EQT Corp (EQT) Business

Item 1.        Business

General

We are a vertically integrated natural gas company with upstream, gathering and transmission operations focused in the Appalachian Basin. As of December 31, 2025, we had 28.0 Tcfe of proved natural gas, NGLs and oil reserves across approximately 2.3 million gross acres and approximately 2,945 miles of pipeline infrastructure. In addition, we own an investment in Series A of Mountain Valley Pipeline, LLC (MVP A), which owns the Mountain Valley Pipeline (MVP Mainline), a 303-mile-long pipeline that spans from Wetzel County, West Virginia to Pittsylvania County, Virginia.

Strategy

Our core business strategy is to be the leading low-cost producer of natural gas with a business model designed to generate durable free cash flow across commodity price cycles. This strategy relies on our substantial inventory of core drilling locations, our vast midstream infrastructure spanning across the Appalachian Basin, our investment grade credit metrics, the low emissions profile of our operations and our best-in-class team and culture. As the only large-scale, integrated natural gas producer in the United States, we believe we are well positioned to excel during times of market volatility and to serve growing sources of demand, including power generation, industrial consumption, domestic data center development and LNG exports.

Our operational strategy centers on the execution of large-scale, multi-pad development projects, which we refer to as combo-development. Combo-development generates value across all levels of the reserves development process by maximizing operational and capital efficiencies. In the drilling stage, rigs spend more time drilling and less time transitioning to new sites. Advanced planning, a prerequisite to pursuing combo-development, facilitates the delivery of bulk hydraulic fracturing sand and piped fresh and recycled water and provides the ability to continuously meet completions supply needs and the use of environmentally friendly technologies such as electric hydraulic fracturing powered by natural gas. Our operational strategy is further enhanced by our robust midstream pipelines and services, which are synchronized with the timing of our development plan. Our synchronized development plan supports an integrated business model that keeps development costs low and limits our need to hedge future production.

Combo-development also provides meaningful environmental and social benefits when compared to more fragmented development approaches. Our operational strategy is integrated with our sustainability framework, which emphasizes continuous improvement in emissions performance, data quality and transparency, workforce development and stakeholder engagement. By concentrating development activity, combo-development results in fewer well sites, reduced truck traffic, lower fuel consumption, shorter and fewer periods of surface disturbance and reduced incremental midstream construction, contributing to improved safety performance and reduced environmental and community impacts.

Further, our integrated business model provides resilience across pricing environments. In periods of low commodity prices, our midstream assets support durable free cash flow due to their annuity-like nature of generating stable, predictable, long-term revenue. In periods of high commodity prices, our low-cost structure permits lower levels of financial hedging, thus providing increased exposure to higher natural gas prices. Correspondingly, we have implemented a robust capital allocation strategy directed at responsibly developing our assets and positioning us for organic growth, while also returning capital to our shareholders through a combination of debt retirements, a base dividend and opportunistic share repurchases. We are also focused on maintaining and strengthening our investment grade credit metrics, which improve our access to reliable, low-cost capital throughout market cycles.

We believe the benefits of our operating model can be enhanced through select strategic transactions, and, as such, part of our strategy also includes creating value through mergers and acquisitions, divestitures, joint ventures and similar business transactions as well as investing in energy-related opportunities directed at complementing and, in certain cases, diversifying our core business operations.

Our proprietary digital work environment, the size and contiguity of our asset base, and our robust midstream pipeline network uniquely position us to execute on a multi-decade inventory of combo-development projects in our core acreage position. Through disciplined execution of our strategy, we aim to be the operator of choice for our stakeholders while supporting the reliable supply of natural gas to meet domestic needs and growing global demand, in a manner that promotes energy security, affordability and sustainable development.

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2025 and Recent Highlights

•Achieved sales volume of 2,382 Bcfe, with an average realized price of $3.19 per Mcfe.

•Generated $5.1 billion of net cash provided by operating activities.

•Delivered on our shareholder return strategy through debt retirements and dividends.

◦Retired $1.4 billion aggregate principal of senior notes.

◦Paid $390 million aggregate dividends to shareholders.

◦Increased the quarterly base dividend by 5% to $0.165 per share ($0.66 per share annualized).

•Increased total proved reserves by 1,782 Bcfe, or 7%, compared to 2024.

•Completed the Olympus Energy Acquisition (defined in Note 11 to the Consolidated Financial Statements).

•In January 2026, exercised our preferential buy-out right to acquire additional interests in MVP A and Series C of Mountain Valley Pipeline, LLC (MVP C) for approximately $200.7 million and $12.5 million, respectively, subject to purchase price adjustments. Of the total consideration for the acquisition of additional interests in MVP A, approximately $98.4 million is expected to be funded by the BXCI Affiliate (defined in Note 9 to the Consolidated Financial Statements). The transaction is expected to close in the first half of 2026, subject to regulatory approvals.

Outlook

In 2026, we expect to spend approximately $2,650 million to $2,850 million on total capital expenditures, allocated as shown below.

a.Of the total planned capital expenditures, we expect to allocate approximately $580 million to $640 million to growth projects.

In 2026, we expect to make approximately $70 million to $80 million of capital contributions to our equity method investments, including to Mountain Valley Pipeline, LLC (the MVP Joint Venture). See "Transmission Segment Assets and Operations – MVP Joint Venture" for discussion of our investments in the MVP Joint Venture.

In 2026, we expect our sales volume to be 2,275 Bcfe to 2,375 Bcfe.

We are committed to maintaining investment grade credit metrics. In 2024, we published a leverage and debt retirement strategy with the goal of reducing our debt to $7.5 billion by the end of 2025, and in 2025, we published an update to our leverage and debt retirement strategy with the long-term goal of reducing our debt to $5.0 billion, subject to the overall performance of the commodity markets (our Debt Retirement Plan). Our capital allocation plan is focused on maintaining production volumes while also returning capital to shareholders, including through our quarterly cash dividend and share repurchase program, pursuant to which we are authorized to repurchase shares of our outstanding common stock for an aggregate purchase price of up to $2 billion, excluding fees, commissions and expenses. Furthermore, we have aligned our hedging strategy in a manner that we believe will mitigate the risk of volatility of natural gas and NGLs prices, thereby enabling us to execute on our capital expenditure, debt retirement and shareholder return strategy.

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Our revenues, earnings and liquidity are substantially dependent on the prices we receive for, and our ability to develop our reserves of, natural gas, NGLs and oil, which are also largely dependent on natural gas prices. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas, NGLs and oil at our ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations. Changes in natural gas, NGLs and oil prices could affect, among other things, our development plans, which would increase or decrease the pace of the development and the level of our reserves, as well as our revenues, earnings or liquidity. Lower prices and changes in our development plans could also result in non-cash impairments in the book value of our oil and gas properties and midstream infrastructure or downward adjustments to our estimated proved reserves. Any such impairments or downward adjustments to our estimated reserves could potentially be material to us.

See "Critical Accounting Estimates" included in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 to the Consolidated Financial Statements for a discussion of our significant accounting policies and assumptions related to accounting for natural gas, NGLs and oil producing activities and impairment of our oil and gas properties. See also Item 1A., "Risk Factors – Natural gas, NGLs and oil price declines, and changes in our development strategy, have resulted in impairment of certain of our assets. Future declines in commodity prices, increases in operating costs or adverse changes in well performance or additional changes in our development strategy may result in additional write-downs of the carrying amounts of our assets, including long-lived intangible assets, which could materially and adversely affect our results of operations in future periods."

Segment and Geographical Information

We have three reportable segments consisting of Upstream, Gathering and Transmission. Effective as of December 31, 2025, we renamed our previously reported "Production" segment as the "Upstream" segment to better align with the nature of our operations and our internal reporting framework. This change had no impact on the structure of our internal organization, including the composition of our reportable segments. See Note 2 to the Consolidated Financial Statements as well as Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further discussion of our reportable segments.

Substantially all of our assets and operations are located in the Appalachian Basin.

Composition of Operating Revenues

The following table summarizes the composition of our operating revenues by business segment.

(a)Primarily sales of natural gas, NGLs and oil and gains on derivatives.

(b)Primarily pipeline revenues.

(c)Primarily elimination of intercompany transactions between our Upstream segment and our Gathering or Transmission segments for the transportation of our natural gas.

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Upstream Segment Assets and Operations

Reserves

The following table summarizes our proved developed and undeveloped natural gas, NGLs and oil reserves using average first-day-of-the-month closing prices for the prior twelve months and disaggregated by product. Substantially all of our reserves reside in continuous accumulations.

91% of our total proved developed reserves, over 99% of our total proved undeveloped reserves and 93% of our total proved reserves are located in the Marcellus Shale.

The following table summarizes our proved developed and undeveloped reserves using average first-day-of-the-month closing prices for the prior twelve months and disaggregated by state.

Our 2025 total proved reserves increased by 1,782 Bcfe, or 7%, compared to 2024 due to extensions, discoveries and other additions of 2,445 Bcfe and acquisitions from the Olympus Energy Acquisition of 1,768 Bcfe, partly offset by production of 2,382 Bcfe, negative revisions of previous estimates of 27 Bcfe and decreases from the Non-Core Asset Divestiture (defined in Note 12 to the Consolidated Financial Statements) of 22 Bcfe.

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Our 2025 proved undeveloped reserves increased by 5 Bcfe, or 0.1%, compared to 2024. The following table provides a rollforward of our proved undeveloped reserves.

(a)Composed of proved undeveloped locations acquired in the Olympus Energy Acquisition. See Note 11 to the Consolidated Financial Statements.

(b)Composed of (i) negative revisions of 560 Bcfe related to proved undeveloped locations that we no longer expect to develop as proved reserves within five years of initial booking primarily as a result of development schedule changes, (ii) negative revisions of 42 Bcfe primarily related to revisions to lateral lengths and type curves, partly offset by (iii) positive revisions of 291 Bcfe due primarily to changes in ownership interests.

(c)Composed of (i) 1,998 Bcfe from proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2025 reserve development that expanded the number of our proven locations and additions to our five-year drilling plan and (ii) positive revisions of 133 Bcfe from the extension of lateral lengths of proved undeveloped reserves.

As of December 31, 2025, we had zero wells with proved undeveloped reserves that had remained undeveloped for more than five years from their time of booking.

The following table presents estimated future net cash flows from proved reserves (excluding cash flows from open derivative contracts), the present value of such net cash flows discounted at a rate of 10% (PV-10) and the prices used in estimating such net cash flows. Our reserve estimates do not include any probable or possible reserves. Future net cash flows represent projected revenues from the sale of proved reserves, net of production and development costs (including transportation and gathering expenses, operating expenses and production taxes) and net of estimated income taxes. Revenues are based on a twelve-month unweighted average of the first-day-of-the-month pricing without escalation. Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current economic conditions at each year-end. There can be no assurance that the proved reserves will be produced in the future or that prices, production or development costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information. See Note 17 to the Consolidated Financial Statements for further discussion of the preparation of, and year-over-year changes in, our reserves estimate and calculation of the standardized measure of discounted future net cash flows (the Standardized Measure).

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(a)PV-10 is a non-GAAP financial measure. PV-10 is derived from the Standardized Measure, which is the most comparable financial measure calculated in accordance with GAAP. PV-10 differs from the Standardized Measure in that PV-10 excludes the effects of income taxes on future net revenues. We believe the presentation of PV-10 is relevant and useful to investors because it provides the discounted future net cash flows attributable to our proved reserves without regard to any of our specific income tax characteristics and is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Investors may use PV-10 as a basis for comparing the relative size and value of our proved reserves to that of other companies. PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure. Neither PV-10 nor the Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. See below for a reconciliation of the Standardized Measure to PV-10.

The following table provides the reconciliation of the Standardized Measure to PV-10.

If the prices we used to calculate the Standardized Measure instead reflected five-year strip pricing as of December 31, 2025 and held constant thereafter using (i) the NYMEX five-year strip adjusted for regional differentials using Texas Eastern Transmission Corp. M-2, Transcontinental Gas Pipe Line, Leidy Line, and Tennessee Gas Pipeline Co., Zone 4-300 Leg for gas and (ii) the NYMEX WTI five-year strip for oil, adjusted for regional differentials consistent with those used in the Standardized Measure, and holding all other assumptions constant, our total proved reserves would be 28,117 Bcfe, the Standardized Measure of our proved reserves would be $24,809 million, the discounted future net cash flows before taxes would be $29,798 million and the average realized product prices weighted by production over the remaining lives of the properties would be $3.132 per Mcf of gas, $24.52 per barrel of NGLs and $44.48 per barrel of oil.

The NYMEX strip price for proved reserves and related metrics are intended to illustrate reserve sensitivities to market expectations of commodity prices and should not be confused with SEC pricing for proved reserves and do not comply with SEC pricing assumptions. We believe that the presentation of reserve volume and related metrics using NYMEX forward strip prices provides investors with additional useful information about our reserves because the forward prices are based on the market's forward-looking expectations of oil and gas prices as of a certain date. The price at which we can sell our production in the future is the major determinant of the likely economic producibility of our reserves. We hedge certain amounts of future production based on futures prices. In addition, we use such forward-looking market-based data in developing our drilling plans, assessing our capital expenditure needs and projecting future cash flows. While NYMEX strip prices represent a consensus estimate of future pricing, such prices are only an estimate and are not necessarily an accurate projection of future oil and gas prices. Actual future prices may vary significantly from NYMEX prices; therefore, actual revenue and value generated may be more or less than the amounts disclosed. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC pricing, when considering our reserves.

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Based on our mix of proved undeveloped probable and possible reserves, we estimate that we have an undeveloped drilling inventory of approximately 4,000 gross locations. At our current drilling pace, these locations are projected to provide more than 30 years of drilling inventory based on gross undeveloped acres, average expected lateral length of 12,000 feet and well spacing of 1,000 feet.

Upstream Acreage

The majority of our Upstream acreage is held by lease or occupied under perpetual easements or other rights acquired, for the most part, without warranty of underlying land titles. Approximately 39% of our total gross acres is developed. We retain deep drilling rights on the majority of our production acreage.

The following table summarizes our Upstream acreage disaggregated by state.

We have an active lease renewal program in areas targeted for development. In the event that production is not established or we do not extend or renew the terms of our expiring leases, 20,309, 28,255 and 14,997 of our net undeveloped Upstream acreage as of December 31, 2025 will expire in the years ending December 31, 2026, 2027 and 2028, respectively.

Productive and In-Process Wells

The following table summarizes our productive and in-process natural gas wells. We had no productive or in-process oil wells as of December 31, 2025.

(a)We had 101 gross conventional wells in Pennsylvania, 6 gross conventional wells in West Virginia and no gross conventional wells in Ohio. In addition, we had 4 gross operated wells with multiple completions.

Drilling Activity

The following table summarizes our net productive development wells.

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During the years ended December 31, 2025, 2024 and 2023, we drilled zero net dry development wells. In addition, during the years ended December 31, 2025, 2024 and 2023, we drilled zero exploratory wells.

The following table summarizes the gross and net wells on which we initiated drilling operations (spud) during 2025.

Upstream Sales, Pricing, Commitments and Costs

The following table summarizes our natural gas, NGLs and oil sales volume by state.

Natural Gas Sales. Natural gas is a commodity and, therefore, we typically receive market-based pricing for our produced natural gas. The market price for natural gas in the Appalachian Basin is typically lower relative to NYMEX Henry Hub, Louisiana (the location for pricing NYMEX natural gas futures) as a result of increased supply of natural gas in the Northeast United States and limited pipeline capacity to transport the supply to other regions. To protect our cash flow from undue exposure to the risk of changing commodity prices, we hedge a portion of our forecasted natural gas production at, for the most part, NYMEX natural gas prices. We also enter into derivative instruments to hedge basis. For information on our hedging strategy and our derivative instruments, refer to "Commodity Risk Management" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations," Item 7A., "Quantitative and Qualitative Disclosures About Market Risk" and Note 4 to the Consolidated Financial Statements.

NGLs Sales. We primarily sell NGLs recovered from our natural gas production. We contract with our Gathering segment (which owns and operates a processing facility), MarkWest Energy Partners, L.P., Williams Ohio Valley Midstream LLC and Blue Racer Midstream to process and extract heavier hydrocarbon streams (consisting predominately of ethane, propane, isobutane, normal butane and natural gasoline) from our produced natural gas. We market the majority of our NGLs.

Natural Gas and NGLs Customers. We sell natural gas and NGLs to marketers, utilities and industrial customers located in the Appalachian Basin and in markets that are accessible through our transportation portfolio, particularly where there is expected future demand growth such as in the Gulf Coast, Midwest, East Coast corridor and Northeast United States and Canada. As of December 31, 2025, approximately 49% of our sales volume reaches markets outside of Appalachia. We do not depend on any single customer and believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, NGLs and oil.

We have access to approximately 4.3 Bcf per day of firm pipeline takeaway capacity, including 1.29 Bcf per day of firm pipeline takeaway capacity on MVP Mainline that we have contracted through June 30, 2044. In addition, we are committed to an additional 0.55 Bcf per day of firm pipeline takeaway capacity on MVP Southgate (defined below) once placed into service. We have access to approximately 1.0 Bcf per day of firm processing capacity, including 0.2 Bcf per day of firm processing capacity on the processing facility owned by our Gathering segment. These firm transportation and processing agreements may require minimum volume delivery commitments, which we expect to principally fulfill with production from existing reserves.

Natural Gas Marketing. EQT Energy, LLC, our indirect, wholly owned marketing subsidiary, provides marketing services and contractual pipeline capacity management services primarily for our benefit. EQT Energy, LLC also engages in risk management and hedging activities to limit our exposure to shifts in market prices.

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Average Sales Price. The following table presents our average sales price per unit of natural gas, NGLs and oil, with and without the effects of cash settled derivatives, as applicable.

For additional information on pricing, see "Average Realized Price Reconciliation" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Delivery Commitments. We have contractually agreed to deliver firm quantities of gas and NGLs to various customers, which we expect to fulfill with production from existing reserves. We regularly monitor our proved developed reserves to ensure sufficient availability to meet commitments for the next one to three years. The following table summarizes our total gross commitments as of December 31, 2025.

We are party to two firm sales agreements under which we have committed to deliver and sell up to an aggregate 1.2 Bcf per day of gas using our capacity on MVP Mainline for up to ten years beginning in 2027. These agreements are subject to conditions that have not yet been satisfied related to the in-service date of the Transco Southeast Supply Enhancement project; therefore, their impact has been excluded from the schedule of total gross commitments in the table above.

LNG Offtake and Tolling Commitments. As of December 31, 2025, we have entered into three 20-year LNG offtake agreements for an aggregate 4.5 MTPA of LNG, of which 3.0 MTPA is expected to commence as early as 2030 and 1.5 MTPA expected to commence in 2031. In addition, we have entered into a 20-year LNG tolling agreement for up to 2.0 MTPA of capacity expected to commence no earlier than 2030. Of the capacity that may commence in 2030, 1.0 MTPA under the offtake agreements and the 2.0 MTPA tolling commitment relate to projects that have not yet reached final investment decisions to proceed with construction, which require, among other things, the receipt of all necessary authorizations and permits for the project. As a result, the timing, volume or realization of these commitments may be delayed, reduced or may not occur.

Average Production Cost. For the years ended December 31, 2025, 2024 and 2023, lease operating expenses (LOE) per Mcfe were $0.09, $0.09 and $0.07, respectively. For more information on our Upstream segment's operating expenses, refer to "Business Segment Results of Operations – UPSTREAM" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations."

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Gathering Segment Assets and Operations

Gathering System

The following table presents information on our gathering system. In addition, we own a processing facility with capacity of 0.2 Bcf per day.

Gathering Customers

Our Gathering segment has gathering agreements with our Upstream segment and with third parties. Certain of these agreements grant us the right to elect to gather the entire volume of natural gas produced from wells within specified dedicated acreage. For the year ended December 31, 2025, our Upstream segment accounted for approximately 73% of our gathering system throughput and approximately 76% of our Gathering segment's operating revenues.

As of December 31, 2025, our gathering system had total contracted firm reservation capacity, including contracted MVCs, of approximately 7.8 Bcf per day.

As of December 31, 2025, based on total projected contractual revenues, our firm gathering contracts had weighted average remaining terms of approximately 10 years for third-party contracts and 13 years for affiliate contracts.

Generally, our Gathering segment does not take title to the natural gas gathered by its assets, but it retains a percentage of wellhead gas receipts to recover natural gas used to fuel its compressor stations and meet other requirements of its gathering system.

Transmission Segment Assets and Operations

Transmission and Storage System

The following table presents information on our transmission and storage system.

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Transmission and Storage Customers

Our Transmission segment has transmission and storage agreements with our Upstream segment and with third parties. Third-party transmission and storage customers include local distribution companies, other producers, marketers and commercial and industrial users. For the year ended December 31, 2025, our Upstream segment accounted for approximately 69% of our transmission system throughput and approximately 61% of our Transmission segment's operating revenues.

As of December 31, 2025, our transmission and storage system had total contracted firm transmission capacity of approximately 5.7 Bcf per day and total contracted firm storage capacity of 29.8 Bcf.

As of December 31, 2025, based on total projected contractual revenues, our firm transmission and storage contracts had weighted average remaining terms of approximately 10 years for third-party contracts and 13 years for affiliate contracts.

Generally, our Transmission segment does not take title to the natural gas transported or stored by its assets but does retain a percentage of the gas receipts to recover natural gas used to fuel its compressor stations and meet other requirements of its transmission and storage system.

As of December 31, 2025, approximately 95% of our Transmission segment's contracted firm transmission capacity was subscribed under negotiated rate agreements. As of December 31, 2025, our Transmission segment had minimal contracted firm transmission capacity subscribed at discounted rates and recourse rates. See also "Regulation" below and Part I, "Item 1A. Risk Factors – A substantial majority of the services we provide on our transmission and storage systems 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, and cash flows could be adversely affected." for additional information.

MVP Joint Venture

The MVP Joint Venture is a Delaware series limited liability company formed as a joint venture for the purpose of constructing and owning natural gas assets. The MVP Joint Venture has three series, as follows: Series A (MVP A), which owns MVP Mainline; Series B (MVP B), which owns the MVP Southgate project; and Series C (MVP C), which owns certain assets associated with the MVP Boost project.

MVP A. We own an equity method investment in MVP A, which owns MVP Mainline, a 303-mile long, 42-inch diameter natural gas interstate pipeline with a total capacity of 2.0 Bcf per day that spans from our transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia and has 3 interconnect points to other interstate pipelines. As of December 31, 2025, based on total projected contractual revenues, MVP Mainline's firm transmission and storage contracts had weighted average remaining terms of approximately 19 years.

MVP B. We own an equity method investment in MVP B, which was formed for the purpose of constructing and owning MVP Southgate, a contemplated 31-mile-long, 30-inch diameter natural gas interstate pipeline with a projected capacity of 0.55 Bcf per day that would extend from the terminus of MVP Mainline in Pittsylvania County, Virginia to new delivery points in Rockingham County, North Carolina (MVP Southgate).

Pending receipt of remaining regulatory approvals, MVP Southgate is expected to be placed into service by mid-2028. MVP Southgate is estimated to have a total cost of approximately $370 million to $430 million, excluding allowance for funds used during construction (AFUDC) and certain costs incurred for purposes of the originally certificated project, of which we will fund our proportionate share through capital contributions to MVP B.

MVP C. We own an equity method investment in MVP C, which was formed on November 1, 2025 for the purpose of constructing and owning certain assets associated with the MVP Boost project, a contemplated project to add compression to MVP Mainline, which is projected to increase the capacity on MVP Mainline by 0.6 Bcf per day (MVP Boost). As designed, MVP Boost would add compression at three existing compressor stations in West Virginia and construct a new compressor station in Virginia.

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On October 23, 2025, the MVP Joint Venture applied to the FERC for authorization to construct MVP Boost. Pending receipt of regulatory approvals, MVP Boost is expected to be placed into service by mid-2028. MVP Boost is estimated to have a total cost of approximately $400 million to $540 million, excluding AFUDC, of which we will fund our proportionate share through capital contributions to MVP C.

Seasonality

Generally, but not always, the demand for natural gas (including the demand for our gathering, transmission and storage services) decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or summers may also affect demand.

Competition

Other natural gas producers compete with us in the acquisition of properties; the search for, and development of, reserves; the production and sale of natural gas and NGLs; and the securing of services, labor, equipment and transportation required to conduct operations. Our competitors include independent oil and gas companies, major oil and gas companies, individual producers, operators and marketing companies and other energy companies that produce substitutes for the commodities that we produce.

Competitors for our natural gas gathering business include companies that own major natural gas pipelines, independent gas gatherers and integrated energy companies, including natural gas producers that develop or acquire their own gathering system. When compared to us, some of our competitors have operations in multiple natural gas producing basins, greater capital resources and access to, or control of, larger natural gas supplies.

Competition for our natural gas transmission and storage business is based primarily on rates, customer commitment levels, timing, performance, commercial terms, reliability, service levels, location, reputation and fuel efficiencies. Our principal competitors include companies that own major natural gas pipelines in the Appalachian Basin. In addition, we compete 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.

Regulation

Regulation of Our Operations

Our exploration and production operations are subject to various federal, state and local laws and regulations, including regulations related to the following: the location of wells; the method of drilling, well construction, well stimulation, hydraulic fracturing and casing design; water withdrawal and procurement for well stimulation purposes; well production; spill prevention plans; the use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations; surface usage and the reclamation of properties upon which wells or other facilities have been located; the plugging and abandoning of wells; the calculation, reporting and disbursement of royalties and taxes; and the gathering of production in certain circumstances. These regulations, and any delays in obtaining related authorizations, may affect the costs and timing of developing our natural gas resources.

Our operations are also subject to conservation and correlative rights regulations, including the following: regulation of the size of drilling and spacing units or field rule units; setbacks; the number of wells that may be drilled in a unit or in close proximity to other wells; drilling in the vicinity of coal mining operations and certain other structures; and the unitization or pooling of natural gas properties. Ohio allows the statutory pooling or unitization of tracts to facilitate development and exploration. In Pennsylvania, lease integration legislation authorizes joint development of existing contiguous leases. West Virginia allows the operator of a proposed horizontal well to develop the acreage of non-consenting and unlocatable and unknown owners if 75% of the mineral interest owners and 55% of the working interest owners in the proposed well unit consent to the development. Additionally, state conservation and oil and gas laws generally limit the venting or flaring of natural gas. Various states also impose certain regulatory requirements to transfer wells to third parties or discontinue operations in the event of divestitures by us.

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We also have gathering and processing operations that are subject to various federal and state laws and local zoning ordinances, including the following: air permitting requirements for compressor station and dehydration units and other permitting requirements; erosion and sediment control requirements for compressor station and pipeline construction projects; waste management requirements and spill prevention plans for compressor stations; various recordkeeping and reporting requirements for air permits and waste management practices; compliance with safety regulations, including regulations by the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (the PHMSA); and siting and noise regulations for compressor stations. These regulations may increase the costs of operating existing pipelines and compressor stations and increase the costs of, and the time to develop, new or expanded pipelines and compressor stations.

We use financial derivative instruments to hedge the impact of fluctuations in natural gas, NGLs and oil prices on our results of operations and cash flows. In 2010, Congress adopted comprehensive financial reform legislation that established federal oversight and regulation of the OTC derivative market and entities, such as us, that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), required the CFTC, the SEC and other regulatory agencies to promulgate rules and regulations implementing this legislation. Among other things, the Dodd-Frank Act established margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail or alter their derivative activities. The Dodd-Frank Act also created new categories of regulated market participants, such as "swap dealers" and "security-based swap dealers" that are subject to significant new capital, registration, recordkeeping, reporting, disclosure, business conduct and other regulatory requirements, a large number of which have been implemented. This regulatory framework has significantly increased the costs of entering into derivatives transactions for end-users of derivatives, such as us. In particular, new margin requirements and capital charges, even when not directly applicable to us, have increased the pricing of derivatives that we transact in.

New exchange trading margin regulations, trade reporting requirements and position limits may lead to changes in the liquidity of our derivative transactions or higher pricing. That said, our hedging activities are not subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing, although we are subject to certain recordkeeping and reporting obligations associated with the Dodd-Frank Act. Additionally, our uncleared swaps are not subject to regulatory margin requirements. Finally, we believe that the majority, if not all, of our hedging activities constitute bona fide hedging under applicable federal and exchange-mandated position limits rules and are not materially impacted by the limitations under such rules.

In addition to U.S. laws and regulations relating to derivatives, certain non-U.S. regulatory authorities have passed or proposed, or may propose in the future, legislation similar to that imposed by the Dodd-Frank Act. For example, European Union legislation imposes position limits on certain commodity transactions, and the European Market Infrastructure Regulation (EMIR) requires reporting of derivatives and various risk mitigation techniques to be applied to derivatives entered into by parties that are subject to EMIR. Other similar regulations are in development throughout the globe and may increase our cost of doing business even if not directly binding on us.

Regulators periodically review or audit our compliance with applicable regulatory requirements. Additional proposals relating to regulations that affect the oil and gas industry are regularly considered by Congress, the states, regulatory agencies and the courts. We cannot predict when or whether any such proposals may become effective or the effect that such proposals may have on us.

The following is a summary of the more significant existing laws, rules and regulations to which our business operations are subject. Although compliance with such laws, rules and regulations increases our capital expenditures and adversely affects our earnings, we believe such regulatory obligations generally do not affect us differently, or to any materially greater or lesser extent, than they affect others in our industry with similar operations and types, quantities and locations of production. As such, we anticipate that compliance with such existing laws, rules and regulations will not have a material adverse effect on our competitive position.

Natural Gas Sales and Transportation. The availability, terms and cost of transportation significantly affect sales of natural gas and oil. The interstate transportation and sale for resale of natural gas and oil is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the FERC. Federal and state regulations govern the price and terms for access to natural gas and oil pipeline transportation. The FERC's regulations for interstate natural gas and oil transportation in some circumstances may also affect the intrastate transportation of oil and natural gas.

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Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (the NGA) and the Natural Gas Policy Act of 1978 (the NGPA). Various federal laws enacted since 1978 have resulted in the removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of our sales of our own production. Under the Energy Policy Act of 2005, the FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties of approximately $1.6 million (as of February 11, 2026 and adjusted periodically for inflation) per day for each violation and disgorgement of profits associated with any violation. While our production activities have not been regulated by the FERC as a natural gas company under the NGA, we are required to report the aggregate volume of natural gas purchased or sold at wholesale to the extent such transactions exceed a specific volume and use or contribute to, or may contribute to, the formation of price indices. In addition, Congress may enact legislation or the FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject us to civil penalties.

The CFTC also holds authority to monitor certain segments of the physical, futures and other derivatives energy commodities markets, including natural gas, NGLs and oil. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by the CFTC. The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties.

The FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of natural gas and release of our natural gas pipeline capacity. Commencing in 1985, the FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide non-unduly discriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. The FERC's initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by the FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas production activities.

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 customers. Generally, the FERC's authority extends to rates and charges for: our natural gas transmission and storage services; certification and construction of new interstate transmission and storage facilities; abandonment of interstate transmission and storage services and 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.

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.

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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 our 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, and 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.

Our 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 our 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, 2025, approximately 95% of our Transmission segment's contracted firm transmission capacity was subscribed under negotiated rate agreements. 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 us to seek modification of, the agreement, or alternatively require us 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. 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.

In April 2018, the FERC issued a 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. The formal comment period in this proceeding closed in June 2018. In February 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. The formal comment period closed in May 2021. In February 2022, the FERC issued an Updated Certificate Policy Statement and an interim greenhouse gas (GHG) policy. In March 2022, the FERC issued an order suspending the effectiveness of the Updated Certificate Policy Statement and the interim GHG policy. In January 2025, the FERC terminated the interim GHG policy proceeding, stating that GHG-related considerations are better considered on a case-by-case basis in individual proceedings. In September 2025, the FERC terminated the Updated Certificate Policy Statement proceeding. There is a possibility that Congress could pass legislation revising the NGA or other statutes that may impact our existing facilities and operations or the ability to construct new facilities. 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.

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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. We believe that our 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 Congress.

NGLs and Oil Price Controls and Transportation Rates. Sales prices of NGLs and oil are not currently regulated and are made at market prices. Our sales of these commodities are, however, subject to laws and regulations issued by the FTC prohibiting manipulative or fraudulent conduct in the wholesale petroleum market. The FTC holds substantial enforcement authority under these regulations, including the ability to assess civil penalties of more than $1.5 million per day per violation. Our sales of these commodities, and any related hedging activities, are also subject to CFTC oversight and enforcement authority as discussed above.

The price we receive from the sale of our produced NGLs and oil may be affected by the cost of transporting such products to market. Some of our transportation of NGLs and oil is through FERC-regulated interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. The FERC's regulation of NGLs and oil transportation rates may tend to increase the cost of transporting NGLs and oil by interstate pipelines, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. The FERC's five-year index level for 2021 through 2026 went into effect on July 1, 2021. In January 2022, the FERC issued an order on rehearing, lowering the index level and directing oil pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022 to ensure compliance with the new index level. In July 2024, the U.S. Court of Appeals for the District of Columbia Circuit (the D.C. Circuit) found that the FERC did not adhere to notice-and-comment procedures in its January 2022 rehearing order. The court vacated the rehearing order. In October 2024, the FERC issued a supplemental notice of proposed rulemaking, which would amend the initial index prospectively by adopting a revised index level for the remainder of the five-year period that began on July 1, 2021. In November 2025, the FERC declined to readopt the lower rate established by the January 2022 order on rehearing and withdrew its October 2024 supplemental notice of proposed rulemaking, effectively setting the five-year index level for 2021 through 2026 at the level initially established in 2021. In November 2025, the FERC also issued a notice of proposed rulemaking for the five-year index level for 2026-2031.

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Environmental, Health and Safety Regulations

Our business operations are also subject to numerous stringent federal, state and local environmental, health and safety laws and regulations pertaining to, among other things, the release, emission or discharge of materials into the environment; the generation, storage, transportation, handling and disposal of certain materials, including solid and hazardous wastes; the safety of employees and the general public; pollution; site remediation; and preservation or protection of human health and safety, natural resources, wildlife and the environment. We must take into account environmental, health and safety regulations in, among other things, planning, designing, constructing, operating and plugging and abandoning wells and related facilities. Violations of these laws can result in substantial administrative, civil and criminal penalties. These laws and regulations may require us to acquire permits before drilling, constructing pipelines or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with our operations; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities or pipeline construction in certain areas and on certain lands lying within wilderness, wetlands and other protected areas or areas with endangered or threatened species restrictions; require some form of remedial action to prevent, remediate or mitigate pollution from operations, such as plugging abandoned wells or closing earthen pits; establish specific health and safety criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with applicable laws and regulations. In addition, these laws and regulations may restrict the rate of our production. Although compliance with environmental, safety and health laws and regulations increases our capital expenditures and adversely affects our earnings, we believe such regulatory obligations generally do not affect us differently, or to any materially greater or lesser extent, than they affect others in our industry with similar operations and types, quantities and locations of production. As such, we anticipate that compliance with existing environmental, health and safety regulations will not have a material adverse effect on our competitive position.

Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, federal agencies, the states, local governments and the courts. We cannot predict when or whether any such proposals may become effective. Therefore, we are unable to predict the future costs or impact of compliance. However, over time, the trend has been for stricter regulation of activities that have the potential to affect the environment.

The following is a summary of the more significant environmental and occupational health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, earnings or business.

Hazardous Substances and Waste Handling. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the "Superfund" law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, despite the "petroleum exclusion" of Section 101(14) of CERCLA, which currently encompasses oil and natural gas, we generate materials in the course of our operations that may be regulated as hazardous substances based on their characteristics; however, we are unaware of any liabilities arising under CERCLA for which we may be held responsible that would materially and adversely affect us.

The Resource Conservation and Recovery Act (RCRA) and analogous state laws establish detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced water and other wastes associated with the exploration, development or production of oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA, or state agencies under RCRA's less stringent nonhazardous solid waste provisions, or under state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes currently classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. Any changes to state or federal programs could result in an increase in our costs to manage and dispose waste, which could have a material adverse effect on our capital expenditures and earnings.

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We currently own, lease or operate numerous properties that have been used for natural gas and oil exploration and production activities for many years. Although we believe that we have used operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including offsite locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. We are able to directly control the operation of only those wells with respect to which we act or have acted as operator. The failure of a prior owner or operator to comply with applicable environmental regulations may, in certain circumstances, be attributed to us as the current owner or operator under CERCLA. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, regardless of fault, which could include removal of previously disposed substances and wastes, clean-up of contaminated property or performance of remedial plugging or waste pit closure operations to prevent future contamination.

Water Discharges. The Federal Water Pollution Control Act, known as the Clean Water Act (the CWA), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or a state equivalent agency. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the Corps). In June 2015, the EPA and the Corps issued a rule defining the scope of the EPA's and the Corps' jurisdiction over waters of the United States (WOTUS), which never took effect before being replaced by the Navigable Waters Protection Rule (the NWPR) in December 2019. A coalition of states and cities, environmental groups, and agricultural groups challenged the NWPR, which was vacated by a federal district court in August 2021. In January 2023, the EPA and the Corps issued a final rule that based the definition of WOTUS on the pre-2015 definition. The definition of WOTUS was further impacted by the U.S. Supreme Court's decision issued in May 2023 in Sackett v. EPA, wherein the Court held that the jurisdiction of the CWA extends only to those adjacent wetlands that are indistinguishable from traditional navigable bodies of water due to a continuous surface connection and rejected the "significant nexus" test embraced in earlier jurisprudence. In September 2023, the EPA and the Corps published a direct-to-final rule redefining WOTUS to amend the January 2023 rule and align with the decision in Sackett. The final rule eliminated the "significant nexus" test from consideration when determining federal jurisdiction and clarified that the CWA only extends to relatively permanent bodies of water and wetlands that have a continuous surface connection with such bodies of water. Roughly half of the states and other plaintiffs are challenging the September 2023 rule, and the EPA and the Corps are using the pre-2015 definition of WOTUS in these states while litigation continues. In addition, in an April 2020 decision further defining the scope of the CWA, the U.S. Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit. The Court rejected the EPA and the Corps' assertion that groundwater should be totally excluded from the CWA. In November 2023, the EPA issued draft guidance describing the information that should be used to determine which discharges through groundwater may require a permit. In November 2025, the EPA and the Corps published a proposed rule that would revise regulations defining WOTUS under the CWA. Accordingly, future implementation and enforcement of these rules and policies is uncertain at this time. To the extent a new rule or further litigation expands the scope of the CWA's jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which could delay our development projects and pipeline construction. Also, pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or stormwater and to develop and implement spill prevention, control and countermeasure plans in connection with on-site storage of significant quantities of oil. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances and may impose substantial potential liability for the costs of removal and remediation and other damages.

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The Sackett decision may also have effects on the implementation of Water Quality Certifications (WQCs) under Section 401 of the CWA. Section 401 requires that any activity that may result in a discharge to WOTUS must first receive a Section 401 WQC before a federal agency may issue a permit for that activity. A WQC is typically issued by the state where the discharge originates or by the EPA itself in areas where a state or tribe does not have authority. In 2020, the EPA finalized a series of changes to the CWA regulations governing the WQC process, largely curtailing state and tribal authority over WQCs. In September 2023, the EPA published a final rule that restores state and tribal authority to review requests for WQCs and imposes additional requirements on the WQC process. The final rule took effect on November 27, 2023, but has been challenged by states and regulated entities in ongoing litigation to enjoin its enforcement. In January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise or rescind all agency actions that are unduly burdensome on the identification, development or use of domestic energy resources. In November 2025, the EPA sent the WQC Improvement Rule of Section 401 of the CWA to the White House Office of Management and Budget for interagency review. Accordingly, future implementation and enforcement of the final rule is uncertain. If certain elements of the final rule remain in effect, we could face increased costs and delays with respect to obtaining permits for pipeline crossings and other activities in jurisdictional and non-jurisdictional waters.

Nationwide Permits (NWPs) are issued by the Corps under the CWA 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. In March 2022, the 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 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. However, in January 2025, President Trump issued an executive order instructing the Corps to use emergency authorities and NWPs to grant approvals for energy projects under Section 404 of the CWA. In June 2025, the Corps published a notice of proposed rulemaking to reissue and modify NWPs, which includes modifications to NWP 12. As a result, any future revisions to NWPs, including NWP 12, are uncertain at this time. To the extent future revisions to NWP 12 or litigation relating to such revisions modify its provisions with respect to oil and natural gas pipeline activities, we could face increased costs and delays with respect to obtaining permits for certain activities in jurisdictional waters, including wetlands.

Air Emissions. Through the federal Clean Air Act (the CAA) and comparable state and local laws and regulations, the EPA regulates emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits.

In November 2021, the EPA announced a proposed rule expanding upon its New Source Performance Standards (NSPS) rule in Subpart OOOOa, establishing standards for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. The proposed rule sought to make existing regulations more stringent, create a Subpart OOOOb to expand reduction requirements for new, modified and reconstructed natural gas and oil sources, and create a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule, which, among other things, created a new third-party monitoring program to identify large emissions events, referred to in the proposed rule as "super emitters." The EPA announced a final rule in December 2023, which, among other things, requires the phase out of routine flaring of natural gas from new oil wells and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with applicable compliance dates under state plans. The final rule gives states until March 2026 to develop and submit their plans for reducing methane from existing sources. Subpart OOOOc then provides until 2029 for existing sources to comply. Fines and penalties for violation of the final rule could be substantial. The final rule is subject to ongoing litigation. In December 2025, the EPA issued a final rule that extends several compliance deadlines in the 2024 New Source Performance Standards and Emissions Guidelines for OOOOb and OOOOc. Consequently, future implementation and enforcement of the final rule remains uncertain at this time.

As a result of these regulatory changes, the scope of any final air emissions regulations or the costs for complying with such regulations are uncertain. We may incur costs as necessary to remain in compliance with these regulations. Obtaining or renewing permits also has the potential to delay the development of natural gas and oil projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

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National Environmental Policy Act (NEPA). NEPA establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action with the potential to significantly impact the environment requires review under NEPA. Some activities are subject to robust NEPA review, which could lead to delays and increased costs that could materially adversely affect our capital expenditures and earnings. Other activities are covered under a categorical exclusion, which results in a shorter NEPA review process. In April 2022, the White House Council on Environmental Quality (CEQ) finalized the first of two planned rules to undo changes to NEPA enacted in 2020 under the first Trump Administration. The Phase I final rule generally restores certain regulatory provisions that were in effect prior to the 2020 rule, affecting the assessment of projects ranging from oil and gas leasing to development on public and Native American lands. Additionally, in September 2023, the Biden Administration announced that federal agencies will be directed to consider the social cost of carbon in agency budgeting, procurement and other agency decisions, including in environmental reviews conducted pursuant to NEPA, where appropriate. In May 2024, CEQ finalized the Phase II rule, which generally restores certain mitigation language from the pre-2020 version of the NEPA regulations, proposes further revisions and meets environmental, environmental justice and climate change objectives. At least 20 states have challenged the Phase II rule in federal district court. CEQ's changes could result in increased NEPA review timelines for projects involving agency action regarding federal lands, federal funds or federal permits or approvals. Additionally, in November 2024, a federal appeals court found that CEQ lacks statutory authority to issue NEPA regulations binding other federal agencies. However, the court's holding was confined to striking down the agencies' action under review on separate grounds. In January 2025, President Trump issued executive orders (i) requiring CEQ to provide guidance on implementing NEPA and to propose rescinding and replacing CEQ's NEPA regulations with implementing regulations at the agency level; (ii) requiring the EPA to issue guidance on and to consider eliminating the social cost of carbon calculation from federal permitting or regulatory decisions; and (iii) instructing federal agencies to adhere to only the relevant legislated requirements for environmental reviews and to prioritize efficiency and certainty over any other objectives in such reviews. In February 2025, CEQ issued an interim final rule withdrawing the NEPA implementing regulations. Also in February 2025, CEQ issued a memorandum to federal agencies and departments providing guidance to agencies establishing or revising their agency-specific NEPA implementing procedures. The guidance document was updated and replaced by a subsequent memorandum issued by CEQ in September 2025. In May 2025, CEQ also withdrew its January 2023 interim guidance to federal agencies regarding consideration of the effects of GHG emissions and climate change when conducting environmental reviews pursuant to NEPA. Additionally, in May 2025, the U.S. Supreme Court held in Seven County Infrastructure Coalition v. Eagle County that NEPA is a purely procedural statute affording substantial deference to agencies. Following this decision, in July 2025, a number of federal agencies, including the Department of the Interior, the Department of Transportation, the Corps and the Department of Energy, revised their NEPA implementing regulations and issued interim final rules. The potential impact of further changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our capital expenditures and earnings.

Climate Change and Regulation of Methane and Other Greenhouse Gas Emissions. In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in nearly 200 countries, including the United States, coming together to develop the Paris Agreement, which calls for the signatories to the agreement to undertake "ambitious efforts" to limit increases in the average global temperature. Although the agreement does not create any binding obligations for nations to limit their GHG emissions, it does require pledges to voluntarily limit or reduce future emissions. In January 2026, the United States withdrew from the Paris Agreement and announced that it would also withdraw from the United Nations Framework Convention on Climate Change. Nonetheless, various state and local governments have publicly committed to furthering the goals of the Paris Agreement and many of these initiatives are expected to continue. The full impact of these actions and initiatives remains uncertain at this time.

In recent years, Congress has considered legislation to reduce GHG emissions. While Congress has not passed comprehensive climate legislation regulating the emission of GHGs, energy legislation and other regulatory initiatives have been enacted or proposed that are relevant to GHG emissions and climate change. In November 2021, Congress approved a $1 trillion legislative infrastructure package known as the Inflation Reduction Act of 2022 (the IRA), which included a number of climate-focused spending initiatives. However, portions of the IRA were rescinded or modified by the One Big Beautiful Bill Act (the OBBBA) passed in July 2025. For example, the IRA had instituted a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems. This program requires the EPA to impose a "waste emissions charge" on methane emissions from certain natural gas and oil facilities that are in excess of a specified threshold. In November 2024, the EPA finalized a rule implementing the IRA's waste emissions charge that took effect in January 2025. In March 2025, a Joint Resolution of Disapproval under the Congressional Review Act disapproved implementing the waste emissions charge, and in July 2025, the OBBBA rescinded unobligated funds from the Methane Emissions Reduction Program and postponed the EPA's imposition of the program's waste emissions charge to calendar year 2034.

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In May 2024, the EPA finalized revisions to the Greenhouse Gas Reporting Program for petroleum and natural gas systems (Subpart W). Among other things, the final rule (the Subpart W Revisions Rule) expands the emissions events that are subject to reporting requirements to include "other large release events" and applies reporting requirements to certain new sources and sectors. The emissions reported under the Greenhouse Gas Reporting Program will be the basis for any payments under the Methane Emissions and Waste Reduction Incentive Program in the IRA, and the Subpart W Revisions Rule may result in an increase in reported methane and other GHG emissions under Subpart W for many operators. The Subpart W Revisions Rule took effect in January 2025. However, in September 2025, the EPA proposed to permanently remove program obligations from the Greenhouse Gas Reporting Program for most source categories and suspend program obligations for some sources subject to Subpart W until 2034.

Furthermore, in May 2024, the EPA published final rules for carbon emission limits and guidelines for new, modified, reconstructed and existing fossil fuel-fired (i.e., coal, oil and gas-fired) power plants. The rules purport to reflect the best system of emissions reduction and use of technology-based improvements, including carbon capture and sequestration and low-GHG hydrogen. The rules also revise the NSPS for new fossil fuel-fired stationary combustion turbine units and existing fossil fuel-fired steam generating electric generating units (EGUs), create new GHG emissions guidelines for existing fossil fuel-fired steam generating EGUs and for existing large, frequently operated stationary combustion turbines. The rules require states to submit plans for the establishment, implementation and enforcement of performance standards for existing sources to the EPA within 24 months of the effective date of the emission guidelines, and compliance deadlines for stationary sources begin by 2030 for existing steam generating units, and 2032 or 2035 for existing combustion turbine units, depending on their subcategory. A coalition of 25 states, energy companies, utilities and fossil fuel industry groups immediately challenged the rules in federal court. In October 2024, the U.S. Supreme Court denied a request to stay the rule for new gas-fired and existing coal-fired power plants while the litigation continues. However, in February 2025, the D.C. Circuit granted the EPA's motion to hold the litigation in abeyance to allow new EPA leadership to review the underlying rule. In June 2025, the EPA issued a proposed rule that would repeal all GHG emissions standards for new and existing fossil fuel-fired power plants, including the May 2024 rule. Additionally, in February 2026, the EPA issued a pre-publication copy of a final rule to rescind the EPA's 2009 finding that GHGs endanger public health and welfare (the Endangerment Finding). The Endangerment Finding has been the foundation for regulating GHG emissions, and without the Endangerment Finding, the EPA may assert that it lacks authority under the CAA to prescribe emissions standards. The potential impact of the final rule, potential subsequent revisions to existing emission standards and outcome of related litigation remain uncertain.

Additionally, a number of U.S. state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of carbon taxes, policies and incentives, and cap-and-trade programs. In October 2019, then-Pennsylvania Governor Wolf signed an Executive Order directing the Pennsylvania Department of Environmental Protection to draft regulations establishing a cap-and-trade program with the intent of enabling Pennsylvania to join the Regional Greenhouse Gas Initiative (RGGI), a multi-state regional cap-and-trade program comprised of several Eastern U.S. states. Pennsylvania became a member of RGGI in April 2022; however, since joining RGGI, Pennsylvania's membership has been the subject of various legal challenges. In November 2023, the Pennsylvania Commonwealth Court held that the state's participation in RGGI is unconstitutional, and funds raised by the state through its participation in RGGI constitute an invalid tax, which ruling was appealed in December 2023 to the Supreme Court of Pennsylvania. In March 2024, Pennsylvania Governor Shapiro unveiled a proposal to adopt a carbon pricing program similar to RGGI and stated that he would pull Pennsylvania out of RGGI if the state legislature enacts his proposal. In November 2025, Pennsylvania enacted legislation ending the state's participation in RGGI.

Regulations requiring the disclosure of GHG emissions and other climate-related information or information substantiating climate-related claims are also being adopted or proposed at the state level. For example, California has enacted legislation that will ultimately require certain companies that do business in California to publicly disclose certain climate-related information, including their Scopes 1, 2, and 3 GHG emissions, with third party assurance of such data, and climate-related financial risks and related mitigation measures. These laws are subject to ongoing legal challenges and certain requirements are currently enjoined. It is unclear how the litigation process and additional legal developments will impact enforceability of these requirements and the timeline and cost of compliance.

Any legislation or regulatory programs at the international, federal, state or local levels designed to reduce methane or other GHG emissions could increase the cost of consuming, and thereby reduce demand for, the natural gas and NGLs we produce, gather, process and transport. Consequently, legislation and regulatory programs designed to reduce emissions of methane or other GHGs could have an adverse effect on our earnings and business.

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It is not possible at this time to predict how legislation or regulations that may be adopted to address climate change, methane and other GHG emissions would impact our earnings or business. Further, the U.S. Supreme Court's decision in Loper Bright Enterprises v. Raimondo to overrule Chevron U.S.A. Inc. v. Natural Resources Defense Council, Inc. ending the concept of general deference to regulatory agency interpretations of laws introduces new complexity for federal agencies and administration of climate change policy and regulatory programs. However, many of these initiatives at the international, state and local levels are expected to continue, and existing laws and regulations and any such future laws and regulations of this nature, including those imposing reporting obligations on, or imposing a tax or fee or otherwise limiting emissions of methane or other GHG emissions from, our equipment and operations, could require us to incur capital expenditures to comply with such regulations. Substantial limitations or fees on methane or other GHG emissions could also adversely affect demand for the natural gas and NGLs we produce, gather, process and transport and lower the value of our reserves.

Further, activism directed at shifting funding away from fossil fuel companies could result in limitations or restrictions on certain sources of funding for the sector. Moreover, activist shareholders have introduced proposals to certain companies seeking to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult to engage in our operations.

Finally, it should be noted that many scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere produce climate changes that may have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events. If any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water and thus could have an adverse effect on our operations.

Hydraulic Fracturing Activities. Vast quantities of natural gas deposits exist in shale and other formations. It is customary in our industry to recover natural gas from these shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations underground where water, sand and other additives are pumped under high pressure into a shale gas formation. These deeper formations are geologically separated and isolated from fresh ground water supplies by overlying rock layers. Our well construction practices include installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers. To assess water sources near our drilling locations, we conduct multiple pre-drill samplings for all water sources within 3,000 feet of our sites and post-drill samplings for sources within 1,500 feet of our sites.

Hydraulic fracturing typically is regulated by state oil and natural gas agencies, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (the SDWA) over certain hydraulic fracturing activities involving the use of diesel fuels and has prohibited the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have sought to ban hydraulic fracturing altogether. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from constructing wells.

In April 2024, the Bureau of Land Management (the BLM) finalized a rule to reduce the waste of natural gas from venting, flaring and leaks during oil and gas production activities on federal and Native American leases. The final rule took effect in June 2024. However, in May 2024, the states of North Dakota, Texas, Montana, Wyoming and Utah challenged the rule. In September 2024, the U.S. District Court for the District of North Dakota granted a motion prohibiting the BLM from enforcing the rule against those states pending the outcome of the litigation. The U.S. Court of Appeals for the Eighth Circuit granted the BLM an initial 60-day stay of the litigation in February 2025, and the case continues to be held in abeyance. In November 2025, the BLM announced it would delay enforcement of two provisions of the April 2024 rule previously scheduled to take effect in December 2025. The relevant provisions imposed measurement device and sampling requirements for flares flowing between 1,050 and 6,000 Mcf/month and required operators to submit Leak Detection and Repair plans to the state BLM office. Consequently, future implementation and enforcement of the final rule remains uncertain at this time.

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Pipeline Safety and Maintenance Regulations. Our interstate natural gas pipeline system and natural gas storage assets are subject to regulation by the PHMSA. The 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 our performance of customary pipeline and storage management activities, we 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, the 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). The 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.

Further, in June 2016, then-President Obama signed the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the 2016 Pipeline Safety Act), extending the PHMSA's statutory mandate under prior legislation through 2019. In addition, the 2016 Pipeline Safety Act empowered the PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing and also required the PHMSA to develop new safety standards for natural gas storage facilities by June 2018. Pursuant to those provisions of the 2016 Pipeline Safety Act, the PHMSA issued 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.

The PHMSA has also published five final rules on pipeline safety applicable to us: "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); "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); "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 the 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 the PHMSA of proposed alternative approaches to achieving the objectives of the minimum safety standards. Mega Rule Part II, which was finalized in November 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 submitted 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 in August 2022, went into effect on 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 and storage 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.

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We do expect certain compliance costs related to the pipeline safety and maintenance regulations to increase in the future, which could materially impact our future costs of operations and earnings. For example, Mega Rule Part I requires MAOP reconfirmation of certain previously untested transmission pipeline segments, which are commonly referred to as "grandfathered" pipelines. Our grandfathered pipeline MAOP reconfirmation efforts, which we have initiated, may result in unanticipated testing and/or replacement costs. When reconfirming MAOP on certain of our grandfathered pipeline segments we 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 our pipelines during the pendency of any such actions, which could be material to our capital expenditures, earnings and competitive position. Additionally, ensuring complete compliance with the applicable Mega Rule compliance deadlines may cause us 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 our natural gas facilities fall within a class that is not subject to integrity management requirements, we may incur significant costs and liabilities associated with repair, remediation, preventive or mitigation measures associated with our 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 our pipelines during the pendency of any such actions, could be material to our capital expenditures, earnings and competitive position.

Should we fail to comply with U.S. Department of Transportation regulations adopted under authority granted to the PHMSA, we could be subject to penalties and fines. The PHMSA has the statutory authority to impose civil penalties for pipeline safety violations of up to $272,926 per day for each violation and up to approximately $2.7 million for a related series of violations, in each case as of February 11, 2026. This maximum penalty authority established by statute is adjusted periodically to account for inflation. In addition, we could be required to make additional, unforeseen maintenance capital expenditures in the future for our regulatory compliance initiatives. Furthermore, the adoption of new laws and regulations could result in significant added costs, delays or the termination of projects, which could have a material adverse effect on us in the future.

In December 2020, President Trump signed the "Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020" (the PIPES Act), which reauthorized the federal pipeline safety program that expired in 2019. The PIPES Act identifies areas where Congress believed additional oversight, research or regulation was needed. The PIPES Act includes new mandates for the PHMSA to require operators to update, as needed, their emergency response plans and operating and maintenance plans. The PIPES Act also requires operators to manage records and update, as necessary, their existing district regulator stations to eliminate a common mode of failure. The PHMSA will also require that leak detection and repair programs consider the environment, the use of advanced 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. We have not incurred and do not anticipate incurring material capital expenditures in connection with complying with the PIPES Act.

Occupational Safety and Health Act. We are subject to the requirements of the federal Occupational Safety and Health Act and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Health and Safety Administration's hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations, and similar state statutes and regulations require us to maintain information about hazardous materials used or produced in our operations and this information is required to be provided to employees, state and local government authorities, and citizens.

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Endangered Species Act and Migratory Bird Treaty Act. The federal Endangered Species Act (the ESA) provides for the protection of endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species' habitat. The U.S. Fish and Wildlife Service (the FWS) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. In June and July 2022, the FWS issued final rules rescinding the regulations defining "habitat" and governing critical habitat exclusions. In March 2024, the FWS issued three final rules governing interagency cooperation, listing species and designating critical habitat, and expanding protection options for species listed as threatened pursuant to the ESA. Protections similar to the ESA are offered to migratory birds under the Migratory Bird Treaty Act (the MBTA), which makes it illegal to, among other things, hunt, capture, kill, possess, sell or purchase migratory birds, nests or eggs without a permit. This prohibition covers most bird species in the U.S. In April 2025, the Solicitor for the Department of the Interior reinstated a 2017 legal opinion finding that unintentional or incidental injury or death of migratory birds was not prohibited under the MBTA. Also in April 2025, the FWS and the National Marine Fisheries Service issued a notice of proposed rulemaking to rescind the regulatory definition of "harm" included in their respective ESA regulations. Consequently, future implementation and enforcement of the rules impacting the ESA and the MBTA are uncertain. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for natural gas development. Further, the designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our upstream and midstream activities that could have an adverse impact on our ability to develop and produce reserves and transport products to points of sale. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take other measures that may adversely impact our earnings, business or operations.

See Note 13 to the Consolidated Financial Statements for a description of expenditures related to environmental matters.

Human Capital Resources

As of December 31, 2025, we had 1,523 full-time equivalent employees (i.e., excluding temporary employees and contractors), none of whom were subject to a collective bargaining agreement. Of our employee base, 76% are male and 24% are female. In addition, 94% of our employees reside in Pennsylvania, West Virginia, Texas or Ohio, and approximately 56% work remotely.

We aim to develop a workforce that produces peer-leading results. To further that goal, we have focused on creating a modern, innovative, collaborative and digitally-enabled work environment. Our cloud-based digital work environment serves as our primary platform for communication and collaboration as well as the home for our critical work processes and drives decision-making based on a shared and transparent view of operational data. We use our digital work environment to engage directly with our employees by sharing company updates and personnel accomplishments as well as to solicit suggestions and comments from all employees. We believe that this helps promote real-time feedback and a greater degree of employee engagement, which lays the foundation for the success of our workforce.

We understand that providing employees with the resources and support they need to live a physically, mentally and financially healthy life is critical for sustaining a workplace of choice. We offer benefits that include subsidized health insurance, a company contribution and company match on 401(k) retirement savings, an employee stock purchase plan, paid maternity and paternity leave, flexible work arrangements, volunteer time off and a company match on employee donations to qualified non-profits. We also offer our employees the flexibility to elect to work a "9/80" work schedule, under which, during the standard 80-hour pay period, an employee works eight 9-hour days and one 8-hour day (Friday), with a tenth day off (alternating Fridays).

We also offer an "equity-for-all" program, pursuant to which we grant annual equity awards to all of our employees. With the equity-for-all program, all of our employees become owners of EQT and have the opportunity to share directly in our financial success.

Availability of Reports and Other Information

We make certain filings with the SEC, including our Annual Reports 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 our investor relations website, https://ir.eqt.com, as soon as reasonably practicable after they are filed with or furnished to the SEC. Reports filed with the SEC are also available on the SEC's website, https://www.sec.gov.

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We use our X (formerly known as Twitter) account, @EQTCorp, our Facebook account, @EQTCorporation, and our LinkedIn account, EQT Corporation, as additional ways of disseminating information that may be relevant to investors.

We generally post the following to our investor relations website shortly before or promptly following its first use or release: financially-related press releases, including earnings releases and supplemental financial information; various SEC filings; presentation materials associated with earnings and other investor conference calls or events; and access to live and recorded audio from earnings and other investor conference calls or events. In certain cases, we may post the presentation materials for other investor conference calls or events several days prior to the call or event. For earnings and other conference calls or events, we generally include within our posted materials a cautionary statement regarding forward-looking and non-GAAP financial information as well as non-GAAP to GAAP financial information reconciliations (if available). Such GAAP reconciliations may be in materials for the applicable presentation, in materials for prior presentations or in our annual, quarterly or current reports.

In certain circumstances, we may post information, such as presentation materials and press releases, to our corporate website, https://EQT.com, or our investor relations website to expedite public access to information regarding the Company in lieu of making a filing with the SEC for first disclosure of the information. When permissible, we expect to continue to do so without also providing disclosure of this information through filings with the SEC.

Internet addresses included in this Annual Report on Form 10-K are included as inactive textual references only. Except as specifically incorporated by reference into this Annual Report on Form 10-K, information on those websites is not part hereof.

Jurisdiction and Year of Formation

EQT is a Pennsylvania corporation formed in 2008 in connection with a holding company reorganization of the former Equitable Resources, Inc.