Unless context otherwise requires, a reference to a “Note”"Note" herein refers to the accompanying Notes to Consolidated Financial Statements contained in "Item 8. Financial Statements and Supplementary Data."

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

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

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, as a result of the Separation (defined(as defined below).

In connection with the Separation, the Company acquired control of the entities conducting the Midstream Business. See Note 1 to the consolidated financial statements for further information on the entities conducting the Midstream Business.

On December 31, 2018, the Company exercised a limited call right (the Limited Call Right) under EQGP's partnership agreement, pursuant to which, on January 10, 2019, the Company closed on the acquisition of the remaining 11,097,287 outstanding EQGP common units not owned by the Company or its affiliates for an aggregate purchase price of $221.9 million (such acquisition, together with the EQGP Unit Purchases, the EQGP Buyout), and EQGP became an indirect, wholly owned subsidiary of the Company. See Note 1 to the consolidated financial statements for further information on the EQGP Buyout.

price of $48.77 per EQM Series A Preferred Unit, resulting in total gross proceeds of approximately $1.2 billion. The net proceeds from the Private Placement were used in part to fund the purchase price in the Bolt-on Acquisition (defined(as defined in Note 3 to the consolidated financial statements)3) and to pay certain fees and expenses related to the Bolt-on Acquisition, and the remainder was used for general partnership purposes. The Private Placement closed concurrently with the closing of the Bolt-on Acquisition on April 10, 2019. See Note 2 to the consolidated financial statements for further information on the EQM Series A Preferred Units, none of which remain outstanding, and Note 3 to the consolidated financial statement for further information on the Bolt-on Acquisition.

The gathering MVC fees payable by EQT to the Company set forth in the EQT Global GGA are subject to potential reductions for certain contract years as set forth in the EQT Global GGA, conditioned uponto begin the first day of the quarter in which the full in-service date of the MVP occurs, which provide for estimated aggregate fee relief of approximately $270 million in the first year after the in-service date of the MVP,twelve-month period, approximately $230 million in the second year after the in-service date of the MVPtwelve-month period and approximately $35 million in the third year aftertwelve-month period. Further, the EQT Global GGA provides for a fee credit to the gathering rate for certain gathered volumes that also receive separate transmission services under certain transmission contracts. In addition, given that the MVP full in-service date of the MVP. In addition, if the MVP in-service date hasdid not occurredoccur by January 1, 2022, EQT has an option, exercisable for a period of twelve months (or such shorter period if the in-service date of the MVP occurs),through December 31, 2022, to forgo approximately $145 million of the gathering fee relief in thesuch first year after the MVP in-service datetwelve-month period and approximately $90 million of the gathering fee relief in thesuch second year after the MVP in-service datetwelve-month period in exchange for a cash payment from the Company to EQT in the amount of approximately $196 million (the EQT Cash Option). See Note 6 to the consolidated financial statements for further information on the EQT Global GGA.

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.

The following diagram depicts the Company's organizational and ownership structure as of December 31, 2020:2021:

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 service system,network, which primarily consists of water pipelines impoundment facilities, pumping stations, take point facilities and measurementother facilities that support well completion activities and collect flowback and produced water for recycling or disposal.handling activities.

As of December 31, 2020,2021, the Company provided a majority of its natural gas gathering, transmission and storage services under long-term contracts that generally include fixed monthlyfirm reservation fees or MVCs.fees. The Company maintains a stable cash flow profile, with approximately 66%64% of the Company's operating revenues for the year ended December 31, 20202021 generated from firm reservation fees. The percentage of the Company's revenues that are generated by firm reservation fees is expected to increase in future years as a result of the 15-year term EQT Global GGA, which includes an MVC of 3.0 Bcf per day that became effective on April 1, 2020 of 3.0 Bcf per day and gradually steps up to 4.0 Bcf per day for several yearsthrough December 2031 following the full in-service date of the MVP project, and the Hammerhead gathering agreement (which is subject to a pending dispute with EQT), which includes a 1.2 Bcf per day firm capacity commitment.MVP. These contract structures enhance the stability of the Company's cash flows and limitslimit its direct exposure to commodity price risk.customer volume variability.

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 the largest natural gas producer in the United States based on average daily sales volumes as of December 31, 2021 and the Company's largest customer as of December 31, 2020.2021. EQT accounted for approximately 64%59% of the Company's revenues for the year ended December 31, 2020.2021.

The following is a map of the Company's gathering, transmission and storage and water services operations as of December 31, 2020.2021. Also included are MVP and MVP Southgate routes, which projects are discussed in "Strategy" under "Developments, Market Trends and Competitive Conditions" in "Item 1. Business."

The Company reports its operations in three segments that reflect its three lines of business: Gathering, Transmission and Water. These segments include all of the Company's operations. For discussion of the composition of the three segments, see Notes 1 and 5 to the consolidated financial statements.

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

The Company's largest customer, is EQT, which was the largest natural gas producer in the United States based on average daily sales volumes as of December 31, 2020. EQT, accounted for approximately 64%59%, 69%64% and 74%69% of the Company's total revenues for the years ended December 31, 2021, 2020 2019 and 2018,2019, respectively.

The Company provides gathering services in two manners: firm service and interruptible service. Firm service contracts are typically long-term and canoften include firm reservation fees, which are fixed, monthly charges for the guaranteed reservation of pipeline access. Revenues under firm reservation fees also include fixed volumetric charges under MVCs. As of December 31, 2020,2021, the gathering system had total contracted firm reservation capacity (including contracted MVCs) of approximately 7.0 Bcf per day (inclusive of Eureka Midstream contracted capacity), which included contracted firm reservation capacity of approximately 1.8 Bcf per day associated with the Company's high-pressure header pipelines (including 1.2 Bcf per day under the Hammerhead gathering agreement, which is currently subject to a dispute with EQT).pipelines. Including future capacity expected from expansion projects that are not yet fully constructed for which the Company has executed firm contracts, the gathering system had total contracted firm reservation capacity (including contracted MVCs) of approximately 8.08.1 Bcf per day (inclusive of Eureka Midstream contracted capacity) as of December 31, 2020,2021, which included contracted firm reservation capacity of approximately 1.8 Bcf per day associated with the Company's high-pressure header pipelines (including 1.2 Bcf per day under the Hammerhead gathering agreement, which is currently subject to a dispute with EQT).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, if system capacity exists.volume. Based on total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed for which the Company has executed firm contracts, the Company's firm gathering contracts had a weighted average remaining term of approximately 1514 years as of December 31, 2020.2021.

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

access to adjacent 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 canoften include firm reservation fees, which are fixed, monthly charges for the guaranteed reservation of pipeline and storage capacity. Volumetric-based fees can also be charged under firm contracts for firm volume transported or stored, as well as for volumes transported or stored in excess of the firm contracted volume, if there is system capacity. Customers are not assuredvolume. As of December 31, 2021, the Company had firm capacity or service for volumes in excesssubscribed under firm transmission contracts of the firm contracted volume as such volumes have the same priority as interruptible service. Includingapproximately 5.6 Bcf per day, which includes future capacity expected from expansion projects that are not yet fully constructed for which the Company has executed firm transmission contracts approximately 4.4 Bcf per day of transmission capacity, excluding, in the aggregate,and excludes 2.3 Bcf per day of firm capacity commitments associated with the MVP and MVP Southgate projects, and 30.5 Bcfprojects. As of December 31, 2021, the Company had firm storage capacity wereof approximately 29.8 Bcf subscribed under firm transmission and firm storage contracts, respectively, as of December 31, 2020.contracts. Based on total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed for which the Company has executed firm contracts, the Company's firm transmission and storage contracts had a weighted average remaining term of approximately 1413 years as of December 31, 2020.2021.

Interruptible service contracts include volumetric-based fees, which are charges for the volume of natural gas transported and generally do not guarantee access to the pipeline or storage facility. These contracts can be short- or long-term. Customers with interruptible service contracts are not assured capacity or service on the transmission and storage systems. 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.customers but retains a percentage of gas receipts to recover natural gas used to power its compressor stations and meet other requirements of the Company's transmission and storage systems.

See also “Water"Water Services Letter Agreement”Agreement" and "2021 Water Services Agreement" above for additional information on the Company's Water customers.

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 or MVC commitments. The Company believes that this approach will enable the Company to achieve its strategic goals.

The Company expects that the MVP project (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, and that its future growth also will be supported by the MVP Southgate project and the water services business, as discussed in further detail below.

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.

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 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 significantly increaseare elevated relative to other forms of energy as fuel) could lead to a reduction in demand for natural gas gathering, transmission and storage, and water services.

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

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

The 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 (Certificate Policy Statement NOI)(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 and there has been no further action. The Company cannot currently predict when2018. On February 18, 2021, the FERC will issue an orderissued 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 proceeding, or what actionNOI). The formal comment period closed May 26, 2021. On February 18, 2022, the FERC may take in any such order.issued an Updated Certificate Policy Statement. The Company is evaluating the Updated Certificate Policy Statement, but at this time, it is not possible to predict the impact that the Updated Certificate Policy will have on the Company, if any.

The change of party control inIn 2021, Congress in 2021 raises the possibility ofdid not pass legislation revising the NGA or other statutes that may impact the Company’sCompany's existing facilities and operations or the ability to construct new facilities.facilities, though that remains a possibility in 2022. 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 require that condemnation authority not be exercised and construction may not begin until a FERC certificate order has been reviewed on rehearing;exercise eminent domain; and (iii) amending Section 19(b) of the NGA to provide the FERC additional time to act on requests for rehearing.

The change of partyParty control at the FERC changed in 2021, may also leadand the FERC reestablished its full complement of five commissioners. In 2021, FERC issued Order Nos. 871-B and -C (amending FERC regulations to regulation or policy changes (in responseprohibit the issuance of authorizations to court orders or the aforementioned potential statutory changes orproceed with construction while certain requests for other reasons) including, but not limited to, (i) requiring additional review of greenhouse gas emissions attributable to a proposed pipeline project; (ii) requiring applications for new pipeline construction to contain more stringentrehearing are pending), demonstrated that it will consider climate change analysis;impacts in individual certificate proceedings, and (iii) revisingincorporated enhanced environmental justice review in pipeline certificate orders. On February 18, 2022, the Certificate Policy StatementFERC issued an interim GHG policy. The Company is evaluating the interim GHG policy, but at this time, it is not possible to require additional showing ofpredict the need for a project beyondimpact that the traditional precedent agreement analysis.interim GHG policy, or any future changes to that policy, will have on the Company, if any.

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

added costs or delays 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"Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES Act) of 2020.”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 forthat operators to 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.

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 itsthe 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, (andand it is generally expected that such trend will likely increase under the Biden Administration).Administration. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be significantly in excess of the amounts the Company currently anticipates. For example, in October 2015, the EPA revisedBiden Administration has announced that it will be reviewing the National Ambient Air Quality Standards (NAAQS) for ozone from 75 parts per billion for the current eight-hour primary and secondary ozonemay make these standards to 70 parts per billion for both standards. The EPA may designate

Finally, pursuant to the Executive OrderAdditionally, on ProtectingJanuary 20, 2021, President Biden signed an executive order on "Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis, on January 20, 2021," under which President Biden directed the heads of all federal agencies to review “all"all existing regulations, orders, guidance documents, policies, and any other similar agency actions (agency actions) promulgated, issued, or adopted”adopted" during the Trump administrationAdministration for consistency with the policies established in the new 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.

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

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. ComplianceFuture 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.