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Item 1. Business

2025-02-19 compared with 2024-02-14 · 368 added, 162 removed, 373 unchanged (59% of the section changed)

We are a natural gas production company with operations focused in the Appalachian Basin.

As of December 31, 2023, we had 27.6 Tcfe of proved natural gas, NGLs and oil reserves across approximately 2.1 million gross acres, and, based on average daily sales volume, we were the largest producer of natural gas in the United States.

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

As of December 31, 2024, we had 26.3 Tcfe of proved natural gas, NGLs and oil reserves across approximately 2.1 million gross acres and approximately 2,925 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 environmentally responsible, reliable low-cost energy.

We measure sustainability through consideration of our best-in-class team and culture, the ESG performance of our operations, our substantial inventory of core drilling locations and our investment grade balance sheet.

We believe that the scale and contiguity of our acreage position differentiates us from our Appalachian Basin peers and that our digitally-enabled exploration and production business enhances our strategic advantage.

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.

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In the drilling stage, rigs spend more time drilling and less time transitioning to new sites.

Advanced planning, a prerequisite to pursuing combo-development, facilitates the delivery of bulk hydraulic fracturing sand and piped fresh and recycled water (as opposed to truck-transported water), and provides the ability to continuously meet completions supply needs and the use of environmentally friendly technologies.

Operational efficiencies realized from combo-development are passed on to our service providers, which reduces overall contract rates.

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.

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

Our business model has been developed to enable us to generate sustainable free cash flow and correspondingly, we have implemented a robust capital allocation strategy directed at responsibly developing our assets while also returning capital to our shareholders through a combination of debt retirements, dividends and strategic share repurchases.

We are also focused on maintaining investment grade credit metrics, which allows us to capture a lower cost of capital and further enhance shareholder returns.

Our strategy, and combo-development projects in particular, requires significant advanced planning, including the establishment of a large, contiguous leasehold position;

the advanced acquisition of regulatory permits and sourcing of fracturing sand and water;

timely midstream connectivity;

and the ability to quickly respond to internal and external stimuli.

Without a digitally-connected operating model or an acreage position that enables operations of this scale, combo-development would not be possible.

Furthermore, we believe the benefits of our operating model can be magnified through select strategic transactions, and part of our strategy includes creating value through mergers and acquisitions, divestitures, joint ventures and similar business transactions, as well as 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, in conjunction with the size and contiguity of our asset base, uniquely position us to execute on a multi-year inventory of combo-development projects in our core acreage position.

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.

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 .

2023 Highlights

• Generated $3.2 billion of net cash provided by operating activities with an average NYMEX price of $2.74 per MMBtu.

• Retired $1.1 billion aggregate principal of debt.

• Increased quarterly base dividend by 5% to $0.1575 per share ($0.63 per share annualized).

• Paid $228 million in dividends to shareholders.

• Repurchased $200 million of common stock, reducing our outstanding share count by 5.9 million shares.

• Completed the Tug Hill and XcL Midstream Acquisition (defined and discussed in Note 6 to the Consolidated Financial Statements).

• Increased total proved reserves by 2,594 Bcfe, or 10.4%, compared to 2022.

• Achieved investment grade credit rating from Moody's Investors Services, making us investment grade rated by all three credit rating agencies.

In 2024, we expect to spend approximately $2.15 billion to $2.35 billion in total capital expenditures.

2024 and Recent Highlights

• Generated $2.8 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 $1,685 million to $1,775 million to fund reserve development, approximately $220 million to $250 million to fund midstream and other infrastructure, approximately $125 million to $190 million to fund land and lease acquisitions, approximately $70 million to $80 million towards capitalized overhead and approximately $50 million to $55 million towards capitalized interest and other items.

Included in total planned capital expenditures is approximately $200 million to $300 million for strategic growth projects composed of approximately $70 million to $90 million for water infrastructure within reserve development, approximately $50 million to $70 million for growth projects within midstream and other infrastructure and approximately $80 million to $140 million for in-fill leasing and mineral purchases within land and lease acquisitions.

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.

In 2025, we expect our sales volume to be 2,175 Bcfe to 2,275 Bcfe.

We are committed to maintaining investment grade credit metrics, and we have a goal to reduce our absolute debt to $3.5 billion, subject to the overall performance of the commodity markets.

We are committed to maintaining investment grade credit metrics.

In 2024, we published a leverage and debt retirement strategy with the goal of reducing our debt to $7.5 billion by the end of 2025, and, in 2025, we published an update to our leverage and debt retirement strategy with the long-term goal of reducing our debt to $5.0 billion, subject to the overall performance of the commodity markets (our Debt Retirement Plan).

Our capital allocation plan is focused on maintaining production volumes while also returning capital to shareholders, including through our quarterly cash dividend and share repurchase program, pursuant to which we are authorized to repurchase shares of our outstanding common stock for an aggregate purchase price of up to $2 billion, excluding fees, commissions and expenses.

Furthermore, we have aligned our hedge strategy in a manner that we believe will mitigate the risk of volatility of future 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.

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.

Our revenues, earnings and liquidity are substantially dependent on the prices we receive for, and our ability to develop our reserves of, natural gas, NGLs and oil, which are also largely dependent on natural gas prices.

Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas, NGLs and oil at our ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations.

Changes in natural gas, NGLs and oil prices could affect, among other things, our development plans, which would increase or decrease the pace of the development and the level of our reserves, as well as our revenues, earnings or liquidity.

Lower prices and changes in our development plans could also result in non-cash impairments in the book value of our oil and gas properties or downward adjustments to our estimated proved reserves.

Lower prices and changes in our development plans could also result in non-cash impairments in the book value of our oil and gas properties and midstream infrastructure or downward adjustments to our estimated proved reserves.

Any such impairments or downward adjustments to our estimated reserves could potentially be material to us.

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Segment and Geographical Information

Our operations consist of one reportable segment.

We have a single, company-wide management team that administers all properties as a whole rather than by discrete operating segments.

We measure financial performance as a single enterprise and not on an area-by-area basis.

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.

See Note 2 to the Consolidated Financial Statements as well as Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further discussion of our reportable segments.

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

Composition of Operating Revenues

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

Years Ended December 31,

2024 2023 2022

Operating revenues:

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

Gathering (b) 749,700 161,395 96,947

Transmission (b) 218,293 — —

Total Segment 5,977,826 7,057,753 7,581,010

Intersegment eliminations and other (c) (704,517) (148,830) (83,321)

EQT Corporation $ 5,273,309 $ 6,908,923 $ 7,497,689

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

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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December 31, 2024

Natural Gas NGLs and Oil Total (a)

Natural Gas NGLs and Oil Total

(Bcf) (MMbbl) (Bcfe)

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Total proved reserves 24,545 286 26,265

(a) The Marcellus Shale comprises 91% of our total proved developed reserves, 98% of our total proved undeveloped reserves and 93% of our total proved reserves.

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.

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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Pennsylvania West Virginia Ohio Total

Proved developed producing reserves 12,855 5,312 552 18,719

Proved developed non-producing reserves 601 234 4 839

Proved developed reserves 12,093 5,850 862 18,805

Proved undeveloped reserves 3,741 3,677 42 7,460

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Net proved undeveloped drilling locations 150 158 3 311

Our 2023 total proved reserves increased by 2,594 Bcfe, or 10.4%, compared to 2022 due to extensions, discoveries and other additions of 3,412 Bcfe and acquisitions of 2,600 Bcfe from the Tug Hill and XcL Midstream Acquisition, partly offset by production of 2,016 Bcfe and revisions to previous estimates of 1,402 Bcfe.

Our 2023 proved undeveloped reserves increased by 550 Bcfe, or 7.3%, compared to 2022.

The following table provides a roll-forward of our proved undeveloped reserves.

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.

The following table provides a rollforward of our proved undeveloped reserves.

Proved Undeveloped Reserves

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Conversions into proved developed reserves (2,637)

Acquisition of in-place reserves 840

Revision of previous estimates (a) (832)

Extensions, discoveries and other additions (b) 3,103

Divestiture (a) (188)

Revision of previous estimates (b) (823)

Extensions, discoveries and other additions (c) 3,069

Balance at December 31, 2024 7,460

(a) Composed of (i) negative revisions of 755 Bcfe related to proved undeveloped locations that we no longer expect to develop as proved reserves within five years of initial booking as a result of development schedule changes, (ii) negative revisions of 367 Bcfe due primarily to revisions to type curves and commodity price change, partly offset by (iii) positive revisions of 290 Bcfe due to changes in ownership interests.

(b) Composed of (i) 1,670 Bcfe from proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2023 reserve development that expanded the number of our proven locations and additions to our five-year drilling plan, (ii) 1,341 Bcfe of proved undeveloped additions for previously proved undeveloped properties reclassified from unproved properties due to their addition to our five-year development plan and (iii) positive revisions of 92 Bcfe from the extension of lateral lengths of proved undeveloped reserves.

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

See Note 7 to the Consolidated Financial Statements.

(b) Composed of (i) negative revisions of 925 Bcfe related to proved undeveloped locations that we no longer expect to develop as proved reserves within five years of initial booking primarily as a result of development schedule changes, (ii) negative revisions of 87 Bcfe primarily related to revisions to lateral lengths and type curves, partly offset by (iii) positive revisions of 189 Bcfe due primarily to changes in ownership interests.

(c) Composed of (i) 2,912 Bcfe from proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2024 reserve development that expanded the number of our proven locations and additions to our five-year drilling plan and (ii) positive revisions of 157 Bcfe from the extension of lateral lengths of proved undeveloped reserves.

As of December 31, 2024, we had zero wells with proved undeveloped reserves that had remained undeveloped for more than five years from their time of booking.

The following table provides the estimated future net cash flows, excluding open derivative contracts, from proved reserves, the present value of those net cash flows discounted at a rate of 10% (PV-10) and the prices used in projecting net cash flows over the past three years.

The following table presents estimated future net cash flows from proved reserves (excluding cash flows from open derivative contracts), the present value of such net cash flows discounted at a rate of 10% (PV-10) and the prices used in estimating such net cash flows.

Our reserve estimates do not include any probable or possible reserves.

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

Standardized measure of discounted future net cash flow 9,262 40,065 17,281

Standardized Measure (a) 7,999 9,262 40,065

PV-10 (a) 9,844 11,520 51,512

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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 directly comparable financial measure computed using GAAP.

PV-10 differs from the Standardized Measure because it does not include the effects of income taxes on future net revenues.

We believe the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to proved reserves held by companies without regard to the specific income tax characteristics of such entities and is a useful measure of evaluating the relative monetary significance of our oil and natural gas properties.

Investors may utilize PV-10 as a basis for comparing the relative size and value of our proved reserves to other companies.

PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure as determined in accordance with GAAP.

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 differs from the Standardized Measure in that PV-10 excludes the effects of income taxes on future net revenues.

We believe the presentation of PV-10 is relevant and useful to investors because it provides the discounted future net cash flows attributable to our proved reserves without regard to any of our specific income tax characteristics and is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties.

Investors may use PV-10 as a basis for comparing the relative size and value of our proved reserves to that of other companies.

PV-10 should not be considered as a substitute for, or more meaningful than, the Standardized Measure.

Neither PV-10 nor the Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties.

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There are numerous uncertainties inherent in estimating reserves and related information.

See Note 14 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 estimated future net cash flows from natural gas and oil reserves.

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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2024 2023 2022

Standardized measure of discounted future net cash flow $ 9,262 $ 40,065 $ 17,281

Standardized Measure $ 7,999 $ 9,262 $ 40,065

Estimated discounted income taxes on future net revenues 1,845 2,258 11,447

PV-10 $ 9,844 $ 11,520 $ 51,512

If the prices used in the calculation of the Standardized Measure instead reflected five-year strip pricing as of December 29, 2023 and held constant thereafter using (i) the NYMEX five-year strip adjusted for regional differentials using Texas Eastern Transmission Corp.

M-2, Transcontinental Gas Pipe Line, Leidy Line, and Tennessee Gas Pipeline Co., Zone 4-300 Leg for gas and (ii) the NYMEX WTI five-year strip for oil, adjusted for regional differentials consistent with those used in the Standardized Measure, and holding all other assumptions constant, our total proved reserves would be 28,042 Bcfe, the Standardized Measure after taxes of our proved reserves would be $18,176 million, the discounted future net cash flows before taxes would be $22,903 million and the average realized product prices weighted by production over the remaining lives of the properties would be $49.71 per barrel of oil, $23.08 per barrel of NGLs and $2.846 per Mcf of gas.

If the prices we used to calculate the Standardized Measure instead reflected five-year strip pricing as of December 31, 2024 and held constant thereafter using (i) the NYMEX five-year strip adjusted for regional differentials using Texas Eastern Transmission Corp.

M-2, Transcontinental Gas Pipe Line, Leidy Line, and Tennessee Gas Pipeline Co., Zone 4-300 Leg for gas and (ii) the NYMEX WTI five-year strip for oil, adjusted for regional differentials consistent with those used in the Standardized Measure, and holding all other assumptions constant, our total proved reserves would be 26,742 Bcfe, the Standardized Measure of our proved reserves would be $22,020 million, the discounted future net cash flows before taxes would be $26,712 million and the average realized product prices weighted by production over the remaining lives of the properties would be $3.016 per Mcf of gas, $24.49 per barrel of NGLs and $47.54 per barrel of oil.

The NYMEX strip price for proved reserves and related metrics are intended to illustrate reserve sensitivities to market expectations of commodity prices and should not be confused with SEC pricing for proved reserves and do not comply with SEC pricing assumptions.

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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.

We believe that our combo-development strategy, coupled with our undeveloped inventory located in a premier core asset base, will lead to sustainable free cash flow generation and higher returns on invested capital.

For the years ended December 31, 2023, 2022 and 2021, lease operating expenses per Mcfe were $0.08, $0.08 and $0.07, respectively.

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

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.

Approximately 37% of our total gross acres is developed.

We retain deep drilling rights on the majority of our acreage.

The following table summarizes our acreage disaggregated by state.

We retain deep drilling rights on the majority of our production acreage.

The following table summarizes our production acreage disaggregated by state.

December 31, 2024

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Total net acreage 1,161,066 595,625 171,369 1,928,060

Average net revenue interest of proved developed reserves (a) 60.1 % 79.4 % 41.2 % 63.6 %

(a) As of December 31, 2023, the average net revenue interest of proved developed reserves was 80.3% for southwestern Pennsylvania and 31.2% for northeastern Pennsylvania.

Average net revenue interest of proved developed reserves 80.6 % 77.2 % 43.4 % 76.5 %

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, 35,844, 22,097 and 30,206 of our net undeveloped acreage as of December 31, 2023 will expire in the years ending December 31, 2024, 2025 and 2026, respectively.

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

Pennsylvania West Virginia Ohio Total

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

Year Ended December 31, 2022 1,493,568 323,113 123,362 1,940,043

Year Ended December 31, 2021 1,422,294 271,747 163,776 1,857,817

Productive Wells

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.

Productive and In-Process Wells

The following table summarizes our productive and in-process natural gas wells.

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Net wells spud 53 35 — 88

Markets and Customers

Production, Sales, Customers and Price

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

Pennsylvania West Virginia Ohio Total

Year Ended December 31, 2024 1,418,812 713,267 96,080 2,228,159

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

Year Ended December 31, 2022 1,493,568 323,113 123,362 1,940,043

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 primarily sell NGLs recovered from our natural gas production.

We contract with MarkWest Energy Partners, L.P., Williams Ohio Valley Midstream LLC and Blue Racer Midstream to process our natural gas and extract heavier hydrocarbon streams (consisting predominately of ethane, propane, isobutane, normal butane and natural gasoline) from our produced natural gas.

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

We market the majority of our NGLs.

Natural Gas and NGLs Customers.

We sell natural gas and NGLs to marketers, utilities and industrial customers located in the Appalachian Basin and in markets that are accessible through our transportation portfolio, particularly where there is expected future demand growth such as in the Gulf Coast, Midwest, East Coast corridor and Northeast United States and Canada.

As of December 31, 2024, approximately 44% of our sales volume reaches markets outside of Appalachia.

We do not depend on any single customer and believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, NGLs and oil.

We have access to approximately 4.9 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.

These firm transportation and processing agreements may require minimum volume delivery commitments, which we expect to principally fulfill with production from existing reserves.

Natural Gas Marketing.

EQT Energy, LLC, our indirect, wholly-owned marketing subsidiary, provides marketing services and contractual pipeline capacity management services primarily for our benefit.

EQT Energy, LLC also engages in risk management and hedging activities to limit our exposure to shifts in market prices.

Average Sales Price.

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

Natural Gas Marketing.

EQT Energy, LLC, our indirect, wholly-owned marketing subsidiary, provides marketing services and contractual pipeline capacity management services primarily for our benefit.

EQT Energy, LLC also engages in risk management and hedging activities to limit our exposure to shifts in market prices.

We sell natural gas and NGLs to marketers, utilities and industrial customers located in the Appalachian Basin and in markets that are accessible through our transportation portfolio, particularly where there is expected future demand growth, such as in the Gulf Coast, Midwest and Northeast United States and Canada.

As of December 31, 2023, approximately 42% of our sales volume reaches markets outside of Appalachia.

We do not depend on any single customer and believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, NGLs and oil.

We have access to approximately 3.6 Bcf per day of firm pipeline takeaway capacity and 0.9 Bcf per day of firm processing capacity.

In addition, we are committed to an initial 1.29 Bcf per day of firm capacity on the Mountain Valley Pipeline once in service.

These firm transportation and processing agreements may require minimum volume delivery commitments, which we expect to principally fulfill with production from existing reserves.

Delivery Commitments

We have contractually agreed to deliver firm quantities of gas and NGLs to various customers, which we expect to fulfill with production from existing reserves.

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Thereafter 1,811 27,380

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 Mountain Valley Pipeline capacity for up to ten years beginning in 2027.

The firm sales agreements are subject to currently unsatisfied conditions related to the in-service dates of the Mountain Valley Pipeline and Transco Southeast Supply Enhancement;

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;

therefore, their impact has been excluded from the schedule of total gross commitments in the table above.

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months.

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.

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

Gathering Customers

Our Gathering segment has gathering agreements with our 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.

As of December 31, 2024, our gathering system had total contracted firm reservation capacity, including contracted MVCs, of approximately 7.5 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.

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.

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.

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

As of December 31, 2024, approximately 99% of our Transmission segment's contracted firm transmission capacity was subscribed under negotiated rate agreements.

As of December 31, 2024, our Transmission segment had minimal contracted firm transmission capacity subscribed at discounted rates and recourse rates.

See also "Regulation" below and Part I, "Item 1A.

Risk Factors – A substantial majority of the services we provide on our transmission and storage systems are subject to long-term, fixed-price 'negotiated rate' contracts that are subject to limited or no adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts, we could be unable to achieve the expected investment return under such contracts, and/or our business, financial condition, results of operations, and cash flows could be adversely affected." for additional information.

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.

Seasonal anomalies such as mild winters or summers may also affect demand.

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Our competitors include independent oil and gas companies, major oil and gas companies, individual producers, operators and marketing companies and other energy companies that produce substitutes for the commodities that we produce.

Competitors for our natural gas gathering business include companies that own major natural gas pipelines, independent gas gatherers and integrated energy companies, including natural gas producers that develop or acquire their own gathering system.

When compared to us, some of our competitors have operations in multiple natural gas producing basins, greater capital resources and access to, or control of, larger natural gas supplies.

Competition for our natural gas transmission and storage business is based primarily on rates, customer commitment levels, timing, performance, commercial terms, reliability, service levels, location, reputation and fuel efficiencies.

Our principal competitors include companies that own major natural gas pipelines in the Appalachian Basin.

In addition, we compete with companies that are building high-pressure gathering facilities that are able to transport natural gas to interstate pipelines without being subject to FERC jurisdiction.

Regulation of our Operations.

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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 used for our own produced natural gas and NGLs 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 environmental 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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various recordkeeping and reporting requirements for air permits and waste management practices;

compliance with safety regulations, including regulations by the Department of Transportation's Pipeline and Hazardous Materials Safety Administration;

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

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

and siting and noise regulations for compressor stations.

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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.

This regulatory framework has significantly increased the costs of entering into derivatives transactions for end-users of derivatives, such as ourselves.

This regulatory framework has significantly increased the costs of entering into derivatives transactions for end-users of derivatives, such as us.

In particular, new margin requirements and capital charges, even when not directly applicable to us, have increased the pricing of derivatives that we transact in.

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Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production.

The FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978.

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 over $1.5 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 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 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.

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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However, the natural gas industry historically has been very heavily regulated;

therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by the FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas-related activities.

Under the FERC's current regulatory regime, transportation services must be provided on an open-access, nondiscriminatory basis at cost-based rates or negotiated rates, both of which are subject to FERC approval.

The FERC also allows jurisdictional natural gas pipeline companies to charge market-based rates if the transportation market at issue is sufficiently competitive.

Gathering service, which occurs upstream of FERC-jurisdictional transmission services, is regulated by the states onshore and in state waters.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC as a natural gas company under the NGA.

Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC's determinations as to the classification of facilities are done on a case-by-case basis.

To the extent that the FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, and, depending on the scope of that decision, our costs of transporting natural gas to point of sale locations may increase.

We believe that the third-party natural gas pipelines on which our gas is gathered meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to regulation as a natural gas company.

However, the distinction between the FERC-regulated transportation services and federally unregulated gathering services could be subject to potential litigation, and the classification and regulation of those gathering facilities are subject to change based on future determinations by the FERC, the courts or Congress.

State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements.

Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Our FERC-regulated operations are pursuant to tariffs approved by the FERC that establish rates (other than market-based rate authority), cost recovery mechanisms and terms and conditions of service to customers.

Generally, the FERC's authority extends to rates and charges for:

our natural gas transmission and storage services;

certification and construction of new interstate transmission and storage facilities;

abandonment of interstate transmission and storage services and facilities;

maintenance of accounts and records;

relationships between pipelines and certain affiliates;

terms and conditions of services and service contracts with customers;

depreciation and amortization policies;

acquisitions and dispositions of interstate transmission and storage facilities;

and initiation and discontinuation of interstate transmission and storage services.

Unless market-based rates have been approved by the FERC, the maximum applicable recourse rates and terms and conditions for service are set forth in the pipeline's FERC-approved tariff.

Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of providing service, including the recovery of a return on the pipeline's actual and prudent historical investment costs.

Key determinants in the ratemaking process include the depreciated capital costs of the facilities, the costs of providing service, the allowed rate of return and income tax allowance, as well as volume throughput and contractual capacity commitment assumptions.

Interstate pipelines may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust or unreasonable, unduly discriminatory or preferential.

Rate design and the allocation of costs also can affect a pipeline's profitability.

While the ratemaking process establishes the maximum rate that can be charged, interstate pipelines, such as our transmission and storage system, are permitted to discount their firm and interruptible rates without further FERC authorization down to a specified minimum level, provided they do not unduly discriminate.

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

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

Rate increases proposed by a pipeline may be allowed to become effective subject to refund and/or a period of suspension, while rates or terms and conditions of service that are the subject of a complaint under Section 5 of the NGA are subject to prospective change by the FERC.

Rate increases proposed by a regulated interstate pipeline may be challenged and such increases may ultimately be rejected by the FERC.

Our interstate pipeline may also use negotiated rates that could involve rates above or below the recourse rate or rates that are subject to a different rate structure than the rates specified in our interstate pipeline tariffs, provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement.

A prerequisite for allowing the negotiated rates is that negotiated rate customers must have had the option to take service under the pipeline's recourse rates.

As of December 31, 2024, approximately 99% of our system's contracted firm transmission capacity was subscribed under negotiated rate agreements under its tariff.

Some negotiated rate transactions are designed to fix the negotiated rate for the term of the firm transportation agreement and the fixed rate is generally not subject to adjustment for increased or decreased costs occurring during the contract term.

The FERC's regulations also extend to the terms and conditions set forth in agreements for transmission and storage services executed between interstate pipelines and their customers.

These service agreements are required to conform, in all material respects, with the form of service agreements set forth in the pipeline's FERC-approved tariff.

Non-conforming agreements must be filed with and accepted by the FERC.

In the event that the FERC finds that an agreement is materially non-conforming, in whole or in part, it could reject, or require us to seek modification of, the agreement, or alternatively require us to modify its tariff so that the non-conforming provisions are generally available to all customers or class of customers.

The FERC's jurisdiction also extends to the certification and construction of new interstate transmission and storage facilities, including, but not limited to, acquisitions, facility replacements and upgrades, expansions, and abandonment of facilities and services.

Prior to commencing construction of new or existing interstate transmission and storage facilities, an interstate pipeline must obtain (except in certain circumstances, such as where the activity is permitted under the FERC's regulations or is authorized under the operator’s existing blanket certificate issued by the FERC) a certificate authorizing the construction, or file to amend its existing certificate, from the FERC.

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

The formal comment period in this proceeding closed 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).

The formal comment period closed in May 2021.

In February 2022, the FERC issued an Updated Certificate Policy Statement and an interim greenhouse gas (GHG) policy.

In March 2022, the FERC issued an order suspending the effectiveness of the Updated Certificate Policy Statement and the interim GHG policy.

In January 2025, the FERC terminated the interim GHG policy proceeding, stating that GHG-related considerations are better considered on a case-by-case basis in individual proceedings;

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

There is a possibility that Congress could pass legislation revising the NGA or other statutes that may impact our existing facilities and operations or the ability to construct new facilities.

Potential areas of revision include, but are not limited to, (i) amending Section 5 of the NGA to allow the FERC to require a pipeline to make refunds from the date that a NGA Section 5 complaint was filed with the FERC if rates are later found to be unjust and unreasonable;

(ii) amending Section 7 of the NGA affecting the ability of companies to exercise eminent domain;

and (iii) amending Section 19(b) of the NGA to provide the FERC additional time to act on requests for rehearing.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC under the NGA.

While the FERC does not generally regulate the rates and terms of service over facilities determined to be performing a natural gas gathering function, it has traditionally regulated rates charged by interstate pipelines for gathering services performed on the pipeline's own gathering facilities when those gathering services are performed in connection with jurisdictional interstate transmission services.

We believe that our high-pressure gathering systems meet the traditional tests the FERC has used to establish a pipeline's status as an exempt gatherer not subject to regulation as a jurisdictional natural gas company.

However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is often the subject of litigation in the industry, so the classification and regulation of these systems are subject to change based on future determinations by the FERC, the courts or Congress.

Oil and NGLs Price Controls and Transportation Rates.

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Our sales of these commodities are, however, subject to laws and regulations issued by the FTC prohibiting manipulative or fraudulent conduct in the wholesale petroleum market.

The FTC holds substantial enforcement authority under these regulations, including the ability to assess civil penalties of almost $1.5 million per day per violation.

The FTC holds substantial enforcement authority under these regulations, including the ability to assess civil penalties of more than $1.5 million per day per violation.

Our sales of these commodities, and any related hedging activities, are also subject to CFTC oversight and enforcement authority as discussed above.

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In January 2022, the FERC issued an order on rehearing, lowering the index level and directing oil pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022 to ensure compliance with the new index level.

In July 2024, the U.S.

Court of Appeals for the District of Columbia Circuit 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.

Environmental, Health and Safety Regulations.

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The final rule eliminated the "significant nexus" test from consideration when determining federal jurisdiction and clarified that the CWA only extends to relatively permanent bodies of water and wetlands that have a continuous surface connection with such bodies of water.

Roughly half of the states and other plaintiffs are challenging the September 2023 rule, and the EPA and the Corps are using the pre-2015 definition of WOTUS in these states while litigation continues.

In addition, in an April 2020 decision further defining the scope of the CWA, the U.S.

Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit.

The Court rejected the EPA and the Corps' assertion that groundwater should be totally excluded from the CWA.

In November 2023, the EPA issued draft guidance describing the information that should be used to determine which discharges through groundwater may require a permit.

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.

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.

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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.

The Sackett decision may also have effects on the implementation of Water Quality Certifications (WQCs) under Section 401 of the CWA.

Section 401 requires that any activity that may result in a discharge to WOTUS must first receive a Section 401 WQC before a federal agency may issue a permit for that activity.

A WQC is typically issued by the state where the discharge originates, or by the EPA itself in areas where a state or tribe does not have authority.

In 2020, the EPA finalized a series of changes to the CWA regulations governing the WQC process, largely curtailing state and tribal authority over WQCs.

In September 2023, the EPA published a final rule that restores state and tribal authority to review requests for WQCs and imposes additional requirements on the WQC process.

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

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.

Accordingly, future implementation and enforcement of the final rule is uncertain.

If certain elements of the final rule remain in effect, we could face increased costs and delays with respect to obtaining permits for pipeline crossings and other activities in jurisdictional and non-jurisdictional waters.

Nationwide Permits (NWPs) are issued by the Corps under the CWA and the Rivers and Harbors Act of 1899 and act as a type of general permit to minimize delays and paperwork for certain activities and discharges in federal jurisdictional waters and wetlands.

NWPs are typically reviewed and reissued (or modified) every five years.

One such permit, NWP 12, authorizes certain "Oil or Natural Gas Pipeline Activities" and was most recently modified and reissued in January 2021.

In March 2022, the Corps initiated an early review of NWP 12 to determine whether any future actions may be appropriate to modify NWP 12 prior to its expiration in 2026.

The Corps solicited public and stakeholder comments through public meetings held in May 2022, but has not provided any additional updates on the status of its review.

However, in January 2025, President Trump issued an executive order instructing the Corps to use emergency authorities and NWPs to grant approvals for energy projects under Section 404 of the CWA.

As a result, any future revisions to NWPs, including NWP 12, are uncertain at this time.

To the extent future revisions to NWP 12 or litigation relating to such revisions modify its provisions with respect to oil and natural gas pipeline activities, we could face increased costs and delays with respect to obtaining permits for certain activities in jurisdictional waters, including wetlands.

Air Emissions.

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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, 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.

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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Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with applicable compliance dates under state plans.

The final rule gives states two years to develop and submit their plans for reducing methane from existing sources.

Subpart OOOOc then provides three years from the plan submission deadline for existing sources to comply.

The final rule gives states until March 2026 to develop and submit their plans for reducing methane from existing sources.

Subpart OOOOc then provides until 2029 for existing sources to comply.

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

The final rule is subject to ongoing litigation 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.

Consequently, future implementation and enforcement of the final rule remains uncertain at this time.

As a result of these regulatory changes, the scope of any final air emissions regulations or the costs for complying with such regulations are uncertain.

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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.

National Environmental Policy Act (NEPA) .

NEPA establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies.

A major federal agency action with the potential to significantly impact the environment requires review under NEPA.

Some activities are subject to robust NEPA review, which could lead to delays and increased costs that could materially adversely affect our revenues and results of operations.

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.

The Phase I final rule generally restores certain regulatory provisions that were in effect prior to the 2020 rule, affecting the assessment of projects ranging from oil and gas leasing to development on public and Native American lands.

Additionally, in September 2023, the Biden Administration announced that federal agencies will be directed to consider the social cost of carbon in agency budgeting, procurement and other agency decisions, including in environmental reviews conducted pursuant to NEPA, where appropriate.

In May 2024, CEQ finalized the Phase II rule, which generally restores certain mitigation language from the pre-2020 version of the NEPA regulations, proposes further revisions and meets environmental, environmental justice and climate change objectives.

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

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.

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;

(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.

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.

Although the agreement does not create any binding obligations for nations to limit their greenhouse gas (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 – 52% (compared to 2005 levels) by 2030.

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

Since its formal launch at COP26, over 150 countries have joined the Global Methane Pledge, and at COP27, the Biden Administration 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 November 2023, the European Union reached a provisional political agreement on a regulation to track and reduce methane emissions in the energy sector.

The regulation introduces new requirements for the oil and gas sectors to measure, report and verify methane emissions and implements mitigation measures to avoid such emissions.

The regulation also introduces new global monitoring tools to ensure transparency on methane emissions from imports of oil, gas and coal into the European Union.

Monitoring, reporting and verification measures will be required to be applied by exporters to the European Union by January 1, 2027 and "maximum methane intensity values" must be met by 2030.

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.

Most recently, at COP28, President Biden announced the EPA's final standards to reduce methane emissions from existing oil and gas sources.

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.

The goals of the agreement, among other things, are to accelerate efforts towards the phase-down of unabated coal power, phase out inefficient fossil fuel subsidies, and take other measures that drive the transition away from fossil fuels in energy systems.

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.

In recent years, the U.S.

Congress has considered legislation to reduce GHG emissions.

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.

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 particular, 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 reduction program known as the Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems.

This program requires the EPA to impose a fee known as a "waste emissions charge" on methane emissions from certain natural gas and oil facilities that are in excess of a specified threshold.

In January 2024, the EPA proposed a rule implementing the IRA's methane emissions charge.

The methane 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 proposed rule includes potential methodologies for calculating the amount by which a facility's reported methane emissions are below or exceed the waste emissions thresholds and contemplates approaches for implementing 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.

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

Further, in July 2023, the EPA proposed to expand the scope of the Greenhouse Gas Reporting Program for petroleum and natural gas systems (Subpart W), as required by the IRA.

Among other things, the proposed 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, which may result in an increase in reported methane and other GHG emissions under Subpart W for many operators, including us.

The rule is currently scheduled to be finalized in the spring of 2024 and would take effect on January 1, 2025 in advance of the deadline for reporting emissions for calendar year 2024 under Subpart W.

Furthermore, in May 2023, the EPA issued proposed carbon emission limits and guidelines for new, modified, reconstructed and existing fossil fuel-fired (i.e., coal, oil and gas-fired) power plants.

The proposed rule purports to reflect the best system of emissions reduction and use of technology-based improvements, including carbon capture and sequestration and low-GHG hydrogen.

The proposed rule also revises the NSPS for new fossil fuel-fired stationary combustion turbine units and existing fossil fuel-fired steam generating electric generating units (EGUs), proposes new GHG emissions guidelines for existing fossil fuel-fired steam generating EGUs and for existing large, frequently operated stationary combustion turbines.

The proposed rule requires states to submit plans for the establishment, implementation, and enforcement of performance standards for existing sources to the EPA within 24 months of the effective date of the emission guidelines, and compliance deadlines for stationary sources begin by 2030 for existing steam generating units, and 2032 or 2035 for existing combustion turbine units, depending on their subcategory.

A supplemental notice of proposed rulemaking was issued in November 2023, which requested comments on the EPA's initial regulatory flexibility analysis of the rule (particularly reliability concerns raised by small businesses and other commenters), and a final rule is anticipated by April 2024.

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.

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).

Among other things, the final rule (the Subpart W Revisions Rule) expands the emissions events that are subject to reporting requirements to include "other large release events" and applies reporting requirements to certain new sources and sectors.

The emissions reported under the Greenhouse Gas Reporting Program will be the basis for any payments under the Methane Emissions and Waste Reduction Incentive Program in the IRA, and the Subpart W Revisions Rule may result in an increase in reported methane and other GHG emissions under Subpart W for many operators.

The Subpart W Revisions Rule took effect in January 2025.

Furthermore, in May 2024, the EPA published final rules for carbon emission limits and guidelines for new, modified, reconstructed and existing fossil fuel-fired (i.e., coal, oil and gas-fired) power plants.

The rules purport to reflect the best system of emissions reduction and use of technology-based improvements, including carbon capture and sequestration and low-GHG hydrogen.

The rules also revise the NSPS for new fossil fuel-fired stationary combustion turbine units and existing fossil fuel-fired steam generating electric generating units (EGUs), create new GHG emissions guidelines for existing fossil fuel-fired steam generating EGUs and for existing large, frequently operated stationary combustion turbines.

The rules require states to submit plans for the establishment, implementation, and enforcement of performance standards for existing sources to the EPA within 24 months of the effective date of the emission guidelines, and compliance deadlines for stationary sources begin by 2030 for existing steam generating units, and 2032 or 2035 for existing combustion turbine units, depending on their subcategory.

A coalition of 25 states, energy companies, utilities and fossil fuel industry groups immediately challenged the rules in federal court.

In October 2024, the U.S.

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

However, 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.

Additionally, a number of U.S.

state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of carbon taxes, policies and incentives, and cap-and-trade programs.

In October 2019, then-Pennsylvania Governor Tom Wolf signed an Executive Order directing the Pennsylvania Department of Environmental Protection to draft regulations establishing a cap-and-trade program with the intent of enabling Pennsylvania to join the Regional Greenhouse Gas Initiative (RGGI), a multi-state regional cap-and-trade program comprised of several Eastern U.S.

In October 2019, then-Pennsylvania Governor Wolf signed an Executive Order directing the Pennsylvania Department of Environmental Protection to draft regulations establishing a cap-and-trade program with the intent of enabling Pennsylvania to join the Regional Greenhouse Gas Initiative (RGGI), a multi-state regional cap-and-trade program comprised of several Eastern U.S.

Pennsylvania became a member of RGGI in April 2022;

however, since joining RGGI, Pennsylvania's membership has been the subject of various legal challenges.

Most recently, in November 2023, the Pennsylvania Commonwealth Court held that the state's participation in RGGI is unconstitutional, and funds raised by the state through its participation in RGGI constitute an invalid tax, which ruling has been appealed.

In November 2023, the Pennsylvania Commonwealth Court held that the state's participation in RGGI is unconstitutional, and funds raised by the state through its participation in RGGI constitute an invalid tax, which ruling was appealed in December 2023 to the Supreme Court of Pennsylvania.

In March 2024, Pennsylvania Governor Shapiro unveiled a proposal to adopt a carbon pricing program similar to RGGI and stated that he would pull Pennsylvania out of RGGI if the state legislature enacts his proposal.

In 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, the SEC issued a proposed rule in March 2022 that would mandate extensive disclosure of climate-related data, risks, and opportunities, including financial impacts, physical and transition risks, related governance and strategy, and GHG emissions, for certain public companies.

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.

Any legislation or regulatory programs at the international, federal, state or city 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.

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.

However, 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 lower the value of our reserves.

Further, recent activism directed at shifting funding away from fossil fuel companies could result in limitations or restrictions on certain sources of funding for the sector.

Further, the U.S.

Supreme Court's decision in Loper Bright Enterprises v.

Raimondo to overrule Chevron U.S.A.

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.

Further, activism directed at shifting funding away from fossil fuel companies could result in limitations or restrictions on certain sources of funding for the sector.

Moreover, activist shareholders have introduced proposals to certain companies seeking to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities.

While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult to engage in exploration and production activities.

While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult to engage in our operations.

Finally, it should be noted that 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.

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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.

The final rule took effect in June 2024.

However, in May 2024, the states of North Dakota, Texas, Montana, Wyoming and Utah challenged the rule.

In September 2024, the U.S.

District Court for the District of North Dakota granted a motion prohibiting the BLM from enforcing the rule against those states pending the outcome of the litigation.

Consequently, future implementation and enforcement of the final rule remains uncertain at this time.

Pipeline Safety and Maintenance Regulations.

Our interstate natural gas pipeline system and natural gas storage assets are subject to regulation by the PHMSA.

The PHMSA has established safety requirements pertaining to the design, installation, testing, construction, operation and maintenance of gas pipeline and storage facilities, including requirements that pipeline and storage operators develop a written qualification program for individuals performing covered tasks on pipeline facilities and implement pipeline and storage well integrity management programs.

These integrity management plans require more frequent inspections and other preventive measures to ensure safe operation of oil and natural gas transportation pipelines and storage facilities in high population areas or facilities that are hard to evacuate and areas of daily concentrations of people.

Notwithstanding the investigatory and preventative maintenance costs incurred in our performance of customary pipeline and storage management activities, we may incur significant additional expenses if anomalous pipeline or storage conditions are discovered or more stringent safety requirements are implemented.

For example, in April 2016, the PHMSA published a notice of proposed rulemaking addressing several integrity management topics and proposing new requirements to address safety issues for natural gas transmission and gathering lines, along with certain storage facilities (the Mega Rule).

The PHMSA intended the Mega Rule to strengthen existing integrity management requirements, expand assessment and repair requirements to pipelines in areas with medium population densities, and extend regulatory requirements to onshore gas gathering lines that are currently exempt.

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.

In addition, the 2016 Pipeline Safety Act empowered the PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing and also required the PHMSA to develop new safety standards for natural gas storage facilities by June 2018.

Pursuant to those provisions of the 2016 Pipeline Safety Act, the PHMSA issued a final rule effective December 2, 2019 that expanded the agency's authority to impose emergency restrictions, prohibitions and safety measures and issued a final rule effective March 13, 2020 that strengthened the rules related to underground natural gas storage facilities, including well integrity, wellbore tubing and casing integrity.

The PHMSA has also published five final rules on pipeline safety applicable to us:

"Enhanced Emergency Order Procedures;" "Safety of Gas Transmission Pipelines:

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

and "Safety of Gas Gathering Pipelines:

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

and "Safety of Gas Transmission Pipelines:

Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments" (also known as the Mega Rule Part III);

and “Pipeline Safety:

Requirement of Valve Installation and Minimum Rupture Detection Standards” (the valve rule).

The Enhanced Emergency Order Procedures rule, which became effective on December 2, 2019, implements an existing statutory authorization for the PHMSA to issue emergency orders related to pipeline safety if an unsafe condition or practice, or a combination of unsafe conditions and practices, constitutes, or is causing an imminent hazard.

Mega Rule Part I, which went into effect on July 1, 2020, requires operators of certain gas transmission pipelines that have been tested or that have inadequate records to determine the material strength of their lines by reconfirming the Maximum Allowable Operating Pressure (MAOP), and establishes a new Moderate Consequence Area for determining regulatory requirements for gas transmission pipeline segments outside of high consequence areas.

The rule also establishes new requirements for conducting baseline assessments, incorporates into the regulations industry standards and guidelines regarding design, construction and in-line inspections (ILI), and new requirements for data integration and risk analysis in integrity management programs, including seismicity, manufacturing and construction defects, and crack and crack-like defects, and includes several requirements that allow operators to notify the PHMSA of proposed alternative approaches to achieving the objectives of the minimum safety standards.

Mega Rule Part II, which was finalized in November 2021 and went into effect on May 16, 2022, extends existing design, operational and maintenance, and reporting requirements to onshore natural gas gathering pipelines in rural areas.

The rule requires operators of onshore gas gathering pipelines to report incidents and file annual reports (with the first annual reports submitted in Spring 2023) and creates new safety requirements that vary based on pipeline diameter and potential consequences of a failure.

Mega Rule Part III, which was finalized in August 2022, went into effect on May 24, 2023.

The rule requires operators of certain transmission pipelines to assess their integrity management practices and comply with enhanced corrosion control and mitigation timelines.

It also establishes new requirements for pipeline inspections following an extreme weather event or natural disaster and provides enhanced guidance for pipeline repairs.

The valve rule requires the installation of remote operated rupture mitigation valves on new or entirely replaced transmission and storage lines when valves are installed to meet valve spacing requirements.

In addition, the valve rule includes requirements for operator actions to be taken when notified of a potential rupture that include notifying emergency response agencies and closing valves within a specified timeframe.

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.

For example, Mega Rule Part I requires MAOP reconfirmation of certain previously untested transmission pipeline segments, which are commonly referred to as ‘‘grandfathered’’ pipelines.

Our grandfathered pipeline MAOP reconfirmation efforts, which we have initiated, may result in unanticipated testing and/or replacement costs.

When reconfirming MAOP on certain of our grandfathered pipeline segments we may be required to remove portions of pipelines for testing, shut in certain pipelines, and/or may face significant operational or technical challenges when performing either a pressure test or an ILI examination, which could result in substantial costs related thereto, or to repairs, remediation, or replacing existing pipelines, and/or other mitigating actions that may be determined to be necessary as a result of the tests, as well as lost cash flows resulting from shutting down our pipelines during the pendency of any such actions, which could be material to our capital expenditures, earnings and competitive position.

Additionally, ensuring complete compliance with the applicable Mega Rule compliance deadlines may cause us to incur significant additional expenses if anomalous pipeline conditions are discovered.

States are generally preempted by federal law in the area of pipeline safety, but state agencies may qualify to assume responsibility for enforcing federal regulations over intrastate pipelines.

They may also promulgate additive pipeline safety regulations provided that the state standards are at least as stringent as the federal standards.

Although many of our natural gas facilities fall within a class that is not subject to integrity management requirements, we may incur significant costs and liabilities associated with repair, remediation, preventive or mitigation measures associated with our non-exempt transmission pipelines.

The costs, if any, for repair, remediation, preventive or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of any such actions, could be material to our capital expenditures, earnings and competitive position.

Should we fail to comply with U.S.

Department of Transportation regulations adopted under authority granted to the PHMSA, we could be subject to penalties and fines.

The PHMSA has the statutory authority to impose civil penalties for pipeline safety violations 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.

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.

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.

We have not incurred and do not anticipate incurring material capital expenditures in connection with complying with the PIPES Act.

Occupational Safety and Health Act.

We are also 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.

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.

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In June and July 2022, the FWS issued final rules rescinding the regulations defining "habitat" and governing critical habitat exclusions.

In June 2023, the FWS issued three proposed rules governing interagency cooperation, listing species and designating critical habitat, and expanding protection options for species listed as threatened pursuant to the ESA.

The final rules are expected by April 2024.

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.

This prohibition covers most bird species in the U.S.

In January 2021, the Department of the Interior finalized a rule limiting application of the MBTA;

however, the Department of the Interior revoked the rule in October 2021 and 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 proposed rule was anticipated in November 2023, with final action expected by April 2024, but the FWS instead announced in November 2023 that it had received additional technical comments that need further review.

Future implementation of the rules impacting the ESA and the MBTA are uncertain.

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.

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.

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Human Capital Resources

As of December 31, 2023, we had 881 employees (excluding temporary employees and contractors), none of whom were subject to a collective bargaining agreement.

As of December 31, 2024, we had 1,461 full-time equivalent employees (i.e., excluding temporary employees and contractors), none of whom were subject to a collective bargaining agreement.

Of our employee base, 77% are male and 23% are female.

Approximately 64% of our employees work remotely, with 94% residing in Pennsylvania, Texas or West Virginia.

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

We aim to develop a workforce that produces peer-leading results.

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Except as specifically incorporated by reference into this Annual Report on Form 10-K, information on those websites is not part hereof.

Composition of Operating Revenues

The following table presents total operating revenues for each class of our products and services.

Years Ended December 31,

2023 2022 2021

Operating revenues:

Sales of natural gas, natural gas liquids and oil $ 5,044,768 $ 12,114,168 $ 6,804,020

Gain (loss) on derivatives 1,838,941 (4,642,932) (3,775,042)

Net marketing services and other 25,214 26,453 35,685

Total operating revenues $ 6,908,923 $ 7,497,689 $ 3,064,663

Jurisdiction and Year of Formation

1 unchanged sentence

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