP full in-service date occurs through the calendar quarter ending December 31, 2024 (the Henry Hub cash bonus payment provision). The fair value of the derivative asset attributable to the Henry Hub cash bonus payment provision is largely determined by estimates of the NYMEX Henry Hub natural gas forward price curve and probability-weighted assumptions regarding MVP full in-service timing, and payments are conditioned upon the quarterly average of certain Henry Hub natural gas prices exceeding certain price thresholds. The NYMEX Henry Hub future price of natural gas is a widely used benchmark for the price of natural gas in the United States. Based on the Henry Hub natural gas forward strip prices as of February 17, 2023 and the terms of the Henry Hub cash bonus payment provision, any adverse change in assumptions regarding the MVP project may further decrease the estimated fair value of the derivative asset attributable to the Henry Hub cash bonus payment provision, and such decrease may be substantial. Such changes in estimated fair value, if any, would be recognized in other income (expense), net, on our statements of consolidated comprehensive income. Depending on the future NYMEX Henry Hub prices, payments under the Henry Hub cash bonus payment provision may not be triggered even if MVP were to be placed in-service (and, even if prices are sufficient to meet necessary thresholds, payments will not be triggered if the MVP is not placed in-service in or before the quarter ending December 31, 2024), which could have an adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations and future development.
We do not own all of the land on which our pipelines, storage systems and facilities have been constructed, and we have been, and in the future could be, subject to more onerous terms, and/or increased costs or delays, in attempting (or by virtue of the need to attempt) to acquire or to maintain use rights to land. See “Item 2. Properties” in Part I of this Annual Report on Form 10-K for additional information. Although many of these rights are perpetual in nature, we occasionally obtain the rights to construct and operate our pipelines and other facilities on land owned by third parties and governmental agencies for a specific period of time or in a manner in which certain facts could give rise to the presumption of the abandonment of the pipeline or other facilities. As has been the case in the past, if we were to be unsuccessful in negotiating or renegotiating rights-of-way or easements, we might have to institute condemnation proceedings on our FERC-regulated assets, the potential for which may have a negative effect on the timing and/or terms of FERC action on a project’s certification application, or relocate our facilities for non-regulated assets. The FERC has announced a policy that would presumptively stay the effectiveness of certain future construction certificates, which may limit when we are able to exercise condemnation authority. It is possible that the U.S. Congress may amend Section 7 of the NGA to codify the FERC's presumptive stay or otherwise limit, modify, or remove the ability to utilize condemnation. A loss of rights-of-way, lease or easements or a relocation of our non-regulated assets could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. Additionally, even when we own an interest in the land on which our pipelines, storage systems and facilities have been constructed, agreements with correlative rights owners have caused us to, and in the future may require that we, relocate pipelines and facilities or shut in storage systems and facilities to facilitate the development of the correlative rights owners’ estate, or pay the correlative rights owners the lost value of their estate if they are not willing to accommodate development.
Legal and Regulatory Risk
Our natural gas gathering, transmission and storage services are subject to extensive regulation by federal, state and local regulatory authorities. Changes in or additional regulatory measures adopted by such authorities, and related litigation, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends.
Our interstate natural gas transmission and storage operations are regulated by the FERC under the NGA and the NGPA and the regulations, rules and policies promulgated under those and other statutes. Certain portions of our gathering operations are also currently regulated by the FERC in connection with our interstate transmission operations. Our FERC-regulated operations are pursuant to tariffs approved by the FERC that establish rates (other than market-based rate authority), cost recovery mechanisms and terms and conditions of service to our customers. The FERC’s authority extends to a variety of matters relevant to our operations. For additional information, see “Regulatory Environment-FERC Regulation” and “Regulatory Environment-FERC Regulation of Gathering Rates and Terms of Service” under “Item 1. Business” in Part I of this Annual Report on Form 10-K.
Pursuant to the NGA, existing interstate transmission and storage rates, terms and conditions of service, and contracts may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases, changes to terms and conditions of service and contracts proposed by a regulated interstate pipeline may be protested and such actions can be delayed and may ultimately be rejected by the FERC. We currently hold authority from the FERC to charge and collect (i) “recourse rates,” which are the maximum rates an interstate pipeline may charge for its services under its tariff, (ii) “discount rates,” which are rates below the “recourse rates” and above a minimum level, (iii) “negotiated rates,” which involve rates that may be above or below the “recourse rates,” provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement, and (iv) market-based rates for some of our storage services from which we derive a small portion of our revenues. As of December 31, 2022, approximately 97% of our contracted firm transmission capacity was subscribed by customers under negotiated rate agreements under our tariff, rather than recourse, discount or market-based rate contracts. There can be no guarantee that we will be allowed to continue to operate under such rates or rate structures for the remainder of those assets’ operating lives. Customers, the FERC or other interested stakeholders, such as state regulatory agencies, may challenge our rates offered to customers or the terms and conditions of service included in our tariffs. We do not have an agreement in place that would prohibit customers, including EQT or its affiliates, from challenging our tariffs. Any successful challenge against rates charged for our transmission and storage services could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Any changes to the FERC’s policies regarding the natural gas industry may have an impact on us, including the FERC’s approach to pro-competitive policies as it considers matters such as interstate pipeline rates and rules and policies that may affect rights of access to natural gas transmission capacity and transmission and storage facilities. The FERC and Congress may continue to evaluate changes in the NGA or new or modified FERC regulations or policies that may impact our operations and affect our ability to construct new facilities and the timing and cost of such new facilities, as well as the rates we charge our customers and the services we provide.
Our and the MVP Joint Venture’s significant construction projects generally require review by multiple governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any agency’s delay in the issuance of, or refusal to issue, authorizations or permits, issuance of such authorizations or permits with unanticipated conditions, or the loss of a previously-issued authorization or permit, for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate (as has been the case with our MVP project). Such delays, refusals or resulting modifications to projects could materially and negatively impact the revenues and costs expected from these projects or cause us to abandon planned projects. For example, see “Developments, Market Trends and Competitive Conditions” under “Item 1. Business” and “Item 3. Legal Proceedings” in Part I of this Annual Report on Form 10-K for a discussion of certain such regulatory matters relevant to the MVP and the MVP Southgate projects.
Failure to comply with applicable provisions of the NGA, the NGPA, federal pipeline safety laws and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties. For example, the FERC is authorized to impose civil penalties of up to approximately $1.3 million (adjusted periodically for inflation) per violation, per day for violations of the NGA, the NGPA or the rules, regulations, restrictions, conditions and orders promulgated under those statutes.
In addition, future federal, state or local legislation or regulations under which we will operate our natural gas gathering, transmission and storage businesses may have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
We are subject to stringent environmental and other laws and regulations that expose us to significant costs and liabilities that could exceed our expectations and affect our business. The current laws and regulations affecting our business are subject to change and in the future we may be subject to additional or revised laws, regulations and legal requirements, that could adversely impact our business.
Our operations are regulated extensively at the federal, state and local levels. For additional information on laws, regulations and other legal requirements applicable to us, see “Regulatory Environment” under “Item 1. Business” in Part I of this Annual Report on Form 10-K. Laws, regulations and other legal requirements applicable to our business, including relating to the environmental protection, health and safety, cybersecurity, as well as climate change, have, among other things, increased, and in the future could continue to increase, our cost of compliance and doing business, including costs related to planning, designing, permitting, constructing, installing, operating, updating and/or abandoning gathering, transmission and water systems and pipelines, as well as storage systems. The need to comply with such laws, regulations and other legal requirements, and incidents of noncompliance, whether by us or third parties with whom we engage, has adversely affected and will likely continue to adversely affect our business, such as by, among other things and as applicable, resulting in costly delays, operating restrictions and diversion of management time and resources in evaluating the ability to pursue projects, such as when new or additional permits or alternative construction methods are required. For example, as discussed in Part I, “Item IA. Risk Factors” of this Annual Report on Form 10-K under “The regulatory approval process for the construction of new midstream assets is very challenging, has significantly increased costs and delayed then-targeted in-service dates, and decisions by regulatory and judicial authorities in pending or potential proceedings, particularly with respect to litigation in the Fourth Circuit regarding the MVP, are likely to impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations necessary to complete certain projects in a timely manner or at all or our ability to achieve the expected investment returns on the projects.”, there are several pending applications for and/or challenges to certain aspects of the MVP project and the MVP Southgate project that affect the MVP project and the MVP Southgate project, as applicable, including those litigation and regulatory-related delays discussed in “Item 3. Legal Proceedings” in Part I of this Annual Report on Form 10-K. In addition, noncompliance with applicable laws, regulations or other legal requirements, including required permits and other approvals, has subjected and could subject us to, among other things, claims for personal injuries, property damage and other damages and, even if as a result of factors beyond our control and irrespective of our fault, could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages that could materially and negatively affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders. The risk of our incurring environmental costs and liabilities in connection with our operations is significant given our handling of natural gas, produced water and other hydrocarbons, as well as air emissions related to our operations. Risk is also present as a result of historical industry operations and waste disposal practices, and our handling of waste. These matters are subject to stringent and complex federal, state and local laws and regulations governing environmental protection and could affect our business in many ways. For example, release, irrespective of fault, from one of our pipelines or storage systems, has subjected and could subject us, as applicable, to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may not be able to recover all or any of these costs from insurance. Further, we are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps to take to bring certain facilities that were acquired into compliance have been expensive. In the future, steps to bring other acquired facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
Laws, regulations and other legal requirements applicable to our business also are constantly changing, and implementation of compliant processes in response to such changes could be costly and time consuming. As an example, designations of previously unprotected species as being endangered or threatened, or the designation of previously unprotected areas as a critical habitat for such species, has adversely affected and may in the future adversely affect our assets or projects. Additionally, as discussed under “Regulatory Environment” in “Item 1. Business” in Part I of this Annual Report on Form 10-K, federal and state governments and agencies, including states where we operate, have made advancing environmental justice a priority. A significant number of current environmental justice initiatives focus on enhancing public participation in permitting and other project development-related decisions. Our projects and the MVP Joint Venture’s projects have been, and in the future may be, the target of objections to permits before state and federal agencies and related litigation brought by individuals or advocacy organizations that are purporting to raise environmental justice issues. In addition, various federal and state agencies have increased their focus on, and resources devoted to, environmental justice and certain agencies, including EPA and DOJ, have sought out opportunities to address environmental justice issues through federal and state enforcement actions. Revised or additional laws, regulations or legal requirements (or interpretations thereof) that result in increased compliance costs, litigation or additional operating restrictions, particularly if those costs are not fully recoverable from our
customers, or affect our customers’ production and operations, could have a material adverse effect on our business, financial position, results of operations, liquidity and ability to pay dividends to our shareholders.
For information related to risks associated with laws and regulations concerning climate change, see “Our business is subject to climate change-related transitional risks (including evolving climate-focused regulation and climate change-driven trends emphasizing financing non-fossil fuel businesses and prompting pursuit of emissions reductions, lower-carbon technologies and alternative forms of energy) and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers’ development plans, and reduce demand for our products and services.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K.
We may incur significant costs and liabilities as a result of performance of our pipeline and storage integrity management programs and compliance with increasingly stringent safety regulation.
The DOT, acting through PHMSA, and certain state agencies certificated by PHMSA, have adopted regulations requiring pipeline operators to develop an integrity management program for transmission pipelines located where a leak or rupture could impact high population sensitive areas (also known as High Consequence Areas or HCAs) and newly defined Moderate Consequence Areas (MCAs), and an integrity management program for storage wells, unless the operator effectively demonstrates by a prescriptive risk assessment that these operational assets have mitigated risks that could affect these predefined areas, as applicable. The regulations require operators, including us, to perform ongoing assessments of pipeline and storage integrity; identify and characterize applicable threats to pipeline segments and storage wells that could impact population sensitive areas; confirm maximum allowable operating pressures; maintain and improve processes for data collection, integration and analysis; repair and remediate facilities as necessary; and implement preventive and mitigating actions. In addition to population sensitive areas, PHMSA has recently adopted regulations extending existing design, operational and maintenance, and reporting requirements to onshore gathering pipelines in rural areas. Finally, new PHMSA regulations require operators of certain transmission pipelines to assess their integrity management and maintenance practices, comply with enhanced corrosion control and mitigation timelines, and follow new requirements for pipeline inspections following an extreme weather event or natural disaster.
The cost and financial impact of compliance will vary and depend on factors such as the number and extent of maintenance determined to be necessary as a result of the application of our integrity management programs, and such costs and financial impact could have a material adverse effect on us. Further, our pipeline and storage integrity management programs depend in part on inspection tools and methodologies developed, maintained, enhanced and applied, and certain testing conducted, by certain third parties, many of which are widely utilized within the natural gas industry. Advances in these tools and methodologies could identify potential and/or additional integrity issues for our assets. Consequently, we may incur additional costs and expenses to remediate those newly identified or potential issues, and we may not have the ability to timely comply with applicable laws and regulations. Additionally, pipeline and storage safety laws and regulations are subject to change and failures to comply with pipeline and storage safety laws and regulations, including changes in such laws and regulations or interpretations thereof that result in more stringent or costly safety standards, could have a material adverse effect on us. For more information on the laws, regulations and risks applicable to us, including risks associated with compliance with the Mega Rule, see “Regulatory Environment- Safety and Maintenance” under “Item 1. Business” in Part I of this Annual Report on Form 10-K.
The adoption of legislation relating to hydraulic fracturing and the enactment of new or increased severance taxes and impact fees on natural gas production could cause our current and potential customers to reduce the number of wells they drill in the Marcellus and Utica Shales or curtail production of existing wells connected to our assets. If reductions are significant for those or other reasons, the reductions could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders.
Our assets are primarily located in the Marcellus Shale fairway in southwestern Pennsylvania and northern West Virginia and the Utica Shale fairway in southeastern Ohio, and a substantial majority of the production that we receive from customers is produced from wells completed using hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional resource plays like the Marcellus and Utica Shales.
The U.S. Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing, while a number of states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Some states, such as Pennsylvania, have imposed fees on the drilling of new unconventional oil and gas wells. Some states have elected, and other states could elect, to prohibit hydraulic fracturing altogether. The Biden Administration temporarily banned new leases for oil and gas drilling on federal lands in January 2021, although litigation relating to that ban is continuing. Also, certain local governments have adopted, and others may adopt, ordinances within their jurisdictions
regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Further, several federal governmental agencies, including the EPA, as well as certain states, have conducted reviews and studies on the environmental aspects of hydraulic fracturing, including with regard to a possible connection between hydraulic fracturing-related activities and the increased occurrence of seismic activity. The results of such reviews or studies have and could further spur initiatives to further regulate hydraulic fracturing.
The adoption of new laws, regulations, ordinances, or executive actions at the federal, state or local levels imposing more stringent restrictions on hydraulic fracturing could make it more difficult for our customers to complete natural gas wells, increase customers’ costs of compliance and doing business, and otherwise adversely affect the hydraulic fracturing services they perform, which could negatively impact demand for our gathering, transmission and storage, or water services.
Furthermore, the tax laws, rules and regulations that affect our customers are subject to change. For example, in Pennsylvania legislation was proposed to impose a state severance tax on the extraction of natural resources, including natural gas produced from the Marcellus and Utica Shale formations, either in replacement of or in addition to the existing state impact fee. Pennsylvania’s legislature has not thus far advanced any of the severance tax proposals; however, severance tax legislation may continue to be proposed in future legislative sessions. Any such tax increase or change could adversely impact the earnings, cash flows and financial position of our customers and cause them to reduce their drilling in the areas in which we operate, which could negatively impact demand on our gathering, transmission and storage, and water services.
Risks Related to an Investment in Us
For the taxable years prior to January 1, 2021, the tax treatment of EQM depended on its status as a partnership for U.S. federal income tax purposes, as well as it not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat EQM as a corporation or if EQM becomes subject to additional amounts of entity-level taxation for state or foreign tax purposes for any open taxable year prior to January 1, 2021, it would reduce the amount of cash we have available to pay dividends to our shareholders.
Prior to the EQM Merger, EQM was a publicly traded partnership and the anticipated after-tax economic benefit of an investment in our shares depended largely on EQM being treated as a partnership for federal income tax purposes, which requires that 90% or more of EQM’s gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Code. As a result of the EQM Merger, the requirements under Section 7704 of the Code are no longer applicable to EQM for taxable years beginning after December 31, 2020.
Despite the fact that EQM is a limited partnership under Delaware law and has not elected to be treated as a corporation for federal income tax purposes, it is possible, under certain circumstances, that the IRS could determine on audit for taxable years prior to January 1, 2021 for EQM to be treated as a corporation for federal income tax purposes. For example, EQM would be treated as a corporation if the IRS determined that less than 90% of EQM’s gross income for any such taxable year consisted of qualifying income within the meaning of Section 7704 of the Code.
If EQM was treated as a corporation for federal income tax purposes for any taxable year prior to January 1, 2021, EQM would be required to pay federal income tax on its taxable income at the corporate tax rate applicable to the relevant tax year and would likely pay state income taxes at varying rates. Distributions to us after the Separation Date would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to us. Treatment of EQM as a corporation could result in a material reduction in the anticipated cash flow in the year of the payment to the IRS, potentially causing, among other things, a substantial reduction in the value of our shares.
If the IRS makes audit adjustments to EQM’s income tax returns for tax years beginning after 2017, the IRS (and some states) may assess and collect any resulting taxes (including any applicable penalties and interest) directly from EQM, in which case we may be required, and potentially former unitholders would be required, to reimburse EQM for such payments or, if EQM is required to bear such payments, such payments could have a material adverse effect on our business, financial position, results of operations, liquidity and ability to pay dividends to our shareholders.
Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to EQM’s income tax return for tax years beginning after 2017, the IRS (and some states) may assess and collect any resulting taxes (including any applicable interest and penalties) directly from EQM. EQM will have a limited ability to shift any such tax liability to its general partner and unitholders, including us, in accordance with their interests in EQM during the year under audit, but there can be no assurance that EQM will be able to do so under all circumstances, or that EQM will be able to effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which EQM does business in the year under audit or in the adjustment year. As a result of the EQM Merger, we own all of the EQM common units. If EQM makes payments of taxes, penalties and interest resulting from audit adjustments with respect to tax periods beginning after 2017 and before 2021, we and potentially former unitholders may be required to reimburse it for such payment or, if EQM is required to bear such payments,
such payments could have a material adverse effect on our business, financial position, results of operations, liquidity and ability to pay dividends to our shareholders.
In the event the IRS makes an audit adjustment to EQM’s income tax returns and EQM does not or cannot shift the liability to its unitholders in accordance with their interests in EQM during the year under audit, EQM will generally have the ability to request that the IRS reduce the determined underpayment by reducing the suspended passive loss carryovers of EQM’s unitholders (without any compensation from EQM to such unitholders), to the extent such underpayment is attributable to a net decrease in passive activity losses allocable to certain partners. Such reduction, if approved by the IRS, will be binding on any affected unitholders.
Our stock price has fluctuated and may fluctuate significantly.
The market price of our common stock has experienced substantial price volatility in the past and may continue to do so due to a number of factors, including the MVP project, some of which may be beyond our control. General market fluctuations, industry factors, such as climate change-related physical and transitional risks, and general economic and political conditions and events, such as economic slowdowns or recessions, as well as factors specific to our business (including the status of and cost to construct the MVP project), have caused and could also continue to cause our stock price to decrease regardless of operating results. If we fail to meet expectations related to future growth, profitability, cash dividends, de-levering, strategic transactions or other market expectations, the market price of our common stock may decline significantly. Additionally, our stock price may be adversely affected by transactions in our common stock by significant shareholders. A reduced stock price affects, among other things, our cost of capital and could affect our ability to execute on future strategic transactions, as well as increases opportunities for investor activism or unsolicited third-party activity affecting us.
We cannot guarantee the timing, amount or payment of dividends on our common stock, and we may further reduce the amount of the cash dividend that we pay on our common stock or may not pay any cash dividends at all to our shareholders. Our ability to declare and pay cash dividends to our shareholders, if any, in the future will depend on various factors, many of which are beyond our control.
We are not required to declare and pay dividends to our common shareholders. Our Board previously has reduced, and in the future may decide to further reduce, the amount of the cash dividend that we pay on our common stock. Our Board may also decide not to declare any dividends in the future. Although we have in the past paid regular cash dividends, any payment of future dividends will be at the sole discretion of our Board and will depend upon many factors, including the Pennsylvania Business Corporation Law (PBCL), the financial condition, earnings, liquidity and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, our leverage, regulatory constraints and other factors deemed relevant by our Board. We 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.
Our shareholders’ percentage of ownership in us may be diluted by future issuances of stock, which could, among other things, have a dilutive effect on our earnings per share and related effects on the market price for our common stock.
Our shareholders’ percentage of ownership in us may be diluted because of equity issuances for acquisitions, capital market transactions or otherwise, including, without limitation, equity awards that we may grant to our directors, officers, and employees. Our Human Capital and Compensation Committee and our Board have authority to grant share-based awards to our employees under employee benefit plans and, from time to time, we issue share-based awards to our employees under our employee benefit plans. Such awards will have a dilutive effect on our earnings per common share, which could adversely affect the market price of our common stock. Equity issuances may have a dilutive effect on our earnings per share, which could adversely affect the market for and the market price of our stock, and have a dilutive effect on our shareholders’ ownership interests in us.
In addition, our Second Amended and Restated Articles of Incorporation authorize us to issue, without the approval of our shareholders, one or more classes or series of preferred stock that have such designations, powers, preferences and relative, participating, optional and other special rights, including preferences over our common stock respecting dividends and distributions, as our Board generally may determine. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce the value of our common stock. Similarly, the repurchase or redemption rights or liquidation preferences we could assign to holders of preferred stock could affect the residual value of our common stock.
As more fully described under “The Equitrans Midstream Preferred Shares by virtue of their terms and preferences present a number of risks to current and future holders of our common stock.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K, upon the occurrence of certain events or the passage of time, the Equitrans Midstream Preferred Shares may be converted by the holder or us, as applicable, initially on a one-for-one basis in the case of certain conversions by holders,
subject to certain anti-dilution adjustments and an adjustment for any dividends that have accrued but not been paid when due and partial period dividends. If we or a holder of the Equitrans Midstream Preferred Shares convert Equitrans Midstream Preferred Shares into common stock, the conversion will have a dilutive effect on our earnings per share of common stock, which could adversely affect the market price of our common stock.
Anti-takeover provisions contained in our Second Amended and Restated Articles of Incorporation and Fifth Amended and Restated Bylaws, as well as provisions of Pennsylvania law, could impair an attempt to acquire us and limit the opportunity for our shareholders to receive a premium for their shares of our common stock.
Our Second Amended and Restated Articles of Incorporation and Fifth Amended and Restated Bylaws contain provisions that could have the effect of rendering more difficult or discouraging an acquisition of us deemed undesirable by our Board. These include provisions:
•authorizing blank check preferred stock, which we could issue with voting, liquidation, dividend and other rights superior to those of our common stock;
•limiting the liability of, and providing indemnification to, our directors and officers;
•specifying that our shareholders may take action only at a duly called annual or special meeting of shareholders and otherwise in accordance with our bylaws and prohibiting our shareholders from calling special meetings;
•requiring advance notice of proposals by our shareholders for business to be conducted at shareholder meetings and for nominations of candidates for election to our Board; and
•controlling the procedures for conduct of our Board and shareholder meetings and election and appointment of our directors.
These provisions, alone or together, could deter or delay hostile takeovers, proxy contests and changes in control or management of us. As a Pennsylvania corporation, we are also subject to provisions of Pennsylvania law, including certain provisions of Chapter 25 of the PBCL, which, among other things, requires enhanced shareholder approval for certain transactions between us and a shareholder who is a party to the transaction or is treated differently from other shareholders and also prevents persons who become the beneficial owner of shares representing 20% or more of our voting power from engaging in certain business combinations without approval of our Board, and in some cases preventing consummation of the transaction for at least five years.
Any provision of our Second Amended and Restated Articles of Incorporation, Fifth Amended and Restated Bylaws or Pennsylvania law that has the effect of delaying or deterring a change in control of us could limit the opportunity for our shareholders to receive a premium for their shares of our common stock and also could affect the price that some investors are willing to pay for our common stock.
Our Fifth Amended and Restated Bylaws designate the state and federal courts sitting in the judicial district of the Commonwealth of Pennsylvania, County of Allegheny, as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could discourage lawsuits and limit our shareholders’ ability to obtain a perceived favorable judicial forum for disputes with us, our directors or our officers.
Our Fifth Amended and Restated Bylaws provide that, unless our Board otherwise determines, the state and federal courts sitting in the judicial district of the Commonwealth of Pennsylvania, County of Allegheny, will be the sole and exclusive forum for any derivative action or proceeding brought on behalf of us, any action asserting a claim of breach of a fiduciary duty owed by any director or officer or other employee of ours to us or our shareholders, any action asserting a claim against us or any director or officer or other employee of us arising pursuant to any provision of the PBCL or our Second Amended and Restated Articles of Incorporation and Fifth Amended and Restated Bylaws or any action asserting a claim against us or any director or officer or other employee of ours governed by the internal affairs doctrine. The choice of forum provision set forth in our Fifth Amended and Restated Bylaws does not apply to actions arising under the Securities Act or the Exchange Act.
When applicable, this exclusive forum provision may limit the ability of our shareholders to bring a claim in a judicial forum that such shareholders find favorable for disputes with us or our directors or officers, which may discourage such lawsuits against us and our directors and officers. Alternatively, if a court outside of Pennsylvania were to find this exclusive forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings described above, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, results of operations and financial condition.
The Equitrans Midstream Preferred Shares by virtue of their terms and preferences present a number of risks to current and future holders of our common stock.
Equitrans Midstream Preferred Shares present a number of risks to current and future holders of our common stock, including a preference in favor of holders of Equitrans Midstream Preferred Shares in the payment of dividends on our common stock, the risk of dilution occurring as a result of the conversion of the Equitrans Midstream Preferred Shares into our common stock and the ability of the holders of the Equitrans Midstream Preferred Shares to vote with the holders of our common stock on most matters, as well as the risk that the holders of the Equitrans Midstream Preferred Shares will have certain other class voting rights with respect to any amendment to our organizational documents that would be adverse (other than in a de minimis manner) to any of the rights, preferences or privileges of the Equitrans Midstream Preferred Shares.
We are party to a registration rights agreement with certain holders of the Equitrans Midstream Preferred Shares pursuant to which, among other things, we gave the investors certain rights to require us to file and maintain one or more registration statements with respect to the resale of the Equitrans Midstream Preferred Shares and the shares of our common stock that are issuable upon conversion of the Equitrans Midstream Preferred Shares, and which, upon request by certain investors party to the Registration Rights Agreement, will require us to initiate underwritten offerings for the Equitrans Midstream Preferred Shares and the shares of our common stock that are issuable upon conversion of the Equitrans Midstream Preferred Shares and use our best efforts to cause the Equitrans Midstream Preferred Shares to be listed on the securities exchange on which the shares of our common stock are then listed. See Note 2 to the consolidated financial statements for further information on the Equitrans Midstream Preferred Shares.
Risks Related to the Separation
If the Separation and Distribution, together with certain related transactions, does not continue to qualify as a transaction that is generally tax-free for U.S. federal income tax purposes, we, EQT, and our respective shareholders could be subject to significant tax liabilities and, in certain circumstances, we could be required to indemnify EQT for material taxes and other related amounts pursuant to indemnification obligations under the tax matters agreement.
It was a condition to the Distribution that (i) a private letter ruling from the IRS regarding the qualification of the Distribution, together with certain related transactions, as a transaction that is generally tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code and certain other U.S. federal income tax matters relating to the Separation and Distribution shall not have been revoked or modified in any material respect and (ii) EQT received an opinion of counsel with respect to certain tax matters relating to the qualification of the Distribution, together with certain related transactions, as a transaction described in Sections 355 and 368(a)(1)(D) of the Code. The IRS private letter ruling is based upon and relies on, and the opinion of counsel is based upon and relies on, among other things, various facts and assumptions, as well as certain representations, statements and undertakings of EQT and us, including those relating to the past and future conduct of EQT and us. If any of these representations, statements or undertakings is, or becomes, inaccurate or incomplete, or if any representations or covenants contained in any of the Separation-related agreements and documents or in any documents relating to any IRS private letter ruling or opinion of counsel are breached, such IRS private letter ruling and/or opinion of counsel may be invalid and the conclusions reached therein could be jeopardized.
Notwithstanding receipt of the IRS private letter ruling and opinion of counsel, the IRS could determine that the Distribution and/or certain related transactions should be treated as taxable transactions for U.S. federal income tax purposes if it determines that any of the representations, assumptions or undertakings upon which such IRS private letter ruling or the opinion of counsel was based are false or have been violated. In addition, the IRS private letter ruling does not address all of the issues that are relevant to determining whether the Distribution, together with certain related transactions, continues to qualify as a transaction that is generally tax-free for U.S. federal income tax purposes, and the opinion of counsel represented the judgment of such counsel and is not binding on the IRS or any court and the IRS or a court may disagree with the conclusions in any opinion of counsel. Accordingly, notwithstanding receipt of an IRS private letter ruling or opinion of counsel, there can be no assurance that the IRS will not assert that the Distribution and/or certain related transactions do not qualify for the intended tax treatment or that a court would not sustain such a challenge. In the event the IRS were to prevail with such challenge we, EQT, and our respective shareholders could be subject to material U.S. federal income tax liability.
Even if the Distribution otherwise qualifies as generally tax-free for U.S. federal income tax purposes under Section 355 and Section 368(a)(1)(D) of the Code, it would result in a material U.S. federal income tax liability to EQT (but not to its shareholders) under Section 355(e) of the Code if one or more persons acquire, directly or indirectly, a 50-percent or greater interest (measured by either vote or value) in EQT’s stock or in the stock of us as part of a plan or series of related transactions that includes the Distribution, and we may be required to indemnify EQT for any such liability under the tax matters agreement entered into by EQT and us in connection with the Distribution. The process for determining whether an acquisition is part of a plan under these rules is complex, inherently factual in nature and subject to a comprehensive analysis of the facts and
circumstances of the particular case. Notwithstanding the IRS private letter ruling and opinion of counsel described above, a sufficient change in ownership of EQT or our common stock may occur which could result in a material tax liability to EQT.
Under the tax matters agreement that EQT entered into with us, we may be required to indemnify EQT against any additional taxes and related amounts resulting from (i) an acquisition of all or a portion of our equity securities or assets, whether by merger or otherwise (and regardless of whether we participated in or otherwise facilitated the acquisition), (ii) other actions or failures to act by us or (iii) any of our representations, covenants or undertakings contained in any of the Separation-related agreements and documents or in any documents relating to the IRS private letter ruling or the opinion of counsel being incorrect or violated. Any such indemnity obligations could be material.
If the IRS were to successfully assert that the EQM Merger or Share Purchases resulted in the Distribution and/or certain related transactions being treated as taxable transactions to EQT for U.S. federal income tax purposes, we may be required to indemnify EQT for such taxes and related amounts.
Certain contingent liabilities allocated to us following the Separation may mature, resulting in material adverse impacts to our business.
There are several significant areas where the liabilities of EQT may become our obligations. For example, under the Code and the related rules and regulations, each corporation that was a member of the EQT consolidated U.S. federal income tax return group (EQT Tax Group) during a taxable period or portion of a taxable period ending on or before the effective date of the Distribution is jointly and severally liable for the U.S. federal income tax liability of the EQT Tax Group for that taxable period. Consequently, if EQT is unable to pay the consolidated U.S. federal income tax liability for a pre-Separation period, we could be required to pay the amount of such tax, which could be substantial and in excess of the amount allocated to us under the tax matters agreement. Other provisions of federal law establish similar liability for other matters, including laws governing tax-qualified pension plans, as well as other contingent liabilities.
Potential indemnification liabilities to or from EQT pursuant to agreements relating to the Separation and Distribution could materially and adversely affect us.
The Separation and Distribution Agreement with EQT provides for, among other things, provisions governing the relationship between us and EQT with respect to and resulting from the Separation. Among other things, the Separation and Distribution Agreement provides for indemnification obligations designed to make us financially responsible for substantially all liabilities that may exist relating to our business activities, whether incurred prior to or after the Separation, as well as those obligations of EQT assumed by us pursuant to the Separation and Distribution Agreement. If we are required to indemnify EQT under the circumstances set forth in the Separation and Distribution Agreement, we may be subject to substantial liabilities. See also the discussion of potential indemnification obligations under “If the Separation and Distribution, together with certain related transactions, does not continue to qualify as a transaction that is generally tax-free for U.S. federal income tax purposes, we, EQT, and our respective shareholders could be subject to significant tax liabilities and, in certain circumstances, we could be required to indemnify EQT for material taxes and other related amounts pursuant to indemnification obligations under the tax matters agreement.” in Part I, “Item 1A. Risk Factors” of this Annual Report on Form 10-K. Further, if EQT is unable or unwilling to satisfy its obligations under these agreements, including its indemnification obligations, our business, results of operations and financial condition could be materially and adversely affected.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES
Item 2. Properties
The Company leases its corporate headquarters office in Canonsburg, Pennsylvania.
The Company's real property falls into two categories: (i) parcels that it owns in fee and (ii) parcels in which its interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the Company's operations. Certain lands on which the Company's pipelines and facilities are located are owned by the Company in fee title, and the Company believes that it has satisfactory title to these lands in all material respects. Other lands on which the Company's pipelines and facilities are located are held pursuant to surface leases or easements between the Company, as lessee or grantee, and the respective fee owners of the lands, as lessors or grantors. The Company has held, leased or owned many of these lands for many years without any material challenge known to the Company relating to the title to the land upon which the assets are located, and the Company believes that it has satisfactory leasehold estates, easement interests or fee ownership to such lands in all material respects. The Company believes that it has satisfactory title to all of its material
leases, easements, rights-of-way, permits and licenses in all material respects, and the Company has no knowledge of any material challenge to its title to such assets or their underlying fee title.
As contemplated under “We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations and future development," included in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K, there are, however, certain lands within the Company's storage pools and where the Company's pipelines and other facilities are located as to which it may not currently have vested real property rights, some of which are subject to ongoing acquisition negotiations or inverse condemnation proceedings. In accordance with Equitrans, L.P.'s FERC certificates, the geological formations within which its permitted storage facilities are located cannot be used by third parties in any way that would detrimentally affect its storage operations, and the Company has the power of eminent domain with respect to the acquisition of necessary real property rights to use such storage facilities. Certain property owners have initiated legal proceedings against the Company and its affiliates for trespass, inverse condemnation and other claims related to these matters, and there is no assurance that other property owners will not initiate similar legal proceedings against the Company and its affiliates prior to final resolution.
See Part I, "Item 1. Business" of this Annual Report on Form 10-K for a discussion of the Company's business segments relevant to its property holdings and map of the Company's operations.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
From time to time, various legal and regulatory claims and proceedings are pending or threatened against the Company and its subsidiaries. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accrues legal and other direct costs related to loss contingencies when incurred. The Company establishes reserves whenever it believes it to be appropriate for pending matters. Furthermore, after consultation with counsel and considering the availability, if any, of insurance, the Company believes, although no assurance can be given, that the ultimate outcome of any matter currently pending against it or any of its consolidated subsidiaries will not materially affect its business, financial condition, results of operations, liquidity or ability to pay dividends to its shareholders.
Environmental Proceedings
Pratt Storage Field. On October 31, 2018, a gas explosion occurred in Morgan Township, Greene County, Pennsylvania (the Incident). Following the explosion, the Pennsylvania Department of Environmental Protection (the PADEP), the Pennsylvania Public Utilities Commission and the PHMSA began investigating the Incident. In January 2020, the PADEP notified the Company that it was required to submit an investigation report pursuant to the state’s gas migration regulations due to the Incident's proximity to the Company's Pratt Storage Field assets. The Company, while disputing the applicability of the regulations, submitted a report to the PADEP in March 2020. In September 2020, the PADEP responded to the Company’s investigation report with a request for additional information. The Company responded to the September 2020 request and is awaiting further direction or inquiry from the PADEP. 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. Additionally, the Company is responding to civil and criminal investigations related to the Incident.
Swarts Storage Field. On April 8, 2021, the PADEP notified the Company that it considered certain aspects of the storage field to be out of compliance due to an alleged failure to plug or recondition wells within 2,000 feet of ongoing coal mining activities by CONSOL Energy Inc. and that a number of wells on the property allegedly did not meet applicable plugging standards. The Company disputes these claims and is working with the PADEP and CONSOL Energy Inc. to resolve these issues. Based on the discussion with the PADEP, the Company anticipates a notice of violation (NOV) will be issued. If penalties are pursued and ultimately imposed, the penalties could result in monetary sanctions in excess of $300,000. However, the Company does not believe that the penalties, if imposed, would have a material impact on the Company's financial condition, results of operations or liquidity.
Rager Mountain Storage Field PADEP Orders and Notices of Violation. On November 6, 2022, the Company became aware of natural gas venting from one of the storage wells, well 2244, at Equitrans, L.P.’s Rager Mountain natural gas storage facility (Rager Mountain facility), located in Jackson Township, a remote section of Cambria County, Pennsylvania. The venting of natural gas from well 2244 was halted on November 19, 2022. The PADEP and PHMSA are investigating the incident and the Company is endeavoring to cooperate in such investigations. On December 7, 2022, the Company and its subsidiary Equitrans, L.P. each separately received an order from the PADEP alleging, in connection with earth disturbance activities undertaken to halt the venting of natural gas from well 2244, (i) in the case of the order received by the Company, violations of Pennsylvania’s Clean Streams Law and requiring certain remedial actions and (ii) in the case of the order received by Equitrans, L.P., violations of Pennsylvania’s 2012 Oil and Gas Act, Clean Streams Law and Solid Waste Management Act and requiring
certain remedial actions. On December 8, 2022, the PADEP submitted a compliance order to Equitrans, L.P. relating to certain alleged violations of law in respect of wells at the Rager Mountain natural gas storage field and the venting of natural gas, including from well 2244. The December 8, 2022 order also prohibits Equitrans, L.P. from injecting natural gas into the storage wells at the Rager Mountain facility. The Company and Equitrans, L.P. disputed aspects of the applicable orders, and on January 5, 2023, the Company and Equitrans, L.P., as applicable, appealed each of the orders to the Commonwealth of Pennsylvania Environmental Hearing Board. Additionally, the Company and Equitrans, L.P., as applicable, have received, and may continue to receive, NOVs related to the incident which allege violations of various Pennsylvania statutes and regulations. If penalties are pursued and ultimately imposed related the Rager Mountain incident, the penalties are expected to result in monetary sanctions in excess of $300,000. While the Company does not believe that penalties, if imposed, would have a material adverse impact on the Company's financial condition, results of operations or liquidity, there can be no assurance as of the filing of this Annual Report on Form 10-K for the year ended December 31, 2022 regarding the scope of potential (or ultimately actual) financial or other impacts to the Company as a result of the Rager Mountain incident.
Rager Mountain Storage Field PHMSA Notice of Proposed Safety Order (NOPSO). On December 29, 2022, the PHMSA issued the Company a NOPSO which includes proposed remedial requirements related to the Rager Mountain natural gas storage field incident, including, but not limited to, completing a root cause failure analysis, a remedial work plan, injection plan and review of records and procedures, an assessment of personnel training and the submittal of quarterly reports to the PHMSA. The Company is working with the PHMSA on the scope of the proposed corrective measures listed in the NOPSO and has commenced certain of the measures, including engaging a third party specialist firm to undertake a root cause analysis. Although the Company could incur additional compliance costs as a result of a safety order or other order, the Company does not believe that such costs would have a material adverse impact on the Company's financial condition, results of operations or liquidity, however, there can be no assurance as to the outcome of the Company’s engagement with the PHMSA as to the scope of any such consent order or resultant costs.
MVP Matters
The MVP Joint Venture is currently defending certain agency actions and judicial challenges to the MVP, as well as pursuing certain authorizations, any of which could affect the ability to complete or operate the project, including the following:
•Sierra Club, et al. Petitioners v. State Water Control Board, et al. Respondents and Mountain Valley Pipeline, Intervenor, Docket No. 21-2425, Fourth Circuit Court of Appeals (Fourth Circuit). On December 20, 2021, the Virginia Department of Environmental Quality (VADEQ) certified that the MVP project would satisfy Virginia’s water quality standards based on its comprehensive nine-month review of the MVP Joint Venture’s Joint Permit Application (VA 401 Permit). On December 22, 2021, Petitioners filed their petition challenging the VADEQ’s approval of the VA 401 Permit with the Fourth Circuit. On December 22, 2021, the Petitioners filed a request for an administrative stay with the VADEQ which was denied on January 4, 2022. On January 4, 2022, the Petitioners filed a petition with the Fourth Circuit seeking a judicial stay of the VA 401 Permit pending a decision on the merits. On February 11, 2022, Petitioners withdrew the stay petition. On May 16, 2022, the MVP Joint Venture filed a motion for random panel assignment with the Fourth Circuit, which motion was denied on June 24, 2022. Briefing is complete and oral argument occurred on January 24, 2023 before the same panel of Fourth Circuit judges as have appeared, and overruled permitting agencies, in numerous prior matters relating to the MVP Joint Venture, and the parties are awaiting a decision. If the challenge were successful on its merits, it could result in the MVP Joint Venture's VA 401 Permit being delayed or vacated and remanded and/or additional legal proceedings, the outcome of which the Company cannot ensure, and cause a delay or further delay in the full in-service date for the MVP project (and consequent impacts related to such delay), or otherwise adverse effects.
•Sierra Club, et al. Petitioners v. West Virginia Department of Environmental Protection, et al. Respondents and Mountain Valley Pipeline, Intervenor, Docket No. 22-1008, Fourth Circuit. On December 30, 2021, the West Virginia Department of Environmental Protection (WVDEP) certified that the MVP project would satisfy West Virginia’s water quality standards based on its comprehensive nine-month review of the MVP Joint Venture’s Joint Permit Application (WV 401 Permit). On January 3, 2022, Petitioners filed their petition challenging the WVDEP’s approval of the WV 401 Permit with the Fourth Circuit. On January 4, 2022, the Petitioners filed a request for an administrative stay with the WVDEP which was denied on January 11, 2022. On January 11, 2022, Petitioners filed a petition with the Fourth Circuit seeking a judicial stay of the WV 401 Permit pending a decision on the merits. The stay petition was denied by the Fourth Circuit on February 8, 2022. On May 16, 2022, the MVP Joint Venture filed a motion for random panel assignment with the Fourth Circuit, which motion was denied on June 22, 2022. Briefing is complete and oral argument before the same panel of Fourth Circuit judges as have appeared, and overruled permitting agencies, in numerous prior matters relating to the MVP Joint Venture occurred on October 25, 2022, and the parties are awaiting a decision. If the challenge were successful on its merits, it could result in the MVP Joint Venture's WV 401 Permit being delayed or vacated and remanded and/or additional legal proceedings, the outcome of which the Company
cannot ensure, and cause a delay or further delay in the full in-service date for the MVP project (and consequent impacts related to such delay), or otherwise adverse effects.
•Jefferson National Forest Crossing and Associated Authorizations. In a different Fourth Circuit appeal, Sierra Club, et al. v. U.S. Forest Service, et al., consolidated under Case No. 17-2399, Fourth Circuit, filed in December 2017, the Sierra Club challenged a Bureau of Land Management (BLM) decision to grant a right-of-way to the MVP Joint Venture and a U.S. Forest Service (USFS) decision to amend its management plan to accommodate the MVP, both of which affect the MVP's approximate 3.5-mile segment in the Jefferson National Forest (JNF) in Virginia. On July 27, 2018, agreeing in part with the Sierra Club, the Fourth Circuit vacated the BLM and USFS decisions, finding fault with the BLM's analysis of the practicality of alternate routes and the USFS' analysis of erosion and sedimentation effects. On January 11, 2021, the MVP Joint Venture received final approval of the Record of Decision from the USFS and, on January 15, 2021, the BLM issued a new required right-of-way permit for the MVP’s 3.5-mile segment in the JNF in Virginia (the JNF Right-of-Way). On January 11, 2021, Sierra Club, et al. filed a petition with the Fourth Circuit to reverse the USFS approval of the Record of Decision and, on January 15, 2021, filed a petition with the Fourth Circuit challenging BLM’s grant of the JNF Right-of-Way. See Wild Virginia, et al. v. United States Forest Service, et al., No. 21-1039(L). On January 25, 2022, the Fourth Circuit, agreeing in part with the petitioners, vacated and remanded the Record of Decision and the JNF Right-of-Way, finding fault with (i) the USFS’ and BLM’s consideration of certain data from the U.S. Geological Survey and (ii) the USFS’ and BLM’s authorization of the use of conventional bores for stream crossings within the JNF based on a variance issued by the FERC, and, as a result of such issues, (iii) the USFS’ amendments in connection with the Record of Decision to the Jefferson Forest plan. On March 11, 2022, the MVP Joint Venture requested that the Fourth Circuit review the January 25, 2022 decision en banc, which rehearing was denied by the Fourth Circuit on March 25, 2022. The vacatur of the Record of Decision and the JNF Right-of-Way caused a delay in the then-targeted full in-service date for the MVP project (and consequent impacts relating to such delay). As discussed in "Developments, Market Trends and Competitive Conditions - Mountain Valley Pipeline" under "Part I, Item 1. Business" in this Annual Report on Form 10-K, the MVP Joint Venture has sought new authorizations relating to the JNF. On December 23, 2022, the USFS issued the draft Supplemental Environmental Impact Statement for the MVP. However, the Company cannot ensure whether and when any new authorizations will be received from the USFS and BLM and, if received, the result of any challenge to such authorizations.
On August 3, 2018, citing the court's vacatur and remand in Sierra Club, et al. v. U.S. Forest Service, et al., consolidated under Case No. 17-2399, the FERC issued a stop work order for the entire pipeline pending the agency actions on remand. The FERC modified its stop work order on August 29, 2018 to allow work to continue on all but approximately 25 miles of the project (the Exclusion Zone) and made certain other limited modifications of the stop work order. 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), other than with respect to the Exclusion Zone, which requires additional authorization. On December 17, 2020, the FERC again modified the stop work order and authorized construction to resume in 17 miles of the Exclusion Zone. The Company cannot guarantee whether or when the FERC will act in respect of any or all of the remaining portions of the Exclusion Zone. The FERC's October 9, 2020 and December 17, 2020 actions are the subject of challenges filed by the Sierra Club in Sierra Club, et al. v. FERC, Case No. 20-1512 (consolidated with No. 21-1040), D.C. Circuit Court of Appeals on December 22, 2020 and January 25, 2021, respectively. Briefing in Sierra Club, et al. v. FERC, Case No. 20-1512 (consolidated with No. 21-1040), D.C. Circuit Court of Appeals was completed in January 2022 and oral argument occurred on April 7, 2022 and the parties are awaiting a decision. If any of the challenges to the FERC's October 9, 2020 and December 17, 2020 orders are successful, it could result in the FERC's orders being vacated and/or additional agency proceedings (the outcome of which the Company cannot ensure) and cause a delay or further delay in the full in-service date for the MVP project (and consequent impacts relating to such delay), or otherwise adverse effects.
•Challenges to FERC Certificate, U.S. Court of Appeals for District of Columbia Circuit (DC Circuit). Multiple parties have sought judicial review of the FERC's order issuing a certificate of public convenience and necessity to the MVP Joint Venture and/or the exercise by the MVP Joint Venture of eminent domain authority. On February 19, 2019, the DC Circuit issued an order rejecting multiple consolidated petitions seeking direct review of the FERC order under the NGA and certain challenges to the exercise by the MVP Joint Venture of eminent domain authority in Appalachian Voices, et al. v. FERC, et al., consolidated under Case No. 17-1271. No petitions for rehearing or petitions for rehearing en banc were filed by the April 5, 2019 deadline. The mandate was issued on April 17, 2019. A 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. The ACP petitioners on November 16, 2022, filed a joint motion for voluntary dismissal of all petitions for review pertaining to ACP, except for the Bold Alliance proceeding. The Court granted the motion on November 17, 2022. On January 5, 2023, the DC Circuit entered an order holding the Bold Alliance proceeding in abeyance pending further order of the court and requiring the parties to file motions to govern future proceedings within 60 days of the Supreme Court of the United States' (SCOTUS) disposition of the petition for writ of certiorari in Bohon et al. v. FERC et al., discussed below.
Similarly, another group of parties filed a complaint in the U.S. District Court for the District of Columbia in Bohon et al. v. FERC et al., Case No. 20-00006, asserting that the delegation of authority to FERC under the NGA violates the nondelegation doctrine and separation-of-powers principle of the U.S. Constitution. The MVP Joint Venture and the FERC filed motions to dismiss which were granted by the court. On July 6, 2020, the landowners filed a notice of appeal to the DC Circuit in Case No. 20-5203. On November 30, 2020, appellants asked the DC Circuit to overturn the decision of the lower court. Oral argument before the DC Circuit was scheduled for March 29, 2021, but the court cancelled and held oral argument in abeyance and directed the parties to file motions to govern future proceedings following a decision by the U.S. Supreme Court in PennEast Pipeline Co. v. New Jersey, Case No. 19-1039, which decision was published on June 29, 2021. Briefing in Bohon et al. v. FERC et al., Case No. 20-00006 on the significance of the PennEast Pipeline Co. opinion was completed on July 29, 2021. The DC Circuit issued an order on September 15, 2021 denying appellants' motion for summary reversal of the decision of the lower court and supplemental briefing was completed as of October 6, 2021. On June 21, 2022, the DC Circuit upheld the lower court's decision to dismiss the lawsuit. On September 15, 2022, the petitioners filed a petition for writ of certiorari with SCOTUS. The FERC and the MVP Joint Venture filed responses to the petition in November 2022. The parties are awaiting a decision from SCOTUS on whether to grant certiorari.
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). Briefing in Sierra Club, et al. v. FERC, Case No. 20-1512 (consolidated with No. 21-1040, D.C. Circuit), was completed in January 2022 and oral argument occurred on April 7, 2022, and the parties are awaiting a decision. Separately, on June 24, 2022, citing litigation and regulatory matters, the MVP Joint Venture filed a request with the FERC for an extension of time to complete the MVP project through October 13, 2026, which was granted on August 23, 2022. Parties filed timely requests for rehearing with the FERC regarding such approval, which were denied by the FERC on October 24, 2022 and February 17, 2023. Parties also filed a petition for review of such approval with the DC Circuit on December 23, 2022 (Case No. 22-1330). The DC Circuit put the appeal of the second extension (Case No. 22-1330) into abeyance in an order issued February 2, 2023. 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 ensure, and cause a delay or further delay in the full in-service date for the MVP project (and consequent impacts related to such delay), or otherwise adverse effects.
•Appalachian Voices, et al. v. U.S. Dep’t of Interior, et al., Fourth Circuit Court of Appeals, Case No. 20-2159. In August 2019, Wild Virginia and certain other petitioners filed a petition in the Fourth Circuit in Wild Virginia et al. v. United States Department of the Interior; Case No. 19-1866, to challenge the MVP Joint Venture’s Biological Opinion and Incidental Take Statement issued by FWS which was approved in November 2017 (the Original BiOp). On October 11, 2019, the Fourth Circuit issued an order approving the petitioners’ requested stay of the Original BiOp and holding the litigation in abeyance until January 11, 2020. On October 15, 2019, the FERC issued an order requiring the MVP Joint Venture to cease all forward-construction progress (the FERC modified this order on October 9, 2020 and December 17, 2020, which the Sierra Club has appealed to the DC Circuit as discussed above under "Jefferson National Forest Crossing and Associated Authorizations"). On September 4, 2020, FWS issued the MVP Joint Venture a new Biological Opinion and Incidental Take Statement (the 2020 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 2020 BiOp. On February 2, 2022, the Fourth Circuit vacated and remanded the 2020 BiOp holding, in part, that the FWS did not adequately analyze the environmental context for species at issue. On March 11, 2022, the MVP Joint Venture requested that the Fourth Circuit review the February 2, 2022 decision en banc, which rehearing was denied by the Fourth Circuit on April 1, 2022. The vacatur of the 2020 BiOp caused a delay in the then-targeted full in-service date for the MVP project (and consequent impacts relating to such delay). As discussed in "Developments, Market Trends and Competitive Conditions - Mountain Valley Pipeline" under "Part I, Item 1. Business" of this Annual Report on Form 10-K, the MVP Joint Venture is pursuing a new BiOp from the FWS. However, the Company cannot ensure whether and when a new BiOp will be received from the FWS and, if received, the result of any challenge to such BiOp.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
Information About Our Executive Officers
Name Age Year Initially Elected as Executive Officer Title
Thomas F. Karam 64 2018 Chief Executive Officer
Diana M. Charletta 50 2018 President and Chief Operating Officer
Kirk R. Oliver 65 2018 Senior Vice President and Chief Financial Officer
Stephen M. Moore 63 2019 Senior Vice President and General Counsel
Brian P. Pietrandrea 48 2019 Vice President and Chief Accounting Officer
Mr. Karam has served as Chief Executive Officer of Equitrans Midstream since September 2018, a Director on the Board since November 2018 and Chairman of the Board since July 2019. Mr. Karam also served as President of Equitrans Midstream from September 2018 to July 2019. Prior to his service at Equitrans Midstream, he served as senior vice president, EQT and president, midstream from August 2018, serving in those capacities until the Separation. Mr. Karam served as chief executive officer and chairman of the EQM General Partner from July 2019 until the EQM Merger in June 2020, chairman, president and chief executive officer, from October 2018 to July 2019, and as president, chief executive officer and director, from August 2018 to October 2018. Additionally, he served as chairman, president and chief executive officer of the general partner of EQGP from October 2018 through Equitrans Midstream's acquisition of 100% of the limited partner interests in EQGP in January 2019 (the EQGP Buyout), as well as president, chief executive officer and director from August 2018 to October 2018. Mr. Karam served on EQT’s board of directors from November 2017 until the Separation. Mr. Karam is the founder and served as chairman of Karbon Partners, LLC, which invests in, owns, constructs, and operates midstream energy assets, from April 2017 to August 2018. Mr. Karam previously served as the founder, chairman and chief executive officer of the general partner of PennTex Midstream Partners, LP (PennTex), a publicly traded master limited partnership with operations in North Louisiana and the Permian Basin from 2014 until its sale to Energy Transfer Partners in 2016. Preceding PennTex, he was the founder, chairman and chief executive officer of Laser Midstream Partners, LLC, one of the first independent natural gas gathering systems in the northeast Marcellus Shale, from 2010 until 2012 when it was acquired by Williams Partners.
Ms. Charletta was appointed President and Chief Operating Officer of Equitrans Midstream in July 2019 and the Board appointed Ms. Charletta as a Director in April 2022. She previously served as Executive Vice President and Chief Operating Officer of Equitrans Midstream since September 2018. She also served as executive vice president, chief operating officer and a director of the EQM General Partner from October 2018 through July 2019, when she was promoted to president and chief operating officer. She served as president, chief operating officer and director of the EQM General Partner through the EQM Merger. Ms. Charletta served as the executive vice president, chief operating officer and as a director of EQGP's general partner from October 2018 through the consummation of the EQGP Buyout. Ms. Charletta joined EQT in 2002 as a senior pipeline engineer and from that time held various management positions with increasing responsibility. She assumed the role of senior vice president of midstream operations of a subsidiary of EQT in December 2013 and was promoted to senior vice president of midstream engineering and construction in July 2017, a position she held until the Separation. Ms. Charletta also has served as a director of the Southern Gas Association, a natural gas trade association, since November 2022.
Mr. Oliver was appointed Senior Vice President and Chief Financial Officer of Equitrans Midstream in September 2018. He also served as senior vice president, chief financial officer and a director of the EQM General Partner from October 2018 through the EQM Merger. Mr. Oliver served as the senior vice president, chief financial officer and as a director of the general partner of EQGP from October 2018 through the EQGP Buyout. Prior to joining Equitrans Midstream, he was chief financial
officer for UGI Corporation, which distributes, stores, transports and markets energy products and related services, from October 2012 through May 2018.
Mr. Moore was appointed Senior Vice President and General Counsel of Equitrans Midstream in April 2019. Prior to joining Equitrans Midstream, Mr. Moore was general counsel of PennTex Midstream Partners, LP, a publicly traded master limited partnership, from 2014 through 2017. From March 2018 to April 2019, Mr. Moore served as special projects counsel to UGI Corporation.
Mr. Pietrandrea was appointed as Vice President and Chief Accounting Officer of Equitrans Midstream in August 2019. He also served as vice president and chief accounting officer of the EQM General Partner from August 2019 through the EQM Merger. Mr. Pietrandrea also served as controller of certain subsidiaries of Equitrans Midstream effective upon the Separation until his promotion in August 2019. Prior to joining Equitrans Midstream, Mr. Pietrandrea served in various roles of increasing responsibility at a subsidiary of EQT, including director, partnership accounting and reporting, from October 2013 through February 2017, controller, from March 2017 through February 2018, and vice president and controller from March 2018 through the Separation.
All executive officers have executed agreements with the Company and serve at the pleasure of the Board. Officers are elected annually to serve during the ensuing year or until their successors are elected and qualified, or until their death, resignation or removal.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Equitrans Midstream common stock trades on the NYSE under the symbol "ETRN".
As of January 31, 2023, there were 1,722 shareholders of record of Equitrans Midstream common stock.
On January 24, 2023, the Board declared cash dividends for the fourth quarter of 2022 of $0.15 per common share and $0.4873 per Equitrans Midstream Preferred Share, which dividends were paid on February 14, 2023 to shareholders of record at the close of business on February 6, 2023.
As discussed under "We cannot guarantee the timing, amount or payment of dividends on our common stock, and we may further reduce the amount of the cash dividend that we pay on our common stock or may not pay any cash dividends at all to our shareholders. Our ability to declare and pay cash dividends to our shareholders, if any, in the future will depend on various factors, many of which are beyond our control.” included in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K, the amount and timing of dividends is subject to the discretion of the Board and depends upon business conditions, including, but not limited to, the financial condition, results of operations, liquidity and capital requirements of the Company's operating subsidiaries, covenants associated with certain debt obligations, legal requirements and strategic direction and other factors deemed relevant by the Board. The Board has the discretion to change the dividend at any time for any reason.
Securities Authorized for Issuance under Equity Compensation Plans
See Part III, “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” of this Annual Report on Form 10-K for information relating to the Company’s equity compensation plans.
Recent Sales of Unregistered Securities
See Notes 1 and 2 to the consolidated financial statements for a description of the Restructuring Agreement and Restructuring.
Market Repurchases
The Company did not have any repurchases of equity securities registered under Section 12 of the Exchange Act during the three months ended December 31, 2022.
Stock Performance Graph
The graph below compares the cumulative forty-nine month total return provided to shareholders on Equitrans Midstream's common stock relative to the cumulative total returns of (i) the S&P 500 index and (ii) the Alerian US Midstream Energy Index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in Equitrans Midstream common stock on November 13, 2018, and with respect to each index, October 31, 2018, and relative performance is tracked through December 31, 2022.
11/13/2018 12/31/2018 12/31/2019 12/31/2020 12/31/2021 12/31/2022
Equitrans Midstream Corporation $ 100.00 $ 95.84 $ 71.75 $ 47.88 $ 66.20 $ 46.18
S&P 500 100.00 92.82 122.05 144.51 185.99 152.31
Alerian U.S. Midstream Energy 100.00 89.60 103.54 77.70 112.67 145.98

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Reserved

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of financial condition and results of operations should be read in conjunction with Part I, "Item 1. Business," Part I, "Item 1A. Risk Factors," and the consolidated financial statements, and the notes thereto, included in Part II, "Item 8. Financial Statements and Supplementary Data" in this Annual Report on Form 10-K.
The information covered in this section provides a comparison of material changes in the Company's results of operations and financial condition for fiscal year 2022 and fiscal year 2021. For the discussion of fiscal year 2021 relative to fiscal year 2020, see Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of the Company's Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 23, 2022.
Executive Overview
Net loss attributable to Equitrans Midstream common shareholders was $(327.9) million, ($0.76) per diluted share, in 2022 compared to $(1,470.3) million, ($3.40) per diluted share, in 2021. The decrease is primarily from lower impairments of the Company's equity method investment in the MVP Joint Venture and long-lived assets, higher other income (expense), net, higher operating revenues and lower loss on extinguishment of debt charges, partially offset by higher income tax expense, lower equity income and higher net interest expense. See Note 3 to the consolidated financial statements for a discussion of the impairments of the Company's equity method investment in the MVP Joint Venture.
In the course of its year-end 2022 process, the Company identified certain corrections in its previously issued consolidated financial statements primarily related to the accounting for the Henry Hub cash bonus payment provision. The Company determined that the related impact was not material and has revised its previously issued consolidated financial statements for the affected prior periods. See Note 1 to the consolidated financial statements for additional information.
Sustainability and Corporate Responsibility
The Company recognizes that the long-term interests of shareholders are served by managing ESG matters important to the Company’s stakeholders and working to be resilient and appropriately positioned in any environment, including a lower-carbon economy. The Company embraces working to conduct business in a socially responsible and ethical manner by respecting all stakeholders, and is focused on identifying and executing on ESG and sustainability initiatives while further integrating corporate responsibility and ESG concerns into its business strategy and decision-making throughout the organization. The Company also is committed to continuing to operate with integrity, accountability and transparency. As a result, the Company anticipates that it will continue to prudently allocate capital resources to ESG and sustainability initiatives in the future, which may include at increasing levels, which the Company believes will benefit the sustainability of the Company's business and help to create value.
The Company believes that natural gas will remain a significant component of the global and national energy complex and will play a vital role in the transformation to a lower-carbon economy, notwithstanding increased demand for alternative energy sources and negative sentiment with respect to natural gas, including natural gas infrastructure, from certain actors. Further, the Company believes that continued natural gas production and infrastructure growth are directly supportive of the United States' energy security. The Company also acknowledges the reality and risks of climate change as a critical current issue and, as an energy infrastructure company, recognizes the ongoing developments and risks surrounding climate change. As a result, the Company is focused on long-term sustainable performance, such as continuing to proactively pursue climate change mitigation aspirations while also balancing the immediate and increasing need to deliver reliable, safe, and affordable natural gas energy in the United States now and in the future.
The Company is focused on executing on sustainability initiatives while further integrating sustainability-focused risks and opportunities into the Company’s strategic and capital spending decision processes, as well as its employee compensation structure. For example, in support of its published climate policy and GHG reduction goals, in 2022 the Company made investments to replace gas-driven pneumatics with instrument air systems and high-bleed pneumatic devices with low- or intermittent-bleed controllers to reduce methane emissions relative to 2019 baseline levels. Further, the Company’s new compressor station designs employ reduced methane emission strategies such as non-venting shutdowns, compressed air pneumatics, electric motor dehydration pumps, and vent gas recovery to suction. Additionally, aspects of the Company's compensation structure reflect sustainability-oriented goals and developments. For example, the Human Capital and Compensation Committee of the Board determined to again include a methane emissions mitigation metric in the Company’s 2022 short-term incentive compensation program applicable to all employees, including executives, which provided that the Company undertake and complete certain projects to achieve targeted methane emissions mitigation. The Human Capital and Compensation Committee also added a new sustainability metric reflecting the timely completion and submission of the voluntary CDP Water Security Questionnaire response, which included a comprehensive water inventory. The Company expects to continue to pursue strategic sustainability initiatives as appropriate, including with respect to climate change, and to incur costs and capital expenditures to do so. Costs and expenses associated with sustainability and ESG matters could be material.
As discussed in “Our business is subject to climate change-related transitional risks (including evolving climate-focused regulation and climate change-driven trends emphasizing financing non-fossil fuel businesses and prompting pursuit of emissions reductions, lower-carbon technologies and alternative forms of energy) and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers’ development plans, and reduce demand for our products and services.” in Part I, “Item 1A. Risk Factors” and “Regulatory Environment” in Part I, “Item 1. Business” of this Annual Report on Form 10-K, the Company recognizes the evolving landscape of international accords and federal, state and local laws and regulations regarding GHG emissions or climate change initiatives. The Company also recognizes, as discussed in "Increasing scrutiny and changing stakeholder expectations and disclosures in respect of ESG and sustainability practices may adversely impact our business and our stock price and impose additional costs or expose us to new or additional risks." in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K, the changing expectations from a variety of stakeholders relating to ESG and sustainability practices. Changing market conditions, competition from lower emitting fuels, new laws and regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict the long-term business impact of GHG emission and climate change initiatives on the Company’s liquidity, capital resources, results of operations and financial condition. However, the Company is taking steps to prudently invest capital in furtherance of its goal of long term sustainable operations and recognizes that responsive adaptation efforts are likely to be costly and time consuming.
Business Segment Results
Operating segments are revenue-producing components of an enterprise for which separate financial information is produced internally and is subject to evaluation by the chief operating decision maker in deciding how to allocate resources. Headquarters costs consist primarily of certain unallocated corporate expenses and transaction costs, as applicable. Net interest expense, loss on extinguishment of debt, components of other income (expense), net, and income tax expense (benefit) are managed on a consolidated basis. The Company has presented each segment's operating income (loss), other income (expense), net, equity income, impairment of equity method investment and various operational measures, as applicable, in the following sections. Management believes that the presentation of this information is useful to management and investors regarding the financial condition, results of operations and trends and uncertainties of its segments. The Company has reconciled each segment's operating income (loss) to the Company's consolidated operating income and net income (loss) in Note 4 to the consolidated financial statements.
GATHERING RESULTS OF OPERATIONS
Years Ended December 31,
2022 2021 %
Change 2020 %
Change
FINANCIAL DATA (Thousands, except per day amounts)
Firm reservation fee revenues (a)
$ 562,947 $ 468,156 20.2 $ 595,720 (21.4)
Volumetric-based fee revenues 327,632 393,897 (16.8) 416,561 (5.4)
Total operating revenues 890,579 862,053 3.3 1,012,281 (14.8)
Operating expenses:
Operating and maintenance 101,194 99,387 1.8 87,388 13.7
Selling, general and administrative 82,590 93,245 (11.4) 93,070 0.2
Transaction costs - - - 4,104 (100.0)
Depreciation 195,059 188,633 3.4 172,967 9.1
Amortization of intangible assets 64,819 64,819 - 63,195 2.6
Impairment of long-lived assets - - - 55,581 (100.0)
Total operating expenses 443,662 446,084 (0.5) 476,305 (6.3)
Operating income $ 446,917 $ 415,969 7.4 $ 535,976 (22.4)
Other income (expense), net (b)
$ 13,312 $ (47,804) 127.8 $ 9,661 (594.8)
OPERATIONAL DATA
Gathering volumes (BBtu per day)
Firm capacity (c)
5,211 5,216 (0.1) 4,652 12.1
Volumetric-based services 2,484 3,098 (19.8) 3,553 (12.8)
Total gathered volumes 7,695 8,314 (7.4) 8,205 1.3
Capital expenditures(d)
$ 265,864 $ 223,807 18.8 $ 344,873 (35.1)
(a)For the years ended December 31, 2022, 2021 and 2020, firm reservation fee revenues included approximately $20.2 million, $11.3 million and $15.0 million, respectively, of MVC unbilled revenues.
(b)Other income (expense), net, includes the unrealized gain (loss) on derivative instruments associated with the Henry Hub cash bonus payment provision and gain on sale of gathering assets. See Note 11 to the consolidated financial statements for further information.
(c)Includes volumes up to the contractual MVC under agreements structured with MVCs. Volumes in excess of the contractual MVC are reported under Volumetric-based services.
(d)Includes approximately $20.3 million, $14.1 million and $41.6 million of capital expenditures related to noncontrolling interests in Eureka Midstream for the years ended December 31, 2022, 2021 and 2020, respectively.
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021
Gathering operating revenues increased by $28.5 million for the year ended December 31, 2022 compared to the year ended December 31, 2021. Firm reservation fee revenues increased by $94.8 million due to $85.7 million of higher firm reservation revenues associated with the EQT Global GGA, including lower deferred revenue of $77.9 million primarily resulting from a prior year cumulative adjustment associated with certain potential contract extensions impacting the estimated total consideration under the EQT Global GGA that reduced revenues during the year ended December 31, 2021, and rate adjustments of $7.8 million, and $9.1 million of increased firm reservation revenues from other customers. See Note 5 to the consolidated financial statements for a discussion of deferred revenues under the EQT Global GGA. Volumetric-based fee revenues decreased by $66.3 million primarily due to lower gathered volumes.
Gathering operating expenses decreased by $2.4 million for the year ended December 31, 2022 compared to the year ended December 31, 2021, primarily due to the decrease in selling, general and administrative expenses associated with lower professional service fees and personnel costs. Depreciation expense increased by $6.4 million as a result of additional assets placed in-service.
See Note 5 to the consolidated financial statements for discussions of the EQT Global GGA, and the transactions related thereto, including periodic gathering MVC fee declines even if MVP would not achieve full in-service. Additionally, as discussed in Note 5 to the consolidated financial statements, in connection with MVP full in-service the EQT Global GGA provides for more significant potential gathering MVC fee declines in certain contract years. Firm reservation fee revenues under the Company’s Hammerhead gathering agreement with EQT are expected to contribute to an increase in the Company’s firm reservation fee revenues following achievement of the Hammerhead pipeline full commercial in-service in conjunction with full MVP in-service. However, the percentage of the Company's operating revenues that are generated by firm reservation fees may vary year to year depending on various factors, including customer volumes and the rates realizable under the Company’s contracts, including the EQT Global GGA.
TRANSMISSION RESULTS OF OPERATIONS
Years Ended December 31,
2022 2021 %
Change 2020 %
Change
FINANCIAL DATA (Thousands, except per day amounts)
Firm reservation fee revenues $ 370,769 $ 366,323 1.2 $ 364,533 0.5
Volumetric-based fee revenues 33,748 33,879 (0.4) 29,303 15.6
Total operating revenues 404,517 400,202 1.1 393,836 1.6
Operating expenses:
Operating and maintenance 33,429 33,883 (1.3) 37,635 (10.0)
Selling, general and administrative 37,782 36,483 3.6 26,292 38.8
Depreciation 55,614 55,310 0.5 54,540 1.4
Total operating expenses 126,825 125,676 0.9 118,467 6.1
Operating income $ 277,692 $ 274,526 1.2 $ 275,369 (0.3)
Equity income $ 168 $ 17,579 (99.0) $ 233,833 (92.5)
Impairments of equity method investment $ (583,057) $ (1,926,402) (69.7) $ - 100.0
OPERATIONAL DATA
Transmission pipeline throughput (BBtu per day):
Firm capacity reservation 3,140 2,960 6.1 2,932 1.0
Volumetric-based services 33 11 200.0 16 (31.3)
Total transmission pipeline throughput 3,173 2,971 6.8 2,948 0.8
Average contracted firm transmission reservation commitments (BBtu per day) 4,059 4,082 (0.6) 4,087 (0.1)
Capital expenditures (a)
$ 35,971 $ 25,977 38.5 $ 45,219 (42.6)
(a)Transmission capital expenditures do not include capital contributions made to the MVP Joint Venture for the MVP and MVP Southgate projects of approximately $199.6 million, $287.7 million and $272.8 million for the years ended December 31, 2022, 2021 and 2020, respectively.
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021
Transmission operating revenues increased by $4.3 million for the year ended December 31, 2022 compared to the year ended December 31, 2021. Firm reservation fee revenues increased by $4.4 million primarily due to higher rates and customers contracting for additional firm transmission capacity.
Operating expenses increased by $1.1 million for the year ended December 31, 2022 compared to the year ended December 31, 2021 primarily as a result of higher selling, general and administrative expense resulting from increased professional service fees, partially offset by lower operating and maintenance expense. Operating and maintenance decreased primarily due to operational efficiencies, which were partially offset by expenses associated with the Rager Mountain natural gas storage field incident.
Post-incident response efforts and workstreams related to the Rager Mountain natural gas storage field incident remain ongoing. The Company is continuing and expects to continue to incur costs and expenses as a result of or arising in relation to the incident, which costs and expenses would be reflected in the Company's future Transmission operating results. For additional information, see Note 15 to the consolidated financial statements, Part I, "Item 3. Legal Proceedings", Part I, "Item 1. Business" and "The November 2022 incident involving the venting of natural gas from a well at Equitrans, L.P.’s Rager Mountain natural gas storage facility required that we incur costs and expenses to halt such venting, and investigate and respond to the incident, including undertaking ongoing reviews of other storage assets. Activities and investigations responsive to the incident are ongoing, and, consequently, we are incurring and in the future we expect to incur further costs and expenses, whether resulting from or arising out of the incident, which could, depending on their scope and timing, materially
adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders." in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.
Equity income decreased by $17.4 million for the year ended December 31, 2022 compared to the year ended December 31, 2021 due to the decrease in the MVP Joint Venture's AFUDC on the MVP project.
The Company's equity income in future periods will continue to be affected by the timing of the resumption of the remaining MVP project growth construction activities and associated AFUDC, and the timing of the completion of the MVP project, and such impact could continue to be substantial.
Impairment of equity method investment includes the separate impairments of the Company's equity method investment in the MVP Joint Venture. See Note 3 to the consolidated financial statements for further information.
WATER RESULTS OF OPERATIONS
Years Ended December 31,
2022 2021 %
Change 2020 %
Change
FINANCIAL DATA (Thousands)
Firm reservation fee revenues $ 33,877 $ 5,063 569.1 $ 41,798 (87.9)
Volumetric-based fee revenues 28,774 49,719 (42.1) 62,910 (21.0)
Total operating revenues 62,651 54,782 14.4 104,708 (47.7)
Operating expenses:
Operating and maintenance 19,960 19,801 0.8 29,131 (32.0)
Selling, general and administrative 8,073 7,481 7.9 5,941 25.9
Depreciation 20,016 25,233 (20.7) 30,880 (18.3)
Impairment of long-lived assets - 56,178 (100.0) - 100.0
Total operating expenses 48,049 108,693 (55.8) 65,952 64.8
Operating income (loss) $ 14,602 $ (53,911) 127.1 $ 38,756 (239.1)
OPERATIONAL DATA
Water services volumes (MMgal):
Firm capacity reservation (a)
433 105 312.4 697 (84.9)
Volumetric-based services 706 1,015 (30.4) 1,219 (16.7)
Total water volumes 1,139 1,120 1.7 1,916 (41.5)
Capital expenditures $ 66,569 $ 34,877 90.9 $ 11,905 193.0
(a) Includes volumes up to the contractual MVC under agreements structured with MVCs or ARCs, as applicable. Volumes in excess of the contractual MVC are reported under Volumetric-based services.
Year Ended December 31, 2022 Compared to Year Ended December 31, 2021
Water operating revenues increased by $7.9 million for the year ended December 31, 2022 compared to the year ended December 31, 2021. Firm reservation fee revenues increased by $28.8 million primarily as a result of increased revenues associated with ARCs pursuant to the 2021 Water Services Agreement. Volumetric-based fee revenues decreased $20.9 million primarily due to lower volumetric-based fee volumes resulting from more firm capacity volumes in the current period due to the 2021 Water Services Agreement replacing contracts that provided for service on a volumetric fee basis.
Water operating expenses decreased by $60.6 million for the year ended December 31, 2022 compared to the year ended December 31, 2021 primarily as a result of the $56.2 million impairment of long-lived assets during 2021. Depreciation expense decreased $5.2 million due to such impairment.
The Company’s volumetric-based water services are directly associated with producers’ well completion activities and fresh and produced water needs (which are primarily driven by horizontal lateral lengths and the number of completion stages per well). Therefore, the Water volumetric operating results traditionally fluctuate from year-to-year in response to producers’ well completion activities. Firm reservation revenues are expected to be mostly consistent due to the ARC under the 2021 Water Services Agreement that became effective March 1, 2022.
For further discussion of the 2021 Water Services Agreement, see "2021 Water Services Agreement" in Part I, "Item 1. Business" and Note 5 to the consolidated financial statements of this Annual Report on Form 10-K.
Other Income Statement Items
Other Income (Expense), Net
Other income (expense), net, increased $61.4 million for the year ended December 31, 2022 compared to the year ended December 31, 2021. The increase is primarily due to a $9.6 million unrealized gain on derivative instruments during the year ended December 31, 2022 as compared to a $47.8 million unrealized loss on derivative instruments during the year ended December 31, 2021, due to changes in probability-weighted assumptions regarding MVP full in-service timing and changes in NYMEX Henry Hub natural gas futures prices associated with the Henry Hub cash bonus payment provision, as well as a $3.7 million gain on the sale of non-core gathering assets.
See also "Outlook" for a discussion of factors affecting the estimated fair value of the derivative asset attributable to the Henry Hub cash bonus payment provision that is recognized in other income (expense), net on the Company's statements of consolidated comprehensive income.
Loss on Extinguishment of Debt
Loss on extinguishment of debt decreased $16.1 million for the year ended December 31, 2022 compared to the year ended December 31, 2021. The Company incurred a loss on extinguishment of debt of $24.9 million related to the payment of the 2022 Tender Offers and open market repurchase premiums and fees, and write off of the respective unamortized discounts and financing costs associated with the purchase of portions of 2023, 2024 and 2025 Notes in the 2022 Tender Offers.
The Company incurred a loss on extinguishment of debt of $41.0 million during the year ended December 31, 2021 related to the payment of the 2021 Tender Offers premiums and write off of unamortized discounts and financing costs related to the prepayment of the loans under, and termination of, the Amended 2019 EQM Term Loan Agreement and purchase of portions of 2023 Notes in the 2021 Tender Offers.
See Note 10 to the consolidated financial statements for additional discussion.
Net Interest Expense
Net interest expense increased by $15.7 million for the year ended December 31, 2022 compared to the year ended December 31, 2021 primarily due to the issuance of the 2022 Senior Notes and increased interest rates on the revolving credit facilities, partially offset by the impact of the 2022 Tender Offers.
As a result of the issuance of the 2022 Senior Notes and purchase of portions of 2023, 2024 and 2025 Notes in the 2022 Tender Offers, and the Company's expectations regarding near-term market interest rate levels, the Company expects its annual net interest expense to be higher in future periods.
See also Note 10 to the consolidated financial statements for a discussion of certain of the Company's outstanding debt.
Income Tax Expense (Benefit)
See Note 13 to the consolidated financial statements for an explanation of the changes in income tax expense and effective tax rate for the year ended December 31, 2022 compared to the year ended December 31, 2021.
Net Income Attributable to Noncontrolling Interests
Net income attributable to noncontrolling interests decreased $2.3 million for the year ended December 31, 2022 compared to the year ended December 31, 2021 primarily as a result of lower net income on Eureka Midstream.
Capital Expenditures
See "Investing Activities" and "Capital Requirements" under "Capital Resources and Liquidity" for discussion of capital expenditures and capital contributions.
Outlook
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 one of the largest natural gas producers in the U.S. based on average
daily sales volumes as of December 31, 2022 and EQT's public senior debt had investment grade credit ratings from Standard & Poor's Global Ratings (S&P) and Fitch Ratings (Fitch) as of that date. For the year ended December 31, 2022, approximately 71% of the Company's operating revenues were generated from firm reservation fee revenues. Generally, the Company is focused on utilizing contract structures reflecting long-term firm capacity, MVC or ARC commitments which are intended to provide support to its cash flow profile. The percentage of the Company's operating revenues that are generated by firm reservation fees (as well as the Company's revenues generally) may vary year to year depending on various factors, including customer volumes and the rates realizable under the Company’s contracts, including the EQT Global GGA which provides for periodic gathering MVC fee declines through January 1, 2028 (with the fee then remaining fixed throughout the remaining term), even if MVP would not achieve full in-service. Additionally, as discussed in Note 5 to the consolidated financial statements, in connection with MVP full in-service the EQT Global GGA provides for more significant potential gathering MVC fee declines in certain contract years.
The Company's principal strategy is to achieve greater scale and scope, enhance the durability of its financial strength and to continue to work to position itself for a lower carbon economy, which the Company expects will drive future growth and investment. The Company is implementing its strategy by continuing to pursue its organic growth projects, including particularly the MVP given the Company’s belief that the MVP will, among other benefits, help to promote greater natural gas production in the Appalachian Basin given production levels have been limited by regional takeaway capacity limitations (including the lack of completion of the MVP), focusing on opportunities to use its existing assets to deepen and grow its customer relationships at optimized levels of capital spending and taking into account the Company's leverage, and continuing to prudently invest resources in its sustainability-oriented initiatives. The Company is also continuing to focus on maintaining and strengthening its balance sheet. Additionally, the Company also periodically evaluates strategically aligned inorganic growth opportunities (whether within its exiting footprint or to extend the Company's reach into the southeast United States and to become closer to key demand markets, such as the Gulf of Mexico LNG export market).
As part of its approach to organic growth, the Company is focused on its projects and assets outlined in "Strategy" under "Developments, Market Trends and Competitive Conditions" in Part I, "Item 1. Business" of this Annual Report on Form 10-K, many of which are supported by contracts with firm capacity, MVC or ARC commitments.
EQT Global GGA. On February 26, 2020, the Company entered into the EQT Global GGA, which is a 15-year contract that includes, among other things, a 3.0 Bcf per day MVC (which gradually steps up to 4.0 Bcf per day through December 2031 following the full in-service date of the MVP, should it be placed in service) and the dedication of a substantial majority of EQT’s core acreage in southwestern Pennsylvania and West Virginia to the Company. Under the EQT Global GGA the gathering MVC fee periodically declines through January 1, 2028 (with the fee then remaining fixed throughout the remaining term), even if MVP would not achieve full in-service. EQT also has the potential ability to receive greater gathering MVC fee relief during certain contract years in connection with MVP full in-service. The EQT Global GGA replaced 14 previous gathering agreements between EQT and the Company. See "The EQT Global GGA" in Part I, "Item 1. Business" of this Annual Report on Form 10-K for further discussion.
Based on the Henry Hub natural gas forward strip prices as of February 17, 2023 and the terms of the Henry Hub cash bonus payment provision, any further delays in the full in-service date for the MVP project, including beyond 2023, would further decrease the estimated fair value of the derivative asset attributable to the Henry Hub cash bonus payment provision, and such decrease may be substantial. For a discussion of the potential effect of hypothetical changes to the NYMEX Henry Hub natural gas future prices on the estimated fair value of the derivative asset attributable to the Henry Hub cash bonus payment provision, see "Commodity Prices" in Part II, "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" of this Annual Report on Form 10-K. Changes in estimated fair value are recognized in other income (expense), net, on the Company’s statements of consolidated comprehensive income.
2021 Water Services Agreement. For further discussion of the 2021 Water Services Agreement, see "2021 Water Services Agreement" in Part I, "Item 1. Business" of this Annual Report on Form 10-K.
For discussion of the Company's commercial relationship with EQT and related considerations, including risk factors, see Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K. For further discussion on litigation and regulatory challenges affecting the MVP project, see "Strategy" under "Developments, Market Trends and Competitive Conditions" in Part I, "Item 1. Business" and Part I, "Item 3. Legal Proceedings" of this Annual Report on Form 10-K.
Potential Future Impairments. 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 investment (such as in the MVP Joint Venture) require the Company to make projections and assumptions for many
years into the future for pricing, demand, competition, operating costs, commencement (or recommencement, as applicable) of operations and timing thereof (if at all), 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 its equity method investment, that such investment has suffered other-than-temporary declines in value under ASC 323). The Company believes the estimates and assumptions used in estimating its reporting units’, its long-lived assets' and its equity investment's fair values are reasonable and appropriate as of December 31, 2022; 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. When estimating the fair value of its equity method investment, the Company utilizes an income approach under which significant judgments and assumptions, including the discount rate and probability-weighted scenarios, are sensitive to change. The Company also continues to evaluate and monitor the ongoing legal and regulatory matters affecting the MVP project and MVP Southgate project, as further described in the case of the MVP project in Part I, “Item 3. Legal Proceedings” of this Annual Report on Form 10-K. Further adverse or delayed developments with respect to such matters or other adverse developments, as well as potential macroeconomic factors, including other-than-temporary market fluctuations, changes in interest rates, cost increases and other unanticipated events, could require that the Company further 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 the fair value of its equity investment in the MVP Joint Venture, which could result in an other-than-temporary decline in value, resulting in an incremental impairment of that investment. While macroeconomic factors in and of themselves may not be a direct indicator of impairment, should an impairment indicator be identified in the future, macroeconomic factors such as changes in interest rates could ultimately impact the size and scope of any potential impairment. See “Impairments of our assets, including property, plant, and equipment, intangible assets, goodwill and our equity method investment in the MVP Joint Venture, previously have significantly reduced our earnings, and additional impairments could further reduce our earnings.” included in Part I, “Item 1A. Risk Factors," and the Company's discussion of "Critical Accounting Estimates" included in Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation" of this Annual Report on Form 10-K.
As of the filing of this Annual Report on Form 10-K, the Company cannot predict the likelihood or magnitude of any future impairment. For information on the Company's past impairments, including with respect to its equity method investment in the MVP Joint Venture, see Note 3 to the consolidated financial statements.
For a discussion of capital expenditures, see "Capital Requirements" under "Capital Resources and Liquidity" below.
Capital Resources and Liquidity
The Company's liquidity requirements are to finance its operations, its capital expenditures, potential acquisitions and other strategic transactions and capital contributions to joint ventures, including the MVP Joint Venture, to pay cash dividends and distributions and to satisfy any indebtedness obligations. Additionally, the Company or its affiliates may, at any time and from time to time, seek to retire or purchase outstanding debt through cash purchases and/or exchanges for equity or debt, in open-market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will be upon such terms and at such prices as the Company may determine, and will depend on prevailing market conditions, the Company's other liquidity requirements, contractual restrictions and other factors and the amounts involved may be material. The Company's ability to meet these liquidity requirements depends on the Company's cash flow from operations, the continued ability of the Company to borrow under its credit facilities and the Company's ability to raise capital in banking and capital markets. We believe that our cash on hand and future cash generated from operations, together with available borrowing capacity under our subsidiaries' credit facilities and our access to banking and capital markets, will provide adequate resources to fund our short-term and long-term capital, operating and financing needs. However, cash flow and capital raising activities may be affected by prevailing economic conditions in the natural gas industry and other financial and business factors, including factors discussed in Part I, "Item 1A. Risk Factors" of this Annual Report Form 10-K (such as those market forces discussed in “Our business is subject to climate change-related transitional risks (including evolving climate-focused regulation and climate change-driven trends emphasizing financing non-fossil fuel businesses and prompting pursuit of emissions reductions, lower-carbon technologies and alternative forms of energy) and physical risks that could significantly increase our operating expenses and capital costs, adversely affect our customers’ development plans, and reduce demand for our products and services."), 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, 2022, pursuant to the terms of the Amended EQM Credit Facility, EQM had the ability to borrow approximately $0.5 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. See Note 10 to the consolidated financial statements for further information regarding the Amended EQM Credit Facility. See also "Our
subsidiaries’ significant indebtedness, and any future indebtedness, as well as the restrictions under our subsidiaries’ debt agreements, could adversely affect our operating flexibility, business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders." included in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.
See “Security Ratings” below for a discussion of EQM’s credit ratings during 2022. Based on EQM's credit rating levels, EQM has delivered credit support to the MVP Joint Venture in the form of letters of credit, which, in the case of the MVP project, is in the amount of approximately $219.7 million and is, in the case of the MVP Southgate, $14.2 million, in each case as of December 31, 2022 and which are subject to adjustment based on the applicable construction budget. See "A further downgrade of EQM’s credit ratings, which are determined by independent third parties, could impact our liquidity, access to capital, and costs of doing business." included in Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K. See Note 8 to the consolidated financial statements for further information on EQM's letters of credit.
The following table is a summary of the cash flows by activity for the years ended December 31, 2022, 2021 and 2020, respectively.
Years Ended December 31,
2022 2021 2020
(Thousands)
Cash flows
Net cash provided by operating activities $ 845,775 $ 1,168,768 $ 1,140,886
Net cash used in investing activities (567,037) (572,969) (729,829)
Net cash used in financing activities (345,501) (669,161) (291,356)
Net (decrease) increase in cash and cash equivalents $ (66,763) $ (73,362) $ 119,701
Operating Activities
Net cash flows provided by operating activities were $845.8 million for the year ended December 31, 2022 compared to $1,168.8 million for the year ended December 31, 2021. The decrease was primarily driven by the payment of the EQT Cash Option, higher interest payments and timing of other working capital receipts and payments.
Investing Activities
Net cash flows used in investing activities were $567.0 million for the year ended December 31, 2022 compared to $573.0 million for the year ended December 31, 2021. The decrease was primarily due to lower capital contributions to the MVP Joint Venture, partially offset by an increase in capital expenditure spending on various wellhead gathering and water expansion projects. See “Capital Requirements” below for a discussion of forecasted 2023 capital expenditures and capital contributions to the MVP Joint Venture.
Financing Activities
Net cash flows used in financing activities were $345.5 million for the year ended December 31, 2022 compared to $669.2 million for the year ended December 31, 2021. For the year ended December 31, 2022, the primary uses of financing cash flows were the purchase at an aggregate cost of $1,021.5 million of certain tranches of EQM's outstanding long-term indebtedness pursuant to the 2022 Tender Offers and an open market purchase, repayments on borrowings under the revolving credit facilities, and the payment of dividends to shareholders, while the primary sources of financing cash flows were the issuance of the 2022 Senior Notes and borrowings under the revolving credit facilities. For the year ended December 31, 2021, the primary uses of financing cash flows were the payment for retirement of the loans under and termination of the Amended 2019 EQM Term Loan Agreement, net repayments on borrowings under the revolving credit facilities, the Company's purchase of an aggregate principal amount of $500 million of EQM's 2023 Notes pursuant to the 2021 Tender Offers and the payment of dividends to shareholders, while the primary source of financing cash flows was the issuance of the 2021 Senior Notes.
Capital Requirements
The gathering, transmission and storage and water services businesses are capital intensive, requiring significant investment to develop new facilities and to maintain and upgrade existing operations.
The following represents the Company's material short-term and long-term cash requirements from contractual and other obligations as of December 31, 2022.
Total 2023 2024 - 2025
2026 - 2027
2028 +
(Thousands)
Long-term debt, including current portion thereof (a)
$ 6,498,941 $ 98,941 $ 700,000 $ 1,900,000 $ 3,800,000
Credit facility borrowings (b)
535,000 - 535,000 - -
Interest payments on senior notes (c)
2,535,442 363,421 692,750 523,156 956,115
Purchase obligations (d)
27,173 25,458 1,715 - -
Lease obligations (e)
66,405 10,533 15,488 14,407 25,977
Other liabilities (f)
55,851 45,574 10,277 - -
Total contractual and other obligations $ 9,718,812 $ 543,927 $ 1,955,230 $ 2,437,563 $ 4,782,092
(a)Includes approximately $6.5 billion in aggregate principal amount of EQM's senior notes as of December 31, 2022. See Note 10 to the consolidated financial statements for further information.
(b)Credit facility borrowings are classified based on the termination date of the credit facility agreements. As of December 31, 2022, the Company had aggregate credit facility borrowings outstanding of approximately $240 million and $295 million under the Amended EQM Credit Facility and the 2021 Eureka Credit Facility, respectively. See Note 10 to the consolidated financial statements for further information.
(c)Interest payments exclude interest related to the Amended EQM Credit Facility and the 2021 Eureka Credit Facility as the interest rates on the credit facility borrowings are variable.
(d)Excludes purchase obligations of the MVP Joint Venture. Purchase obligations represent agreements to purchase goods or services that are enforceable, legally binding and specify all significant terms, including the approximate timing of the transaction. As of December 31, 2022, the Company's purchase obligations included commitments for capital expenditures, operating expenses and service contracts.
(e)Lease obligations are primarily entered into for various office locations, compression equipment and a water storage facility.
(f)Other liabilities represent accruals for short-term employee compensation and estimated payouts for the Company's various liability award plans as of December 31, 2022. See "Critical Accounting Estimates" below and Note 9 to the consolidated financial statements for discussion of factors that affect the ultimate amount of the payout of the Company's liability award plans.
Contractual and other obligations exclude dividends associated with the Equitrans Midstream Preferred Shares.
Capital expenditures in 2022 were approximately $368 million (including approximately $20 million attributable to the noncontrolling interest in Eureka Midstream). Capital contributions to the MVP Joint Venture in 2022 were approximately $200 million. Capital expenditures in 2023 are expected to be approximately $375 million to $445 million (including approximately $15 million attributable to the noncontrolling interest in Eureka Midstream). If the MVP project were to be completed in 2023, the Company expects it would make total capital contributions to the MVP Joint Venture in 2023 of approximately $610 million to $660 million primarily related to forward construction or, if no forward construction were to occur in 2023, the Company expects it would make total capital contributions to the MVP Joint Venture in 2023 of approximately $150 million to $200 million, primarily related to right-of-way maintenance and environmental compliance measures. Capital contributions payable to the MVP Joint Venture are accrued upon the issuance of a capital call by the MVP Joint Venture. The Company's short-term and long-term capital investments may vary significantly from period to period based on the available investment opportunities, the timing of the construction of the MVP, MVP Southgate and other projects, and maintenance needs. The Company expects to fund short-term and long-term capital expenditures and capital contributions primarily through cash on hand, cash generated from operations, available borrowings under its subsidiaries' credit facilities and its access to banking and capital markets.
Credit Facility Borrowings
See Note 10 to the consolidated financial statements for discussion of the Amended EQM Credit Facility and the 2021 Eureka Credit Facility.
Security Ratings
The table below sets forth the credit ratings for EQM's debt instruments at December 31, 2022.
EQM
Senior Notes
Rating Service Rating Outlook
Moody's
Ba3 Stable
S&P
BB- Negative
Fitch
BB Negative
On September 30, 2022, Moody's affirmed EQM's rating of Ba3 and revised EQM's outlook from negative to stable. In connection with the issuance of the 2022 Notes each of Moody's, S&P and Fitch affirmed EQM's credit ratings. EQM's credit ratings are subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. The Company cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in its judgment, circumstances so warrant. If any credit rating agency downgrades or withdraws EQM's ratings, including for reasons relating to the MVP project (such as delays affecting the MVP project or increases in such project’s targeted costs), EQM’s leverage or credit ratings of the Company's customers, the Company's access to the capital markets could become more challenging, borrowing costs will likely increase, the Company may be required to provide additional credit assurances (the amount of which may be substantial), in support of commercial agreements such as joint venture agreements, and the potential pool of investors and funding sources may decrease. In order to be considered investment grade, a company must be rated Baa3 or higher by Moody's, BBB- or higher by S&P, or BBB- or higher by Fitch. All of EQM's credit ratings are considered non-investment grade.
Commitments and Contingencies
From time to time, various legal and regulatory claims and proceedings are pending or threatened against the Company and its subsidiaries. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accrues legal and other direct costs related to loss contingencies when incurred. The Company establishes reserves whenever it believes it to be appropriate for pending matters. Furthermore, after consultation with counsel and considering the availability, if any, of insurance, the Company believes, although no assurance can be given, that the ultimate outcome of any matter currently pending against it or any of its consolidated subsidiaries will not materially adversely affect its business, financial condition, results of operations, liquidity or ability to pay dividends to its shareholders.
See "The regulatory approval process for the construction of new midstream assets is very challenging, has significantly increased costs and delayed then-targeted in-service dates, and decisions by regulatory and judicial authorities in pending or potential proceedings, particularly with respect to litigation in the Fourth Circuit regarding MVP, are likely to impact our or the MVP Joint Venture's ability to obtain or maintain in effect all approvals and authorizations necessary to complete certain projects in a timely manner or at all or our ability to achieve the expected investment returns on the projects." and "The November 2022 incident involving the venting of natural gas from a well at Equitrans, L.P.'s Rager Mountain natural gas storage facility required that we incur costs and expenses to halt such venting, and investigate and respond to the incident, including undertaking ongoing reviews of other storage assets. Activities and investigations responsive to the incident are ongoing, and, consequently, we are incurring and in the future we expect to incur further costs and expenses, whether resulting from or arising out of the incident, which could, depending on their scope and timing, materially adversely affect our business, financial condition, results of operations, liquidity and ability to pay dividends to our shareholders." under Part I, "Item 1A. Risk Factors," and Part I, "Item 3. Legal Proceedings" of this Annual Report on Form 10-K for discussion of litigation and regulatory proceedings, including related to the MVP project and the Rager Mountain natural gas storage field incident.
See Note 15 to the consolidated financial statements for further discussion of the Company's commitments and contingencies.
Dividends
On February 14, 2023, the Company paid cash dividends for the fourth quarter of 2022 of $0.15 per common share and $0.4873 per Equitrans Midstream Preferred Share to shareholders of record at the close of business on February 6, 2023.
Recently Issued Accounting Standards
Recently issued accounting standards relevant to the Company are described in Note 1 to the consolidated financial statements.
Critical Accounting Estimates
The Company's critical accounting policies are described in Note 1 to the consolidated financial statements, which have been prepared in accordance with GAAP. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to the Company's consolidated financial statements. Preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts in the Company's consolidated financial statements and accompanying notes. The Company's critical accounting policies are considered critical due to the significant judgments and estimates used in the preparation of the Company's consolidated financial statements and the material impact on the results of operations or financial condition. Actual results could differ from those judgments and estimates.
Property, Plant and Equipment. Determination of depreciation expense requires judgment regarding the estimated useful lives and salvage values of property, plant and equipment. The Company has not historically experienced material changes in its results of operations from changes in the estimated useful lives or salvage values of its property, plant and equipment; however, these estimates are reviewed periodically, including each time Equitrans, L.P. files with the FERC for a change in its transmission, storage and gathering rates. The Company believes that the accounting estimate related to depreciation is a "critical accounting estimate" because the assumptions used to estimate useful lives and salvage values of property, plant and equipment are susceptible to change. These assumptions affect depreciation expense and, if changed, could have a material effect on the Company's results of operations and financial position. See Note 1 to the consolidated financial statements for additional information.
Impairments of Long-Lived Assets and Equity Method Investment. 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 been and may be different from estimated levels.
Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business. Goodwill is evaluated for impairment at least annually or whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Company uses a combination of an income and market approach to estimate the fair value of its reporting units.
The Company believes that the accounting estimates related to impairments are "critical accounting estimates" because they require assumptions that are susceptible to change, including estimating fair value which requires considerable judgment. For example, in the case of goodwill, management’s estimate of a reporting unit’s future financial results is sensitive to changes in assumptions, such as changes in the Company's stock price, weighted-average cost of capital, terminal growth rates and industry multiples. The Company believes the estimates and assumptions used in estimating its reporting units’ fair values as of December 31, 2022 are reasonable and appropriate; however, different assumptions and estimates could materially affect the calculated fair value and the resulting conclusion of whether goodwill is impaired, which could materially affect the Company’s results of operations and financial position.
The Company’s investment in unconsolidated entities also requires considerable judgment to estimate fair value because the Company’s investment is not traded on an active market. When estimating the fair value of its equity method investment, the Company utilizes an income approach under which significant judgments and assumptions, including the discount rate and probability-weighted scenarios, are sensitive to change. Additionally, the Company's investment in unconsolidated entities is susceptible to impairment risk from further adverse macroeconomic conditions and/or other adverse factors (such as, in the case of the Company's equity investment in the MVP Joint Venture, permitting and litigation matters impacting the MVP project). 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 the fair value of its equity investment in the MVP Joint Venture, which could result in an incremental other-than-temporary impairment of that investment. While macroeconomic factors in and of themselves may not be a direct indicator of impairment, should an impairment indicator be identified in the future, macroeconomic factors such as changes in interest rates could ultimately impact the size and scope of any potential impairment.
See Notes 1 and 3 to the consolidated financial statements for additional information.
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 and ARCs. Variable consideration is generally dependent on volumes and recognized in the period they occur. At each reporting date and, as circumstances or events warrant, management reviews and updates the assumptions utilized to estimate the total consideration for all contracts. The Company allocates the transaction price to each performance obligation based on the estimated 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 or ARCs. If a customer under such an agreement fails to meet its MVC or ARC 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 volumes and the MVC or ARC 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 or ARC period.
Revenue related to services provided but not yet billed is estimated each month. These estimates are generally based on contract data, preliminary throughput and allocation measurements. Final amounts for the current month are billed and collected in the following month. See Note 5 to the consolidated financial statements for additional information.
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 allowance, 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, a decline in the market price for natural gas affecting producer activity combined with additional customers on the Company's systems may result in a greater exposure to potential losses than management's current estimates.
The Company believes that the accounting estimates related to revenue recognition are "critical accounting estimates" because estimated relative standalone selling prices and volumes are subject to change based on actual measurements. In addition, the Company believes that the accounting estimates related to the allowance for credit losses are "critical accounting estimates" because the underlying assumptions used for the allowance can change and the actual mix of customers and their ability to pay may vary significantly from management's estimates, which could affect the collectability of customer receivables. These accounting estimates could potentially have a material effect on the Company's results of operations and financial position.
Income Taxes. The Company recognizes deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the Company's consolidated financial statements or tax returns.
The Company has federal and state net operating loss (NOL) carryforwards related to federal and various state jurisdictions. The federal, commonwealth of Virginia and state of 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 between 2038 and 2041. In addition to the NOL carryforwards, the Company has deferred tax assets and liabilities principally resulting from its investment in partnerships.
Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not (greater than 50%) that a tax benefit will not be realized. In evaluating the need for a valuation allowance, management considers available evidence, both positive and negative, including potential sources of taxable income, income available in carry-back periods, future reversals of taxable temporary differences, projections of taxable income and income from tax planning strategies. Positive evidence includes reversing temporary differences and projection of future profitability within the carry-forward period, including from tax planning strategies. Negative evidence includes historical pre-tax book losses and Pennsylvania NOL expirations.
Deferred tax assets for which no valuation allowance is recorded may not be realized, and changes in facts and circumstances may result in the establishment of a valuation allowance. Existing valuation allowances are re-examined under the same standards of positive and negative evidence that apply to valuation allowance establishment. If it is determined that it is more likely than not that a deferred tax asset for which a valuation allowance is recorded will be realized, all or a portion of the valuation allowance may be released. Deferred tax assets and liabilities are also remeasured to reflect changes in underlying tax rates from tax law changes. Any determination to change the valuation allowance would impact the Company's income tax expense (benefit) in the period in which such a determination is made.
The Company believes that accounting estimates related to income taxes are "critical accounting estimates" because the Company must assess the likelihood that deferred tax assets will be recovered from future taxable income, and exercise judgment when evaluating whether or not a valuation allowance must be established on deferred tax assets. As of December 31, 2022, the Company had valuation allowances related to federal and state NOL, federal and state interest disallowance under Internal Revenue Code Section 163(j) and its investment in partnership deferred tax assets. The Company records the impact of valuation allowances or any uncertain tax position within income tax expense (benefit) on the statements of consolidated comprehensive income. See Note 13 to the consolidated financial statements for additional information.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
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. The Amended EQM Credit Facility and the 2021 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 EQM Credit Facility are impacted by changes in EQM's credit ratings (which changes may be caused by factors outside of EQM's control). Eureka's interest rates under the 2021 Eureka Credit Facility are impacted by changes in Eureka's Consolidated Leverage Ratio (as defined in the 2021 Eureka Credit Facility) which may fluctuate based on Eureka Midstream's distributions to its members, liquidity needs or operating results. Accordingly, if interest rates were to increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash flows, including cash available for servicing our indebtedness, will correspondingly decrease. Based on commitments as of the Earlier Maturity Date (as defined in Note 10) and assuming all loans are fully drawn, each quarter point change in interest rates would result in a change of approximately $5.4 million in annual interest expense on indebtedness under the Amended EQM Credit Facility. Assuming all loans are fully drawn, each quarter point change in interest rates would result in a change of approximately $1.0 million in annual interest expense on indebtedness under the 2021 Eureka Credit Facility. Further, regarding the dividend payable on Equitrans Midstream Preferred Shares after March 31, 2024, changes in interest rates and/or the reference rate ultimately utilized to replace the London Interbank Offered Rate (LIBOR) in connection with determining such dividend, may affect such dividend (which will not be less than 10.50% under the Company's Second Amended and Restated Articles of Incorporation), which could affect the amount of cash the Company has available to make quarterly cash dividends to its shareholders. 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 2, 10 and 11 to the consolidated financial statements for discussions of the dividend payable on the Equitrans Midstream Preferred Shares after March 31, 2024, borrowings and fair value measurements, respectively. EQM and Eureka may from time to time hedge the interest on portions of borrowings under the revolving credit facilities, as applicable, in order to manage risks associated with floating interest rates. However, the Company may not maintain hedges with respect to all of its variable rate indebtedness, and any hedges it enters into may not fully mitigate its 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 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.
The Company is exposed to the credit risk of its customers, including its largest customer, EQT, including as a result of changes in customer credit ratings, liquidity and access to capital markets. At December 31, 2022, EQT's public senior debt had investment grade credit ratings from S&P and Fitch and a non-investment grade credit rating from Moody's. See "Credit Letter Agreement" included in Part I, "Item 1. Business" of this Annual Report on Form 10-K for information regarding the Credit Letter Agreement and associated EQT credit rating requirements. In addition, EQT has guaranteed the payment obligations of certain of its subsidiaries, up to a maximum amount of $115 million, $131 million and $30 million related to gathering, transmission and water services, respectively, across all applicable contracts, for the benefit of the subsidiaries of the Company providing such services. See Note 14 to the consolidated financial statements for further discussion of the Company's exposure to certain credit risks.
Commodity Prices. The Company's business is dependent on continued natural gas production and the availability and development of reserves in its areas of operation. Prices for natural gas and NGLs, including regional basis differentials, have previously adversely affected, and may in the future adversely affect, timing of development of additional reserves and production that is accessible by the Company’s pipeline and storage assets, which also negatively affects the Company’s water services business, and the creditworthiness of the Company’s customers.
Increases in natural gas prices do not necessarily result in corresponding increases to the production forecasts of the Company's customers and, as of the date of the filing of this Annual Report on Form 10-K, the Company's largest customers have continued to maintain their production forecasts without significant increases. Even at commercially attractive natural gas prices, certain of the Company's customers have maintained largely flat production forecasts in light of, among other things, the absence of incremental takeaway capacity from the Appalachian Basin and the Company's customers may still maintain flat or modest increases to production forecasts based on various factors, which could include regional takeaway capacity limitations, access to capital, investor expectations regarding free cash flow, a desire to reduce or refinance leverage or other factors.
Additionally, prices may decline based on numerous factors, including levels of associated gas. See also “Decreases in production of natural gas in our areas of operation, whether as a result of producer corporate capital allocation strategies, lower regional natural gas prices, regional takeaway constraints, and/or other factors, have adversely affected, and in the future could adversely affect, our business and operating results and reduce our cash available to pay cash dividends to our shareholders.” and "The lack of diversification of our assets and geographic locations could adversely affect us." under Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K. Additionally, lower natural gas prices (including regionally), corporate capital allocation strategies or regional takeaway constraints, could cause producers to determine in the future that drilling activities in areas outside of the Company's current areas of operation are strategically more attractive to them.
Many of the Company’s customers, including EQT, have entered into long-term firm reservation gathering, transmission and water contracts or contracts with MVCs on the Company's systems and approximately 71% of the Company's operating revenues for the year ended December 31, 2022 was generated by firm reservation fee revenues. The Company believes that such contract structure is advantageous to its overall business, although significant declines in gas production in the Company's areas of operations would likely adversely affect the Company's results of operations, financial condition and liquidity as approximately 29% of the Company’s operating revenues for the year ended December 31, 2022 was generated by volumetric-based fee revenues. See "Our exposure to direct commodity price risk may increase in the future and NYMEX Henry Hub futures prices affect the fair value, and may affect the realizability, of potential cash payments to us by EQT pursuant to the EQT Global GGA." and “We generate a substantial majority of our revenues from EQT. Therefore, we are subject to business and liquidity risks of EQT, and any decrease in EQT’s drilling or completion activity (or significant production curtailments) or a shift in such activity away from our assets could adversely affect our business and operating results. Various factors have affected and may further affect our ability to realize the benefits we believe associated with the EQT Global GGA at the time of its execution." under Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.
Price declines and sustained periods of low natural gas and NGL prices could 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, as discussed above, activity levels and, accordingly, volumetric-based fees, which could affect the Company’s results of operations, liquidity or financial position. Credit risk and related management is further discussed above under “Credit Risk” in Part II, “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” of this Annual Report on Form 10-K.
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, gathered or provided on its systems above MVC levels will be dependent on receiving consistent or increasing commitments and production from its existing customers, which may be impacted by regional takeaway capacity limitations, commodity prices, including regional commodity prices, and/or other factors, including corporate capital allocation strategies. While EQT has dedicated a substantial portion of its core acreage in southwestern Pennsylvania and West Virginia 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 or otherwise strategically determine to curtail volumes on the Company's systems. 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 5 to the consolidated financial statements and "Outlook" included in Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of the EQT Global GGA and the 2021 Water Services Agreement.
The fair value of the Company’s derivative instruments is, in part, determined by estimates of the NYMEX Henry Hub natural gas forward price curve. A hypothetical 10% increase in NYMEX Henry Hub natural gas futures prices would increase the valuation of the Company’s derivative instruments by approximately $1.9 million, while a hypothetical 10% decrease in NYMEX Henry Hub natural gas futures prices would decrease the valuation of the Company’s derivative instruments by approximately $2.2 million. This fair value change assumes volatility based on prevailing market parameters at December 31, 2022. See Notes 5 and 11 to the consolidated financial statements for a discussion of the Henry Hub cash bonus payment provision.
For further discussion of commodity prices and related risks, see "Our exposure to direct commodity price risk may increase in the future and NYMEX Henry Hub futures prices affect the fair value, and may affect the realizability, of potential cash payments to us by EQT pursuant to the EQT Global GGA," and "Decreases in production of natural gas in our areas of operation, whether as a result of producer corporate capital allocation strategies, lower regional natural gas prices, regional takeaway constraints, and/or other factors, have adversely affected, and in the future could adversely affect, our business and operating results and reduce our cash available to pay cash dividends to our shareholders," and "The lack of diversification of our assets and geographic locations could adversely affect us." under Part I, "Item 1A. Risk Factors" of this Annual Report on Form 10-K.
Other Market Risks. The Amended EQM Credit Facility is underwritten by a syndicate of 21 financial institutions until the Earlier Maturity Date, and a syndicate of 14 financial institutions from the Earlier Maturity Date through the Later Maturity Date (as defined in Note 10). The 2021 Eureka Credit Facility is underwritten by a syndicate of 16 financial institutions. Each financial institution is obligated to fund its pro rata portion of any borrowings by EQM or Eureka, as applicable. In each case, no one lender of the financial institutions in the syndicate holds more than 10% of such facility. EQM's and Eureka's respective large syndicate groups and relatively low percentage of participation by each lender is expected to limit the Company's and Eureka's respective exposure to disruption or consolidation in the banking industry. See Note 10 to the consolidated financial statements for further details.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
Page No.
Reports of Independent Registered Public Accounting Firm (PCAOB ID: 42)
Statements of Consolidated Comprehensive Income for the Years Ended December 31, 2022, 2021 and 2020 94
Statements of Consolidated Cash Flows for the Years Ended December 31, 2022, 2021 and 2020 95
Consolidated Balance Sheets as of December 31, 2022 and 2021 96
Statements of Consolidated Shareholders' Equity and Mezzanine Equity for the Years Ended December 31, 2022, 2021 and 2020 97
Notes to Consolidated Financial Statements 98
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of Equitrans Midstream Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Equitrans Midstream Corporation (the Company) as of December 31, 2022 and 2021, the related statements of consolidated comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2022, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 21, 2023 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Valuation of EQM OpCo Reporting Unit Goodwill
Description of the Matter At December 31, 2022, the Company had goodwill of approximately $486.7 million related to the EQM Gathering Opco, LLC reporting unit. As discussed in Notes 1 and 3 to the consolidated financial statements, goodwill is evaluated for impairment at least annually and whenever events or changes in circumstance indicate 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, 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. 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 test for the reporting unit associated with EQM Gathering Opco, LLC 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 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 reporting unit associated with EQM Gathering Opco, LLC for which a quantitative impairment test was 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 reporting unit goodwill associated with EQM Gathering Opco, LLC described in Note 3 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, 2022, the Company has an investment in the MVP Joint Venture of approximately $828.2 million. As discussed in Notes 1, 3, and 8 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 charge equal to the difference between the investment's carrying value and fair value. During the year ended December 31, 2022, the Company evaluated its investment in the MVP Joint Venture for impairment. As described in Notes 3 and 8 to the consolidated financial statements, during the third quarter 2022 assessment the Company identified an increased risk of further permitting delays resulting primarily from legal developments and regulatory uncertainties, as well as macroeconomic pressures primarily due to an increase in interest rates impacting the discount rate used within the estimated fair value of its investment in the MVP Joint Venture. The Company considered these factors to be indicators of a decline in value. As such, the Company evaluated if the carrying value of its equity method investment in the MVP Joint Venture exceeded the fair value and, if so, whether that decline in value was other-than-temporary, and thus the equity method investment was impaired under ASC 323. The Company estimated the fair value of its investment in the MVP Joint Venture using an income approach. As a result of the assessment, the Company recognized a pre-tax impairment charge of approximately $583 million. 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 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 assessed 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 and management’s plans to resolve outstanding permitting issues. We evaluated both supporting and contrary evidence. 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 3 and 8 to the consolidated financial statements.
/s/ Ernst & Young LLP
We have served as the Company's auditor since 2018.
Pittsburgh, Pennsylvania
February 21, 2023
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of Equitrans Midstream Corporation
Opinion on Internal Control over Financial Reporting
We have audited Equitrans Midstream Corporation's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Equitrans Midstream Corporation (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2022 and 2021, the related statements of consolidated comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2022 and the related notes and our report dated February 21, 2023 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
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.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
February 21, 2023
EQUITRANS MIDSTREAM CORPORATION
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31,
2022 2021 2020
(Thousands, except per share amounts)
Operating revenues $ 1,357,747 $ 1,317,037 $ 1,510,825
Operating expenses:
Operating and maintenance 154,667 153,179 154,109
Selling, general and administrative 128,472 137,056 129,969
Transaction costs - - 23,797
Depreciation 272,195 270,404 259,613
Amortization of intangible assets 64,819 64,819 63,195
Impairments of long-lived assets - 56,178 55,581
Total operating expenses 620,153 681,636 686,264
Operating income 737,594 635,401 824,561
Equity income (a)
168 17,579 233,833
Impairments of equity method investment (583,057) (1,926,402) -
Other income (expense), net 13,871 (47,546) 10,427
Loss on extinguishment of debt (24,937) (41,025) (24,864)
Net interest expense (394,333) (378,650) (307,380)
(Loss) income before income taxes (250,694) (1,740,643) 736,577
Income tax expense (benefit) 6,444 (343,353) 103,593
Net (loss) income (257,138) (1,397,290) 632,984
Net income attributable to noncontrolling interests 12,204 14,530 214,912
Net (loss) income attributable to Equitrans Midstream (269,342) (1,411,820) 418,072
Preferred dividends 58,512 58,512 58,760
Net (loss) income attributable to Equitrans Midstream common shareholders $ (327,854) $ (1,470,332) $ 359,312
(Loss) earnings per share of common stock attributable to Equitrans Midstream common shareholders - basic
$ (0.76) $ (3.40) $ 1.04
(Loss) earnings per share of common stock attributable to Equitrans Midstream common shareholders - diluted $ (0.76) $ (3.40) $ 1.04
Weighted average common shares outstanding - basic 433,341 433,008 343,935
Weighted average common shares outstanding - diluted 433,341 433,008 343,975
Net (loss) income $ (257,138) $ (1,397,290) $ 632,984
Other comprehensive loss, net of tax:
Pension and other post-retirement benefits liability adjustment, net of tax expense (benefit) of $236, $62 and $(70)
722 175 (203)
Other comprehensive income (loss) 722 175 (203)
Comprehensive (loss) income (256,416) (1,397,115) 632,781
Less: Comprehensive income attributable to noncontrolling interests 12,204 14,530 214,912
Less: Comprehensive income attributable to preferred dividends 58,512 58,512 58,760
Comprehensive (loss) income attributable to Equitrans Midstream common shareholders $ (327,132) $ (1,470,157) $ 359,109
Dividends declared per common share $ 0.60 $ 0.60 $ 0.60
(a)Represents equity income from Mountain Valley Pipeline, LLC (the MVP Joint Venture). See Note 8.
The accompanying notes are an integral part of these consolidated financial statements.
EQUITRANS MIDSTREAM CORPORATION
STATEMENTS OF CONSOLIDATED CASH FLOWS
YEARS ENDED DECEMBER 31,
2022 2021 2020
(Thousands)
Cash flows from operating activities:
Net (loss) income $ (257,138) $ (1,397,290) $ 632,984
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation 272,195 270,404 259,613
Amortization of intangible assets 64,819 64,819 63,195
Deferred income taxes 5,472 (348,206) 100,980
Impairments of long-lived assets and equity method investments 583,057 1,982,580 55,581
Equity income (a)
(168) (17,579) (233,833)
Other (income) expense, net (13,644) 47,485 (10,480)
Loss on extinguishment of debt 24,937 41,025 24,864
Non-cash long-term compensation expense 15,800 13,083 12,301
Changes in other assets and liabilities:
Accounts receivable 22,858 64,172 (37,810)
Accounts payable 12,667 (2,709) (7,922)
Accrued interest (16,147) 25,718 52,736
Deferred revenue 346,491 423,666 225,746
EQT Cash Option (195,820) - -
Other assets and other liabilities (19,604) 1,600 2,931
Net cash provided by operating activities 845,775 1,168,768 1,140,886
Cash flows from investing activities:
Capital expenditures (376,661) (290,521) (462,031)
Capital contributions to the MVP Joint Venture (199,613) (287,665) (272,801)
Principal payments received on the Preferred Interest (defined in Note 1) 5,518 5,217 5,003
Proceeds from sale of gathering assets 3,719 - -
Net cash used in investing activities (567,037) (572,969) (729,829)
Cash flows from financing activities:
Proceeds from revolving credit facility borrowings 554,500 467,500 1,965,000
Payments on revolving credit facility borrowings (524,500) (750,000) (2,080,000)
Proceeds from issuance of long-term debt 1,000,000 1,900,000 1,600,000
Debt discounts, debt issuance costs and credit facility arrangement fees (19,880) (29,904) (26,720)
Payments for retirement of long-term debt (1,021,459) (1,936,250) (594,000)
Distributions paid to noncontrolling interests (16,000) (2,500) (128,770)
Dividends paid to holders of Equitrans Midstream Preferred Shares (58,512) (58,512) (16,879)
Dividends paid to common shareholders (259,650) (259,495) (278,395)
Redemption of EQM Series A Preferred Units (defined in Note 1) - - (617,338)
Distributions paid to holders of EQM Series A Preferred Units - - (61,931)
Cash Shares and Cash Amount (defined in Note 5)
- - (52,323)
Net cash used in financing activities (345,501) (669,161) (291,356)
Net change in cash and cash equivalents (66,763) (73,362) 119,701
Cash and cash equivalents at beginning of year 134,661 208,023 88,322
Cash and cash equivalents at end of year $ 67,898 $ 134,661 $ 208,023
Cash paid during the year for:
Interest, net of amount capitalized $ 401,156 $ 343,351 $ 249,302
Income taxes 1,243 3,500 3,709
Non-cash activity during the period for:
Issuance of Equitrans Midstream common stock pursuant to the EQM Merger (defined in Note 1), net of tax $ - $ - $ 2,736,229
Issuance of Equitrans Midstream Preferred Shares pursuant to the Restructuring Agreement - - 667,214
Contract liability - - 121,483
The accompanying notes are an integral part of these consolidated financial statements.
(a) Represents equity income from the MVP Joint Venture. See Note 8.
EQUITRANS MIDSTREAM CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
2022 2021
(Thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 67,898 $ 134,661
Accounts receivable (net of allowance for credit losses of $3,031 and $2,696 as of December 31, 2022 and 2021, respectively)
246,887 252,301
Other current assets 74,917 59,867
Total current assets 389,702 446,829
Property, plant and equipment 9,365,051 9,004,602
Less: accumulated depreciation (1,480,720) (1,217,099)
Net property, plant and equipment 7,884,331 7,787,503
Investments in unconsolidated entities (a)
819,743 1,239,039
Goodwill 486,698 486,698
Net intangible assets 586,952 651,771
Other assets 278,159 270,684
Total assets $ 10,445,585 $ 10,882,524
LIABILITIES, MEZZANINE EQUITY AND SHAREHOLDERS' EQUITY
Current liabilities:
Current portion of long-term debt $ 98,830 $ -
Accounts payable 60,528 59,627
Capital contributions payable to the MVP Joint Venture 34,355 72,188
Accrued interest 135,762 151,909
Accrued liabilities 83,835 83,852
Total current liabilities 413,310 367,576
Long-term liabilities:
Revolving credit facility borrowings 535,000 505,000
Long-term debt 6,335,320 6,434,945
Contract liability 968,535 821,342
Regulatory and other long-term liabilities 112,974 99,333
Total liabilities 8,365,139 8,228,196
Mezzanine equity:
Equitrans Midstream Preferred Shares, 30,018 shares issued and outstanding as of December 31, 2022 and 2021
681,842 681,842
Shareholders' equity:
Common stock, no par value, 432,781 and 432,522 shares issued and outstanding as of December 31, 2022 and 2021, respectively
3,974,127 3,955,918
Retained deficit (3,053,590) (2,464,573)
Accumulated other comprehensive loss (1,332) (2,054)
Total common shareholders' equity 919,205 1,489,291
Noncontrolling interests 479,399 483,195
Total shareholders' equity 1,398,604 1,972,486
Total liabilities, mezzanine equity and shareholders' equity $ 10,445,585 $ 10,882,524
(a) Represents investment in the MVP Joint Venture. See Note 8.
The accompanying notes are an integral part of these consolidated financial statements.
EQUITRANS MIDSTREAM CORPORATION
STATEMENTS OF CONSOLIDATED SHAREHOLDERS' EQUITY AND MEZZANINE EQUITY
Mezzanine
Common Stock Equity
Accumulated Other Equitrans
Retained Midstream
Shares No Earnings Comprehensive Noncontrolling Total Preferred
Outstanding Par Value (Deficit) Loss Interests Equity Shares
(Thousands, except per unit and share amounts)
Balance at January 1, 2020 254,745 $ 1,292,804 $ (618,062) $ (2,026) $ 4,609,364 $ 5,282,080 $ -
Other comprehensive income (net of tax):
Net income - - 386,565 - 214,912 601,477 31,507
Pension and other post-retirement benefits liability adjustment, net of tax benefit of $(70)
- - - (203) - (203) -
Dividends on common shares ($0.90 per share)
(178) - (280,559) - - (280,559) -
Share-based compensation plans, net 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)
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 5)
(25,300) - (190,992) - - (190,992) -
Adoption of Topic 326 - - (3,718) - - (3,718) -
Balance at December 31, 2020 432,470 $ 3,941,295 $ (734,019) $ (2,229) $ 471,165 $ 3,676,212 $ 681,842
Other comprehensive income (net of tax):
Net (loss) income - - (1,470,332) - 14,530 (1,455,802) 58,512
Pension and other post-retirement benefits liability adjustment, net of tax expense of $62
- - - 175 - 175 -
Dividends on common shares ($0.60 per share)
- - (260,222) - - (260,222) -
Share-based compensation plans, net 52 14,623 - - - 14,623 -
Distributions paid to noncontrolling interest in Eureka Midstream Holdings, LLC - - - - (2,500) (2,500) -
Dividends paid to holders of Equitrans Midstream Preferred Shares ($1.9492 per share)
- - - - - - (58,512)
Balance at December 31, 2021 432,522 $ 3,955,918 $ (2,464,573) $ (2,054) $ 483,195 $ 1,972,486 $ 681,842
Other comprehensive income (net of tax):
Net (loss) income - - (327,854) - 12,204 (315,650) 58,512
Pension and other post-retirement benefits liability adjustment, net of tax expense of $236
- - - 722 - 722 -
Dividends on common shares ($0.60 per share)
- - (261,163) - - (261,163) -
Share-based compensation plans, net 259 18,209 - - - 18,209 -
Distributions paid to noncontrolling interest in Eureka Midstream Holdings, LLC - - - - (16,000) (16,000) -
Dividends paid to holders of Equitrans Midstream Preferred Shares ($1.9492 per share)
- - - - - - (58,512)
Balance at December 31, 2022 432,781 $ 3,974,127 $ (3,053,590) $ (1,332) $ 479,399 $ 1,398,604 $ 681,842
The accompanying notes are an integral part of these consolidated financial statements.
EQUITRANS MIDSTREAM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2022
1. Summary of Operations and Significant Accounting Policies
Organization
Equitrans Midstream Corporation (together with its consolidated subsidiaries as applicable, the Company or Equitrans Midstream), a Pennsylvania corporation, is an independent, publicly traded company that owns, operates, acquires and develops midstream assets, in and originating from the Appalachian Basin. The Company's operating subsidiaries hold the majority of the Company's assets and there are substantially no assets at the Equitrans Midstream stand alone entity.
On November 12, 2018, the Company, EQT Corporation (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), 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. During April 2022, EQT sold the last of its remaining shares in Equitrans Midstream and, based solely on information reported by EQT in a Schedule 13G/A filed with the SEC on April 28, 2022, EQT no longer holds any common stock of the Company.
Immediately following the Separation, the Company held investments in the entities then-conducting the Midstream Business, including limited and general partner interests in EQGP Holdings, LP (EQGP), which, as of the date of Separation, owned limited partner interests, the entire general partner interest and all of the incentive distribution rights (IDRs) in EQM Midstream Partners, LP (EQM). On January 10, 2019, following the Company's acquisition of 100% of the limited partner interests in EQGP in January 2019 (the EQGP Buyout), EQGP became an indirect, wholly owned subsidiary of the Company.
EQGP Services, LLC is EQM's general partner (the EQM General Partner) and is an indirect, wholly owned subsidiary of Equitrans Midstream.
EQM Merger. On June 17, 2020, pursuant to that certain Agreement and Plan of Merger, dated as of February 26, 2020 (the EQM Merger Agreement), by and among the Company, EQM LP LLC (formerly, EQM LP Corporation), a wholly owned subsidiary of the Company (EQM LP), LS Merger Sub, LLC, a wholly owned subsidiary of EQM LP (Merger Sub), EQM and the EQM General Partner, Merger Sub merged with and into EQM (the EQM Merger), with EQM continuing and surviving as an indirect, wholly owned subsidiary of the Company. Upon consummation of the EQM Merger, the Company acquired all of the outstanding EQM common units that the Company and its subsidiaries did not already own. Following the closing of the EQM Merger, EQM was no longer a publicly traded entity. See Note 2 for further information on the EQM Merger.
Preferred Restructuring Agreement. On February 26, 2020, Equitrans Midstream and EQM entered into a Preferred Restructuring Agreement (the Restructuring Agreement) with all of the holders of the Series A Perpetual Convertible Preferred Units representing limited partner interests in EQM (such units, EQM Series A Preferred Units and, such investors, collectively, the Investors), pursuant to which, at the effective time of the EQM Merger (the Effective Time): (i) EQM redeemed $600 million aggregate principal amount of the Investors' EQM Series A Preferred Units issued and outstanding immediately prior to the Restructuring Closing (as defined below), which occurred substantially concurrent with the closing of the EQM Merger, for cash at 101% of the EQM Series A Preferred Unit purchase price of $48.77 per such unit (the EQM Series A Preferred Unit Purchase Price) plus any accrued and unpaid distribution amounts and partial period distribution amounts, and (ii) immediately following such redemption, each remaining issued and outstanding EQM Series A Preferred Unit was exchanged for 2.44 shares of a newly authorized and created series of preferred stock, without par value, of Equitrans Midstream, convertible into Equitrans Midstream common stock (the Equitrans Midstream Preferred Shares) on a one for one basis, in each case, in connection with the occurrence of the “Series A Change of Control” (as defined in the Fourth Amended and Restated Agreement of Limited Partnership of EQM (as amended, the Former EQM Partnership Agreement)) that occurred upon the closing of the EQM Merger (collectively, the Restructuring and, the closing of the Restructuring, the Restructuring Closing). See Note 2 for further information on the Restructuring Agreement.
Nature of Business
The Company's operating subsidiaries provide midstream services to the Company's customers in Pennsylvania, West Virginia and Ohio through three primary assets: the gathering system, which includes predominantly dry gas gathering systems of high-pressure gathering lines; the transmission system, which includes FERC-regulated interstate pipelines and storage systems; and the water network, which primarily consists of water pipelines and other facilities that support well completion activities and produced water handling activities.
As of December 31, 2022, the gathering system, inclusive of Eureka Midstream's gathering system, included approximately 1,180 miles of high-pressure gathering lines with total contracted firm reservation capacity of approximately 7.4 billion cubic feet (Bcf) per day, which included contracted firm reservation capacity of approximately 1.8 Bcf per day associated with the Company's high-pressure header pipelines, 135 compressor units with compression of approximately 493,000 horsepower and multiple interconnect points with the Company's transmission and storage system and to other interstate pipelines.
As of December 31, 2022, the transmission and storage system included approximately 940 miles of FERC-regulated, interstate pipelines that have interconnect points to seven interstate pipelines and multiple local distribution companies (LDCs). The transmission and storage system is supported by 43 compressor units, with total throughput capacity of approximately 4.4 Bcf per day and compression of approximately 136,000 horsepower, and 18 associated natural gas storage reservoirs, which have a peak withdrawal capacity of approximately 820 million cubic feet (MMcf) per day and a working gas capacity of approximately 43 Bcf, in each case as of December 31, 2022.
As of December 31, 2022, the Company's fresh water systems included approximately 201 miles of pipelines that deliver fresh water from local municipal water authorities, the Monongahela River, the Ohio River, local reservoirs and several regional waterways. The fresh water delivery services systems consist of permanent, buried pipelines, surface pipelines, 21 fresh water impoundment facilities, as well as pumping stations, which support water transportation throughout the systems, and take point facilities and measurement facilities, which support well completion activities. The mixed water system, upon completion, is designed to include approximately 70 miles of buried pipeline and two water storage facilities with 350,000 barrels of capacity, as well as two interconnects with the Company’s existing Pennsylvania fresh water systems and provides services to producers in southwestern Pennsylvania. The Company expects the remaining portions of the mixed water system to be substantially complete in 2023.
Revisions of Previously Issued Financial Statements
In the course of its year-end 2022 process, the Company identified certain corrections in its previously issued consolidated financial statements primarily related to the accounting for the Henry Hub cash bonus payment provision (as defined in Note 11).
In accordance with Staff Accounting Bulletin (SAB) No. 99, Materiality, and SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, the Company evaluated the corrections and, based on its analysis of quantitative and qualitative factors, determined that the related impact was not material to the Company's 2021 and 2020 audited consolidated financial statements or those of its affected unaudited interim consolidated financial statements in 2022, 2021 and 2020. The Company has made the appropriate revisions to its previously issued consolidated financial statements in order to correct the Henry Hub cash bonus payment provision. The Company also made other immaterial revisions to its 2021 audited consolidated financial statements, and the fourth quarter of 2021 and first quarter of 2022 unaudited interim consolidated financial statements.
The Company has revised its audited consolidated financial statements for the affected prior periods below and its unaudited interim consolidated financial statements for the affected prior periods in Note 16.
Statements of Consolidated Comprehensive Income
Year Ended December 31, 2021 Year Ended December 31, 2020
(in thousands, except per share amounts) As Reported Adjustment As Revised As Reported Adjustment As Revised
Operating and maintenance $ 153,426 $ (247) $ 153,179 $ 154,109 $ - $ 154,109
Selling, general and administrative 138,647 (1,591) 137,056 129,969 - 129,969
Total operating expenses 683,474 (1,838) 681,636 686,264 - 686,264
Operating income 633,563 1,838 635,401 824,561 - 824,561
Other (expense) income, net (16,104) (31,442) (47,546) 17,225 (6,798) 10,427
(Loss) income before income taxes (1,711,039) (29,604) (1,740,643) 743,375 (6,798) 736,577
Income tax (benefit) expense (345,091) 1,738 (343,353) 105,331 (1,738) 103,593
Net (loss) income (1,365,948) (31,342) (1,397,290) 638,044 (5,060) 632,984
Net (loss) income attributable to Equitrans Midstream (1,380,478) (31,342) (1,411,820) 423,132 (5,060) 418,072
Net (loss) income attributable to Equitrans Midstream common shareholders (1,438,990) (31,342) (1,470,332) 364,372 (5,060) 359,312
(Loss) earnings per share of common stock attributable to Equitrans Midstream common shareholders - basic (3.32) (0.08) (3.40) 1.06 (0.02) 1.04
(Loss) earnings per share of common stock attributable to Equitrans Midstream common shareholders - diluted (3.32) (0.08) (3.40) 1.06 (0.02) 1.04
Statements of Consolidated Cash Flows
Year Ended December 31, 2021 Year Ended December 31, 2020
(in thousands) As Reported Adjustment As Revised As Reported Adjustment As Revised
Net (loss) income $ (1,365,948) $ (31,342) $ (1,397,290) $ 638,044 $ (5,060) $ 632,984
Deferred income taxes (349,944) 1,738 (348,206) 102,718 (1,738) 100,980
Other expense (income), net 16,043 31,442 47,485 (17,278) 6,798 (10,480)
Non-cash long-term compensation expense 14,921 (1,838) 13,083 12,301 - 12,301
Net cash provided by operating activities 1,168,768 - 1,168,768 1,140,886 - 1,140,886
The revisions had no net effect on the Company's previously issued year ended 2021 and 2020 net cash flows from operating activities, investing activities or financing activities.
Consolidated Balance Sheets
December 31, 2021
(in thousands) As Reported Adjustment As Revised
Other assets $ 308,924 $ (38,240) $ 270,684
Total assets 10,920,764 (38,240) 10,882,524
Common stock, no par value 3,957,756 (1,838) 3,955,918
Retained deficit (2,428,171) (36,402) (2,464,573)
Total common shareholders' equity 1,527,531 (38,240) 1,489,291
Total shareholders' equity 2,010,726 (38,240) 1,972,486
Total liabilities, mezzanine equity and shareholders' equity 10,920,764 (38,240) 10,882,524
The revisions decreased total assets and retained earnings by approximately $7 million as of December 31, 2020.
Statements of Consolidated Shareholders' Equity and Mezzanine Equity
Common Stock
No Par Value Retained Earnings (Deficit) Total Equity
(in thousands) As Reported Adjustment As Revised As Reported Adjustment As Revised As Reported Adjustment As Revised
Balance at January 1, 2020 $ 1,292,804 $ - $ 1,292,804 $ (618,062) $ - $ (618,062) $ 5,282,080 $ - $ 5,282,080
Net income - - - 391,625 (5,060) 386,565 606,537 (5,060) 601,477
Balance at December 31, 2020 $ 3,941,295 $ - $ 3,941,295 $ (728,959) $ (5,060) $ (734,019) $ 3,681,272 $ (5,060) $ 3,676,212
Net (loss) - - - (1,438,990) (31,342) (1,470,332) (1,424,460) (31,342) (1,455,802)
Share-based compensation plans, net 16,461 (1,838) 14,623 - - - 16,461 (1,838) 14,623
Balance at December 31, 2021 $ 3,957,756 $ (1,838) $ 3,955,918 $ (2,428,171) $ (36,402) $ (2,464,573) $ 2,010,726 $ (38,240) $ 1,972,486
Significant Accounting Policies
Principles of Consolidation. The consolidated financial statements include the accounts of all entities in which the Company holds a controlling financial interest. For consolidated subsidiaries in which the Company’s ownership is less than 100%, the Company records noncontrolling interest related to the third-party ownership interests in those entities. Investments over which the Company can exert significant influence, but not control, over operating and financial policies are accounted for under the equity method of accounting. Intercompany transactions have been eliminated for purposes of preparing these consolidated financial statements. References in these financial statements to Equitrans Midstream or the Company refer collectively to Equitrans Midstream Corporation and its consolidated subsidiaries for all periods presented, unless otherwise indicated.
Segments. Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and is subject to evaluation by the Company's chief operating decision maker in deciding how to allocate resources. The Company reports its operations in three segments that reflect its three lines of business of Gathering, Transmission and Water. The operating segments are evaluated based on their contribution to the Company's operating income and equity income. Transmission also includes the Company's investment in the MVP Joint Venture, which is accounted for as an equity investment as described in Note 8; as a result, Transmission's portion of the MVP Joint Venture's operating results is reflected in equity income and not in Transmission's operating income. All of the Company's operating revenues, income and assets are generated or located in the United States. See Note 4 for financial information by segment.
Reclassification. Certain previously reported amounts have been reclassified to conform to current year presentation.
Use of Estimates. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect amounts reported in these financial statements. Actual results could differ from those estimates.
Cash Equivalents. The Company classifies highly-liquid investments with original maturities of three months or less as cash equivalents. Interest earned on cash equivalents is recorded as a reduction to net interest expense on the statements of consolidated comprehensive income.
Accounts Receivables. Trade and other receivables are stated at their historical carrying amount. Judgment is required to determine the ultimate realization of accounts receivable, including assessing the probability of collection and the creditworthiness of customers. The Company evaluates the allowance for credit losses on a quarterly basis in order to estimate uncollectible receivables.
Other Current Assets. The following table summarizes the Company's other current assets as of December 31, 2022 and 2021.
December 31,
(Thousands)
Unbilled revenue
$ 24,465 $ 15,931
Prepaid expenses
23,346 21,848
Inventory
19,173 20,347
Other current assets
7,933 1,741
Total other current assets
$ 74,917 $ 59,867
Derivative Instruments. Derivative instruments are recorded on the Company’s consolidated balance sheets as either an asset or liability measured at fair value. See Note 11.
Fair Value of Financial Instruments. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the reporting date. The Company’s assets and liabilities that are measured at fair value at each reporting date are classified according to a hierarchy that prioritizes inputs and assumptions underlying the valuation techniques. This fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs and consists of three broad levels:
•Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
•Level 2: Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date.
•Level 3: Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
The Company prioritizes valuation techniques that maximize the use of observable inputs. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each reporting period. See Note 11 for information regarding the fair value of financial instruments.
Property, Plant and Equipment. The Company's property, plant and equipment are stated at depreciated cost. Maintenance projects that do not increase the overall life of the related assets are expensed as incurred. Expenditures that extend the useful life of the asset are capitalized. The Company capitalized internal labor costs of $47.3 million, $50.8 million and $44.9 million in the years ended December 31, 2022, 2021 and 2020, respectively. The Company capitalized interest, including the debt component of Allowance for Funds Used During Construction (AFUDC), of $8.7 million, $4.9 million and $18.6 million in the years ended December 31, 2022, 2021 and 2020, respectively.
The following table summarizes the Company's property, plant and equipment.
December 31,
2022 2021
(Thousands)
Gathering assets $ 7,176,011 $ 6,911,268
Accumulated depreciation (919,465) (727,735)
Net gathering assets 6,256,546 6,183,533
Transmission and storage assets 1,928,894 1,901,756
Accumulated depreciation (475,688) (424,918)
Net transmission and storage assets 1,453,206 1,476,838
Water services assets 245,258 176,245
Accumulated depreciation (79,518) (60,379)
Net water services assets 165,740 115,866
Other property, plant and equipment 14,888 15,332
Accumulated depreciation (6,049) (4,066)
Net other property, plant and equipment 8,839 11,266
Net property, plant and equipment $ 7,884,331 $ 7,787,503
Property, plant and equipment includes capitalized qualified implementation costs incurred in a hosting arrangement that is a service contract of $9.0 million and $10.0 million, respectively, as of December 31, 2022 and 2021. The Company finalized the implementation of certain portions of its enterprise resource planning system throughout 2021 and amortized approximately $1.0 million and $0.9 million of implementation costs in the years ended December 31, 2022 and 2021, respectively.
Depreciation is recorded using composite rates on a straight-line basis over the estimated useful life of the asset. The average depreciation rates for the years ended December 31, 2022, 2021 and 2020 were 2.6%, 2.6% and 2.5%, respectively. The Company estimates that gathering and transmission pipelines have useful lives of 20 years to 50 years and compression equipment has useful lives of 20 years to 50 years. The Company estimates that water pipelines, pumping stations and impoundment facilities have useful lives of 10 years to 15 years. As circumstances warrant, depreciation estimates are reviewed to determine if any changes in the underlying assumptions are necessary. Equitrans, L.P., the Company's FERC-regulated subsidiary, re-evaluates depreciation rates for its regulated property, plant and equipment each time it files with the FERC for a change in transmission, storage and gathering rates.
Intangible Assets. Intangible assets are recorded under the acquisition method of accounting at their estimated fair values at the acquisition date, which are calculated as the present value of estimated future cash flows using a risk-adjusted discount rate. The Company's intangible assets are amortized on a straight-line basis over each intangible asset's estimated remaining useful life. The estimated annual amortization expense related to the intangible assets for each of the next five years is $64.8 million for years one through four and then $62.5 million in year five and the weighted average amortization period is 9.3 years.
The following tables summarize the Company's intangible assets as of December 31, 2022 and 2021:
December 31, 2022
(In thousands) Remaining Life Gross Accumulated Amortization Net
Customer relationships 10 years $ 623,199 $ (213,273) $ 409,926
Eureka Midstream-related customer relationships 8 years 237,000 (69,128) 167,872
Hornet Midstream-related customer relationships 4 years 74,000 (64,846) 9,154
$ 934,199 $ (347,247) $ 586,952
December 31, 2021
(In thousands) Remaining Life Gross Accumulated Amortization Net
Customer relationships 11 years $ 623,199 $ (171,726) $ 451,473
Eureka Midstream-related customer relationships 9 years 237,000 (48,144) 188,856
Hornet Midstream-related customer relationships 5 years 74,000 (62,558) 11,442
$ 934,199 $ (282,428) $ 651,771
Impairment of Goodwill and Long-Lived Assets. Goodwill is evaluated for impairment at least annually or whenever events or changes in circumstance indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Company may perform either a qualitative assessment of potential impairment or proceed directly to a quantitative assessment of potential impairment. The Company's qualitative assessment of potential impairment may result in the determination that a quantitative impairment analysis is not necessary. The Company assesses qualitative factors to determine whether the existence of events or circumstances leads the Company 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, 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. 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.
The Company evaluates long-lived assets 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. These cash flow estimates require the Company to make projections and assumptions for many years into the future for volumes, pricing, demand, competition, operating costs and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, the Company recognizes 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 the Company 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 the Company makes to these projections and assumptions could result in significant revisions to its evaluations of recoverability and the recognition of additional impairments. See Note 3 for further detail.
Investments in Unconsolidated Entities. The Company accounts for the investments in its unconsolidated entities under the equity method. The Company’s pro-rata share of net income in the unconsolidated entities is included in equity income in the Company’s statements of consolidated comprehensive income. Contributions to or distributions from the unconsolidated entities and the Company’s pro-rata share of net income in the unconsolidated entities are recorded as adjustments to the investment balance. 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 charge equal to the difference between the investment's carrying value and fair value. See Notes 3 and 8 for further detail.
Preferred Interest. EQT Energy Supply, LLC (EES), a subsidiary of EQT, generates revenue by providing services to a local distribution company. The preferred interest that the Company has in EES (the Preferred Interest) is accounted for as a note receivable and is presented in other assets in the consolidated balance sheets with the current portion reported in other current assets. Distributions received from EES are recorded as a reduction to the Preferred Interest and as interest income, which is included in net interest expense in the Company's statements of consolidated comprehensive income. The EES operating agreement provides for mandatory redemption of the Preferred Interest at the end of the preference period, which is expected to be December 31, 2034.
Unamortized Debt Discount and Issuance Costs. The Company amortizes debt discounts and issuance costs over the term of the related borrowing. Costs incurred from the arrangement, issuance and/or extension of revolving credit facilities, including the Amended EQM Credit Facility and the 2021 Eureka Credit Facility (each as defined in Note 10), are presented in other assets in the consolidated balance sheets. Debt discounts and issuance costs for all other debt instruments are presented as a reduction to debt on the consolidated balance sheets. See Note 10 for further detail.
Leases. Right-of-use assets represent the right to use the underlying asset for the lease term and lease liabilities represent the obligation to make lease payments arising from the lease. Right-of-use assets and lease liabilities are recognized on the consolidated balance sheets at the lease commencement date based on the present value of lease payments over the lease term. The Company determines if an arrangement is a lease at inception based on whether the Company has the right to control the use of an identified asset, the right to obtain substantially all of the economic benefits from the use of the asset and the right to direct the use of the asset during the lease term and accounts for leases in accordance with ASC 842, Leases (ASC 842).
Leases in which the Company is the lessee that do not have a readily determinable implicit rate utilize an incremental borrowing rate, based on the information available at the lease commencement date, to determine the present value of lease payments. When a secured borrowing rate is not readily available, unsecured borrowing rates are adjusted for the effects of collateral to determine the incremental borrowing rate. The Company reassesses the incremental borrowing rate for any new and modified lease contracts as of the contract effective date. Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease expense for finance leases includes the amortization of the right-of-use assets on a straight-line basis and the interest expense recognized on lease liabilities using the effective interest method over the lease term. See Note 6.
Other Current Liabilities. The following table summarizes the Company's accrued liabilities as of December 31, 2022 and 2021.
December 31,
2022 2021
(Thousands)
Accrued employee compensation $ 47,742 $ 50,372
Non-income tax accruals 20,629 19,972
Current portion of operating lease liabilities 7,886 8,253
Other accrued liabilities 7,578 5,255
Total accrued liabilities $ 83,835 $ 83,852
Asset Retirement Obligations (AROs). The Company has AROs related to its water system impoundments and to one of its gathering compressor stations, for which the Company recorded an associated liability and capitalized a corresponding amount to asset retirement costs. The liability relates to the expected future obligation to dismantle, reclaim and dispose of these assets and was estimated using the present value of expected future cash flows, adjusted for inflation, and discounted at the
Company's credit-adjusted, risk-free rate. The AROs are recorded in regulatory and other long-term liabilities on the consolidated balance sheets. Beginning in 2020 and continuing throughout 2021 and 2022, the Company undertook the reclamation process for certain water system impoundments.
The following table presents changes in the Company's AROs during 2022 and 2021.
December 31,
2022 2021
(Thousands)
AROs at beginning of period $ 11,241 $ 12,172
Liabilities settled (996) (1,609)
Revisions to estimated liabilities (a)
3,153 -
Accretion expense 563 678
AROs at end of period $ 13,961 $ 11,241
(a)Revisions to estimated liabilities reflect changes in retirement cost assumptions and the estimated timing of liability settlement.
The Company is not legally or contractually obligated to restore or dismantle its transmission and storage systems and its gathering systems, other than the one aforementioned gathering compressor station. The Company is legally required to operate and maintain these assets and intends to do so as long as supply and demand for natural gas exists, which the Company expects to continue into the foreseeable future. Therefore, the Company did not have any AROs related to its transmission and storage and gathering (other than the aforementioned gathering compressor station) assets as of December 31, 2022 and 2021.
Contingencies. The Company is, from time to time, involved in various regulatory and legal proceedings. A liability is recorded when the loss is probable and the amount of loss can be reasonably estimated. The Company considers many factors when making such assessments, including historical knowledge and matter specifics. Estimates are developed through consultation with legal counsel and analysis of the potential results. See Note 15.
Regulatory Accounting. Equitrans, L.P. owns all of the Company's FERC-regulated transmission and storage operations as well as its FERC-regulated low-pressure gathering assets. Through the rate-setting process, rate regulation allows Equitrans, L.P. to recover the costs of providing regulated services plus an allowed return on invested capital. Regulatory accounting allows Equitrans, L.P. to defer expenses and income to its consolidated balance sheets as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate-setting process for a period other than the period that they would be reflected in a non-regulated entity's statements of consolidated comprehensive income. Regulatory assets and liabilities are recognized in the Company's statements of consolidated comprehensive income in the period that the underlying expenses and income are reflected in the rates charged to shippers and operators. Equitrans, L.P. expects to continue to be subject to rate regulation that will provide for the recovery of deferred costs.
The following table summarizes Equitrans, L.P.'s regulatory assets and liabilities that are included in other assets and regulatory and other long-term liabilities, respectively, in the Company's consolidated balance sheets.
December 31,
2022 2021
(Thousands)
Regulatory assets:
Deferred taxes (a)
$ 85,046 $ 91,989
Other recoverable costs (b)
4,608 3,654
Total regulatory assets $ 89,654 $ 95,643
Regulatory liabilities:
Deferred taxes (a)
$ 9,329 $ 9,727
On-going post-retirement benefits other than pension and other reimbursable costs (c)
19,251 10,094
Total regulatory liabilities $ 28,580 $ 19,821
(a)The regulatory asset from deferred taxes is primarily related to a historical deferred income tax position and taxes on the equity component of AFUDC. The regulatory liability from deferred taxes relates to the revaluation of a historical difference between the
regulatory and tax bases of regulated property, plant and equipment. Equitrans, L.P. expects to recover the amortization of the deferred tax positions ratably over the depreciable lives of the underlying assets. Equitrans, L.P. also expects to recover the taxes on the equity component of AFUDC through future rates over the depreciable lives of the underlying long-lived assets.
(b)The regulatory asset from other recoverable costs is primarily related to the costs associated with the Company's legacy post-retirement benefits plan.
(c)Equitrans, L.P. defers expenses for on-going post-retirement benefits other than pensions, which are subject to recovery in approved rates. The regulatory liability reflects lower cumulative actuarial expenses than the amounts recovered through rates.
The following tables present Equitrans, L.P.'s regulated operating revenues and operating expenses and property, plant and equipment included in the Company's statements of consolidated comprehensive income and consolidated balance sheets, respectively.
Years Ended December 31,
2022 2021 2020
(Thousands)
Operating revenues $ 407,884 $ 403,634 $ 397,319
Operating expenses 137,782 135,888 124,206
December 31,
2022 2021
(Thousands)
Property, plant and equipment $ 1,928,898 $ 1,901,924
Accumulated depreciation (475,689) (424,918)
Net property, plant and equipment $ 1,453,209 $ 1,477,006
Gas imbalances occur when the actual amount of gas delivered from a pipeline system or storage facility varies from the amount of gas scheduled for delivery. The Company values gas imbalances due to/from shippers and operators at current index prices. Gas imbalances are settled in-kind, subject to the terms of the applicable FERC tariffs. As of December 31, 2022 and 2021, gas imbalance receivables were $7.0 million and $1.9 million, respectively, and are presented in other current assets, with offsetting amounts recorded to system gas, a component of property, plant and equipment, on the consolidated balance sheets. The Company classifies gas imbalances as current because they are expected to settle within one year.
Revenue Recognition. Revenue is measured based on considerations specific in a contract with a customer. The Company recognizes revenue under gathering, transmission and storage and water services contracts when it satisfies certain performance obligations, as discussed below.
The Company provides gathering, transmission and storage services in two manners: firm service and interruptible service. Firm service is provided under firm contracts, which are contracts for gathering, transmission or storage services that generally obligate the customer to pay a fixed, monthly charge to reserve an agreed upon amount of pipeline or storage capacity regardless of the capacity used by the customer during each month. Volumetric-based fees can also be charged under firm contracts for each firm volume transported, gathered or stored, as well as for volumes transported, gathered or stored in excess of the firm contracted volume, if capacity exists. Interruptible service contracts include volumetric-based fees, which are charges for the volume of gas gathered, transported or stored and generally do not guarantee access to the pipeline or storage facility. Firm and interruptible contracts can be short- or long-term in duration. Firm and interruptible transmission and storage service contracts are billed at the end of each calendar month, with payment typically due within 10 days. Firm and interruptible gathering contracts are billed on a one-month lag, with payment typically due within 21 days. Revenue related to gathering services provided but not yet billed is estimated each month. These estimates are generally based on contract data, preliminary throughput and allocation measurements.
Under a firm contract, the Company has a stand-ready obligation to provide the service over the life of the contract. The performance obligation for firm reservation fee revenue is satisfied over time as the pipeline capacity is made available to the customer. As such, the Company recognizes firm reservation fee revenue evenly over the contract period using a time-elapsed output method to measure progress. The performance obligation for volumetric-based fee revenue is generally satisfied upon the Company's monthly billing to the customer for volumes gathered, transported or stored during the month. The amount billed generally corresponds directly to the value of the Company's performance to date as the customer obtains value as each volume is gathered, transported or stored.
Water service revenues represent fees charged by the Company for the delivery of fresh and produced water to a customer at a specified delivery point and for the collection and recycling or disposal of flowback and produced water. The Company's water service revenues are generated under firm service and interruptible service contracts, which primarily utilize fixed prices per volume delivered. Firm service provides water services under firm contracts to customers with priority. Interruptible service contracts generally do not guarantee access to the water facilities. For fresh and produced water delivery service contracts, the only performance obligation in each contract is for the Company to provide water (usually a minimum daily volume of water) to the customer at a designated delivery point. For flowback and produced water, the performance obligation is collection and disposal of the water, which typically occur within the same day. Water service contracts are billed on a monthly basis, with payment typically due within 30 days.
For all contracts, the Company allocates the transaction price to each performance obligation based on the estimated 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 services agreements, including the EQT Global GGA and the 2021 Water Services Agreement, are structured with MVCs or ARCs, as applicable, which specify minimum quantities for which a customer will be charged regardless of quantities gathered or delivered under the contract. Revenue is recognized for MVCs or ARCs when the performance obligation has been met, which is the earlier of when the gas is gathered or water provided, or when it is remote that the producer will be able to meet its MVC or ARC. If a customer under such an agreement fails to meet its MVC or ARC 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 volumes and the MVC or ARC for the period contained in the contract. See Note 5.
AFUDC. The Company capitalizes the carrying costs of financing the construction of certain long-lived, regulated assets. Such costs are amortized over the asset's estimated useful life and include interest costs (the debt component of AFUDC) and equity costs (the equity component of AFUDC). The debt component of AFUDC is recorded as a reduction to net interest expense on the statements of consolidated comprehensive income, and the equity component of AFUDC is recorded in other income (expense), net, on the statements of consolidated comprehensive income.
Share-Based Compensation. The Company recognizes share-based compensation expense based upon the estimated fair value of awards over the requisite service period. Time-based restricted units expected to be satisfied in cash are accounted for as liability awards recorded over the requisite service period, typically three years. The fair value of liability awards is remeasured at the end of each reporting period based on the closing price of the Company’s common stock. Time-based restricted stock awards expected to be satisfied in Company common stock are accounted for as equity awards and are recorded over the requisite service period, typically three years, based on the grant date fair value. Director phantom units expected to be satisfied in Company common stock vest on the date of grant and are recorded based on the grant date fair value. The grant date fair value, in both cases, is determined based upon the closing price of the Company's common stock on the day before the grant date. The Company accounts for forfeitures as they occur.
Performance-based awards expected to be satisfied in cash are accounted for as liability awards and remeasured at fair value at the end of each reporting period, recognizing a proportionate amount of the compensation expense for each period over the vesting period of the award. Performance-based awards expected to be satisfied in Company common stock are accounted for 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 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. The Company obtains a valuation at each reporting date for liability awards and at the grant date for equity 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, the common stock of the peer group members at the time of valuation.
For plans that include a performance condition that affects the number of awards that will ultimately vest, the probability that the performance condition will be achieved is reevaluated at the end of each reporting period and the payout multiplier is applied to the grant date fair value or measurement date fair value to record compensation expense, as applicable. For plans that include a market condition, compensation expense is based on a grant date fair value using a Monte Carlo simulation that
remains constant throughout the vesting period for equity plans and a fair value based on a Monte Carlo simulation remeasured at each reporting period for liability plans. Each plan subject to a market condition is accounted for separately for each vesting tranche of the award. See Note 9.
Income Taxes. The Company files a consolidated income tax return for federal income taxes and the provision for income taxes is determined using the asset and liability approach of accounting for income taxes. Under this approach, the provision for income taxes represents income taxes paid or payable (or received or receivable) plus the change in deferred taxes for the current year. EQM is a limited partnership for U.S. federal and state income tax purposes. Eureka Midstream is a limited liability company for such purposes. EQM and Eureka Midstream are not subject to U.S. federal or state income taxes.
All of Eureka Midstream's income is, and for the period prior to the closing of the EQM Merger all of EQM'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 for the periods prior to the closing of the EQM Merger. This reduces the Company's effective tax rate in periods when the Company has consolidated pre-tax income and increases the effective tax rate in periods when the Company has consolidated pre-tax losses.
Deferred taxes represent the future tax consequences of differences between the financial and tax bases of the Company's assets and liabilities. Deferred tax balances are adjusted for changes in tax rates and tax laws when enacted. Deferred tax assets are reflected on the consolidated balance sheets for net operating losses, credits or other attributes generated by the Company. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not (greater than 50%) that a tax benefit will not be realized. In evaluating the need for a valuation allowance, management considers all potential sources of taxable income, including income available in carry-back periods, future reversals of taxable temporary differences, projections of taxable income and income from tax planning strategies, as well as all available positive and negative evidence.
Deferred tax assets for which no valuation allowance is recorded may not be realized and changes in facts and circumstances may result in the establishment of a valuation allowance. Existing valuation allowances are re-examined under the same standards of positive and negative evidence that apply to valuation allowance establishment. If it is determined that it is more likely than not that a deferred tax asset for which a valuation is recorded will be realized, all or a portion of the valuation allowance may be released. Deferred tax assets and liabilities are also re-measured to reflect changes in underlying tax rates from tax law changes.
Tax benefits related to uncertain tax positions taken or expected to be taken on a tax return are recorded when such benefits meet a more likely than not threshold; otherwise, the tax benefit is recorded when the tax position has been effectively settled, either because the statute of limitations has expired or the appropriate taxing authority has completed its examination. Interest and penalties related to uncertain tax positions are recognized as part of the provision for income taxes and are accrued in the period that such interest and penalties would be applicable under relevant tax law until such time that the uncertain tax positions are resolved. See Note 13.
Mezzanine Equity. The Equitrans Midstream Preferred Shares are considered redeemable securities under GAAP due to the possibility of redemption outside the Company’s control. They are therefore presented as temporary equity in the mezzanine equity section of the Company’s consolidated balance sheets and are not considered to be a component of shareholders’ equity on the consolidated balance sheets. The Equitrans Midstream Preferred Shares were recorded at fair value as of the date of issuance, and income allocations increase the carrying value and declared dividends decrease the carrying value of the Equitrans Midstream Preferred Shares. As the Equitrans Midstream Preferred Shares are not currently redeemable and were not probable of becoming redeemable as of December 31, 2022, adjustment to the carrying amount is not necessary and would only be required if it becomes probable that the Equitrans Midstream Preferred Shares would become redeemable.
Noncontrolling Interests. Noncontrolling interests represent the portion of the equity of consolidated entities that are not wholly owned by the Company and are reported as a component of shareholders’ equity in the consolidated balance sheets. Noncontrolling interests are adjusted by the amount of net income earned by the entities with noncontrolling interests, distributions paid to noncontrolling interest holders and any changes in the noncontrolling ownership percentages. As of December 31, 2022 and 2021, the Company's noncontrolling interest consisted of the third-party ownership interest in Eureka Midstream.
For all periods presented, the Company's noncontrolling interests included third-party ownership interests in Eureka Midstream. Additionally, for the period from January 1, 2020 through the closing of the EQM Merger, the Company’s noncontrolling interests included the EQM common units not held by the Company or its affiliates and the EQM Series A Preferred Unit holders' interest in EQM's net income.
Earnings Per Share (EPS). Basic EPS is computed by dividing net income (loss) attributable to Equitrans Midstream common shareholders by the weighted average number of shares of Equitrans Midstream common stock outstanding during the period. Diluted EPS is computed by dividing net income (loss) attributable to Equitrans Midstream common shareholders by the weighted average number of shares of Equitrans Midstream common stock outstanding and the assumed issuance of all potentially dilutive securities. Each issue of potential common shares is evaluated separately in sequence from the most dilutive to the least dilutive. The dilutive effect of share-based payment awards and stock options is calculated using the treasury stock method, which assumes share purchases are calculated using the average share price of Equitrans Midstream common stock during the applicable period. The Company uses the if-converted method to compute potential common shares from potentially dilutive convertible securities. Under the if-converted method, dilutive convertible securities are assumed to be converted from the date of the issuance and the resulting common shares are included in the denominator of the diluted EPS calculation for the period being presented. Income attributable to preferred dividends on convertible preferred stock that accumulated during the period is added back to the numerator for purposes of the if-converted method. Diluted EPS also takes into consideration the potential dilution from securities issued by subsidiaries that enable their holders to obtain the subsidiary's common stock. See Note 12.
Recently Issued Accounting Standards
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848), which provides practical expedients for contract modifications and certain hedging relationships associated with the transition from reference rates that are expected to be discontinued. This guidance is applicable to the calculation of each dividend following March 31, 2024 for the Equitrans Midstream Preferred Shares pursuant to the Company's Second Amended and Restated Articles of Incorporation, as well as any Company contracts that use the London Inter-Bank Offered Rate as a reference rate. In December 2022, the FASB issued ASU 2022-06, which amended Topic 848 to defer the sunset date to apply the practical expedients until December 31, 2024. The Company is currently evaluating the potential impact of adopting this standard on its financial statements and related disclosures.
In August 2020, the FASB issued ASU 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies the accounting for convertible debt and convertible preferred stock by removing the requirements to separately present certain conversion features in equity. In addition, the amendments in the ASU 2020-06 also simplify the guidance in ASC Subtopic 815-40, Derivatives and Hedging: Contracts in Entity’s Own Equity, by removing certain criteria that must be satisfied in order to classify a contract as equity. Finally, the amendments revise the guidance on calculating earnings per share, requiring use of the if-converted method for all convertible instruments and rescinding an entity’s ability to rebut the presumption of share settlement for instruments that may be settled in cash or other assets. The amendments were effective for fiscal years beginning after December 15, 2021. The Company adopted this standard on January 1, 2022 with no significant effect on the Company's financial statements or related disclosures.
2. Investments in Consolidated, Non-Wholly Owned Entities
EQM Series A Preferred Units. On March 13, 2019, EQM entered into a Convertible Preferred Unit Purchase Agreement, together with Joinder Agreements entered into on March 18, 2019, with investors to issue and sell in a private placement (the Private Placement) an aggregate of 24,605,291 EQM Series A Preferred Units for a cash purchase price of $48.77 per EQM Series A Preferred Unit, resulting in total gross proceeds of approximately $1.2 billion. See below for a discussion of the Preferred Restructuring Agreement.
EQM Merger. As discussed in Note 1, on June 17, 2020, the Company, EQM, EQM LP, Merger Sub and the EQM General Partner completed the EQM Merger, pursuant to which Merger Sub merged with and into EQM, with EQM continuing and surviving as an indirect, wholly owned subsidiary of the Company. As a result of the EQM Merger, EQM is no longer a publicly traded entity.
At the Effective Time, subject to applicable tax withholding, (i) each outstanding EQM common unit, other than EQM common units owned by the Company and its subsidiaries, was converted into the right to receive 2.44 shares of Equitrans Midstream common stock (the Merger Consideration); (ii) (x) $600.0 million aggregate principal amount of the EQM Series A Preferred Units issued and outstanding immediately prior to the Effective Time were redeemed by EQM for cash at 101% of the EQM Series A Preferred Unit Purchase Price plus any accrued and unpaid distribution amounts and partial period distribution amounts, and (y) immediately following such redemption, each remaining issued and outstanding EQM Series A Preferred Unit was exchanged for 2.44 Equitrans Midstream Preferred Shares; and (iii) each outstanding phantom unit relating to an EQM common unit issued pursuant to the Amended and Restated EQGP Services, LLC 2012 Long-Term Incentive Plan, dated as of February 22, 2019 (the EQM LTIP), and any other award issued pursuant to the EQM LTIP, whether vested or unvested, was converted into the right to receive, with respect to each EQM common unit subject thereto, the Merger Consideration (plus any accrued but unpaid amounts in relation to distribution equivalent rights). The limited partner interests in EQM owned by the
Company and its subsidiaries (including the Class B units) remained outstanding as limited partner interests in the surviving entity. The EQM General Partner continued to own the non-economic general partner interest in the surviving entity.
No fractional shares of Equitrans Midstream common stock were issued in the EQM Merger; instead, all fractions of Equitrans Midstream common stock to which an EQM common unitholder otherwise would have been entitled were aggregated and the resulting fraction was rounded up to the nearest whole share of Equitrans Midstream common stock.
In connection with the EQM Merger, at the Effective Time, the Company's omnibus and secondment agreements with EQM and certain other subsidiaries of the Company terminated, subject to the survival of certain license rights and indemnification obligations.
Because the Company controlled EQM both before and after the EQM Merger, the increase in the Company’s ownership interest in EQM resulting from the EQM Merger was accounted for as an equity transaction and reflected as a reduction of the noncontrolling interest associated with public ownership of EQM common units, offset by an increase in common stock, no par value. No gain or loss was recognized in the Company’s statements of consolidated comprehensive income as a result of the EQM Merger. In addition, the tax effects of the EQM Merger were reported as adjustments to deferred income taxes and Equitrans Midstream common stock, consistent with ASC 740, Income Taxes. As a result of equity transactions relating to the Company's investment in EQM, the Company adjusted its noncontrolling interest and common stock, no par value, balances to reflect the resulting changes in ownership. During the year ended December 31, 2020, as a result of the EQM Merger, the Company recorded, in the aggregate, a $2.7 billion increase of common stock, no par value, a decrease in noncontrolling interest of $3.0 billion and an increase in deferred tax liability of $257.2 million.
Immediately prior to the completion of the EQM Merger, the public limited partners collectively owned a 40.1% interest in EQM, excluding the impact of the EQM Series A Preferred Units. The publicly-owned EQM common units, prior to completion of the EQM Merger, were reflected within noncontrolling interest in the Company's consolidated balance sheets as of March 31, 2020. The portion of EQM earnings attributable to publicly-held EQM common units prior to completion of the EQM Merger was reflected in net income attributable to noncontrolling interests in the Company's statements of consolidated comprehensive income.
Additionally, for the period from January 1, 2020 to June 17, 2020, the Company determined that EQM was a variable interest entity. Through the Company's ownership and control of the general partner of EQM during that period, the Company had the power to direct the activities that most significantly affected EQM's economic performance. As a result of the EQM Merger, EQM is no longer a variable interest entity.
The Company recorded $23.8 million in expenses related to the EQM Merger and the EQT Global GGA (as defined in Note 3) during the year ended December 31, 2020. The expenses consisted of advisor, legal and accounting fees related to the transactions and are included in transaction costs in the statements of consolidated comprehensive income.
Preferred Restructuring Agreement. As discussed in Note 1, on June 17, 2020, concurrently with the closing of the EQM Merger: (i) EQM redeemed $600 million aggregate principal amount of the EQM Series A Preferred Units issued and outstanding immediately prior to the Effective Time for cash at 101% of 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 Equitrans Midstream Preferred Shares, in each case, in connection with the occurrence of the “Series A Change of Control” (as defined in the Former EQM Partnership Agreement) that occurred upon the closing of the EQM Merger. The Equitrans Midstream Preferred Shares issued were not registered under the Securities Act of 1933, as amended (the Securities Act), in reliance upon the exemption provided in Section 4(a)(2) of the Securities Act and/or Regulation D promulgated thereunder.
On June 17, 2020, the Company paid cash of $617.3 million to redeem $600 million aggregate principal amount of then outstanding EQM Series A Preferred Units and pay partial period distributions on such EQM Series A Preferred Units. At the time of the redemption, the carrying value of the EQM Series A Preferred Units was $590.1 million, resulting in a premium over the carrying value of $27.3 million. The premium represented a return similar to distributions to the holders of the EQM Series A Preferred Units and, as such, reduced net income attributable to Equitrans Midstream common shareholders, and was recorded in retained earnings (deficit) in the statements of consolidated shareholders' equity and mezzanine equity.
Pursuant to the Restructuring Agreement, in connection with the Restructuring Closing, the Company filed a statement with respect to shares, attaching a Certificate of Designations (the Certificate of Designations), with the Pennsylvania Department of State on June 17, 2020 to, among other things, authorize and establish the designations, rights and preferences of the Equitrans Midstream Preferred Shares. On August 13, 2020, pursuant to the terms of the Certificate of Designations, the Company paid $10.9 million in the aggregate to holders of Equitrans Midstream Preferred Shares related to forgone partial period distributions
on the EQM Series A Preferred Units that were converted into Equitrans Midstream Preferred Shares in connection with the EQM Merger.
The Company's Second Amended and Restated Articles of Incorporation (the Restated Articles) set forth the designations, rights and preferences of the Equitrans Midstream Preferred Shares.
The Equitrans Midstream Preferred Shares were a new class of security as of June 2020. They rank pari passu with any other outstanding class or series of preferred stock of the Company and senior to Equitrans Midstream common stock with respect to dividend rights and rights upon liquidation. The Equitrans Midstream Preferred Shares vote on an as-converted basis with Equitrans Midstream common stock and have certain other class voting rights with respect to any amendment to the Restated Articles 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.
The holders of the Equitrans Midstream Preferred Shares receive cumulative quarterly dividends at a rate per annum of 9.75% for each quarter ending on or before March 31, 2024, and thereafter quarterly dividends at a rate per annum equal to the sum of (i) Three-Month LIBOR (as defined in the Restated Articles) as of the LIBOR Determination Date (as defined in the Restated Articles) in respect of the applicable quarter and (ii) 8.15%; provided that such rate per annum in respect of periods after March 31, 2024 will not be less than 10.50%. The Company is not permitted to pay any dividends on any junior securities, including on Equitrans Midstream common stock, prior to paying the quarterly dividends payable to the Equitrans Midstream Preferred Shares, including any previously accrued and unpaid dividends.
Each holder of the Equitrans Midstream Preferred Shares may elect to convert all or any portion of the Equitrans Midstream Preferred Shares owned by it into Equitrans Midstream common stock initially on a one-for-one basis, 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 (referred to as the conversion rate), at any time (but not more often than once per fiscal quarter), provided that any conversion involves an aggregate number of Equitrans Midstream Preferred Shares of at least $20.0 million (calculated based on the closing price of Equitrans Midstream common stock on the trading day preceding notice of the conversion) or such lesser amount if such conversion relates to all of a holder’s remaining Equitrans Midstream Preferred Shares or if such conversion is approved by the Company's Board of Directors (Board).
So long as the holders of the Equitrans Midstream Preferred Shares have not elected to convert all of their Equitrans Midstream Preferred Shares into Equitrans Midstream common stock, the Company may elect to convert all of the Equitrans Midstream Preferred Shares into Equitrans Midstream common stock, at the then-applicable conversion rate, if (i) the shares of Equitrans Midstream common stock are listed for, or admitted to, trading on a national securities exchange, (ii) the closing price per share of Equitrans Midstream common stock on the national securities exchange on which the shares of Equitrans Midstream common stock are listed for, or admitted to, trading exceeds $27.99 for the 20 consecutive trading days immediately preceding notice of the conversion, (iii) the average daily trading volume of the Equitrans Midstream common stock on the national securities exchange on which the shares of Equitrans Midstream common stock are listed for, or admitted to, trading exceeds 1,000,000 shares (subject to certain adjustments) of Equitrans Midstream common stock for the 20 consecutive trading days immediately preceding notice of the conversion, (iv) the Company has an effective registration statement on file with the SEC covering resales of the shares of Equitrans Midstream common stock to be received by such holders upon any such conversion and (v) the Company has paid all prior accumulated and unpaid dividends in cash in full to the holders.
Upon certain events involving a Change of Control (as defined in the Restated Articles) in which more than 90% of the consideration payable to the Company, or to the holders of Equitrans Midstream common stock, is payable in cash, the Equitrans Midstream Preferred Shares will automatically convert into Equitrans Midstream common stock at a conversion ratio equal to the greater of (i) the quotient of (a) the sum of (x) $19.99 (such price, the Equitrans Midstream Preferred Share Issue Price) plus (y) any accrued and unpaid dividends as of such date, including any partial period dividends, with respect to the Equitrans Midstream Preferred Shares, divided by (b) the Equitrans Midstream Preferred Share Issue Price and (ii) the quotient of (a) the sum of (x)(1) the Equitrans Midstream Preferred Share Issue Price multiplied by (2) 110% plus (y) any accrued and unpaid dividends on such date, including any partial period dividends with respect to the Equitrans Midstream Preferred Shares, divided by (b) the volume weighted average price of the shares of Equitrans Midstream common stock for the 30-day period ending immediately prior to the execution of definitive documentation relating to the Change of Control.
In connection with other Change of Control events that do not satisfy the 90% cash consideration threshold described above, in addition to certain other conditions, each holder of Equitrans Midstream Preferred Shares may elect to (i) convert all, but not less than all, of its Equitrans Midstream Preferred Shares into Equitrans Midstream common stock at the then-applicable conversion rate, (ii) if the Company is not the surviving entity (or if the Company is the surviving entity, but Equitrans Midstream common stock will cease to be listed), require the Company to use commercially reasonable efforts to cause the surviving entity in any such transaction to deliver, in exchange for such holder's Equitrans Midstream Preferred Shares, a
substantially equivalent security that has rights, preferences and privileges substantially equivalent to the Equitrans Midstream Preferred Shares (or if the Company is unable to cause such substantially equivalent securities to be issued, to exercise the option described in clause (i) or (iv) hereof or elect to convert such Equitrans Midstream Preferred Shares at a conversion ratio reflecting a multiple of invested capital), (iii) if the Company is the surviving entity, continue to hold the Equitrans Midstream Preferred Shares or (iv) require the Company to redeem the Equitrans Midstream Preferred Shares at a price per share equal to 101% of the Equitrans Midstream Preferred Share Issue Price, plus accrued and unpaid dividends, including any partial period dividends, on the applicable Equitrans Midstream Preferred Shares as of such date, which redemption price may be payable in cash, Equitrans Midstream common stock or a combination thereof at the election of the Board (and, if payable in Equitrans Midstream common stock, such Equitrans Midstream common stock will be issued at 95% of the volume-weighted average price of Equitrans Midstream common stock for the 20-day period ending on the fifth trading day immediately preceding the consummation of the Change of Control). Any holder of Equitrans Midstream Preferred Shares that requires the Company to redeem its Equitrans Midstream Preferred Shares pursuant to clause (iv) above will have the right to withdraw such election with respect to all, but not less than all, of its Equitrans Midstream Preferred Shares at any time prior to the fifth trading day immediately preceding the consummation of the Change of Control and instead elect to be treated in accordance with any of clauses (i), (ii) or (iii) above.
At any time on or after January 1, 2024, the Company will have the right, subject to applicable law, to redeem the Equitrans Midstream Preferred Shares, in whole or in part, by paying cash for each Equitrans Midstream Preferred Share to be redeemed in an amount equal to the greater of (a) the sum of (i)(1) the Equitrans Midstream Preferred Share Issue Price multiplied by (2) 110%, plus (ii) any accrued and unpaid dividends, including partial period dividends, with respect to the Equitrans Midstream Preferred Shares as of such date and (b) the amount the holder of such Equitrans Midstream Preferred Share would receive if such holder had converted such Equitrans Midstream Preferred Share into shares of Equitrans Midstream common stock at the then-applicable conversion ratio and the Company liquidated immediately thereafter.
Pursuant to the terms of the Restructuring Agreement, in connection with the Restructuring Closing, the Company entered into a registration rights agreement with the Investors (the Registration Rights Agreement) pursuant to which, among other things, the Company gave the Investors certain rights to require the Company to file and maintain one or more registration statements with respect to the resale of the Equitrans Midstream Preferred Shares and the shares of Equitrans Midstream common stock that are issuable upon conversion of the Equitrans Midstream Preferred Shares, and certain Investors have the right to require the Company to initiate underwritten offerings for the Equitrans Midstream Preferred Shares and the shares of Equitrans Midstream common stock that are issuable upon conversion of the Equitrans Midstream Preferred Shares.
During the year ended December 31, 2020, as a result of the Restructuring Closing, the Company recorded an increase in mezzanine equity of $667.2 million, a decrease in noncontrolling interest of $579.2 million and a decrease in common stock, no par value, of $100.5 million, net of deferred taxes of $12.5 million.
3. Impairments of Long-Lived Assets
Goodwill. The Company's goodwill balance is associated entirely with the reporting unit associated with the gas gathering and compression activities of EQM Gathering Opco, LLC, an indirect wholly owned subsidiary of the Company, and such reporting unit is included within the Gathering segment. The following table summarizes the carrying amount of goodwill associated with the Company's reporting units as of December 31, 2022 and 2021.
December 31,
2022 2021
(Thousands)
Gross Goodwill $ 1,350,721 $ 1,350,721
Accumulated impairment losses (864,023) (864,023)
Balance as of end of period $ 486,698 $ 486,698
There was no impairment to goodwill recorded during the years ended December 31, 2022 and 2021.
During the fourth quarter of 2021 and 2022, the Company performed a quantitative impairment assessment as required as part of the annual goodwill impairment assessment. As a result of the annual assessment, the Company determined that the fair value of the EQM Opco reporting unit was greater than its carrying value. No impairment to goodwill was recorded as a result of each impairment assessment.
The Company believes the estimates and assumptions used in estimating its reporting unit's fair values are reasonable and appropriate; however, different assumptions and estimates, including those that could be driven by risks associated with future adverse market or economic conditions and Company specific qualitative factors, contractual changes or modifications or other
adverse factors such as unexpected production curtailment by customers, could materially affect the calculated fair value of the EQM Opco reporting unit and the resulting conclusions on impairment of goodwill, 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.
Long-Lived Assets. As of March 31, 2020, the Company performed a recoverability test of the Hornet Midstream long-lived assets due to decreased producer activity. As a result of the recoverability test, management determined that the carrying value of the Hornet Midstream long-lived assets (which consisted of gathering assets and customer-related intangible assets) was not recoverable under ASC 360, Impairment Testing: Long-Lived Assets Classified as Held and Used. The Company estimated the fair value of the Hornet Midstream asset group and determined that the fair value was not in excess of the assets’ carrying value, which resulted in impairment charges of approximately $37.9 million to the gathering assets and approximately $17.7 million to the customer-related intangible assets both within the Company’s Gathering segment. The non-cash impairment charges were recognized during the first quarter of 2020 and are included in the impairments of long-lived assets line on the statements of consolidated comprehensive income.
As of June 30, 2021, the Company performed a recoverability test of the Equitrans Water Services (OH) LLC (Ohio Water) long-lived assets due to decreased producer activity in Ohio within the Company's Water segment. As a result of the recoverability test, management determined that the carrying value of the Ohio Water long-lived assets was not recoverable under ASC 360, Impairment Testing: Long-Lived Assets Classified as Held and Used. The Company estimated the fair value of the Ohio Water asset group and determined that the fair value was less than the assets’ carrying value, which resulted in impairment charges of approximately $56.2 million to the Ohio Water assets within the Company's Water segment. The non-cash impairment charge was recognized during the second quarter of 2021 and is included in the impairments of long-lived assets line on the statements of consolidated comprehensive income.
Equity Method Investment. The standard for determining whether an impairment must be recorded under ASC 323 is whether there occurred an other-than-temporary decline in value. The Company monitors events or circumstances that may indicate the carrying value of such investment may have experienced an other-than-temporary decline in value. The fair value of an equity method investment is generally estimated using an income approach under which significant judgments and assumptions include expected future cash flows, the appropriate discount rate and probability-weighted scenarios.
Events or circumstances that may be indicative of an other-than-temporary decline in value of an equity method investment include, but are not limited to:
•a prolonged period of time that the fair value is below the investor’s carrying value;
•the current expected financial performance is significantly worse than anticipated when the investor originally invested in the investee;
•adverse regulatory action is expected to substantially reduce the investee’s product demand or profitability;
•the investee has lost significant customers or suppliers with no immediate prospects for replacement;
•the investee’s discounted or undiscounted cash flows are below the investor’s carrying amount; and
•the investee’s industry is declining and significantly lags the performance of the economy as a whole.
The estimates that the Company makes with respect to its equity method investment are based upon assumptions that management believes are reasonable, and the impact of variations in these estimates or the underlying assumptions could be material. Additionally, if any joint venture to which the investment relates recognizes an impairment under ASC 360, the Company would be required to record its proportionate share of such impairment loss and would also evaluate such investment for an other-than-temporary decline in value under ASC 323.
During the fourth quarter of 2021, certain legal challenges before the Fourth Circuit regarding regulatory authorizations previously granted to the MVP Joint Venture were completed, other than the issuance of decisions in those matters. In connection with the completion of those proceedings, the Company identified as an indicator of an other-than-temporary decline in value the various uncertain legal outcomes and the potential impacts that certain unfavorable outcomes could have on the then targeted full in-service date for the MVP project and consequent timing for certain projects related thereto and total targeted MVP project costs. In January 2022, the Fourth Circuit vacated and remanded the MVP Joint Venture's authorizations related to the Jefferson National Forest (JNF) received from the Bureau of Land Management and the U.S. Forest Service and, in February 2022, the Fourth Circuit vacated and remanded the Biological Opinion and Incidental Take Statement issued by the U.S. Department of the Interior’s Fish and Wildlife Service for the MVP project. The Company considered these unfavorable decisions by the Fourth Circuit as supplemental evidence in evaluating its equity method investment in the MVP Joint Venture
as of December 31, 2021, to determine if the investment’s carrying value exceeded the fair value and, if so, whether that decline in value was other-than-temporary.
The Company estimated the fair value of its investment in the MVP Joint Venture using an income approach that primarily considered revised probability-weighted scenarios of discounted future net cash flows based on the estimates of total project costs and revenues. These scenarios reflected assumptions and judgments regarding potential delays and cost increases resulting from various ongoing legal and regulatory matters affecting the MVP and MVP Southgate projects. The Company’s analysis also took into account, among other things, probability-weighted growth expectations from additional compression expansion opportunities. The Company generally used an after-tax discount rate of 5.5% in the analysis derived based on a market participant approach. The Company considered scenarios under which ongoing or new legal and regulatory matters further delay the completion and increase the total costs of the project; all required legal and regulatory approvals and authorizations and certain compression expansion opportunities are realized; and the MVP project is canceled. As a result of the assessment, the Company recognized a pre-tax impairment charge of approximately $1.9 billion. Given the significant assumptions and judgments used in estimating the fair value of the Company's investment in the MVP Joint Venture, the fair value of the investment in the MVP Joint Venture represents a Level 3 measurement.
During the third quarter of 2022 assessment, the Company identified an increased risk of further permitting delays resulting primarily from legal developments and regulatory uncertainties, as well as macroeconomic pressures primarily due to increased interest rates impacting the discount rate used within the estimated fair value of its investment in the MVP Joint Venture. The Company considered these factors to be indicators of a decline in value. As such, the Company evaluated if the carrying value of its equity method investment in the MVP Joint Venture exceeded the fair value and, if so, whether that decline in value was other-than-temporary, and thus the equity method investment was impaired under ASC 323.
The Company estimated the fair value of its investment in the MVP Joint Venture using an income approach generally consistent with that described above, except that the Company generally used an after-tax discount rate of 7.5% in the analysis derived based on a market participant approach. As a result of the assessment, the Company recognized a pre-tax impairment charge of approximately $583 million.
There is risk that the Company’s equity investment in the MVP Joint Venture may be further impaired in the future. There are ongoing and may be future legal and regulatory matters related to the MVP project which could affect the ability to complete or operate the project, as well as legal and regulatory matters related to the MVP Southgate project that must be resolved in connection with the project. Assumptions and estimates utilized in assessing the fair value of the Company’s investment in the MVP Joint Venture may change depending on the nature or timing of resolutions to the legal and regulatory matters or based on other relevant developments. Adverse changes in circumstances relevant to the likelihood of project or expansion completion could prompt the Company, in future assessments, to apply a lower probability of project or expansion completion and such changes in assumptions or estimates (including probability) could have a material adverse effect on the fair value of the Company's investment in the MVP Joint Venture and potentially result in an additional impairment, which could have a material adverse effect on the Company's results of operations and financial position.
4. Financial Information by Business Segment
The Company reports its operations in three segments that reflect its three lines of business of Gathering, Transmission and Water, which reflects the manner in which management evaluates the business for making operating decisions and assessing performance. Refer to Note 1 for discussion on business segments.
Years Ended December 31,
2022 2021 2020
(Thousands)
Revenues from customers:
Gathering $ 890,579 $ 862,053 $ 1,012,281
Transmission 404,517 400,202 393,836
Water 62,651 54,782 104,708
Total operating revenues $ 1,357,747 $ 1,317,037 $ 1,510,825
Operating income (loss):
Gathering (a)
$ 446,917 $ 415,969 $ 535,976
Transmission 277,692 274,526 275,369
Water (b)
14,602 (53,911) 38,756
Headquarters (c)
(1,617) (1,183) (25,540)
Total operating income $ 737,594 $ 635,401 $ 824,561
Reconciliation of operating income to net (loss) income:
Equity income (d)
$ 168 $ 17,579 $ 233,833
Impairments of equity method investment (d)
(583,057) (1,926,402) -
Other income (expense), net (e)
13,871 (47,546) 10,427
Loss on extinguishment of debt (24,937) (41,025) (24,864)
Net interest expense (394,333) (378,650) (307,380)
Income tax expense (benefit) 6,444 (343,353) 103,593
Net (loss) income $ (257,138) $ (1,397,290) $ 632,984
(a)Impairment of long-lived assets of $55.6 million for the year ended December 31, 2020 was included in Gathering operating income (loss). See Note 3 for further information.
(b)Impairments of long-lived assets of $56.2 million for the year ended December 31, 2021 were included in Water operating income (loss). See Note 3 for further information.
(c)Includes transaction costs and other unallocated corporate expenses.
(d)Equity income and impairment of equity method investment are included in the Transmission segment.
(e)Includes unrealized gains (losses) on derivative instruments and, for the year ended December 31, 2022, gain on sale of gathering assets recorded in the Gathering segment.
December 31,
2022 2021 2020
(Thousands)
Segment assets:
Gathering $ 7,610,233 $ 7,600,637 $ 7,733,038
Transmission (a)
2,333,896 2,769,097 4,357,382
Water 218,680 151,151 185,802
Total operating segments 10,162,809 10,520,885 12,276,222
Headquarters, including cash 282,776 361,639 442,832
Total assets $ 10,445,585 $ 10,882,524 $ 12,719,054
(a)The equity investment in the MVP Joint Venture is included in the Transmission segment.
Years Ended December 31,
2022 2021 2020
(Thousands)
Depreciation:
Gathering $ 195,059 $ 188,633 $ 172,967
Transmission 55,614 55,310 54,540
Water 20,016 25,233 30,880
Headquarters 1,506 1,228 1,226
Total $ 272,195 $ 270,404 $ 259,613
Capital expenditures:
Gathering (a)
$ 265,864 $ 223,807 $ 344,873
Transmission (b)
35,971 25,977 45,219
Water 66,569 34,877 11,905
Headquarters 13 1,494 4,004
Total (c)
$ 368,417 $ 286,155 $ 406,001
(a)Includes approximately $20.3 million, $14.1 million and $41.6 million of capital expenditures related to noncontrolling interests in Eureka Midstream for the years ended December 31, 2022, 2021 and 2020, respectively.
(b)Transmission capital expenditures do not include capital contributions made to the MVP Joint Venture for the MVP and MVP Southgate projects of approximately $199.6 million, $287.7 million and $272.8 million for the years ended December 31, 2022, 2021 and 2020, respectively.
(c)The Company accrues capital expenditures when the work has been completed but the associated bills have not yet been paid. Accrued capital expenditures are excluded from the statements of consolidated cash flows until they are paid. The net impact of non-cash capital expenditures, including the effect of accrued capital expenditures, transfers to/from inventory as assets are completed/assigned to a project and capitalized share-based compensation costs, was $8.2 million, $4.4 million and $56.0 million at December 31, 2022, 2021 and 2020, respectively.
5. Revenue from Contracts with Customers
For the years ended December 31, 2022, 2021 and 2020, substantially all revenues recognized on the Company's statements of consolidated comprehensive income were from contracts with customers. As of December 31, 2022 and 2021, all receivables recorded on the Company's consolidated balance sheets represent performance obligations that have been satisfied and for which an unconditional right to consideration exists.
Summary of disaggregated revenues. The tables below provide disaggregated revenue information by business segment.
Year Ended December 31, 2022
Gathering Transmission Water Total
(Thousands)
Firm reservation fee revenues (a)
$ 562,947 $ 370,769 $ 33,877 $ 967,593
Volumetric-based fee revenues 327,632 33,748 28,774 390,154
Total operating revenues $ 890,579 $ 404,517 $ 62,651 $ 1,357,747
Year Ended December 31, 2021
Gathering Transmission Water Total
(Thousands)
Firm reservation fee revenues (a)
$ 468,156 $ 366,323 $ 5,063 $ 839,542
Volumetric-based fee revenues 393,897 33,879 49,719 477,495
Total operating revenues $ 862,053 $ 400,202 $ 54,782 $ 1,317,037
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
(a) For the years ended December 31, 2022, 2021 and 2020, firm reservation fee revenues associated with Gathering included approximately $20.2 million, $11.3 million and $15.0 million, respectively, of MVC unbilled revenues.
Contract assets. The Company recognizes contract assets primarily in instances where billing occurs subsequent to revenue recognition and the Company's right to invoice the customer is conditioned on something other than the passage of time. The Company's contract assets primarily consist of revenue recognized under contracts containing MVCs (whereby management has concluded (i) it is probable there will be a MVC deficiency payment at the end of the then-current MVC period, which is typically the period beginning at the inception of such contracts through the successive twelve-month periods after that date, and (ii) that a significant reversal of revenue recognized currently for the future MVC deficiency payment will not occur), as well as certain other contractual commitments. As a result, the Company's contract assets related to the Company's future MVC deficiency payments are generally expected to be collected within the next twelve months and are primarily included in other current assets in the Company's consolidated balance sheets until such time as the MVC deficiency payments are invoiced to the customer.
The following table presents changes in the Company's unbilled revenue balance during the years ended December 31, 2022 and 2021:
Unbilled Revenue
2022 2021
(Thousands)
Balance as of beginning of period $ 16,772 $ 18,618
Revenue recognized in excess of amounts invoiced(a)
30,477 26,779
Minimum volume commitments invoiced (b)
(19,256) (28,442)
Amortization (c)
(500) (183)
Balance as of end of period $ 27,493 $ 16,772
(a) Primarily includes revenues associated with MVCs that are generally included in firm reservation fee revenues within the Gathering and Water segments. During the year ended December 31, 2021, also includes other contractual commitments of approximately $6.4 million.
(b) Unbilled revenues are transferred to accounts receivable once the Company has an unconditional right to consideration from the customer.
(c) Amortization of capitalized contract costs paid to customers over the expected life of the agreement.
Contract liabilities. On February 26, 2020 (the EQT Global GGA Effective Date), the Company (through EQM) entered into a Gas Gathering and Compression Agreement (as amended, the EQT Global GGA) with EQT and certain of its affiliates for the provision of certain gas gathering services to EQT in the Marcellus and Utica Shales of Pennsylvania and West Virginia. The Company's contract liabilities consist of deferred revenue primarily associated with the EQT Global GGA. Contract liabilities are classified as current or non-current according to when such amounts are expected to be recognized.
Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide the Company with a significant financing benefit. This determination requires significant judgment and is based on the combined effect of the expected length of time between when the Company transfers the promised goods or services to the customer and when the customer pays for those goods or services and the prevailing interest rates. The Company has assessed the EQT Global GGA and determined that this agreement does not contain a significant financing component.
On July 8, 2022, the Company received written notice from EQT, pursuant to the EQT Global GGA, of EQT’s irrevocable election under the agreement to forgo up to approximately $145 million of potential gathering MVC fee relief in the first twelve-month period beginning the first day of the quarter in which the MVP full in-service date occurs and up to approximately $90 million of potential gathering MVC fee relief in the second such twelve-month period in exchange for a cash payment from the Company to EQT in the amount of approximately $195.8 million (the EQT Cash Option). As a result of EQT’s election to forgo potential rate relief in exchange for the cash option payment, the Company recorded a reduction to the
contract liability of approximately $195.8 million. The Company utilized borrowings under the Amended EQM Credit Facility to effect such payment to EQT on October 4, 2022.
The following table presents changes in the Company's contract liability balances during the years ended December 31, 2022 and 2021:
Contract Liability
2022 2021
(Thousands)
Balance as of beginning of period $ 822,416 $ 398,750
Amounts recorded during the period (a)
359,797 300,496
Change in estimated variable consideration (b)
(11,761) 123,707
Amounts transferred during the period (c)
(1,545) (537)
EQT Cash Option (195,820) -
Balance as of end of period $ 973,087 $ 822,416
(a) Includes deferred billed revenue during the years ended December 31, 2022 and 2021 primarily associated with the EQT Global GGA.
(b) Change in estimated variable consideration represents the change in total deferred revenue required for gathering MVC revenue with a declining rate structure, which change resulted from the EQT Cash Option election that required total estimated gathering consideration to be increased and from contractual amendments that required total estimated gathering consideration to be reduced. See 'EQT Global GGA' discussion below for additional information on the contractual amendments.
(c) Deferred revenues are recognized as revenue upon satisfaction of the Company's performance obligation to the customer.
Summary of remaining performance obligations. The following table summarizes the estimated transaction price allocated to the Company's remaining performance obligations under all contracts with firm reservation fees, MVCs and/or ARCs as of December 31, 2022 that the Company will invoice or transfer from contract liabilities and recognize in future periods.
2023 2024 2025 2026 2027 Thereafter Total
(Thousands)
Gathering firm reservation fees $ 109,721 $ 171,320 $ 176,140 $ 166,962 $ 160,376 $ 1,689,332 $ 2,473,851
Gathering revenues supported by MVCs 465,978 434,969 454,094 465,335 460,211 3,060,675 5,341,262
Transmission firm reservation fees 369,509 388,626 366,764 361,032 360,210 2,956,833 4,802,974
Water revenues supported by ARCs 39,910 37,500 37,500 37,500 37,500 156,250 346,160
Total (a)
$ 985,118 $ 1,032,415 $ 1,034,498 $ 1,030,829 $ 1,018,297 $ 7,863,090 $ 12,964,247
(a) Includes assumptions regarding timing for placing certain projects in-service. Such assumptions may not be realized and delays in the in-service dates for projects have substantially altered, and additional delays may further substantially alter, the remaining performance obligations for certain contracts with firm reservation fees and/or MVCs and/or ARCs. The MVP Joint Venture is accounted for as an equity investment and those amounts are not included in the table above.
Based on total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed or not yet fully in-service for which the Company has executed firm contracts, the Company's firm gathering contracts and firm transmission and storage contracts had weighted average remaining terms of approximately 14 years and 12 years, respectively, as of December 31, 2022.
EQT Global GGA. On the EQT Global GGA Effective Date, the Company entered into 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. The EQT Global GGA is intended to, among other things, incentivize combo and return-to-pad drilling by EQT. Pursuant to the EQT Global GGA, EQT is subject to an initial annual MVC of 3.0 Bcf per day that gradually steps up to 4.0 Bcf per day through December 2031 following the full in-service date of the MVP (should it be placed in-service) and the dedication of a substantial majority of EQT's core acreage in southwestern Pennsylvania and West Virginia. The EQT Global GGA runs from the EQT Global GGA Effective Date through December 31, 2035, and will renew annually thereafter unless terminated by EQT or the Company pursuant to its terms. Pursuant to the EQT Global GGA, the Company has certain obligations to build connections to connect EQT wells to the Company's gathering system, which are subject to limitations, including 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, which could provide capital efficiencies to EQM. Management has estimated the total consideration expected to be received over the life of the EQT Global GGA, including
gathering MVC revenue that periodically decreases through January 1, 2028 and may be further decreased in certain contract years in connection with MVP in-service (as discussed below), the gathering MVC fee credit for certain gathered volumes that also receive separate transmission services under certain transmission contracts (including the FTS (defined below)), the fair value of the Rate Relief Shares (as defined below) and the initial fair value of the Henry Hub cash bonus payment provision. From time to time, and at a minimum, at each reporting date, management reviews and updates, as necessary, the assumptions utilized to estimate the total consideration of the EQT Global GGA. The total consideration is allocated proportionally to the performance obligation under the contract, which is to provide daily MVC capacity over the life of the contract, in order to recognize revenue in accordance with ASC 606, Revenue from Contracts with Customers. The performance obligations will be satisfied during the life of the contract based on a units of production methodology for the daily MVC capacity provided to EQT. Due to the declining rate structure, there will be periods during which the billable gathering MVC revenue will exceed the allocated consideration to the performance obligation, which will result in billable gathering MVC revenue being deferred to the contract liability. The deferred consideration amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied and are classified as current or non-current according to when such amounts are expected to be recognized. In addition to the estimated total consideration allocated to the daily MVC, the EQT Global GGA includes other fees based on variable or volumetric-based services that will be recognized in the period the services are provided. The Company applied judgment in determining the balance sheet classification of the elements of the EQT Global GGA and Share Purchase Agreements (as defined below) under the applicable accounting guidance.
The gathering MVC fees periodically decline through January 1, 2028 (with such fees then remaining fixed throughout the remaining term), even if MVP would not achieve full in-service. Before January 1, 2026, beginning the first day of the quarter in which the full in-service date of the MVP occurs, the gathering MVC fees payable by EQT to the Company are subject to more significant potential declines for certain contract years as set forth in the EQT Global GGA, which, prior to EQT's exercise of the EQT Cash Option, provided for estimated aggregate fee relief of up to approximately $270 million in the first twelve-month period, up to approximately $230 million in the second twelve-month period and up to approximately $35 million in the third twelve-month period. Given that the MVP full in-service date did not occur by January 1, 2022, on July 8, 2022, EQT irrevocably elected to exercise the EQT Cash Option, and, as a result, the maximum aggregate potential fee relief applicable under the EQT Global GGA in such first twelve-month period and such second twelve-month period was reduced to be up to approximately $125 million and $140 million, respectively. The Company utilized borrowings under the Amended EQM Credit Facility to effect payment of the EQT Cash Option to EQT on October 4, 2022. Additionally, the EQT Global GGA provides for a fee credit to the gathering rate for certain gathered volumes that also receive separate transmission services under certain transmission contracts.
During the fourth quarter of 2021, the Company entered into two amendments to an agreement for firm transportation service (FTS) with EQT that, subject to the satisfaction of certain conditions, would have the effect of extending the primary term of the FTS. As a result of the potential extension, management reassessed the expected gathering MVC fee credit assumptions and, as a result of the impacts to such assumptions, the total consideration expected under the EQT Global GGA was reduced. The Company recognized a cumulative adjustment that decreased revenue and increased contract liability by $123.7 million, respectively, during the year ended December 31, 2021. The cumulative adjustment had no impact to the amount billed to and cash collected from EQT under the EQT Global GGA.
The EQT Global GGA provides for potential cash bonus payments payable by EQT to the Company during the period beginning on the first day of the calendar quarter in which the MVP full in-service date occurs through the calendar quarter ending December 31, 2024 (the Henry Hub cash bonus payment provision). The potential cash bonus payments are conditioned upon the quarterly average of certain Henry Hub natural gas prices exceeding certain price thresholds. The Henry Hub cash bonus payment provision meets the definition of an embedded derivative that was required to be bifurcated from the host contract and accounted for separately in accordance with ASC 815, Derivatives and Hedging. The embedded derivative was recorded as a derivative asset at its estimated fair value at inception of approximately $51.5 million and as part of the contract liability to be included in the total consideration to be allocated to the performance obligation under ASC 606. Subsequent changes to the fair value of the derivative instrument through the end of the contract are recognized in other income (expense), net, on the Company's statements of consolidated comprehensive income.
Water Services Letter Agreement and 2021 Water Services Agreement. On February 26, 2020, the Company entered into a letter agreement with EQT relating to the provision of water services in Pennsylvania (such letter agreement, the Water Services Letter Agreement). Subject to the effect of the 2021 Water Services Agreement (as defined below), the Water Services Letter Agreement would have been effective as of the first day of the first month following the MVP full in-service date and would have expired on the fifth anniversary of such date. During each year of the Water Services Letter Agreement, EQT had agreed to pay the Company a minimum $60 million per year Annual Revenue Commitment (ARC) for volumetric water services provided in Pennsylvania, all in accordance with existing water service agreements and new water service agreements entered into between the parties pursuant to the Water Services Letter Agreement (or the related agreements).
On October 22, 2021, the Company and EQT entered into a new 10-year, mixed-use water services agreement covering operations within a dedicated area in southwestern Pennsylvania (as subsequently amended, the 2021 Water Services Agreement). The 2021 Water Services Agreement became effective on March 1, 2022 and replaced the Water Services Letter Agreement and certain other existing Pennsylvania water services agreements. Pursuant to the 2021 Water Services Agreement, EQT agreed to pay the Company a minimum ARC for water services equal to $40 million in each of the first five years of the 10-year contract term and equal to $35 million per year for the remaining five years of the contract term.
Share Purchase Agreements. On February 26, 2020, the Company entered into two share purchase agreements (the Share Purchase Agreements) with EQT, pursuant to which the Company agreed to (i) purchase 4,769,496 shares of Equitrans Midstream common stock (the Cash Shares) from EQT in exchange for approximately $46 million in cash, (ii) purchase 20,530,256 shares of Equitrans Midstream common stock (the Rate Relief Shares and, together with the Cash Shares, the Share Purchases) from EQT in exchange for a promissory note in the aggregate principal amount of approximately $196 million (which EQT subsequently assigned to EQM as consideration for certain commercial terms under the EQT Global GGA), and (iii) pay EQT cash in the amount of approximately $7 million (the Cash Amount). On March 5, 2020, the Company completed the Share Purchases and paid the Cash Amount. The Company used proceeds from the Amended EQM Credit Facility (defined in Note 10) 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. Additionally, the Company recorded a $17.2 million deferred tax liability in conjunction with 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.
6. Leases
The Company has certain facility and compressor operating lease contracts that are classified as operating leases in accordance with ASC 842. The Company entered into one lease contract for the rental of a water storage facility classified as a financing lease during the year ended December 31, 2022. Leases with an initial term of 12 months or less are considered short-term, recognized in expense on a straight-line basis over the lease term and are not recorded on the balance sheet. As of December 31, 2022 and 2021, the Company was not the lessor to any arrangement; however, the Company was party to certain subleasing arrangements whereby the Company, as sublessor, agreed to sublet leased office space to a third party.
The following table summarizes lease cost for the years ended December 31, 2022, 2021 and 2020:
Years Ended December 31,
2022 2021 2020
(Thousands)
Operating lease cost $ 9,540 $ 12,571 $ 14,464
Finance lease cost:
Amortization of leased assets 541 - -
Interest on lease liabilities 310 - -
Short-term lease cost 7,747 6,057 5,075
Variable lease cost 7 7 168
Sublease income (742) (492) (583)
Total lease cost $ 17,403 $ 18,143 $ 19,124
Operating lease expense related to the Company's compressor lease contracts and facility lease contracts is reported in operating and maintenance expense and selling, general and administrative expense, respectively, on the Company's statements of consolidated comprehensive income. Finance lease expense related to the Company's water storage facility contract amortization and interest is reported in operating and maintenance expense and net interest expense, respectively, on the Company's statements of consolidated comprehensive income.
The following table summarizes the cash paid for operating and finance lease liabilities for the years ended December 31, 2022, 2021 and 2020:
Years Ended December 31,
(Thousands)
Operating lease liabilities
$ 10,484 $ 12,792 $ 14,849
Finance lease liabilities
670 -
-
The following table summarizes balance sheet information related to our leases is as follows:
December 31,
Balance Sheet Classification
2022 2021
(Thousands)
Assets:
Operating lease right-of-use
Other assets $ 35,969 $ 43,368
Finance lease
Other assets 15,683 -
Total right-of-use assets
$ 51,652 $ 43,368
Liabilities:
Current operating
Accrued liabilities
$ 6,682 $ 8,253
Current finance
Accrued liabilities
1,203 -
Non-current operating
Regulatory and other long-term liabilities
30,272 36,157
Non-current finance
Regulatory and other long-term liabilities
14,660 -
Total lease liabilities
$ 52,817 $ 44,410
As of December 31, 2022 and 2021, the weighted average remaining operating lease terms, in each case, was seven years and the weighted average discount rates were 5.9% and 5.8%, respectively. As of December 31, 2022, the remaining finance lease term was ten years and the discount rate was 5.9%.
The following table summarizes undiscounted cash flows owed by the Company to lessors pursuant to noncancelable contractual agreements in effect as of December 31, 2022 and related imputed interest.
Operating Leases Finance Leases
Year ending December 31, (Thousands)
2023 $ 8,513 $ 2,020
2024 6,387 2,050
2025 4,970 2,081
2026 5,040 2,112
2027 5,111 2,144
Thereafter 15,542 10,435
Total 45,563 20,842
Less: imputed interest 8,609 4,979
Present value of lease liabilities $ 36,954 $ 15,863
7. Related Party Transactions
In the ordinary course of business, the Company engages in transactions with EQT and its affiliates, including but not limited to, entering into new or amending existing gathering agreements, transportation service and precedent agreements, storage agreements and/or water services agreements, however, based solely on information reported by EQT in a Schedule 13G/A filed with the SEC on April 28, 2022, EQT was no longer a related party of the Company as of April 22, 2022 and the amounts disclosed related to EQT below are accordingly presented with respect to the full 2021 and 2020 periods during which EQT was considered a related party.
The following table summarizes the Company's related party transactions.
Years Ended December 31,
2021 2020
(Thousands)
Operating revenues $ 777,276 $ 964,220
Interest income from the Preferred Interest 5,767 6,053
Principal payments received on the Preferred Interest 5,217 5,003
The following table summarizes the Company's related party receivables and payables.
December 31,
(Thousands)
Accounts receivable $ 190,410
Contract asset 2,246
Preferred Interest 99,838
Contract liability 818,658
8. Investment in Unconsolidated Entity
The MVP Joint Venture is constructing the Mountain Valley Pipeline (MVP), an estimated 300-mile natural gas interstate pipeline that is designed to span from northern West Virginia to southern Virginia. The Company will operate the MVP and owned a 47.2% interest in the MVP project as of December 31, 2022. On November 4, 2019, Consolidated Edison, Inc. (Con Edison) exercised an option to cap its investment in the construction of the MVP project at approximately $530 million (excluding AFUDC). The Company and NextEra Energy, Inc. are obligated to, and RGC Resources, Inc., another member of the MVP Joint Venture owning an interest in the MVP project, has opted to, fund the shortfall in Con Edison's capital contributions, on a pro rata basis. Such funding by the Company and funding by other members has and will correspondingly increase the Company's and such other funding members' respective interests in the MVP project and decrease Con Edison's interest in the MVP project. If the MVP project were to be completed in 2023 at a total project cost of approximately $6.6 billion (excluding AFUDC), the Company’s equity ownership in the MVP project would progressively increase from approximately 47.2% to approximately 48.1%. The MVP Joint Venture is a variable interest entity because it has insufficient equity to finance its activities during the construction stage of the project. The Company is not the primary beneficiary of the MVP Joint Venture because the Company does not have the power to direct the activities that most significantly affect the MVP Joint Venture's economic performance. Certain business decisions, such as decisions to make distributions of cash, require a greater than 66 2/3% ownership interest approval, and no one member owns more than a 66 2/3% interest.
In April 2018, the MVP Joint Venture announced the MVP Southgate project, which is a contemplated interstate pipeline that was approved by the FERC to extend approximately 75 miles from the MVP at Pittsylvania County, Virginia to new delivery points in Rockingham and Alamance Counties, North Carolina. The Company is expected to operate the MVP Southgate pipeline and owned a 47.2% interest in the MVP Southgate project as of December 31, 2022. The MVP Joint Venture continues to evaluate the MVP Southgate project and is focused on its ongoing discussions and negotiations with the project shipper, Dominion Energy North Carolina, and other prospective customers regarding refining the MVP Southgate project's design, scope and/or timing for the benefit of such customers in lieu of pursuing the project as originally contemplated. Dominion Energy North Carolina’s obligations under the precedent agreement in support of the original project are subject to certain conditions, including that the MVP Joint Venture would have completed construction of the project facilities by June 1, 2022, which deadline is subject to extension to June 1, 2023 by virtue of previously declared events of force majeure. The Company is unable to ensure the results of the discussions and negotiations between the MVP Joint Venture and Dominion Energy North Carolina and other prospective customers, including the ultimate design, scope, timing, undertaking or completion of the project.
In the fourth quarter of 2021, the Company incurred an other-than-temporary decline in value in its equity investment in the MVP Joint Venture, primarily due to unfavorable decisions by the Fourth Circuit that vacated and remanded key authorizations, that resulted in a pre-tax impairment charge of $1.9 billion. As a result of the impairment, the carrying value of the Company's equity investment in the MVP Joint Venture was reduced to $1.2 billion as of December 31, 2021. During the third quarter of 2022, the Company incurred an additional other-than-temporary decline in value in its equity investment in the MVP Joint Venture primarily due to increased uncertainty in the permitting process for the MVP project as a result of legal developments and regulatory uncertainties, as well as macroeconomic pressures primarily due to an increase in interest rates impacting the discount rate, that resulted in a pre-tax impairment charge of $583 million. There is risk that the Company's equity investment in the MVP Joint Venture may be further impaired in the future due to ongoing (and potentially future) legal and regulatory matters, as well as potential macroeconomic factors, including other than temporary market fluctuations, changes in interest rates, cost increases and other unanticipated events. While macroeconomic factors in and of themselves may not be a direct indicator of impairment, should an impairment indicator be identified in the future, macroeconomic factors such as changes in interest rates could ultimately impact the size and scope of any potential impairment.
In November 2022, the MVP Joint Venture issued a capital call notice for the funding of the MVP project to MVP Holdco, LLC (MVP Holdco), a wholly owned subsidiary of the Company, for $33.9 million, of which $19.2 million and $11.5 million was paid in January 2023 and February 2023, respectively, with the remaining $3.2 million expected to be paid in March 2023. The capital contributions payable and the corresponding increase to the investment balance are reflected on the consolidated balance sheet as of December 31, 2022.
Pursuant to the MVP Joint Venture's limited liability company agreement, MVP Holdco is obligated to provide performance assurances in respect of the MVP project, which may take the form of a guarantee from EQM (provided that EQM's debt is rated as investment grade in accordance with the requirements of the MVP Joint Venture's limited liability company agreement), a letter of credit or cash collateral, in favor of the MVP Joint Venture to provide assurance as to the funding of MVP Holdco's proportionate share of the construction budget for the MVP project.
In addition, pursuant to the MVP Joint Venture's limited liability company agreement, MVP Holdco is obligated to provide performance assurances in respect of MVP Southgate, which performance assurances may take the form of a guarantee from EQM (provided that EQM's debt is rated as investment grade in accordance with the requirements of the MVP Joint Venture's limited liability company agreement), a letter of credit or cash collateral.
Based on EQM's credit rating levels in the first quarter of 2020, EQM delivered credit support to the MVP Joint Venture in the form of letters of credit in the amounts of approximately $220.2 million and $14.2 million with respect to the MVP and MVP Southgate projects, respectively. In connection with delivering such letters of credit as performance assurances, EQM's prior performance guarantees associated with the MVP and MVP Southgate projects were terminated. As of December 31, 2022, the letter of credit with respect to the MVP project was in the amount of approximately $219.7 million. As of February 15, 2023, given the ongoing discussions and negotiations with respect to the MVP Southgate project as discussed above and absence of forward construction on such project, the MVP Joint Venture for the MVP Southgate project determined to defer MVP Southgate joint venture partners' obligations to post performance assurances temporarily and pending resolution of such matters. Accordingly, EQM is in the process of terminating its $14.2 million letter of credit, which may be reinstituted upon further developments. Upon the FERC's initial release to begin construction of the MVP Southgate project, any EQM letter of credit in effect at such time for the pre-construction period to support MVP Southgate will be terminated, and the Company will be obligated to deliver a new letter of credit (or provide another allowable form of performance assurance) in an amount equal to 33% of MVP Holdco's proportionate share of the remaining capital obligations for the MVP Southgate project under the applicable construction budget.
The following tables summarize the condensed consolidated financial statements of the MVP Joint Venture in relation to the MVP project.
Condensed Consolidated Balance Sheets
December 31,
2022 2021
(Unaudited)
(Thousands)
Current assets $ 71,535 $ 148,820
Non-current assets 6,737,064 6,432,288
Total assets $ 6,808,599 $ 6,581,108
Current liabilities $ 118,679 $ 160,331
Equity 6,689,920 6,420,777
Total liabilities and equity $ 6,808,599 $ 6,581,108
Condensed Statements of Consolidated Operations
Years Ended December 31,
2022 2021 2020
(Unaudited)
(Thousands)
Operating income (expenses) $ 20 $ (399) $ (360)
Other income 335 18 288
Net interest income - 11,452 150,995
AFUDC - equity - 26,722 352,323
Net income $ 355 $ 37,793 $ 503,246
The Company's ownership interest in the MVP Joint Venture related to the MVP project is significant for the year ended December 31, 2020 as defined by the SEC’s Regulation S-X Rule 1-02(w). Accordingly, as required by Regulation S-X Rule 3-09, the Company has included audited financial statements of the MVP Joint Venture, with respect to the MVP project, as of and for the year ended December 31, 2020 as Exhibit 99.1 to this Annual Report on Form 10-K.
9. Share-based Compensation Plans
The Company maintains employee share-based compensation plans for restricted stock, restricted stock units, performance awards, stock options and other equity or cash-based awards as governed by the Equitrans Midstream Corporation 2018 Long-Term Incentive Plan, as amended (the 2018 Plan), which was effective as of November 12, 2018. Non-employee members of the Company's Board receive phantom units in connection with their board service payable in Company common stock upon the director's termination of services from the Board. The 2018 Plan's term is through the 2028 shareholders' meeting and the maximum number of shares of common stock that may be issued and as to which awards may be granted under the 2018 Plan is 38,592,386 shares.
In accordance with an Employee Matters Agreement by and between the Company and EQT entered into on November 12, 2018 in connection with the Separation (Employee Matters Agreement), previously outstanding share-based compensation awards granted under EQT's equity compensation programs prior to the Separation and held by certain executives and employees of the Company and EQT were adjusted to reflect the impact of the Separation on these awards. To preserve the aggregate intrinsic value of EQT awards held prior to the Separation, as measured immediately before and immediately after the Separation (excluding EQT option awards which were converted in accordance with the conversion provisions set forth in the Employee Matters Agreement), each holder of EQT share-based compensation awards generally received an adjusted award consisting of both a share-based compensation award denominated in EQT equity and a share-based compensation award denominated in Company equity. These awards were adjusted in accordance with the basket method, resulting in participants retaining one unit of the existing EQT incentive award while receiving an additional 0.8 units of a Company-based award and included awards that were share-settled and awards satisfied in cash, which were treated as liability awards. The Company recognizes share-based compensation expense related to unvested awards held by its employees, no matter which entity settles the obligation. As of December 31, 2021, all awards granted prior to the Separation were fully vested and the Company's only
remaining obligations pertained to the settlement of unexercised stock options of former employees and outstanding phantom unit awards to certain directors.
Changes in performance and the number of outstanding awards can impact the ultimate amount of the Company's performance awards to be settled. Share-based awards to be settled in Equitrans Midstream common stock upon settlement are funded by shares acquired by the Company in the open market or from any other person, stock issued directly by the Company or any combination of the foregoing. Share counts for share-based compensation discussed herein represent outstanding shares to be remitted by the Company to (i) its employees in connection with compensation programs adopted by the Company and (ii) employees of the Company and EQT (or, as applicable, former employees of the Company or EQT) pursuant to the Employee Matters Agreement.
The following table summarizes the components of share-based compensation expense for the years ended December 31, 2022, 2021 and 2020.
Years Ended December 31,
2022 2021 2020
(Thousands)
2022 PSU Program 5,672 - -
2021 PSU Program 1,527 5,940 -
2020 PSU Program (221) 1,297 2,317
2019 PSU Program - 984 4,935
2018 EQT Incentive PSU Program - - 698
Restricted stock awards 7,840 11,268 7,422
Other programs, including non-employee director awards 1,132 1,367 1,577
Total share-based compensation expense $ 15,950 $ 20,856 $ 16,949
The Company capitalizes compensation cost for its share-based compensation awards based on an employee's job function. Capitalized compensation costs for the years ended December 31, 2022, 2021 and 2020 were $2.0 million, $4.2 million and $1.9 million, respectively. The Company recorded $1.0 million, $2.0 million, and $0.2 million for the years ended December 31, 2022, 2021 and 2020, respectively, of tax expense for excess tax benefits related to share-based compensation plans.
Performance Share Unit Programs - Equity & Liability
The Company assumed portions of the 2018 EQT Incentive Performance Share Unit Program (the 2018 EQT Incentive PSU Program) at the Separation Date.
The Human Capital and Compensation Committee of the Company's Board (formerly the Management Development and Compensation Committee and referred to herein as the Compensation Committee) adopted the Equitrans Midstream Corporation 2019 Performance Share Unit Program (the 2019 PSU Program), the Equitrans Midstream Corporation 2020 Performance Share Unit Program (the 2020 PSU Program), the Equitrans Midstream Corporation 2021 Performance Share Unit Program (the 2021 PSU Program) and the Equitrans Midstream Corporation 2022 Performance Share Unit Program (the 2022 PSU Program). The 2019 PSU Program, the 2020 PSU Program, the 2021 PSU Program and the 2022 PSU Program (collectively, the PSU Programs) vest in both equity and liability awards.
The Company established the PSU Programs to provide long-term incentive opportunities to key employees to further align their interests with those of the Company's shareholders and with the strategic objectives of the Company. The performance period for each of the awards under the PSU Programs, except for the 2020 PSU Program, is 36 months, with vesting occurring upon payment following the expiration of the performance period, subject to continued service through such vesting date. The awards under the 2020 PSU Program may be earned over four separate performance periods as follows: (i) 20% for each of the three calendar years that occurred following the vesting commencement date (i.e., the 2020, 2021 and 2022 calendar years) and (ii) 40% for the cumulative three-year period following the vesting commencement date (i.e., January 1, 2020 through December 31, 2022), with vesting occurring upon payment following the expiration of the cumulative three-year performance period, subject to continued service through such vesting date.
The PSU Program awards granted in 2020, 2021 and 2022 will be earned based on the level of Equitrans Midstream total shareholder return (TSR) relative to a predefined peer group (with respect to the 2020 PSU Program awards not to exceed 100% if the Company's TSR is less than zero percent).
The payout factor for the PSU Programs vary between zero and 200% of the number of outstanding units, each contingent on the applicable performance metrics. The Company recorded the portion of the PSU Programs to be settled in stock as equity awards using a grant date fair value determined through a Monte Carlo simulation, which projects the common stock price for the Company and its peers at the ending point of the applicable performance period. The PSU Programs also included awards to be settled in cash and, therefore, were recorded at fair value as of the measurement date determined through a Monte Carlo simulation, which projects the common stock price for the Company and its peers at the ending point of the applicable performance period. The expected share prices were generated using the Company's annual volatility for the expected term and the commensurate three-year or two-year risk-free rates for equity awards and liability awards, respectively. The vesting of units of the PSU Programs occurs upon payment following the expiration of the applicable performance period, subject to continued service through such date, and the satisfaction of the underlying performance or market condition.
The following table summarizes all PSU Programs to be settled in stock and classified as equity awards:
Non-vested Shares Weighted Average Fair Value Aggregate Fair Value
Outstanding at December 31, 2019 627,234 $ 29.46 $ 18,480,257
Granted 737,390 5.59 4,120,535
Vested (35,728) 120.60 (4,308,797)
Forfeited (28,329) 12.94 (366,528)
Outstanding at December 31, 2020 1,300,567 $ 13.78 $ 17,925,467
Granted 1,540,230 8.77 13,507,817
Vested (85,872) 76.53 (6,571,784)
Forfeited (95,729) 8.45 (808,857)
Outstanding at December 31, 2021 2,659,196 $ 9.05 $ 24,052,643
Granted 1,274,910 14.86 18,945,163
Vested (474,488) 15.03 (7,131,551)
Forfeited - - -
Outstanding at December 31, 2022 3,459,618 $ 10.37 $ 35,866,255
The following table summarizes all PSU Programs to be settled in cash and classified as liability awards:
Non-vested Units Weighted Average Fair Value Aggregate Fair Value
Outstanding at December 31, 2019 409,865 $ 28.84 $ 11,822,175
Granted 427,500 5.59 2,388,870
Vested (84,014) 59.90 (5,032,439)
Forfeited (40,756) 18.09 (737,222)
Outstanding at December 31, 2020 712,595 $ 11.85 $ 8,441,384
Granted 873,460 8.77 7,660,244
Vested (87,145) 33.87 (2,951,624)
Forfeited (27,145) 8.23 (223,349)
Outstanding at December 31, 2021 1,471,765 $ 8.78 $ 12,926,655
Granted 717,930 14.86 10,668,440
Vested (226,135) 14.67 (3,318,009)
Forfeited (85,758) 10.81 (927,125)
Outstanding at December 31, 2022 1,877,802 $ 10.30 $ 19,349,961
Fair value is estimated using a Monte Carlo simulation valuation method with the following weighted average assumptions:
For PSU Programs Issued During the Years Ended December 31,
2022 2021 2020
Accounting Treatment Liability (a)
Equity Liability (a)
Equity Equity
Risk-free rate 4.25 % 1.16 % 4.65 % 0.16 % 0.39 %
Dividend yield N/A N/A N/A N/A N/A
Volatility factor 58.4 % 54.0 % 58.4 % 61.0 % 53.0 %
Expected term 2 years 3 years 1 year 3 years 3 years
(a)Information shown for liability plan valuations is as of the measurement date.
Restricted Stock Awards - Equity
A summary of restricted stock equity award activity during the years ended December 31, 2022, 2021 and 2020 is presented below.
Non-vested Shares 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
Granted 660,250 8.04 5,308,410
Vested (58,185) 44.20 (2,572,026)
Forfeited (49,732) 11.17 (555,522)
Outstanding at December 31, 2021 1,393,401 $ 11.88 $ 16,547,208
Granted 546,520 10.34 5,651,017
Vested (293,281) 17.81 (5,223,311)
Forfeited - - -
Outstanding at December 31, 2022 1,646,640 $ 10.31 $ 16,974,914
The restricted stock equity grants become fully vested at the end of the three-year period commencing with the vesting commencement date, assuming continued service through such date.
As of December 31, 2022, $5.5 million of unrecognized compensation cost related to non-vested restricted stock equity awards was expected to be recognized over a remaining weighted average vesting term of approximately 1.05 years.
Restricted Stock Unit Awards - Liability
A summary of restricted stock unit liability award activity during the years ended December 31, 2022, 2021 and 2020 is presented below.
Non-vested Units Weighted Average Fair Value Aggregate Fair Value
Outstanding at January 1, 2020 567,929 $ 19.38 $ 11,005,969
Granted 474,580 12.43 5,899,650
Vested (131,456) 20.86 (2,741,834)
Forfeited (33,457) 17.87 (597,890)
Outstanding at December 31, 2020 877,596 $ 15.46 $ 13,565,895
Granted 430,800 8.06 3,472,652
Vested (190,036) 20.76 (3,944,942)
Forfeited (38,656) 10.73 (414,837)
Outstanding at December 31, 2021 1,079,704 $ 11.74 $ 12,678,768
Granted 380,250 9.77 3,716,834
Vested (267,642) 16.82 (4,502,803)
Forfeited (45,043) 10.00 (450,504)
Outstanding at December 31, 2022 1,147,269 $ 9.97 $ 11,442,295
The restricted stock unit grants become fully vested at the end of the three-year period commencing with the vesting commencement date, assuming continued service through such date. The total liability recorded for these restricted stock units was $6.5 million and $7.9 million as of December 31, 2022 and 2021, respectively.
Value Driver Performance Share Unit Award Programs
Under the 2018 EQT Value Driver Performance Share Unit Award Program (the 2018 EQT VDA), 50% of the awards confirmed vested upon payment following the first anniversary of the grant date, and the remaining 50% of the awards confirmed vested upon payment following the second anniversary of the grant date subject to continued service through such dates.
The following table provides detailed information on the second tranche of the 2018 EQT VDA award:
Shares Weighted Average Fair Value Aggregate Fair Value
Outstanding at January 1, 2020 174,921 $ 13.36 $ 2,336,952
Granted - - -
Vested (174,921) 13.36 (2,336,952)
Forfeited - - -
Outstanding at December 31, 2020 - $ - $ -
Non-Qualified Stock Options
In connection with the Separation, the Company assumed stock options related to EQT share-based compensation awards. Stock options outstanding and exercisable expire between 2023 and 2028. There were no unrecognized compensation costs related to outstanding non-vested stock options as of December 31, 2022. A summary of stock option activity during the years ended December 31, 2022, 2021 and 2020 is presented below.
Options
Outstanding at January 1, 2020 457,910
Vested 6,966
Expired -
Outstanding at December 31, 2020 464,876
Vested -
Expired -
Outstanding at December 31, 2021 464,876
Vested -
Expired (94,132)
Outstanding at December 31, 2022 370,744
Phantom Units
The Company grants phantom unit awards to certain non-employee directors who serve or at the time of grant served on the Board. Director phantom units expected to be satisfied in Company common stock vest on the date of grant and are recorded based on the grant date fair value, which is determined based upon the closing price of the Company’s common stock on the day before the grant date. The value of director phantom units is paid in Company common stock upon the director's termination of service on the Board. Prior to the completion of the EQM Merger, EQM's general partner granted phantom unit awards to certain non-employee directors of EQM's general partner.
A summary of phantom units' activity for the years ended December 31, 2022, 2021 and 2020 is presented below.
Equitrans Midstream phantom units EQM phantom units
Units Weighted Average Fair Value Aggregate Fair Value Units Weighted Average Fair Value Aggregate Fair Value
Outstanding at January 1, 2020 200,768 $ 20.78 $ 4,172,769 26,700 $ 53.51 $ 1,428,673
Granted 113,869 11.10 1,264,001 9,540 29.91 285,341
Distributions, net (a)
(23,989) 19.08 (457,644) (39,036) 45.36 (1,770,851)
Dividends 27,957 9.14 255,583 2,796 20.33 56,837
Outstanding at December 31, 2020 318,605 $ 16.43 $ 5,234,709 - $ - $ -
Granted 177,156 8.16 1,445,036 - - -
Distributions (16,957) 20.29 (343,982) - - -
Dividends 33,636 8.88 298,813 - - -
Outstanding at December 31, 2021 512,440 $ 12.95 $ 6,634,576 - $ - $ -
Granted 141,778 10.03 1,422,140 - - -
Distributions (104,603) 14.75 (1,542,823) - - -
Dividends 37,533 7.86 294,990 - - -
Outstanding at December 31, 2022 587,148 $ 11.60 $ 6,808,883 - $ - $ -
(a)In connection with the closing of the EQM Merger, the non-employee directors of the EQM General Partner received the Merger Consideration for each EQM phantom unit that they held. See Note 2.
2023 Awards
Effective in February 2023, the Compensation Committee adopted the Equitrans Midstream Corporation 2023 Performance Share Unit Program (2023 PSU Program) under the 2018 Plan. The 2023 PSU Program was established to align the interests of key employees with the interests of shareholders and the strategic objectives of the Company. Awards under the 2023 PSU Program, consisting of both equity and liability awards, are expected to be granted in the first quarter of 2023.
The vesting of the units under the 2023 PSU Program will occur upon payment after the expiration of the Performance Period, which is January 1, 2023 to December 31, 2025, assuming continued employment with the Company. The payout will vary between zero and 200% of the number of outstanding units contingent upon the level of total shareholder return relative to a predefined peer group, the achievement of certain levels of free cash flow before changes in working capital, and the number of ESG-related projects completed, in each case during the Performance Period and, in the case of free cash flow before changes in working capital, on an annual basis within such Performance Period.
The Company also expects to grant restricted stock equity and restricted stock unit liability awards in the first quarter of 2023. The restricted stock equity awards and restricted stock unit liability awards will be fully vested at the end of the three-year period commencing on January 1, 2023, assuming continued employment with the Company.
Employee Savings Plan
For the years ended December 31, 2022, 2021 and 2020, the Company recognized expense related to its defined contribution plan of $8.0 million, $7.6 million and $8.1 million, respectively.
10. Debt
The following table presents the Company's and its consolidated subsidiaries' outstanding debt as of December 31, 2022 and 2021.
December 31, 2022 December 31, 2021
Principal Carrying Value(a)
Fair Value(b)
Principal Carrying Value(a)
Fair Value(b)
(Thousands)
Amended EQM Credit Facility $ 240,000 $ 240,000 $ 240,000 $ 225,000 $ 225,000 $ 225,000
2021 Eureka Credit Facility
295,000 295,000 295,000 280,000 280,000 280,000
Total credit facility borrowings $ 535,000 $ 535,000 $ 535,000 $ 505,000 $ 505,000 $ 505,000
EQM 4.75% Senior Notes due 2023
98,941 98,830 97,086 600,000 598,088 628,380
EQM 4.00% Senior Notes due 2024
300,000 299,270 288,291 500,000 498,014 522,695
EQM 6.00% Senior Notes due 2025
400,000 397,005 386,000 700,000 692,662 763,091
EQM 4.125% Senior Notes due 2026
500,000 496,667 444,700 500,000 495,816 517,695
EQM 6.50% Senior Notes due 2027
900,000 891,417 860,175 900,000 889,510 1,014,417
EQM 7.50% Senior Notes due 2027
500,000 493,130 489,630 - - -
EQM 5.50% Senior Notes due 2028
850,000 843,775 760,036 850,000 842,657 939,684
EQM 4.50% Senior Notes due 2029
800,000 792,217 671,936 800,000 790,927 834,856
EQM 7.50% Senior Notes due 2030
500,000 492,799 481,760 - - -
EQM 4.75% Senior Notes due 2031
1,100,000 1,088,877 899,250 1,100,000 1,087,493 1,166,220
EQM 6.50% Senior Notes due 2048
550,000 540,163 412,198 550,000 539,778 673,458
Total debt 6,498,941 6,434,150 5,791,062 6,500,000 6,434,945 7,060,496
Less current portion of long-term debt 98,941 98,830 97,086 - - -
Total long-term debt $ 6,400,000 $ 6,335,320 $ 5,693,976 $ 6,500,000 $ 6,434,945 $ 7,060,496
(a)Carrying values of the senior notes represent principal amount less unamortized debt issuance costs and debt discounts.
(b)See Note 11 for a discussion of fair value measurements.
As of December 31, 2022, the combined aggregate amounts of maturities for long-term debt, including the current portion thereof, were as follows: $0.1 billion in 2023, $0.3 billion in 2024, $0.4 billion in 2025, $0.5 billion in 2026, $1.4 billion in 2027 and $3.8 billion in 2028 and thereafter.
Equitrans Midstream Term Loan Facility. In December 2018, Equitrans Midstream entered into a term loan credit agreement (as amended in May 2019, the ETRN Term Loan Credit Agreement) that provided for a senior secured term loan facility in an aggregate principal amount of $600 million (the ETRN Term Loans). The Company received net proceeds from the ETRN Term Loans of $568.1 million, inclusive of a discount of $18.0 million and estimated debt issuance costs of $13.9 million. The net proceeds were primarily used to fund the EQGP Buyout, including certain fees, costs and expenses in connection therewith, and the remainder was used for general corporate purposes. On March 3, 2020, EQM drew $650.0 million under the Amended EQM Credit Facility and transferred such funds to the Company, pursuant to a senior unsecured term loan agreement with the Company. The Company utilized a portion of such funds to pay off all of the amounts outstanding under the ETRN Term Loans and the ETRN Term Loan Credit Agreement was terminated. As a result, the Company wrote off $24.4 million of unamortized discount and financing costs related to the ETRN Term Loan Credit Agreement. The write off charge is included in the loss on extinguishment of debt line on the statements of consolidated comprehensive income. On September 29, 2020, the Company made a prepayment to EQM of all principal, interest, fees and other obligations outstanding under the senior unsecured term loan agreement and terminated the agreement. During the period from January 1, 2020 to March 3, 2020, the weighted average annual interest rate was approximately 6.2%.
Equitrans Midstream Credit Facility. In October 2018, Equitrans Midstream entered into a senior secured revolving credit facility agreement that provided for $100 million in borrowing capacity (the Equitrans Midstream Credit Facility). Equitrans Midstream amended the Equitrans Midstream Credit Facility on December 31, 2018 to, among other things, permit the incurrence of the borrowings under the ETRN Term Loan Credit Agreement. The Equitrans Midstream Credit Facility, which was available for general corporate purposes and to fund ongoing working capital requirements, was terminated on March 3,
2020 in conjunction with the Company's termination of the ETRN Term Loan Credit Agreement (see above). As a result, the Company wrote off $0.5 million of unamortized financing costs related to the Equitrans Midstream Credit Facility. The write off charge is included in the loss on extinguishment of debt line on the statements of consolidated comprehensive income.
The Company had no borrowings and no letters of credit outstanding under the Equitrans Midstream Credit Facility during the period from January 1, 2020 to March 3, 2020. Commitment fees paid to maintain credit availability under the Equitrans Midstream Credit Facility were approximately $0.1 million for the period from January 1, 2020 to March 3, 2020.
EQM Revolving Credit Facility. On April 22, 2022 (the Amendment Date), EQM entered into an amendment (the Third Amendment) to that certain Third Amended and Restated Credit Agreement, dated as of October 31, 2018, among EQM, as borrower, Wells Fargo Bank, National Association, as the administrative agent, swing line lender, and an L/C issuer, the lenders party thereto from time to time and any other persons party thereto from time to time, which Third Amended and Restated Credit Agreement previously had been amended by that certain First Amendment to Third Amended and Restated Credit Agreement, dated as of March 30, 2020, and by that certain Second Amendment to Third Amended and Restated Credit Agreement, dated as of April 16, 2021 (as amended by the Third Amendment and as may be further amended, restated, amended and restated, supplemented or otherwise modified from time to time, the Amended EQM Credit Facility). For the avoidance of doubt, any reference to the Amended EQM Credit Facility as of any particular date shall mean the Amended EQM Credit Facility as in effect on such date. Each of the First Amendment and Second Amendment, among other things, amended certain defined terms and negative covenants of the Amended EQM Credit Agreement. The Second Amendment also, among other things, reduced the aggregate commitments to $2.25 billion, and the commitment of each lender thereunder was reduced accordingly on a pro rata basis. The Third Amendment, among other things:
•Replaced LIBOR with the Secured Overnight Financing Rate (SOFR) as the benchmark rate for borrowings, including a credit spread adjustment of 0.10% for all applicable interest periods as well as for daily swing line borrowings.
•Extended the stated maturity date, with such extension only applicable for the lenders approving the Third Amendment, from October 31, 2023 (the Earlier Maturity Date) to April 30, 2025 (the Later Maturity Date).
•Reduced the aggregate commitments available under the Amended EQM Credit Facility on a non-pro rata basis to approximately $2.16 billion, with approximately $1.55 billion in aggregate commitments available under the Amended EQM Credit Facility on and after the Earlier Maturity Date and prior to the Later Maturity Date.
•Amended the definition of “Applicable Rate” to change the applicable percentages per annum set forth in the “Pricing Grid” for certain pricing levels, which continue to be determined on the basis of EQM’s credit ratings. As of the Amendment Date, (i) Base Rate Loans (as defined in the Amended EQM Credit Facility) bear interest at a base rate plus a margin of 1.750% per annum, (ii) SOFR Loans (as defined in the Amended EQM Credit Facility) bear interest at Adjusted Term SOFR (as defined in the Amended EQM Credit Facility) plus a margin of 2.750% per annum, (iii) Daily Simple Swing Line Loans (as defined in the Amended EQM Credit Facility) bear interest at Adjusted Daily Simple SOFR (as defined in the Amended EQM Credit Facility) plus a margin of 2.750% per annum, (iv) the letter of credit fee payable on the daily maximum amount available under each letter of credit is 2.750% per annum and (v) the commitment fee payable for unused commitments is 0.500% per annum.
•Amended the financial covenant, such that the Consolidated Leverage Ratio (as defined in the Amended EQM Credit Facility) as at the end of each fiscal quarter of EQM ending on or after the Amendment Date cannot exceed 5.50 to 1.00; provided that, effective as of the MVP Mobilization Effective Date (as defined in the Amended EQM Credit Facility), the maximum Consolidated Leverage Ratio permitted with respect to the end of the fiscal quarter in which the MVP Mobilization Effective Date occurs and the end of each of the three consecutive fiscal quarters of EQM thereafter shall be 5.85 to 1.00.
•Reduced each of the general lien and general subsidiary debt baskets based on Consolidated Net Tangible Assets (as defined in the Amended EQM Credit Facility) from 5.0% to 2.5% of Consolidated Net Tangible Assets.
•Added a borrowing condition requiring that, solely to the extent a credit extension is used to repay, redeem or refinance EQM’s senior notes, total outstanding amounts under the Amended EQM Credit Facility must not exceed 85% of the aggregate commitments after giving effect to the use of proceeds.
As of December 31, 2022, the Company had aggregate commitments available under the Amended EQM Credit Facility of approximately $2.16 billion before the Earlier Maturity Date, with approximately $1.55 billion in aggregate commitments available on and after the Earlier Maturity Date and prior to the Later Maturity Date. As of December 31, 2022, EQM had approximately $240 million of borrowings and $234.9 million of letters of credit outstanding under the Amended EQM Credit Facility. As of December 31, 2022, pursuant to the terms of the Amended EQM Credit Facility, EQM had the ability to borrow
approximately $0.5 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. As of December 31, 2021, EQM had approximately $225 million of borrowings and $234.9 million of letters of credit outstanding under the Amended EQM Credit Facility.
During the years ended December 31, 2022, 2021 and 2020, the maximum outstanding borrowings were $315 million, $525 million and $2,040 million, respectively, the average daily balances were approximately $193 million, $395 million and $852 million, respectively, and the weighted average annual interest rates were approximately 4.5%, 2.6% and 2.9%, respectively. For the years ended December 31, 2022, 2021 and 2020, commitment fees of $8.4 million, $7.4 million and $7.2 million, respectively, were paid to maintain credit availability under the Amended EQM Credit Facility. As of December 31, 2022, no term loans were outstanding under the Amended EQM Credit Facility.
Amended 2019 EQM Term Loan Agreement. In August 2019, EQM entered into a term loan agreement (the 2019 EQM Term Loan Agreement) that provided for unsecured term loans in an aggregate principal amount of $1.4 billion. On March 30, 2020, EQM entered into an amendment to the 2019 EQM Term Loan Agreement (as amended, the Amended 2019 EQM Term Loan Agreement) which, among other things, amended certain defined terms and negative covenants in the 2019 EQM Term Loan Agreement.
On January 8, 2021, EQM (i) applied a portion of the proceeds from the issuance of the 2021 Senior Notes (as defined below) to prepay all principal, interest, fees and other obligations outstanding under the Amended 2019 EQM Term Loan Agreement and (ii) terminated the Amended 2019 EQM Term Loan Agreement and the loan documents associated therewith. EQM repaid outstanding loans with a principal amount of $1.4 billion in connection with the termination of the Amended 2019 EQM Term Loan Agreement. Prior to its termination in January 2021, the Amended 2019 EQM Term Loan Agreement would have matured in August 2022.
The Amended 2019 EQM Term Loan Agreement provided EQM with the right to request incremental term loans in an aggregate amount of up to $300 million, subject to, among other things, obtaining additional commitments from existing lenders or commitments from new lenders. As of December 31, 2020, EQM had $1.4 billion of borrowings outstanding under the Amended 2019 EQM Term Loan Agreement. During the period from January 1, 2021 through January 7, 2021, the weighted average annual interest rate was approximately 2.4%. During the year ended December 30, 2020, the weighted average annual interest rates were approximately 2.7%.
Eureka Credit Facilities. On May 13, 2021, Eureka Midstream, LLC (Eureka), a wholly owned subsidiary of Eureka Midstream, repaid all outstanding principal borrowings plus accrued and unpaid interest under and terminated its credit facility with ABN AMRO Capital USA LLC, as administrative agent, the lenders party thereto from time to time and any other persons party thereto from time to time (the Former Eureka Credit Facility). In conjunction with the termination of, and to fund the repayment of all outstanding amounts under the Former Eureka Credit Facility, on May 13, 2021, Eureka entered into a $400 million senior secured revolving credit facility with Sumitomo Mitsui Banking Corporation, as administrative agent, the lenders party thereto from time to time and any other persons party thereto from time to time (the 2021 Eureka Credit Facility). The 2021 Eureka Credit Facility matures on November 13, 2024, and is available for general business purposes, including financing maintenance and expansion capital expenditures related to the Eureka system and providing working capital for Eureka’s operations.
As of December 31, 2022 and 2021, Eureka had approximately $295 million and $280 million, respectively, of borrowings outstanding under the 2021 Eureka Credit Facility. During the year ended December 31, 2022, the maximum amount of outstanding borrowings under the 2021 Eureka Credit Facility at any time was approximately $295 million, the average daily balance was approximately $281 million and Eureka incurred interest at weighted average annual interest rate of approximately 4.4%. For the year ended December 31, 2022, commitment fees of $0.5 million were paid to maintain credit availability under the 2021 Eureka Credit Facility. During the year ended December 31, 2021, the maximum amount of outstanding borrowings under the Former Eureka Credit Facility and the 2021 Eureka Credit Facility at any time was approximately $315 million, the average daily balance was approximately $301 million and Eureka incurred interest at a weighted average annual interest rate of approximately 2.5%. For the year ended December 31, 2021, commitment fees of $0.5 million were paid to maintain credit availability under the Former Eureka Credit Facility and the 2021 Eureka Credit Facility. During the year ended December 31, 2020, the maximum amount of outstanding borrowings under the Former Eureka Credit Facility at any time was approximately $323 million, the average daily balance was approximately $301 million and Eureka incurred interest at weighted average annual interest rates of approximately 2.6%. For the year ended December 31, 2020, commitment fees of $0.6 million were paid to maintain credit availability under the Former Eureka Credit Facility.
2022 Senior Notes. On June 7, 2022, EQM completed a private offering of $500 million aggregate principal amount of new 7.50% senior notes due 2027 (the 2027 Notes) and $500 million aggregate principal amount of new 7.50% senior notes due
2030 (the 2030 Notes and, together with the 2027 Notes, the 2022 Senior Notes) and received net proceeds from the offering of approximately $984.5 million (excluding costs related to the 2022 Tender Offers discussed below), inclusive of a discount of approximately $12.5 million and debt issuance costs of approximately $3.0 million.
The 2022 Senior Notes were issued under and are governed by an indenture, dated June 7, 2022 (the 2022 Indenture), between EQM and U.S. Bank Trust Company, National Association, as trustee. The 2022 Indenture contains covenants that limit EQM’s ability to, among other things, incur certain liens securing indebtedness, engage in certain sale and leaseback transactions, and enter into certain consolidations, mergers, conveyances, transfers or leases of all or substantially all of EQM’s assets. The 2027 Notes will mature on June 1, 2027 and interest on the 2027 Notes is payable semi-annually on June 1 and December 1 of each year, commencing December 1, 2022. The 2030 Notes will mature on June 1, 2030 and interest on the 2030 Notes is payable semi-annually on June 1 and December 1 of each year, commencing December 1, 2022.
The 2022 Senior Notes are unsecured and rank equally with all of EQM’s existing and future senior obligations. The 2022 Senior Notes are senior in right of payment to any of EQM’s future obligations that are, by their terms, expressly subordinated in right of payment to the 2022 Senior Notes. The 2022 Senior Notes are effectively subordinated to EQM’s secured obligations, if any, to the extent of the value of the collateral securing such obligations, and structurally subordinated to all indebtedness and obligations, including trade payables, of EQM’s subsidiaries, other than any subsidiaries that may guarantee the 2022 Senior Notes in the future.
EQM may, at its option, redeem some or all of the 2027 Notes and the 2030 Notes, in whole or in part, at any time prior to their maturity at the applicable redemption price as set forth in the 2022 Indenture.
Upon the occurrence of a Change of Control Triggering Event (as defined in the 2022 Indenture), EQM may be required to offer to purchase the 2022 Senior Notes at a purchase price equal to 101% of the aggregate principal amount of the 2022 Senior Notes repurchased, plus accrued and unpaid interest, if any, to, but excluding, the repurchase date.
The 2022 Indenture contains certain events of default, including the following: (1) default in the payment of interest on such 2022 Senior Notes when due that continues for 30 days; (2) default in the payment of principal of or premium, if any, on any such 2022 Senior Notes when due, whether at its stated maturity, upon redemption or otherwise; (3) failure by EQM or any subsidiary guarantor, if any, to comply for 90 days with the other agreements with respect to such 2022 Senior Notes contained in the 2022 Indenture after written notice by the trustee or by the holders of at least 25% in principal amount of the outstanding 2022 Senior Notes of such series; (4) certain events of bankruptcy, insolvency or reorganization of EQM or any subsidiary guarantor, if any, that is one of EQM’s Significant Subsidiaries (as defined in the 2022 Indenture); and (5) if such 2022 Senior Notes are guaranteed by a subsidiary guarantor that is one of EQM’s Significant Subsidiaries, (a) the guarantee of that subsidiary guarantor ceases to be in full force and effect, except as otherwise provided in the 2022 Indenture; (b) the guarantee of that subsidiary guarantor is declared null and void in a judicial proceeding; or (c) that subsidiary guarantor denies or disaffirms its obligations under the 2022 Indenture or its guarantee.
If an event of default occurs and is continuing, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2022 Senior Notes of such series may declare the 2022 Senior Notes of such series to be due and payable. Upon such a declaration, such principal, premium, if any, and accrued and unpaid interest on such 2022 Senior Notes will be due and payable immediately. If an event of default relating to certain events of bankruptcy, insolvency or reorganization occurs, all outstanding 2022 Senior Notes will become due and payable immediately without further action or notice on the part of the trustee or any holders of the 2022 Senior Notes.
EQM used the net proceeds from the offering of the 2022 Senior Notes and cash on hand to purchase (i) an aggregate principal amount of approximately $501.1 million of its outstanding 4.75% notes due 2023 (2023 Notes) pursuant to a tender offer for any and all of the outstanding 2023 Notes (the Any and All Tender Offer) and an open market purchase following the expiration of the Any and All Tender Offer, and (ii) an aggregate principal amount of $300 million of its outstanding 6.00% notes due 2025 (2025 Notes), and an aggregate principal amount of $200 million of its outstanding 4.00% notes due 2024 (2024 Notes), pursuant to tender offers (the Maximum Tender Offers, together with the Any and All Tender Offer, the 2022 Tender Offers) for the 2025 Notes and 2024 Notes, which such Maximum Tender Offers reflected a maximum aggregate principal amount of 2025 Notes and 2024 Notes to be purchased of $500 million (such amount, the Aggregate Maximum Principal Amount).
2022 Tender Offers. On June 6, 2022, the Any and All Tender Offer expired and, on June 7, 2022 and June 9, 2022, EQM purchased an aggregate principal amount of approximately $496.8 million of 2023 Notes at an aggregate cost of approximately $506.7 million pursuant to the Any and All Tender Offer. On June 10, 2022, which was after the closing of the Any and All Tender Offer, EQM also repurchased an aggregate principal amount of approximately $4.3 million of 2023 Notes in the open market at an aggregate cost of approximately $4.4 million. On June 13, 2022, which was the early tender deadline for the Maximum Tender Offers, the Aggregate Maximum Principal Amount was fully subscribed by the 2024 Notes and 2025 Notes
then tendered, and, on June 14, 2022, EQM purchased an aggregate principal amount of $200 million of 2024 Notes and $300 million of 2025 Notes at an aggregate cost of approximately $509 million (inclusive of the applicable early tender premium for the 2024 Notes and 2025 Notes described in that certain Offer to Purchase of EQM dated May 31, 2022, as amended).
The Company incurred a loss on the extinguishment of debt of approximately $24.9 million during the year ended December 31, 2022 related to the payment of the 2022 Tender Offers and open market repurchase premiums and fees, and write off of the respective unamortized discounts and financing costs associated with the purchase of portions of 2023, 2024 and 2025 Notes in the 2022 Tender Offers. This amount is included in the loss on extinguishment of debt line on the statements of consolidated comprehensive income.
2021 Senior Notes. During the first quarter of 2021, EQM issued, in a private offering, $800 million aggregate principal amount of new 4.50% senior notes due 2029 (the 2029 Notes) and $1,100 million aggregate principal amount of new 4.75% senior notes due 2031 (the 2031 Notes and, together with the 2029 Notes, the 2021 Senior Notes) and received net proceeds from the offering of approximately $1,876.5 million (excluding costs related to the 2021 Tender Offers discussed below), inclusive of a discount of $19 million and debt issuance costs of $4.5 million. EQM used the net proceeds from the offering of the 2021 Senior Notes and cash on hand to repay all outstanding borrowings under the Amended 2019 EQM Term Loan Agreement, to purchase an aggregate principal amount of $500 million of its outstanding 2023 Notes pursuant to tender offers for certain of EQM's outstanding indebtedness (such tender offers, the 2021 Tender Offers), and for general partnership purposes.
The 2021 Senior Notes were issued under and are governed by an indenture, dated January 8, 2021 (the 2021 Indenture), between EQM and The Bank of New York Mellon Trust Company, N.A., as trustee. The 2021 Indenture contains covenants that limit EQM’s ability to, among other things, incur certain liens securing indebtedness, engage in certain sale and leaseback transactions, and enter into certain consolidations, mergers, conveyances, transfers or leases of all or substantially all of EQM’s assets. The 2029 Notes will mature on January 15, 2029 and interest on the 2029 Notes is payable semi-annually on January 15 and July 15 of each year, commencing July 15, 2021. The 2031 Notes will mature on January 15, 2031 and interest on the 2031 Notes is payable semi-annually on January 15 and July 15 of each year, commencing July 15, 2021.
The 2021 Senior Notes are unsecured and rank equally with all of EQM’s existing and future senior obligations. The 2021 Senior Notes are senior in right of payment to any of EQM’s future obligations that are, by their terms, expressly subordinated in right of payment to the 2021 Senior Notes. The 2021 Senior Notes are effectively subordinated to EQM’s secured obligations, if any, to the extent of the value of the collateral securing such obligations, and structurally subordinated to all indebtedness and obligations, including trade payables, of EQM’s subsidiaries, other than any subsidiaries that may guarantee the 2021 Senior Notes in the future. EQM may, at its option, redeem some or all of the 2029 Notes and the 2031 Notes, in whole or in part, at any time prior to their maturity at the applicable redemption price as set forth in the 2021 Indenture.
Upon the occurrence of a Change of Control Triggering Event (as defined in the 2021 Indenture), EQM may be required to offer to purchase the 2021 Senior Notes at a purchase price equal to 101% of the aggregate principal amount of the 2021 Senior Notes repurchased, plus accrued and unpaid interest, if any, to, but excluding, the repurchase date.
The 2021 Indenture contains certain events of default, including the following: (i) default in the payment of interest on such 2021 Senior Notes when due that continues for 30 days; (ii) default in the payment of principal of or premium, if any, on any such 2021 Senior Notes when due, whether at its stated maturity, upon redemption or otherwise; (iii) failure by EQM or any subsidiary guarantor, if any, to comply for 90 days with the other agreements with respect to such 2021 Senior Notes contained in the 2021 Indenture after written notice by the trustee or by the holders of at least 25% in principal amount of the outstanding 2021 Senior Notes of such series; (iv) certain events of bankruptcy, insolvency or reorganization of EQM or any subsidiary guarantor, if any, that is one of EQM’s Significant Subsidiaries (as defined in the 2021 Indenture); and (v) if such 2021 Senior Notes are guaranteed by a subsidiary guarantor that is one of EQM’s Significant Subsidiaries, (a) the guarantee of that subsidiary guarantor ceases to be in full force and effect, except as otherwise provided in the 2021 Indenture; (b) the guarantee of that subsidiary guarantor is declared null and void in a judicial proceeding; or (c) that subsidiary guarantor denies or disaffirms its obligations under the 2021 Indenture or its guarantee.
If an event of default occurs and is continuing with respect to any of the 2021 Senior Notes, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2021 Senior Notes of such series may declare the 2021 Senior Notes of such series to be due and payable. Upon such a declaration, such principal, premium, if any, and accrued and unpaid interest on such 2021 Senior Notes will be due and payable immediately. If an event of default relating to certain events of bankruptcy, insolvency or reorganization occurs, all outstanding 2021 Senior Notes will become due and payable immediately without further action or notice on the part of the trustee or any holders of the 2021 Senior Notes.
2021 Tender Offers. On January 15, 2021 (the 2021 early tender deadline), the maximum principal amount for the 2021 Tender Offers was fully subscribed by the 2023 Notes tendered as of the 2021 early tender deadline and on January 20, 2021, EQM
purchased an aggregate principal amount of $500 million of 2023 Notes at an aggregate cost of approximately $537 million (inclusive of the applicable early tender premium for the 2023 Notes described in that certain Offer to Purchase of EQM dated January 4, 2021, as amended, plus accrued interest).
The Company incurred a loss on the extinguishment of debt of $41.0 million during the 2021 related to the payment of the premium in the 2021 Tender Offers and write off of unamortized discounts and financing costs related to the prepayment of the loans under, and termination of, the Amended 2019 EQM Term Loan Agreement and purchase of 2023 Notes in the 2021 Tender Offers. This amount is included in the loss on extinguishment of debt line on the statements of consolidated comprehensive income.
2020 Senior Notes. During the second quarter of 2020, EQM issued $700 million aggregate principal amount of new 6.00% senior unsecured notes due July 1, 2025 and $900 million aggregate principal amount of new 6.50% senior unsecured notes due July 1, 2027 (collectively, the 2020 Senior Notes) and received net proceeds from the offering of approximately $1,576.1 million, inclusive of a discount of $20.0 million and debt issuance costs of $3.9 million. A portion of the net proceeds were used to repay a portion of the borrowings outstanding under the Amended EQM Credit Facility, and the remainder was used for general partnership purposes.
The 2020 Senior Notes were issued under and are governed by an indenture, dated June 18, 2020 (the 2020 Indenture), between EQM and The Bank of New York Mellon Trust Company, N.A., as trustee. The 2020 Indenture contains covenants that limit EQM's ability to, among other things, incur certain liens securing indebtedness, engage in certain sale and leaseback transactions, and enter into certain consolidations, mergers, conveyances, transfers or leases of all or substantially all of EQM's assets. Upon the occurrence of a Change of Control Triggering Event (as defined in the 2020 Indenture), EQM may be required to offer to purchase the 2020 Senior Notes at a purchase price equal to 101% of the aggregate principal amount of the 2020 Senior Notes repurchased, plus accrued and unpaid interest, if any, to, but excluding, the repurchase date.
The 2020 Senior Notes are unsecured and rank equally with all of EQM’s existing and future senior obligations. The 2020 Senior Notes are senior in right of payment to any of EQM’s future obligations that are, by their terms, expressly subordinated in right of payment to the 2020 Senior Notes. The 2020 Senior Notes are effectively subordinated to EQM’s secured obligations, if any, to the extent of the value of the collateral securing such obligations, and structurally subordinated to all indebtedness and obligations, including trade payables, of EQM’s subsidiaries, other than any subsidiaries that may guarantee the 2020 Senior Notes in the future.
The 2020 Indenture contains certain events of default, including the following: (1) default in the payment of interest on such 2020 Senior Notes when due that continues for 30 days; (2) default in the payment of principal of or premium, if any, on any such 2020 Senior Notes when due, whether at its stated maturity, upon redemption or otherwise; (3) failure by EQM or any subsidiary guarantor, if any, to comply for 90 days with the other agreements with respect to such 2020 Senior Notes contained in the 2020 Indenture after written notice by the trustee or by the holders of at least 25% in principal amount of the outstanding 2020 Senior Notes of such series; (4) certain events of bankruptcy, insolvency or reorganization of EQM or any subsidiary guarantor, if any, that is one of EQM’s Significant Subsidiaries (as defined in the 2020 Indenture); and (5) if such 2020 Senior Notes are guaranteed by a subsidiary guarantor that is one of EQM’s Significant Subsidiaries, (a) the guarantee of that subsidiary guarantor ceases to be in full force and effect, except as otherwise provided in the 2020 Indenture; (b) the guarantee of that subsidiary guarantor is declared null and void in a judicial proceeding; or (c) that subsidiary guarantor denies or disaffirms its obligations under the 2020 Indenture or its guarantee.
If an event of default occurs and is continuing with respect to any of the 2020 Senior Notes, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2020 Senior Notes of such series may declare the 2020 Senior Notes of such series to be due and payable. Upon such a declaration, such principal, premium, if any, and accrued and unpaid interest on such 2020 Senior Notes will be due and payable immediately. If an event of default relating to certain events of bankruptcy, insolvency or reorganization occurs, all outstanding 2020 Senior Notes will become due and payable immediately without further action or notice on the part of the trustee or any holders of the 2020 Senior Notes.
As of December 31, 2022, EQM and Eureka were in compliance with all debt provisions and covenants.
11. Fair Value Measurements
Assets Measured at Fair Value on a Recurring Basis. The Company records derivative instruments at fair value on a gross basis in its consolidated balance sheets. The EQT Global GGA provides for potential cash bonus payments payable by EQT to the Company during the period beginning on the first day of the calendar quarter in which the MVP full in-service date occurs through the calendar quarter ending December 31, 2024 (the Henry Hub cash bonus payment provision). The potential cash bonus payments are conditioned upon the quarterly average of certain Henry Hub natural gas prices exceeding certain price thresholds. The Henry Hub cash bonus payment provision is accounted for as a derivative instrument and recorded at its
estimated fair value using a Monte Carlo simulation model. Significant inputs used in the fair value measurement include NYMEX Henry Hub natural gas futures prices as of the date of valuation, probability-weighted assumptions regarding MVP full in-service timing, risk-free interest rates based on U.S. Treasury rates, expected volatility of NYMEX Henry Hub natural gas futures prices and an estimated credit spread of EQT. The probability-weighted assumptions regarding MVP full in-service timing, utilizing internally developed methodologies, and the expected volatility of NYMEX Henry Hub natural gas futures prices used in the valuation methodology represent significant unobservable inputs causing the Henry Hub cash bonus payment provision to be designated as a Level 3 fair value measurement. An expected average volatility of approximately 62.5% was utilized in the valuation model, which is based on market-quoted volatilities of relevant NYMEX Henry Hub natural gas forward prices.
As of December 31, 2022 and 2021, the fair values of the Henry Hub cash bonus payment provision were $23.0 million and $13.4 million, respectively, which were recorded in other assets on the Company's consolidated balance sheets. During the years ended December 31, 2022, 2021 and 2020, the Company recognized a gain of $9.6 million, a loss of $47.8 million and a gain of $9.7 million, respectively, representing the change in estimated fair value of the derivative instrument during the respective periods and are recorded in other income (expense), net, in the Company's statements of consolidated comprehensive income.
Other Financial Instruments. The carrying values of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short maturity of the instruments. The carrying values of borrowings under the Amended EQM Credit Facility, the Former Eureka Credit Facility (prior to its termination), the 2021 Eureka Credit Facility and the Amended 2019 EQM Term Loan Agreement (prior to its termination) approximate fair value as the interest rates are based on prevailing market rates. As EQM's borrowings under its senior notes are not actively traded, their fair values are estimated using an income approach model that applies a discount rate based on prevailing market rates for debt with similar remaining time-to-maturity and credit risk; as such, their fair values are Level 2 fair value measurements. See Note 10 for further information on the fair value of the Company’s outstanding debt. The fair value of the Preferred Interest is a Level 3 fair value measurement and is estimated using an income approach model that applies a market-based discount rate. As of December 31, 2022 and 2021, the estimated fair values of the Preferred Interest were approximately $95.2 million and $116.5 million, respectively, and the carrying values of the Preferred Interest were approximately $94.3 million and $99.8 million, respectively.
12. (Loss) Earnings Per Share
The following tables set forth the computation of the basic and diluted (loss) earnings per share attributable to Equitrans Midstream common shareholders for the years ended December 31, 2022, 2021 and 2020:
Year Ended December 31,
2022 2021 2020
Basic Diluted Basic Diluted Basic Diluted
(In thousands, except per share data)
Net (loss) income $ (257,138) $ (257,138) $ (1,397,290) $ (1,397,290) $ 632,984 $ 632,984
Less: Net income attributable to noncontrolling interests (excluding EQM Series A Preferred Units) 12,204 12,204 14,530 14,530 167,553 167,553
Less: EQM Series A Preferred Units interest in net income - - - - 47,359 47,359
Less: Preferred dividends 58,512 58,512 58,512 58,512 58,760 58,760
Net (loss) income attributable to Equitrans Midstream common shareholders $ (327,854) $ (327,854) $ (1,470,332) $ (1,470,332) $ 359,312 $ 359,312
Basic weighted average common shares outstanding 433,341 433,341 433,008 433,008 343,935 343,935
Dilutive securities (a)
- - - - - 40
Diluted weighted average common shares outstanding 433,341 433,341 433,008 433,008 343,935 343,975
(Loss) earnings per share of common stock attributable to Equitrans Midstream common shareholders $ (0.76) $ (0.76) $ (3.40) $ (3.40) $ 1.04 $ 1.04
(a) For the years ended December 31, 2022, 2021 and 2020, the Company excluded 30,835 (in thousands), 30,556 (in thousands), and 16,512 (in thousands), respectively, of weighted average anti-dilutive securities related to the Equitrans Midstream Preferred Shares and stock-based compensation awards.
Preferred dividends include a $27.3 million premium recognized on the redemption of the EQM Series A Preferred Units as part of the Restructuring Closing during the year ended December 31, 2020.
The Company grants Equitrans Midstream phantom units to certain non-employee directors that will be paid in Equitrans Midstream common stock upon the director's termination of service on the Board. As there are no remaining service, performance or market conditions related to these awards, 595, 498 and 288 (in thousands) Equitrans Midstream phantom units were included in the computation of basic and diluted weighted average common shares outstanding for the years ended December 31, 2022, 2021 and 2020, respectively. See Note 9 for information on Equitrans Midstream phantom units.
13. Income Taxes
The following table summarizes income tax (benefit) expense for the years ended December 31, 2022, 2021 and 2020.
Years Ended December 31,
2022 2021 2020
(Thousands)
Current income tax expense:
Federal $ - $ - $ -
State 972 4,853 2,613
Total current income tax expense 972 4,853 2,613
Deferred income tax expense (benefit):
Federal (5,391) (273,512) 79,861
State 10,863 (74,694) 21,119
Total deferred income tax expense (benefit) 5,472 (348,206) 100,980
Total income tax expense (benefit) $ 6,444 $ (343,353) $ 103,593
The following table summarizes differences between income tax expense (benefit) and amounts computed at the applicable federal statutory rate on pre-tax income for the years ended December 31, 2022, 2021 and 2020.
Years Ended December 31,
2022 2021 2020
(Thousands)
Income tax (benefit) expense at statutory rate $ (52,646) $ (365,535) $ 154,681
Valuation allowances 49,799 106,886 -
State income tax expense (benefit) 9,440 (81,573) 18,748
Noncontrolling interests' share of earnings (2,563) (3,051) (45,132)
AFUDC - equity 11 (2,595) (28,346)
Other 2,403 2,515 3,642
Income tax expense (benefit) $ 6,444 $ (343,353) $ 103,593
Effective tax rate (2.6) % 19.7 % 14.1 %
For the year ended December 31, 2022, the effective tax rate was lower than the federal and state statutory rates due to the increase in the valuation allowances that limit tax benefits for the Company's federal and state deferred tax assets, primarily due to the impairment of the Company's equity method investment in the MVP Joint Venture and its impact on the loss before income taxes and deferred income tax assets. For the year ended December 31, 2022, the effective tax rate was lower than the year ended December 31, 2021, primarily due to the lower 2022 impairment of the Company's equity method investment in the MVP Joint Venture and its impact on the loss before income taxes and deferred income tax assets as compared to the 2021 impairment of the Company's equity method investment in the MVP Joint Venture. For the year ended December 31, 2022, state income tax decreased the effective tax rate before valuation allowances due to the reduction of the future Pennsylvania Corporate Income Tax Rates and reduced the Pennsylvania deferred tax asset. As a result of an offsetting decrease to valuation allowances, the decrease in the Pennsylvania Corporate Income Tax Rates had no net impact on the effective tax rate for the year ended December 31, 2022.
For the year ended December 31, 2021, the effective tax rate was lower than the federal and state statutory rates due to valuation allowances that limit tax benefits for the Company's federal and state deferred tax assets primarily due to the increase in the impairment of the Company's equity method investment in the MVP Joint Venture and its impact on the loss before income taxes and deferred income tax assets. For the year ended December 31, 2021, the effective tax rate was higher than the year ended December 31, 2020, primarily due to the EQM Merger impact on noncontrolling interest and the decrease in MVP Joint Venture AFUDC on the construction of MVP. The effective tax rate was also higher for the year ended December 31, 2021, due to the impairment of equity method investment (see Note 3) and its impact on the loss before income taxes. Noncontrolling interest and AFUDC - equity increase the effective tax rate in periods with a loss before income taxes.
For the years ended December 31, 2021 and 2020, the effective tax rates also were lower than the federal and state statutory rates because the Company does not record income tax expense for the applicable periods on the portions of its income attributable to the noncontrolling member of Eureka Midstream and for the year ended December 31, 2020, the effective tax rate was lower than the federal and state statutory rate because the Company did not record income tax expense on the portion of its income attributable to noncontrolling limited partners of EQM for the periods prior to the closing of the EQM Merger.
The following table summarizes the components of net deferred tax (liabilities) assets.
December 31,
2022 2021
(Thousands)
Deferred income tax assets:
Investment in partnerships $ 65,896 $ 76,405
163(j) interest limitation 36,523 -
Net operating loss carryforwards 71,639 51,230
Total deferred tax assets 174,058 127,635
Valuation allowance (156,685) (106,886)
Net deferred tax asset 17,373 20,749
Deferred income tax liabilities:
Deferred revenue (15,143) (17,120)
Other (2,230) (3,629)
Total deferred income tax liability (17,373) (20,749)
Net deferred income tax asset (liability) $ - $ -
As of December 31, 2022, the Company had federal NOL of $61.7 million and state NOL of $9.9 million related to various state jurisdictions with a corresponding valuation allowance of $61.7 million and $9.9 million, respectively. The Company has a valuation allowance related to federal and state interest disallowances under Internal Revenue Code Section 163(j) of $36.5 million. The Company also has a valuation allowance related to its investment in partnership deferred tax assets, net of offsetting deferred tax liability of $48.6 million. As of December 31, 2021, the Company had federal NOL of $34.5 million and state NOL of $16.7 million related to various state jurisdictions with a corresponding valuation allowance of $34.5 million and $16.7 million, respectively. As of December 31, 2021, the Company also had a valuation allowance related to its investment in partnership deferred tax assets, net of offsetting deferred tax liabilities of $55.7 million. The federal and commonwealth of Virginia and state of 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 between 2038 and 2042 and utilization is limited to 40% of taxable income in the year of utilization.
For the year ended December 31, 2022, the Company believes that it is more likely than not that the benefit from a portion of its state net operating loss (NOL) carryforwards, deferred tax assets related to interest disallowance under Internal Revenue Code Section 163(j), and certain state deferred tax assets, net of offsetting deferred tax liabilities, will not be realized and accordingly, the Company maintains related valuation allowances. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not (greater than 50%) that a tax benefit will not be realized. In evaluating the need for a valuation allowance, management considers available evidence, both positive and negative, including potential sources of taxable income, income available in carry-back periods, future reversals of taxable temporary differences, projections of taxable income and income from tax planning strategies. Positive evidence includes reversing temporary differences and projection of future profitability within the carry-forward period, including from tax planning strategies. Negative evidence includes historical pre-tax book losses and Pennsylvania NOL expirations. A review of positive and negative evidence regarding these tax benefits resulted in
the conclusion that valuation allowances on a portion of the Company’s federal and state NOL carryforwards and reversals of the investment in partnership deferred tax asset, net of offsetting deferred tax liabilities, were warranted as it was more likely than not that these assets will not be realized. 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.
The following table summarizes the changes in valuation allowances for the years ended December 31, 2022 and 2021:
Deferred income tax asset valuation allowance
(Thousands)
Balance at January 1, 2021 $ -
Valuation allowance provision 106,886
Balance at December 31, 2021 $ 106,886
Valuation allowance provision 49,799
Balance at December 31, 2022 $ 156,685
The Company has not identified any uncertain tax positions for the years ended December 31, 2022, 2021 or 2020.
The Company is not subject to federal or state income tax examination by tax authorities for years before 2019.
14. Concentrations of Credit Risk
The Company is exposed to the credit risk of its customers, including EQT, its largest customer, other producers, natural gas marketers, distribution companies and other end users. For the years ended December 31, 2022, 2021 and 2020, EQT accounted for approximately 61%, 59% and 64%, respectively, of the Company's total revenues across all of the Company's operating segments. As of December 31, 2022, EQT had credit ratings of BBB- from S&P (with a stable outlook), Ba1 from Moody's (with a positive outlook) and BBB- from Fitch (with a stable outlook). Each of S&P's and Fitch's ratings were considered investment grade and Moody's rating was considered non-investment grade. As of December 31, 2021, EQT's credit ratings with each of S&P, Moody's and Fitch were considered non-investment grade.
As of December 31, 2022 and 2021, EQT accounted for 72% and 75%, respectively, of the Company's accounts receivable balances, while various other natural gas marketers and producers accounted for the majority of the remaining accounts receivable balances. To manage the credit risk related to transactions with marketers, the Company engages with only those that meet specified criteria for credit and liquidity strength and actively monitors accounts with marketers. In connection with its assessment of marketer credit and liquidity strength, the Company may request a letter of credit, guarantee, performance bond or other credit enhancement. The Company did not experience significant defaults on accounts receivable during the years ended December 31, 2022, 2021 and 2020.
15. Commitments and Contingencies
From time to time, various legal and regulatory claims and proceedings are pending or threatened against the Company and its subsidiaries. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accrues legal and other direct costs related to loss contingencies when incurred. The Company establishes reserves whenever it believes it to be appropriate for pending matters. Furthermore, after consultation with counsel and considering the availability, if any, of insurance, the Company believes, although no assurance can be given, that the ultimate outcome of any matter currently pending against it or any of its consolidated subsidiaries will not materially adversely affect its business, financial condition, results of operations, liquidity or ability to pay dividends to its shareholders.
On November 6, 2022, the Company became aware that a storage well at Equitrans, L.P.’s Rager Mountain natural gas storage facility located in Jackson Township, a remote section of Cambria County, Pennsylvania, was venting natural gas. The venting from such well was successfully halted on November 19, 2022. The Company has established a regulatory reserve in connection with the Rager Mountain natural gas storage field incident, which is included in regulatory and other long-term liabilities in the consolidated balance sheets as of December 31, 2022. The Company is incurring and expects to continue to incur costs and expenses as a result of the incident, including beyond such reserve or not foreseen or estimable as of the date of the filing of this Annual Report on Form 10-K, which amounts, if significant individually or in the aggregate, could have a material adverse effect on the Company's business, financial condition, results of operations, liquidity or ability to pay dividends to the Company's shareholders.
The Company is subject to federal, state and local environmental laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and, in certain instances, have resulted and can result in assessment of fines. The Company has established procedures for the ongoing evaluation of its operations to seek to identify potential environmental exposures and to promote compliance with regulatory requirements. The estimated costs associated with identified situations requiring remedial action are accrued; however, when recoverable through future regulated rates, certain of these costs are deferred as regulatory assets. Through December 31, 2022, ongoing expenditures for compliance with environmental laws and regulations, including investments in facilities to meet environmental requirements, have not been material. Based on applicable environmental laws and regulations, management believes that required expenditures in respect thereof will not be significantly different in either nature or amount in the future and, based on such environmental laws and regulations, does not know of any future environmental liabilities that will have a material adverse effect on the Company's business, financial condition, results of operations, liquidity or ability to pay dividends to the Company's shareholders (however, the Company cautions that the ultimate expenditures related to or arising out of the Rager Mountain incident may affect the nature and magnitude of future expenditures, and such expenditures and the ultimate impact of the Rager Mountain incident are not yet known). Nonetheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and it is generally expected that such trend will likely increase in the future. Thus, compliance with future environmental laws and regulations could result in significant costs and could have a material adverse effect on the Company's business, financial condition, results of operations, liquidity or ability to pay dividends to the Company's shareholders.
Purchase obligations represent agreements to purchase goods or services that are enforceable, legally binding and specify all significant terms, including the approximate timing of the transaction. As of December 31, 2022, the Company had approximately $27.2 million of purchase obligations, which included commitments for capital expenditures, operating expenses and service contracts.
For information related to operating lease rental payments for office locations and compressors, see Note 6.
See Note 8 for discussion of the letters of credit to support MVP Holdco's performance assurances to the MVP Joint Venture.
16. Selected Quarterly Financial Information (unaudited)
In the course of its year-end 2022 process, the Company identified certain corrections in its previously issued unaudited interim consolidated financial statements primarily related to the accounting for the Henry Hub cash bonus payment provision. In accordance with SAB No. 99 and SAB No. 108, the Company evaluated the corrections and, based on its analysis of quantitative and qualitative factors, determined that the related impact was not material to those of its affected unaudited interim consolidated financial statements in 2022, 2021 and 2020. The Company also made other immaterial revisions to its fourth quarter of 2021 and first quarter of 2022 unaudited interim consolidated financial statements.
The Company has revised its unaudited interim consolidated financial statements for the affected prior periods below.
Statements of Consolidated Comprehensive Income
Three Months Ended March 31, 2022 Three Months Ended June 30, 2022 Three Months Ended September 30, 2022
(in thousands, except per share amounts) As Reported Adjustment As Revised As Reported Adjustment As Revised As Reported Adjustment As Revised
Operating and maintenance $ 32,834 $ 247 $ 33,081 $ 32,442 $ - $ 32,442 $ 35,297 $ - $ 35,297
Selling, general and administrative 28,126 1,591 29,717 29,009 - 29,009 33,348 - 33,348
Total operating expenses 144,208 1,838 146,046 145,313 - 145,313 153,421 - 153,421
Operating income 197,938 (1,838) 196,100 183,298 - 183,298 178,330 - 178,330
Other income (expense), net 6,348 (4,837) 1,511 14,173 (10,025) 4,148 893 1,572 2,465
Income (loss) before income taxes 111,169 (6,675) 104,494 77,456 (10,025) 67,431 (504,871) 1,572 (503,299)
Income tax expense (benefit) 6,261 (660) 5,601 3,650 (958) 2,692 (1,275) 909 (366)
Net income (loss) 104,908 (6,015) 98,893 73,806 (9,067) 64,739 (503,596) 663 (502,933)
Net income (loss) attributable to Equitrans Midstream 101,133 (6,015) 95,118 69,858 (9,067) 60,791 (506,528) 663 (505,865)
Net income (loss) attributable to Equitrans Midstream common shareholders 86,505 (6,015) 80,490 55,230 (9,067) 46,163 (521,156) 663 (520,493)
Earnings (loss) per share of common stock attributable to Equitrans Midstream common shareholders - basic 0.20 (0.01) 0.19 0.13 (0.02) 0.11 (1.20) 0.00 (1.20)
Earnings (loss) per share of common stock attributable to Equitrans Midstream common shareholders - diluted 0.20 (0.01) 0.19 0.13 (0.02) 0.11 (1.20) 0.00 (1.20)
Three Months Ended March 31, 2021 Three Months Ended June 30, 2021
(in thousands, except per share amounts) As Reported Adjustment As Revised As Reported Adjustment As Revised
Other income (expense) , net $ 7,599 $ (714) $ 6,885 $ 9,453 $ (943) $ 8,510
Income (loss) before income taxes 97,013 (714) 96,299 52,685 (943) 51,742
Income tax expense (benefit) 20,416 (157) 20,259 12,564 (232) 12,332
Net income (loss) 76,597 (557) 76,040 40,121 (711) 39,410
Net income (loss) attributable to Equitrans Midstream 72,683 (557) 72,126 37,113 (711) 36,402
Net income (loss) attributable to Equitrans Midstream common shareholders 58,055 (557) 57,498 22,485 (711) 21,774
Earnings (loss) per share of common stock attributable to Equitrans Midstream common shareholders - basic 0.13 0.00 0.13 0.05 0.00 0.05
Earnings (loss) per share of common stock attributable to Equitrans Midstream common shareholders - diluted 0.13 0.00 0.13 0.05 0.00 0.05
Three Months Ended September 30, 2021 Three Months Ended December 31, 2021
(in thousands, except per share amounts) As Reported Adjustment As Revised As Reported Adjustment As Revised
Operating and maintenance $ 38,743 $ - $ 38,743 $ 42,422 $ (247) $ 42,175
Selling, general and administrative 33,560 - 33,560 34,111 (1,591) 32,520
Total operating expenses 154,528 - 154,528 159,188 (1,838) 157,350
Operating income 187,546 - 187,546 87,484 1,838 89,322
Other income (expense) , net 21,199 (2,133) 19,066 (54,355) (27,652) (82,007)
Income (loss) before income taxes 123,105 (2,133) 120,972 (1,983,842) (25,814) (2,009,656)
Income tax expense (benefit) 32,200 (558) 31,642 (410,271) 2,685 (407,586)
Net income (loss) 90,905 (1,575) 89,330 (1,573,571) (28,499) (1,602,070)
Net income (loss) attributable to Equitrans Midstream 87,348 (1,575) 85,773 (1,577,622) (28,499) (1,606,121)
Net income (loss) attributable to Equitrans Midstream common shareholders 72,720 (1,575) 71,145 (1,592,250) (28,499) (1,620,749)
Earnings (loss) per share of common stock attributable to Equitrans Midstream common shareholders - basic 0.17 (0.01) 0.16 (3.68) (0.06) (3.74)
Earnings (loss) per share of common stock attributable to Equitrans Midstream common shareholders - diluted 0.17 (0.01) 0.16 (3.68) (0.06) (3.74)
Statements of Consolidated Cash Flows
Three Months Ended March 31, 2022 Six Months Ended June 30, 2022 Nine Months Ended September 30, 2022
(in thousands) As Reported Adjustment As Revised As Reported Adjustment As Revised As Reported Adjustment As Revised
Net (loss) income $ 104,908 $ (6,015) $ 98,893 $ 178,714 $ (15,082) $ 163,632 $ (324,882) $ (14,419) $ (339,301)
Deferred income taxes 4,603 (660) 3,943 6,990 (1,618) 5,372 8,101 (709) 7,392
Other (income) expense, net (6,501) 4,837 (1,664) (20,272) 14,862 (5,410) (21,681) 13,290 (8,391)
Non-cash long-term compensation expense 2,990 1,838 4,828 6,646 1,838 8,484 10,304 1,838 12,142
Net cash provided by operating activities 185,946 - 185,946 536,972 - 536,972 746,539 - 746,539
Three Months Ended March 31, 2021 Six Months Ended June 30, 2021 Nine Months Ended September 30, 2021
(in thousands) As Reported Adjustment As Revised As Reported Adjustment As Revised As Reported Adjustment As Revised
Net (loss) income $ 76,597 $ (557) $ 76,040 $ 116,718 $ (1,268) $ 115,450 $ 207,623 $ (2,843) $ 204,780
Deferred income taxes 20,406 (157) 20,249 32,500 (389) 32,111 61,267 (947) 60,320
Other (income) expense, net (7,254) 714 (6,540) (16,750) 1,657 (15,093) (38,160) 3,790 (34,370)
Net cash provided by operating activities 229,552 - 229,552 612,147 - 612,147 822,024 - 822,024
Consolidated Balance Sheets
March 31, 2022 June 30, 2022 September 30, 2022
(in thousands) As Reported Adjustment As Revised As Reported Adjustment As Revised As Reported Adjustment As Revised
Other assets $ 307,965 $ (43,077) $ 264,888 $ 316,074 $ (53,102) $ 262,972 $ 321,444 $ (51,530) $ 269,914
Total assets 10,818,702 (43,077) 10,775,625 10,961,930 (53,102) 10,908,828 10,386,504 (51,530) 10,334,974
Regulatory and other long-term liabilities 97,156 (660) 96,496 96,742 (1,618) 95,124 108,272 (709) 107,563
Total liabilities 8,098,572 (660) 8,097,912 8,243,109 (1,618) 8,241,491 8,263,019 (709) 8,262,310
Retained deficit (2,407,250) (42,417) (2,449,667) (2,417,011) (51,484) (2,468,495) (3,003,848) (50,821) (3,054,669)
Total common shareholders' equity 1,551,318 (42,417) 1,508,901 1,546,061 (51,484) 1,494,577 963,793 (50,821) 912,972
Total shareholders' equity 2,038,288 (42,417) 1,995,871 2,036,979 (51,484) 1,985,495 1,441,643 (50,821) 1,390,822
Total liabilities, mezzanine equity and shareholders' equity 10,818,702 (43,077) 10,775,625 10,961,930 (53,102) 10,908,828 10,386,504 (51,530) 10,334,974
March 31, 2021 June 30, 2021 September 30, 2021
(in thousands) As Reported Adjustment As Revised As Reported Adjustment As Revised As Reported Adjustment As Revised
Other assets $ 343,341 $ (7,512) $ 335,829 $ 351,043 $ (8,455) $ 342,588 $ 365,586 $ (10,588) $ 354,998
Total assets 12,788,847 (7,512) 12,781,335 12,806,331 (8,455) 12,797,876 12,868,402 (10,588) 12,857,814
Regulatory and other long-term liabilities 97,759 (1,895) 95,864 98,122 (2,127) 95,995 98,870 (2,685) 96,185
Total liabilities 8,426,552 (1,895) 8,424,657 8,479,623 (2,127) 8,477,496 8,527,415 (2,685) 8,524,730
Retained deficit (735,888) (5,617) (741,505) (778,153) (6,328) (784,481) (770,769) (7,903) (778,672)
Total common shareholders' equity 3,207,874 (5,617) 3,202,257 3,169,279 (6,328) 3,162,951 3,180,001 (7,903) 3,172,098
Total shareholders' equity 3,680,453 (5,617) 3,674,836 3,644,866 (6,328) 3,638,538 3,659,145 (7,903) 3,651,242
Total liabilities, mezzanine equity and shareholders' equity 12,788,847 (7,512) 12,781,335 12,806,331 (8,455) 12,797,876 12,868,402 (10,588) 12,857,814
Statements of Consolidated Shareholders' Equity and Mezzanine Equity
Common Stock
No Par Value Retained Earnings (Deficit) Total Equity
(in thousands) As Reported Adjustment As Revised As Reported Adjustment As Revised As Reported Adjustment As Revised
Balance at January 1, 2021 $ 3,941,295 $ - $ 3,941,295 $ (728,959) $ (5,060) $ (734,019) $ 3,681,272 $ (5,060) $ 3,676,212
Net income - - - 58,055 (557) 57,498 61,969 (557) 61,412
Balance at March 31, 2021 $ 3,945,957 $ - $ 3,945,957 $ (735,888) $ (5,617) $ (741,505) $ 3,680,453 $ (5,617) $ 3,674,836
Net income - - - 22,485 (711) 21,774 25,493 (711) 24,782
Balance at June 30, 2021 $ 3,949,592 $ - $ 3,949,592 $ (778,153) $ (6,328) $ (784,481) $ 3,644,866 $ (6,328) $ 3,638,538
Net income - - - 72,720 (1,575) 71,145 76,277 (1,575) 74,702
Balance at September 30, 2021 $ 3,952,896 $ - $ 3,952,896 $ (770,769) $ (7,903) $ (778,672) $ 3,659,145 $ (7,903) $ 3,651,242
Net (loss) income - - - (1,592,250) (28,499) (1,620,749) (1,588,199) (28,499) (1,616,698)
Share-based compensation plans, net 4,860 (1,838) 3,022 - - - 4,860 (1,838) 3,022
Balance at December 31, 2021 $ 3,957,756 $ (1,838) $ 3,955,918 $ (2,428,171) $ (36,402) $ (2,464,573) $ 2,010,726 $ (38,240) $ 1,972,486
Common Stock
No Par Value Retained Earnings (Deficit) Total Equity
(in thousands) As Reported Adjustment As Revised As Reported Adjustment As Revised As Reported Adjustment As Revised
Balance at January 1, 2022 $ 3,957,756 $ (1,838) $ 3,955,918 $ (2,428,171) $ (36,402) $ (2,464,573) $ 2,010,726 $ (38,240) $ 1,972,486
Net income - - - 86,505 (6,015) 80,490 90,280 (6,015) 84,265
Share-based compensation plans, net 2,832 1,838 4,670 - - - 2,832 1,838 4,670
Balance at March 31, 2022 $ 3,960,588 $ - $ 3,960,588 $ (2,407,250) $ (42,417) $ (2,449,667) $ 2,038,288 $ (42,417) $ 1,995,871
Net income - - - 55,230 (9,067) 46,163 59,178 (9,067) 50,111
Balance at June 30, 2022 $ 3,965,058 $ - $ 3,965,058 $ (2,417,011) $ (51,484) $ (2,468,495) $ 2,036,979 $ (51,484) $ 1,985,495
Net (loss) income - - - (521,156) 663 (520,493) (518,224) 663 (517,561)
Balance at September 30, 2022 $ 3,969,591 $ - $ 3,969,591 $ (3,003,848) $ (50,821) $ (3,054,669) $ 1,441,643 $ (50,821) $ 1,390,822

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. Under the supervision and with the participation of management, including the Company's Principal Executive Officer and Principal Financial Officer, an evaluation of the Company's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), was conducted as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and Principal Financial Officer concluded that the Company's disclosure controls and procedures were effective as of the end of the period covered by this report.
Changes in Internal Control over Financial Reporting. There were no changes in internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of 2022 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
Management's Report on Internal Control over Financial Reporting. The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company's internal control system is designed to provide reasonable assurance to the management and Board of the Company regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Accordingly, even effective controls can provide only reasonable assurance with respect to financial statement preparation and presentation.
The management of the Company assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2022. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013). Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2022.
Ernst & Young LLP (Ernst & Young), the independent registered public accounting firm that audited the Company's consolidated financial statements, has issued an attestation report on the Company's internal control over financial reporting. Ernst & Young's attestation report on the Company's internal control over financial reporting appears in Part II, "Item 8. Financial Statements and Supplementary Data" of this Annual Report on Form 10-K and is incorporated by reference herein.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
On February 20, 2023, the Board, upon the recommendation of the Compensation Committee, approved the 2023 compensation program. Awards under the 2023 compensation program are expected to be granted in the first quarter of 2023.
Long-Term Incentive Awards. The Board and Compensation Committee established the 2023 Performance Share Unit Program (2023 PSUP) under the 2018 Equitrans Midstream Corporation Long-Term Incentive Plan, as amended from time to time (the 2018 LTIP) to provide long-term incentive opportunities to key employees to further align their interests with those of the Company’s shareholders and with the strategic objectives of the Company. In general, the vesting of the units under the 2023 PSUP will occur upon payment after the expiration of the Performance Period, which is January 1, 2023 to December 31, 2025, assuming continued employment with the Company. The payout will vary between zero and 200% of the number of outstanding units contingent upon the level of total shareholder return (TSR) relative to a predefined peer group (relative TSR), the achievement of certain levels of free cash flow before changes in working capital (Free Cash Flow), and the number of ESG-related projects completed (sustainability metric), in each case during the Performance Period and, in the case of Free Cash Flow, on an annual basis within such Performance Period (each such annual period within the Performance Period referred to herein as a subperiod).
Upon the occurrence of a Qualifying Change of Control (as defined in the 2023 PSUP - e.g., the 2023 PSUP awards are not assumed by the acquirer or equitably converted in the transaction), all of the awards under the 2023 PSUP will vest and be measured on the closing date of the Qualifying Change of Control based on the (i) greater of target or actual performance for the relative TSR metric, the sustainability metric and any in progress subperiods for the Free Cash Flow metric, (ii) actual performance for any completed subperiods with respect to the Free Cash Flow metric, and (iii) target performance for any subperiods that have not commenced with respect to the Free Cash Flow metric.
In the event of a Change of Control (as defined in the 2018 LTIP) that is not a Qualifying Change of Control (e.g., the 2023 PSUP awards are assumed by the surviving entity or the Company is the surviving entity) the Aggregate Payout Factor (as defined in the 2023 PSUP) shall be measured on the closing date of the Change of Control and determined based on the (i)
greater of target or actual performance for the relative TSR metric, the sustainability metric and any in progress subperiods for the Free Cash Flow metric, (ii) actual performance for any completed subperiods with respect to the Free Cash Flow metric, and (iii) target performance for any subperiods that have not commenced with respect to the Free Cash Flow metric and the award shall be converted into a time-based award for the remainder of the Performance Period. Such time-based award shall vest on the earlier of: (i) the date participant’s employment is terminated without Cause (as defined in the 2023 PSUP); (ii) the date participant resigns for Good Reason (as defined in the 2023 PSUP), in each case prior to the second anniversary of the Change of Control; or (iii) the end of the Performance Period.
In general, in the event of a participant’s termination by reason of his or her death or Disability (as defined in the 2023 PSUP), the 2023 PSUP award will vest in full at target. In general, in the event of a participant’s termination as a result of his or her Retirement (as defined in the 2023 PSUP) or termination by the Company without Cause, the participant shall retain a pro-rata portion (calculated as set forth in the 2023 PSUP) of the 2023 PSUP award, subject to achievement of the performance conditions. In the event of a participant’s termination as a result of his or her voluntary termination (including Retirement) or by the Company without Cause and the participant remains on the board of directors of the Company or an Affiliate (as defined in the 2018 LTIP) following such termination, in general, the participant shall retain his or her 2023 PSUP award, subject to the achievement of the performance conditions. In all other termination scenarios, the 2023 PSUP award will be forfeited.
The foregoing summary is qualified in its entirety by reference to the Equitrans Midstream Corporation 2023 Performance Share Unit Program filed as Exhibit 10.47 to this Annual Report on Form 10-K and incorporated herein by reference.
The Board and Compensation Committee also approved restricted stock awards which are expected to be granted in the first quarter of 2023 on terms materially consistent with the terms previously disclosed for prior annual restricted stock awards, except that a pro-rata portion of the restricted shares will vest upon a participant’s termination without Cause (as defined in the Restricted Stock Award Agreement). The foregoing summary is qualified in its entirety by reference to the Equitrans Midstream Corporation 2023 Restricted Stock Award Agreement form filed as Exhibit 10.49 to this Annual Report on Form 10-K and incorporated herein by reference.
Short-Term Incentive Awards. On February 20, 2023, the Board and Compensation Committee also approved the Second Amended and Restated Equitrans Midstream Corporation Executive Short-Term Incentive Plan (the ESTIP) the terms of which are materially consistent with the existing and previously disclosed Amended and Restated Equitrans Midstream Corporation Executive Short-Term Incentive Plan, except that an executive will be entitled to a pro-rata Award Bonus (as defined in the ESTIP) in the event of the executive’s termination by the Company without Cause (as defined in the ESTIP). Additionally, in the event of a Change of Control (as defined in the 2018 LTIP) the Performance Period (as defined in the ESTIP) under the ESTIP shall end on the date of the Change of Control and the Performance Metrics (as defined in the ESTIP) shall be deemed to have been achieved at the greater of target or actual levels for the pro-rata portion of the Performance Period that has elapsed through the date of the Change of Control.
The foregoing summary is qualified in its entirety by reference to the Second Amended and Restated Equitrans Midstream Corporation Executive Short-Term Incentive Plan filed as Exhibit 10.50 to this Annual Report on Form 10-K and incorporated herein by reference.
Confidentiality, Non-Solicitation and Non-Competition Agreements. In addition, on February 20, 2023, the Company entered into amendments to the existing Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreements with each of Messrs. Karam and Oliver and Ms. Charletta and the Confidentiality, Non-Solicitation and Non-Competition Agreement with Mr. Moore (collectively, the First Amendments to Non-Compete Agreements), which among other things:
•increased Mr. Karam’s cash severance payment to 30 months of base salary; and
•restated the benefits continuation payment to provide for a lump sum payment equal to the monthly Consolidated Omnibus Budget Reconciliation Act of 1985 (COBRA) rate for family coverage, multiplied by 24 (30 for Mr. Karam).
On February 20, 2023, the Company terminated Mr. Pietrandrea’s existing Confidentiality, Non-Solicitation and Change of Control Agreement and entered into a Confidentiality, Non-Solicitation and Non-Competition Agreement with Mr. Pietrandrea (Non-Compete Agreement), which among other things, subjects Mr. Pietrandrea to the following restrictive covenants:
•a perpetual nondisclosure covenant;
•restrictions on competition for 18 months post-termination;
•restrictions on customer solicitation for 18 months post-termination; and
•restrictions on employee, consultant, vendor or independent contractor recruitment for 30 months post-termination.
Mr. Pietrandrea’s Non-Compete Agreement provides for the following severance payments and benefits in the event of a termination of employment by the Company without “cause” or by Mr. Pietrandrea for “good reason:”
•a lump sum cash severance payment equal to the sum of 18 months of base salary;
•a lump sum cash payment equal to two times Mr. Pietrandrea’s target annual incentive; and
•a lump sum cash payment equal to the monthly COBRA rate for family coverage, multiplied by 18.
The foregoing summary is qualified in its entirety by reference to the First Amendments to Non-Compete Agreements with each of Ms. Charletta and Messrs. Karam, Oliver and Moore and the Non-Compete Agreement with Mr. Pietrandrea filed as Exhibits 10.14(b), 10.15(b), 10.16(b), 10.18(b) and 10.20, respectively, to this Annual Report on Form 10-K and incorporated herein by reference.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
The information required by Item 10 is incorporated by reference from the information under the captions "PROXY STATEMENT SUMMARY," "ITEM NO. 1 - ELECTION OF DIRECTORS," "EQUITY OWNERSHIP" AND "CORPORATE GOVERNANCE AND BOARD MATTERS", to the extent applicable, in the Proxy Statement and under the caption "Information About Our Executive Officers" in Part I of this Annual Report on Form 10-K.
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 relate 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.
Information required by Item 401 of Regulation S-K with respect to executive officers is included after Item 4 at the end of Part I of this Annual Report on Form 10-K under the caption "Information About Our Executive Officers" and is incorporated herein by reference.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required by Item 11 is incorporated by reference from the information under the captions "CORPORATE GOVERNANCE AND BOARD MATTERS," "DIRECTORS' COMPENSATION" and "EXECUTIVE COMPENSATION INFORMATION" in the Proxy Statement.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by Item 12 is incorporated by reference from the information under the captions "EQUITY OWNERSHIP" and "SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS" in the Proxy Statement.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Party Transactions and Director Independence
The information required by Item 13 is incorporated by reference from the information under the captions "ITEM NO. 1 - ELECTION OF DIRECTORS" and "CORPORATE GOVERNANCE AND BOARD MATTERS" in the Proxy Statement.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services
The information required by Item 14 is incorporated by reference from the information under the caption "ITEM NO. 3 - RATIFICATION OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM" in the Proxy Statement.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits and Financial Statement Schedules
(a) Documents filed as part of this report
1 Financial Statements Page
Reference
Statements of Consolidated Comprehensive Income for the Years Ended December 31, 2022, 2021 and 2020 94
Statements of Consolidated Cash Flows for the Years Ended December 31, 2022, 2021 and 2020 95
Consolidated Balance Sheets as of December 31, 2022 and 2021 96
Statements of Consolidated Shareholders' Equity and Mezzanine Equity for the Years Ended December 31, 2022, 2021 and 2020 97
Notes to Consolidated Financial Statements 98
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.
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**
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.
2.5**
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
Second 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 April 28, 2021.
3.2
Fifth Amended and Restated Bylaws of Equitrans Midstream Corporation. Incorporated herein by reference to Exhibit 3.1 to Form 8-K (#001-38629) filed on December 14, 2022.
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
Description of Certain of Registrant's Securities. Filed herewith as Exhibit 4.7.
4.8
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.
4.9
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.
4.10
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.
4.11
Indenture, dated as of June 7, 2022, by and between EQM Midstream Partners, LP and U.S. Bank Trust Company, National Association, as trustee. Incorporated herein by reference to Exhibit 4.1 to Form 8-K (#001-38629) filed on June 7, 2022.
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.
10.1(c)
Second Amendment to Third Amended and Restated Credit Agreement, dated as of April 16, 2021, 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 April 19, 2021.
10.1(d)
Third Amendment to Third Amended and Restated Credit Agreement, dated as of April 22, 2022, 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 April 25, 2022.
10.2
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.
10.3
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.
10.4(a)
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.
10.4(b)#
Letter Agreement, dated as of December 21, 2020, by and between EQM Olympus Midstream, LLC and Rice Drilling D LLC.
Incorporated herein by reference to Exhibit 10.04(b) to Form 10-K (#001-38629) for the year ended December 31, 2021.
10.4(c)#
Letter Agreement, dated as of February 9, 2021, by and among EQM Gathering Opco, LLC, EQM Olympus Midstream, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC, EQT Energy, LLC and Rice Drilling D LLC. Incorporated herein by reference to Exhibit 10.9 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2021.
10.4(d)#
Letter Agreement, dated as of February 18, 2021, by and between EQM Olympus Midstream, LLC and Rice Drilling D LLC.
Incorporated herein by reference to Exhibit 10.11 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2021.
10.4(e)#
Letter Agreement, dated as of February 1, 2022, by and between EQM Olympus Midstream, LLC and Rice Drilling D LLC. Incorporated herein by reference to Exhibit 10.04(d) to Form 10-K (#001-38629) for the year ended December 31, 2021.
10.5(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.
10.5(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 herein by reference to Exhibit 10.21(b) to Form 10-K (#001-38629) for the year ended December 31, 2019.
10.6
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.
10.7
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.
10.8(a)
Transportation Service Agreement Applicable to Firm Transportation Service Under Rate Schedule FTS, Contract No. EQTR 20242-852, dated as of September 24, 2014, and Exhibit A amended August 12, 2020 and Exhibit C amended April 1, 2019 by and between Equitrans, L.P. and EQT Energy, LLC. Incorporated herein by reference as Exhibit 10.10(a) to Form 10-K (#001-38629) for the year ended December 31, 2021.
10.8(b)
Transportation Service Agreement Applicable to Firm Transportation Service Under Rate Schedule FTS, Contract No. EQTR 20242-852, dated as of September 24, 2014 as Amended December 6, 2021 by and between Equitrans L.P and EQT Energy, LLC. Incorporated herein by reference as Exhibit 10.10(b) to Form 10-K (#001-38629) for the year ended December 31, 2021.
10.8(c)
Transportation Service Agreement Applicable to Firm Transportation Service Under Rate Schedule FTS, Contract No. EQTR 20242-852, dated as of September 24, 2014 as amended December 6, 2021 by and between Equitrans L.P and EQT Energy, LLC. Incorporated herein by reference as Exhibit 10.10(c) to Form 10-K (#001-38629) for the year ended December 31, 2021.
10.9
Transportation Service Agreement Applicable to Firm Transportation Service Under Rate Schedule FTS, Contract No. EQTR19837-1296, dated as of January 8, 2016 and amended December 6, 2021, by and between Equitrans, L.P. and EQT Energy, LLC.
Incorporated herein by reference as Exhibit 10.11 to Form 10-K (#001-38629) for the year ended December 31, 2021.
10.10*
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.
10.11(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.
10.11(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.
10.12*
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.
10.13*
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.
10.14(a)*
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.
10.14(b)*
First Amendment, dated February 20, 2023, to Amended and Restated Confidentiality, Non-Solicitation and Non-Competition Agreement, dated as of January 15, 2019, with Diana M. Charletta. Filed herewith as Exhibit 10.14(b).
10.15(a)*
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.
10.15(b)*
First Amendment, dated as of February 20, 2023, to 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. Filed herewith as Exhibit 10.15(b).
10.16(a)*
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.
10.16(b)*
First Amendment, dated as of February 20, 2023, to 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. Filed herewith as Exhibit 10.16(b).
10.17*
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.
10.18(a)*
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.
10.18(b)*
First Amendment, dated as of February 20, 2023, to Confidentiality, Non-Solicitation and Non-Competition Agreement, dated April 15, 2019, by and between Equitrans Midstream Corporation and Stephen M. Moore. Filed herewith as Exhibit 10.18(b).
10.19*
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.
10.20*
Confidentiality, Non-Solicitation and Non-Competition Agreement, dated as of February 20, 2023, by and between Equitrans Midstream Corporation and Brian P. Pietrandrea.
Filed herewith as Exhibit 10.20.
10.21*
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.
10.22*
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.
10.23*
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.
10.24*
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.
10.25*
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.
10.26*
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.
10.27*
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.
10.28*
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.
10.29*
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.
10.30**
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.
10.31(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.
10.31(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.
10.31(c)#
Letter Agreement, dated as of February 23, 2021, by and among EQM Gathering Opco, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC and EQT Energy, LLC
Incorporated herein by reference to Exhibit 10.7 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2021.
10.31(d)#
Letter Agreement, dated as of February 2, 2021, by and among EQM Gathering Opco, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC and EQT Energy, LLC.
Incorporated herein by reference to Exhibit 10.8 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2021.
10.31(e)#
Letter Agreement, dated as of February 9, 2021, by and among EQM Gathering Opco, LLC, EQM Olympus Midstream, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC, EQT Energy, LLC and Rice Drilling D LLC.
Incorporated herein by reference to Exhibit 10.9 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2021.
10.31(f)#
Letter Agreement, dated as of February 3, 2021, by and among EQM Gathering Opco, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC and EQT Energy, LLC.
Incorporated herein by reference to Exhibit 10.10 to Form 10-Q (#001-38629) for the quarterly period ended March 31, 2021.
10.31(g)#
Letter Agreement, dated as of July 10, 2021, by and among EQM Gathering Opco, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC, and EQT Energy, LLC.
Incorporated herein by reference to Exhibit 10.1 to Form 10-Q (#001-38629) for the quarterly period ended September 30, 2021.
10.31(h)#
Letter Agreement, dated as of August 25, 2021, by and among EQM Gathering Opco, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC, and EQT Energy, LLC.
Incorporated herein by reference to Exhibit 10.2 to Form 10-Q (#001-38629) for the quarterly period ended September 30, 2021.
10.31(i)#
Letter Agreement, dated as of September 13, 2021, by and among EQM Gathering Opco, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC, and EQT Energy, LLC.
Incorporated herein by reference to Exhibit 10.3 to Form 10-Q (#001-38629) for the quarterly period ended September 30, 2021.
10.31(j)#
Second Amendment to Gas Gathering and Compression Agreement, dated as of December 6, 2021, by and among EQT Production Company, Rice Drilling B LLC, EQT Energy, LLC and EQM Gathering Opco, LLC.
Incorporated herein by reference to Exhibit 10.34(j) to Form 10-K (#001-38629) for the year ended December 31, 2021.
10.31(k)#
Third Amendment to Gas Gathering and Compression Agreement, dated as of December 21, 2021, by and among EQT Production Company, Rice Drilling B LLC, EQT Energy, LLC and EQM Gathering Opco, LLC. Incorporated herein by reference to Exhibit 10.34(k) to Form 10-K (#001-38629) for the year ended December 31, 2021.
10.31(l)#
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. Incorporated herein by reference to Exhibit 10.45 to Form 10-K (#001-38629) for the year ended December 31, 2020.
10.31(m)#
Letter Agreement, dated as of February 4, 2022, by and among EQM Gathering Opco, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC and EQT Energy, LLC. Incorporated herein by reference to Exhibit 10.34(m) to Form 10-K (#001-38629) for the year ended December 31, 2021.
10.31(n)#
Letter Agreement, dated as of April 27, 2022, by and among EQM Gathering Opco, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC, and EQT Energy, LLC. Incorporated herein by reference to Exhibit 10.04 to Form 10-Q (#001-38629) for the quarterly period ended June 30, 2022.
10.31(o)#
Letter Agreement, dated as of June 10, 2022, by and among EQM Gathering Opco, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC, and EQT Energy, LLC. Incorporated herein by reference to Exhibit 10.05 to Form 10-Q (#001-38629) for the quarterly period ended June 30, 2022.
10.31(p)#
Letter Agreement, dated as of September 19, 2022, by and among EQM Gathering Opco, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC, and EQT Energy, LLC. Incorporated herein by reference to Exhibit 10.01 to Form 10-Q (#001-38629) for the quarterly period ended September 30, 2022.
10.31(q)#
Letter Agreement, dated as of December 14, 2022, by and among EQM Gathering Opco, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC, and EQT Energy, LLC. Filed herewith as Exhibit 10.31(q).
10.31(r)#
Fourth Amendment to Gas Gathering and Compression Agreement, dated as of January 23, 2023, by and among EQT Production Company, Rice Drilling B LLC, EQT Energy, LLC and EQM Gathering Opco, LLC. Filed herewith as Exhibit 10.31(r).
10.31(s)#
Letter Agreement, dated as of January 23, 2023, by and among EQM Gathering Opco, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC, and EQT Energy, LLC. Filed herewith as Exhibit 10.31(s).
10.31(t)#
Letter Agreement, dated as of January 27, 2023, by and among EQM Gathering Opco, LLC, EQT Corporation, EQT Production Company, Rice Drilling B LLC, and EQT Energy, LLC. Filed herewith as Exhibit 10.31(t).
10.32#
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.
10.33
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.
10.34
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.
10.35
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.
10.36
Purchase Agreement, dated May 31, 2022, by and among EQM Midstream Partners, LP, Equitrans Midstream Corporation (for certain limited purposes) and BofA Securities 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 June 2, 2022.
10.37*
Equitrans Midstream Corporation Executive Short-Term Incentive Plan (2021). Incorporated herein by reference to Exhibit 10.46 to Form 10-K (#001-38629) filed on February 23, 2021.
10.38*
Equitrans Midstream Corporation 2021 Performance Share Unit Program. Incorporated herein by reference to Exhibit 10.47 to Form 10-K (#001-38629) filed on February 23, 2021.
10.39*
Form of Participant Award Agreement under 2021 Performance Share Unit Program. Incorporated herein by reference to Exhibit 10.48 to Form 10-K (#001-38629) filed on February 23, 2021.
10.40*
Form of Equitrans Midstream Corporation Restricted Stock Award Agreement (2021 Awards). Incorporated herein by reference to Exhibit 10.49 to Form 10-K (#001-38629) filed on February 23, 2021.
10.41*
Form of Equitrans Midstream Corporation Senior Executive 2021 MVP Performance Share Units Award Agreement.
Incorporated herein by reference to Exhibit 10.3 to Form 8-K (#001-38629) filed on December 7, 2021.
10.42*
Equitrans Midstream Corporation 2022 Performance Share Unit Program. Incorporated herein by reference to Exhibit 10.44 to Form 10-K (#001-38629) for the year ended December 31, 2021.
10.43*
Form of Participant Award Agreement under 2022 Performance Share Unit Program. Incorporated herein by reference to Exhibit 10.45 to Form 10-K (#001-38629) for the year ended December 31, 2021.
10.44*
Form of Equitrans Midstream Corporation Restricted Stock Award Agreement (2022 Awards). Incorporated herein by reference to Exhibit 10.46 to Form 10-K (#001-38629) for the year ended December 31, 2021.
10.45*
Equitrans Midstream Corporation Amended and Restated Executive Short-Term Incentive Plan
Incorporated herein by reference to Exhibit 10.47 to Form 10-K (#001-38629) for the year ended December 31, 2021.
10.46*
Equitrans Midstream Corporation Employee Stock Purchase Plan Incorporated herein by reference to Exhibit 10.1 to Form 8-K (#001-38629) filed on April 27, 2022.
10.47*
Equitrans Midstream Corporation 2023 Performance Share Unit Program. Filed herewith as Exhibit 10.47
10.48*
Form of Participant Award Agreement under 2023 Performance Share Unit Program. Filed herewith as Exhibit 10.48
10.49*
Form of Equitrans Midstream Corporation Restricted Stock Award Agreement (2023 Awards). Filed herewith as Exhibit 10.49
10.50*
Equitrans Midstream Corporation Second Amended and Restated Executive Short-Term Incentive Plan Filed herewith as Exhibit 10.50
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 Auditors (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.
* Management contract and compensatory arrangement in which any director or any named executive officer participates
** Schedules and exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K. Equitrans Midstream Corporation hereby undertakes to furnish supplemental copies of any of the omitted schedules and exhibits upon request by the SEC.
# Certain portions of the exhibits that are not material and is of the type Equitrans Midstream treats as confidential have been redacted pursuant to Item 601(b)(10)(iv) of Regulation S-K. Copies of the unredacted exhibits will be furnished to the SEC upon request.
## Certain personally identifiable information has been omitted from this exhibit pursuant to Item 601(a)(6) of Regulation S-K.