What changed in this filing

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Item 1. Business

2026-02-18 compared with 2025-02-19 · 248 added, 209 removed, 532 unchanged (46% of the section changed)

We are a vertically integrated natural gas company with production, gathering and transmission operations focused in the Appalachian Basin.

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 operate and hold an investment in the Mountain Valley Pipeline (the MVP), a 303-mile long pipeline that spans from Wetzel County, West Virginia to Pittsylvania County, Virginia.

We are committed to responsibly developing our world-class asset base and being the operator of choice for all stakeholders.

By promoting a culture that prioritizes operational efficiency, technology, sustainability and safety, we seek to continuously improve the way we produce and deliver environmentally responsible, reliable and affordable energy.

Our business strategy is to be the lowest-cost producer of natural gas.

The durability of this strategy relies on our substantial inventory of core drilling locations, our vast midstream infrastructure spanning the Appalachian Basin, our investment grade balance sheet, 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 are situated to endure and excel during times of market volatility.

In periods of low commodity prices, our integrated business model is designed to produce durable free cash flow due to the annuity-like nature of our midstream assets.

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.

Our peer-leading drilling inventory coupled with our midstream ownership and operatorship also positions us to provide production growth to serve growing demand from the power and LNG markets.

Our operational strategy focuses on the successful execution of combo-development projects.

Combo-development refers to the development of several multi-well pads in tandem.

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.

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.

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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, enabling us to keep our development costs low and limiting our need to hedge our future production, providing both downside protection and better exposure to natural gas price increases in the face of a volatile commodity market.

The benefits of combo-development extend beyond financial gains to include environmental and social interests.

We have developed an integrated ESG program that interplays with our combo-development-driven operational strategy.

Core tenets of our ESG program include investing in technology and human capital;

improving data collection, analysis and reporting;

and engaging with stakeholders to understand, and align our actions with, their needs and expectations.

Combo-development, when compared to similar production from non-combo-development operations, translates into fewer trucks on the road, decreased fuel usage, shorter periods of noise pollution, fewer areas impacted by midstream pipeline construction and shortened duration of site operations, all of which fosters a greater focus on safety, environmental protection and social responsibility.

We believe that combo-development projects are key to delivering sustainably low well costs and higher returns on invested capital.

Our business model enables us to generate durable free cash flow and 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.

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.

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

We believe that 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.

Our operational strategy employs this differentiation to advance our mission of being the operator of choice for all stakeholders, while simultaneously helping to address energy security and affordability both domestically and globally .

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.

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.

• Completed the Equitrans Midstream Merger (defined in Note 6 to the Consolidated Financial Statements).

• Completed the First NEPA Non-Operated Asset Divestiture (defined in Note 7 to the Consolidated Financial Statements) in May 2024 and the Second NEPA Non-Operated Asset Divestiture (defined in Note 7 to the Consolidated Financial Statements) in December 2024.

• Completed the Midstream Joint Venture Transaction (defined in Note 8 to the Consolidated Financial Statements).

• Retired $4.3 billion aggregate principal of senior notes and term loans outstanding under the Term Loan Facility (defined in Note 10 to the Consolidated Financial Statements).

• Paid $327 million in aggregate dividends to shareholders.

In 2025, we expect to spend approximately $2.3 billion to $2.5 billion on total capital expenditures.

We expect to allocate the total planned capital expenditures as follows:

approximately $1,445 million to $1,555 million to fund reserve development, approximately $160 million to $180 million to fund land and lease acquisitions, approximately $80 million to $90 million to fund other production infrastructure, approximately $360 million to $390 million to fund gathering infrastructure, approximately $50 million to $60 million to fund transmission infrastructure and approximately $205 million to $225 million towards capitalized interest, capitalized overhead and other.

Of the total planned capital expenditures, we expect to allocate approximately $350 million to $380 million to strategic growth projects composed of approximately $85 million to $95 million for water infrastructure within reserve development, approximately $130 million to $140 million for growth projects within gathering infrastructure and approximately $135 million to $145 million for in-fill leasing within land and lease acquisitions.

• 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.

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

Full Year 2026

Reserve development $ 1,630 – $ 1,710

Land and lease 165 – 185

Other upstream infrastructure 85 – 95

Gathering infrastructure 530 – 580

Transmission infrastructure 20 – 30

Capitalized overhead, capitalized interest and other corporate items 220 – 250

Total (a) $ 2,650 – $ 2,850

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.

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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 hedge 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.

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.

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.

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Segment and Geographical Information

Prior to the completion of the Equitrans Midstream Merger, we reported our results of operations as a single consolidated segment.

Thereafter, and as a result thereof, we adjusted our internal reporting structure and our chief operating decision maker changed the manner in which he measures financial performance and allocates resources to incorporate the gathering and transmission assets we acquired in the Equitrans Midstream Merger.

Hence, our operations expanded to comprise three discrete segments reflective of our three lines of business of Production, Gathering and Transmission.

Accordingly, the manner in which we report our operations has been changed retrospectively, with certain prior period amounts recast between our Production segment and Gathering segment.

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.

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Operating revenues:

Production (a) $ 5,009,833 $ 6,896,358 $ 7,484,063

Upstream (a) $ 8,024,057 $ 5,009,833 $ 6,896,358

Gathering (b) 1,301,434 749,700 161,395

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EQT Corporation $ 8,644,211 $ 5,273,309 $ 6,908,923

(a) Primarily sales of natural gas, NGLs and oil and, for 2023 and 2022, gain (loss) on derivatives.

(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 Production segment and our Gathering or Transmission segments for the transportation of our natural gas.

Production Segment Assets and Operations

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

Upstream Segment Assets and Operations

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.

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Total proved reserves 26,416 272 28,046

90% of our total proved developed reserves, 98% of our total proved undeveloped reserves and 92% of our total proved reserves are located in the Marcellus Shale.

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.

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Net proved undeveloped drilling locations 177 145 — 322

Our 2024 total proved reserves decreased by 1,332 Bcfe, or 4.8%, compared to 2023 due to production of 2,228 Bcfe, negative revisions of previous estimates of 1,080 Bcfe and decreases from the NEPA Non-Operated Asset Divestitures of 1,563 Bcfe, partly offset by extensions, discoveries and other additions of 3,126 Bcfe and acquisitions from the First NEPA Non-Operated Asset Divestiture of 413 Bcfe.

Our 2024 proved undeveloped reserves decreased by 579 Bcfe, or 7.2%, compared to 2023.

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.

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.

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Conversions into proved developed reserves (2,380)

Divestiture (a) (188)

Acquisition (a) 565

Revision of previous estimates (b) (311)

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Balance at December 31, 2025 7,465

(a) Proved undeveloped non-operated assets divested in the NEPA Non-Operated Asset Divestitures.

(a) Composed of proved undeveloped locations acquired in the Olympus Energy Acquisition.

See Note 11 to the Consolidated Financial Statements.

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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).

Years Ended December 31,

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(Millions, unless otherwise noted)

Future net cash flow $ 17,094 $ 19,031 $ 87,612

Future net cash flows $ 43,263 $ 17,094 $ 19,031

Standardized Measure (a) 21,310 7,999 9,262

PV-10 (a) 25,594 9,844 11,520

Prices, including regional adjustments:

Prices, including regional differentials:

Natural gas price ($/Mcf) $ 2.749 $ 1.468 $ 1.700

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(a) PV-10 is a non-GAAP financial measure.

PV-10 is derived from the standardized measure of discounted future net cash flows (the Standardized Measure), which is the most comparable financial measure calculated in accordance with GAAP.

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.

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See below for a reconciliation of the Standardized Measure to PV-10.

Revenues are based on a twelve-month unweighted average of the first-day-of-the-month pricing without escalation.

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.

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

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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 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.

Production Acreage

The majority of our production acreage is held by lease or occupied under perpetual easements or other rights acquired, for the most part, without warranty of underlying land titles.

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 production acreage disaggregated by state.

The following table summarizes our Upstream acreage disaggregated by state.

December 31, 2025

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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, 17,345, 26,478 and 29,342 of our net undeveloped production acreage as of December 31, 2024 will expire in the years ending December 31, 2025, 2026 and 2027, respectively.

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

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Total net in-process wells 148 109 — 257

(a) Of our total gross productive wells, there are 744 gross conventional wells in Pennsylvania and 6 gross conventional wells in West Virginia.

We have no gross conventional wells in Ohio.

(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 completed net productive development wells.

During the years ended December 31, 2024, 2023 and 2022, we did not drill any net dry development, net productive exploratory or net dry exploratory wells.

The following table summarizes our net productive development wells.

Pennsylvania West Virginia Ohio Total

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Year ended December 31, 2023 91 47 2 140

The following table summarizes the gross and net wells on which we commenced drilling operations (spud) in 2024.

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.

Pennsylvania West Virginia Ohio Total

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Net wells spud 81 36 4 121

Production, Sales, Customers and Price

Upstream Sales, Pricing, Commitments and Costs

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

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Year ended December 31, 2023 1,496,197 435,898 84,178 2,016,273

For the years ended December 31, 2024, 2023 and 2022, lease operating expenses (LOE) per Mcfe were $0.09, $0.07 and $0.08, respectively.

For more information on our Production segment's operating expenses, refer to "Business Segment Results of Operations – PRODUCTION" in Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Natural Gas Sales.

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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 4.9 Bcf per day of firm pipeline takeaway capacity, including 1.29 Bcf per day of firm pipeline takeaway capacity on the MVP 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 once in service.

We have access to approximately 1.1 Bcf per day of firm processing capacity, including 0.2 Bcf per day of firm processing capacity on our owned processing facility.

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.

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Thereafter 1,543 23,730

During the fourth quarter of 2023, we entered into two firm sales agreements, pursuant to which we agreed to deliver and sell to the parties thereto up to an aggregate 1.2 Bcf per day of gas using our capacity on the MVP for up to ten years beginning in 2027.

The firm sales agreements are subject to currently unsatisfied conditions related to the in-service date of the Transco Southeast Supply Enhancement project;

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."

Gathering Segment Assets and Operations

Gathering System

As of December 31, 2024, our gathering system included approximately 1,975 miles of gathering lines (of which approximately 1,260 miles were high-pressure gathering lines), 179 compression units with an aggregate compression of approximately 623,000 horsepower and multiple interconnect points to our transmission and storage system and to other interstate pipelines.

The following table presents information on our gathering system.

In addition, we own a processing facility with capacity of 0.2 Bcf per day.

December 31, 2025

Gathering pipeline miles 1,995

Compression units 200

Compression horsepower 650,000

Gathering Customers

Our Gathering segment has gathering agreements with our Production segment and third parties.

Certain of our Gathering segment's agreements provide us the right to elect to gather all natural gas produced from wells located in specified dedicated acreage.

For the year ended December 31, 2024, our Production segment accounted for approximately 71% of our gathering system's throughput and approximately 80% of our Gathering segment's operating revenues.

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.

Including future capacity expected from expansion projects that are not yet fully constructed or not yet fully in service for which we have executed firm service contracts, our gathering system had total contracted firm reservation capacity, including contracted MVCs, of approximately 8.6 Bcf per day as of December 31, 2024.

Based on total projected contractual revenues, our firm gathering contracts with third parties had a weighted average remaining term of approximately 10 years as of December 31, 2024.

In addition, based on total projected contractual revenues, our firm gathering contracts with our Production segment had a weighted average remaining term of approximately 14 years as of December 31, 2024.

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 System

As of December 31, 2024, our transmission and storage system included approximately 950 miles of FERC-regulated, interstate pipelines with total throughput capacity of approximately 5.0 Bcf per day, 44 compression units with an aggregate compression of approximately 175,000 horsepower and 8 interconnect points to other interstate pipelines and multiple local distribution companies.

As of December 31, 2024, our transmission and storage system included 18 natural gas storage reservoirs with a peak withdrawal capacity of approximately 800 MMcf per day and a working gas capacity of approximately 43 Bcf.

Transmission Customers

Our Transmission segment has transmission and storage agreements with our Production segment and third parties.

Transmission and Storage System

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

December 31, 2025

Transmission:

Pipeline miles 950

Throughput capacity (Bcf per day) 5.0

Interconnect points 8

Compression units 45

Compression horsepower 197,000

Reservoirs 18

Peak withdrawal capacity (Bcf per day)

Working gas capacity (Bcf)

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, 2024, our Production segment accounted for approximately 64% of our transmission assets' throughput and approximately 59% of our Transmission segment's operating revenues.

Including future capacity expected from expansion projects that are not yet fully constructed or not yet fully in service for which we have executed firm service contracts, our transmission and storage system had total firm capacity subscribed under transmission contracts of approximately 5.4 Bcf per day and total firm capacity subscribed under storage contracts of 38.4 Bcf as of December 31, 2024.

Based on total projected contractual revenues, our firm transmission and storage contracts with third parties had a weighted average remaining term of approximately 11 years as of December 31, 2024.

In addition, based on total projected contractual revenues, our firm transmission and storage contracts with our Production segment had a weighted average remaining term of approximately 13 years as of December 31, 2024.

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.

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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.

The MVP and MVP Southgate

We operate and hold an equity method investment in the MVP, a 303-mile long, 42-inch diameter natural gas interstate pipeline with a total capacity of 2.0 Bcf per day that spans from the Company's transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia and has 3 interconnect points to other interstate pipelines.

Based on total projected contractual revenues, the MVP's firm transmission contracts had a weighted average remaining term of approximately 19.5 years as of December 31, 2024.

In addition, we hold an equity method investment in MVP Southgate, a contemplated 31-mile, 30-inch diameter natural gas interstate pipeline with a targeted capacity of 0.55 Bcf per day that would extend from the terminus of the MVP in Pittsylvania County, Virginia to new delivery points in Rockingham County, North Carolina.

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 (see Note 11 to the Consolidated Financial Statements for further details), of which we will fund our proportionate share through capital contributions to the MVP Joint Venture (defined in Note 11 to the Consolidated Financial Statements).

Generally, but not always, the demand for natural gas (including the demand for its gathering, transmission or storage) decreases during the summer months and increases during the winter months.

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.

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.

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.

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.

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.

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.

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Various states also impose certain regulatory requirements to transfer wells to third parties or discontinue operations in the event of divestitures by us.

We also have gathering and processing operations that are subject to various federal and state environmental laws and local zoning ordinances, including the following:

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;

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compliance with safety regulations, including regulations by the U.S.

Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA);

Department of Transportation's Pipeline and Hazardous Materials Safety Administration (the PHMSA);

and siting and noise regulations for compressor stations.

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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" (SDs) and "security-based swap dealers" (SBSDs) 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.

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.

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Regulators periodically review or audit our compliance with applicable regulatory requirements.

We anticipate that compliance with existing laws and regulations governing our current operations will not have a material adverse effect on our capital expenditures, earnings or competitive position.

Additional proposals that affect the oil and gas industry are regularly considered by Congress, the states, regulatory agencies and the courts.

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 some of the existing laws, rules and regulations to which our business operations are subject.

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 oil and natural gas.

The interstate transportation and sale for resale of oil and natural gas 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 oil and natural gas pipeline transportation.

The FERC's regulations for interstate oil and natural gas transportation in some circumstances may also affect the intrastate transportation of oil and natural gas.

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.

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 (NGA) and the Natural Gas Policy Act of 1978 (NGPA).

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 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, contribute to or may contribute to the formation of price indices.

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.

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In addition, pipelines are allowed to negotiate different rates with their customers, under certain circumstances.

Changes to rates or terms and conditions of service, and contracts can be proposed by a pipeline company under Section 4 of the NGA, or the existing interstate transmission and storage rates, terms and conditions of service and/or contracts may be challenged by a complaint filed by interested persons including customers, state agencies or the FERC under Section 5 of the NGA.

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.

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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, 2024, approximately 99% of our system's contracted firm transmission capacity was subscribed under negotiated rate agreements under its tariff.

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.

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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 (2018 Notice of Inquiry) seeking information regarding whether, and if so how, it should revise its approach under its currently effective policy statement on the certification of new natural gas transportation facilities (Certificate Policy Statement).

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 (together with the 2018 Notice of Inquiry, the Certificate Policy Statement NOI).

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.

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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.

the FERC has taken no further action to date on the Updated Certificate Policy Statement.

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.

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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.

Oil and NGLs Price Controls and Transportation Rates.

Sales prices of oil and NGLs are not currently regulated and are made at market prices.

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.

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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 oil and NGLs may be affected by the cost of transporting such products to market.

Some of our transportation of oil and NGLs is through FERC-regulated interstate common carrier pipelines.

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 oil and NGLs transportation rates may tend to increase the cost of transporting oil and NGLs by interstate pipelines, although the annual adjustments may result in decreased rates in a given year.

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.

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In July 2024, the U.S.

Court of Appeals for the District of Columbia Circuit found that the FERC did not adhere to notice-and-comment procedures in its January 2022 rehearing order.

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.

Environmental, Health and Safety Regulations

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In addition, these laws and regulations may restrict the rate of our production.

Moreover, the trend has been for stricter regulation of activities that have the potential to affect the environment.

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.

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Therefore, we are unable to predict the future costs or impact of compliance.

The regulatory burden on the industry increases the cost of doing business and affects profitability.

We have established procedures, however, for the ongoing evaluation of our operations to identify potential environmental exposures and to track compliance with regulatory policies and procedures.

The following is a summary of the more significant environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our financial condition, earnings or cash flows.

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.

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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 results of operations and financial condition.

We currently own, lease or operate numerous properties that have been used for oil and natural gas exploration and production activities for many years.

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.

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.

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Water Discharges.

The Federal Water Pollution Control Act, known as the Clean Water Act (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 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 (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 (NWPR) in December 2019.

Army Corps of Engineers (the Corps).

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.

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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.

However, in January 2025, President Trump issued executive orders directing (i) the EPA and the Corps to identify planned or potential actions that could be subject to emergency treatment under Section 404 of the CWA and (ii) the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions, including all existing regulations and guidance documents, that are unduly burdensome on the identification, development, or use of domestic energy resources.

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 (SPCC) plans in connection with on-site storage of significant quantities of oil.

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 final rule took effect on November 27, 2023, but has been challenged by states and regulated entities in ongoing litigation to enjoin its enforcement.

However, 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 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.

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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.

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Air Emissions.

Through the federal Clean Air Act (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.

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 (VOCs) from new and modified oil and natural gas production and natural gas processing and transmission facilities which would establish standards for existing wells, impose more frequent and stringent leak monitoring, and mandate that all pneumatic controllers have zero emissions, among other requirements.

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.

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Fines and penalties for violation of the final rule could be substantial.

The final rule is subject to ongoing litigation but remains in effect.

However, 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.

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.

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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 oil and natural gas projects.

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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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 revenues and results of operations.

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 Trump Administration.

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.

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At least 20 states have challenged the Phase II rule in federal district court.

The 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.

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, and CEQ's Phase I and II rules remain in effect.

However, 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;

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 sent an interim final rule to the White House Office of Management and Budget that would immediately withdraw the NEPA implementing regulations.

The potential impact of further changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our business and operations.

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 (COP) 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.

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.

Pursuant to the terms of the Paris Agreement, the Biden Administration announced goals aimed at reducing the U.S.'s GHG emissions by 50 to 52% (compared to 2005 levels) by 2030.

In addition, in September 2021, the Biden Administration publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions to at least 30% below 2020 levels by 2030.

At COP27, the United States agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas.

In August 2024, the European Union adopted a regulation to track and reduce methane emissions in the energy sector, including requiring new monitoring, reporting and verification measures to be applied by exporters to the European Union by January 1, 2027 and "maximum methane intensity values" must be met by 2030 and every year thereafter.

Each member state will have the power to impose administrative penalties for failure to comply and the standard will be mandatory for supply contracts signed after the law takes effect.

Additionally, at COP28, nearly 200 countries, including the United States, agreed to transition away from fossil fuels while accelerating action in this decade to achieve net zero by 2050 and entered into an agreement that calls for actions towards achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030.

Most recently, at COP29, participants representing 159 countries met and, among other things, agreed on rules to operationalize international carbon markets under Article 6 of the Paris Agreement.

Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement.

However, in January 2025, President Trump issued an executive order directing immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change.

The full impact of these actions remains uncertain at this time.

In recent years, the Congress has considered legislation to reduce GHG 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 (IRA) which includes a number of climate-focused spending initiatives.

The IRA also provides significant funding and incentives for research and development of low-carbon energy production methods, carbon capture, and other programs directed at addressing climate change, including instituting a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems.

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.

The waste emissions charge imposed under the program for 2024 is $900 per ton emitted over the annual methane emissions threshold, and will increase to $1,200 in 2025, and $1,500 in 2026.

The rule includes methodologies for calculating the amount by which a facility's reported methane emissions are below or exceed the waste emissions thresholds and certain exemptions created by the IRA.

For petroleum and natural gas production facilities, the threshold is methane emissions in excess of 0.2% of the natural gas sent to sale from the facility or 10 metric tons of methane per million barrels of oil sent to sale from facility if the facility sends no natural gas to sale.

If a facility's methane emissions do not exceed the 0.2% threshold, no fee is assessed under the program.

Further, in May 2024, the EPA finalized revisions to the Greenhouse Gas Reporting Program for petroleum and natural gas systems (Subpart W).

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.

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.

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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.

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Supreme Court denied a request to stay the rule for new gas-fired and existing coal-fired power plants while the litigation continues.

However, petitions for reconsideration to the EPA are pending and litigation in the D.C.

Circuit has commenced.

Additionally, 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.

Consequently, future implementation and enforcement of these rules remains uncertain at this time.

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.

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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 September 2024, legislation that would repeal the state’s participation in RGGI passed the Pennsylvania Senate.

At this time, it is unclear to what extent, if any, Pennsylvania will continue to seek participation in RGGI or a similar emissions cap-and-trade program.

Regulations requiring the disclosure of GHG emissions and other climate-related information or information substantiating climate-related claims are also increasingly being adopted or proposed at the federal and state level.

For example, at the state level, California enacted legislation in October 2023 that will ultimately require certain companies that do business in California to publicly disclose their Scopes 1, 2, and 3 GHG emissions, with third party assurance of such data, and issue public reports on their climate-related financial risk and related mitigation measures, as well as legislation that requires companies operating in California to disclose information that supports certain climate-related claims.

Certain of California's climate disclosure rules took effect in January 2025, with the disclosure of Scope 1 and 2 GHG emissions data scheduled to take effect beginning in 2026.

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, NGLs and oil we produce.

Consequently, legislation and regulatory programs designed to reduce emissions of methane or other GHGs could have an adverse effect on our business, financial condition and results of operations.

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 business.

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.

Consequently, legislation and regulatory programs designed to reduce emissions of methane or other GHGs could have an adverse effect on our earnings and business.

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.

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Natural Resources Defense Council, Inc.

and end 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 costs to comply with such regulations.

Substantial limitations or fees on methane or other GHG emissions could also adversely affect demand for the natural gas, NGLs and oil we produce and transport and lower the value of our reserves.

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.

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.

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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 some 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.

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.

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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 (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.

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.

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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 (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.

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.

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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.

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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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.

Part I of the Mega Rule was promulgated in October 2019, with an effective date of July 1, 2020 (see discussion below).

Part II was promulgated in November 2021, with an effective date of May 16, 2022 (see discussion below).

Finally, Part III of the Mega Rule was promulgated in August 2022, with an effective date of May 24, 2023 (see discussion below).

Further, in June 2016, then-President Obama signed the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the 2016 Pipeline Safety Act), extending the PHMSA's statutory mandate under prior legislation through 2019.

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Maximum Allowable Operating Pressure Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments" (also known as the Mega Rule Part I);

and "Safety of Gas Gathering Pipelines:

"Safety of Gas Gathering Pipelines:

Extension of Reporting Requirements, Regulation of Large, High-Pressure Lines, and Other Related Amendments" (also known as the Mega Rule Part II);

and "Safety of Gas Transmission Pipelines:

"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);

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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.

However, as discussed below, we do expect certain compliance costs to increase in the future, and we continue to assess the impact of compliance with these rules which could materially impact our future costs of operations and revenue from operations.

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.

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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 up to a maximum of approximately $272,926 per day for each violation and approximately $2.7 million for a related series of violations.

This maximum penalty authority established by statute will continue to be adjusted periodically to account for inflation.

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.

Additionally, the adoption of new laws and regulations, such as the Mega Rule discussed above, could result in significant added costs or delays to in service or the termination of projects, which could have a material adverse effect on us in the future.

In December 2020, President Trump signed the "Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES Act) of 2020," which reauthorized the federal pipeline safety program that expired in 2019.

The PIPES Act identifies areas where Congress believed additional oversight, research, or regulations was needed.

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 advance lead detection practices and technologies, and that operators be able to locate and categorize all leaks that are hazardous to human safety, the environment, or that can become hazardous.

The 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.

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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 (OSHA) 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.

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.

Endangered Species Act and Migratory Bird Treaty Act.

The federal Endangered Species Act (ESA) provides for the protection of endangered and threatened species.

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.

Fish and Wildlife Service (FWS) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species.

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 (MBTA), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit.

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 October 2021, the Department of the Interior issued an advance notice of proposed rulemaking seeking comment on the Department's plan to develop regulations that authorize incidental taking under certain prescribed conditions.

The Department has not yet issued a proposed rule.

However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend or rescind all agency actions that are unduly burdensome on the identification, development or use of domestic energy resources.

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 exploration, production 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 business or operations.

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.

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

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Of our employee base, 76% are male and 24% are female.

Approximately 56% of our permanent employees work remotely, with 95% residing in Pennsylvania, West Virginia, Texas or Ohio.

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.

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Availability of Reports and Other Information

We make certain filings with the SEC, including our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through our investor relations website, http://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, http://www.sec.gov.

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.

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.

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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, www.EQT.com, or our investor relations website to expedite public access to information regarding EQT in lieu of making a filing with the SEC for first disclosure of the information.

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.

Where we have included internet addresses in this Annual Report on Form 10-K, we have included those internet addresses as inactive textual references only.

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

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

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

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business