What changed in this filing

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Item 2. Management’s Discussion and Analysis

2026-04-29 compared with 2025-10-29 · 148 added, 324 removed, 211 unchanged (69% of the section changed)

12 unchanged sentences

Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to develop our reserves and production, primarily on our existing multi-year inventory of drilling locations in the Appalachian Basin.

As of September 30, 2025, we held approximately 528,000 net acres in the Appalachian Basin.

As of March 31, 2026, we held approximately 855,000 net acres in the Appalachian Basin.

HG Acquisition

On December 5, 2025, we entered into a definitive agreement to acquire 100% of the issued and outstanding equity interests of HG Production for total cash consideration of $2.8 billion, subject to the terms and conditions thereof.

The HG Acquisition included approximately 385,000 net acres in the core of the Marcellus Shale in West Virginia.

This acquisition closed on February 3, 2026.

The HG Acquisition was funded with borrowings under the Term Loan, net proceeds of the 2036 Notes, borrowings under the Credit Facility and restricted cash.

See Note 3—Transactions to our unaudited condensed consolidated financial statements for additional information.

The Company’s condensed consolidated statement of operations for the three months ended March 31, 2026 included results of operations from the assets and operations acquired in the HG Acquisition from February 3, 2026 through March 31, 2026.

In light of the nature and location of the assets and operations acquired in the HG Acquisition, we and Antero Midstream agreed in principle to certain updates to, and intend to modify, our existing commercial arrangements to provide for on-pad compression with respect to certain wells and to provide certain water services.

See Note 15—Related Parties to our unaudited condensed consolidated financial statements for additional information.

Utica Shale Divestiture

On December 5, 2025, we entered into a purchase and sale agreement with the Buyer Parties to sell our Utica Shale Properties for aggregate cash consideration of $800 million, subject to the terms and conditions thereof.

The Utica Shale Properties included approximately 80,000 gross (70,000 net) acres located in Ohio and proved reserves of approximately 600 Bcfe as of December 31, 2025.

The Utica Shale Divestiture closed on February 23, 2026, with an effective date of July 1, 2025.

The net proceeds from the Utica Shale Divestiture were used for the repayment of long-term debt.

See Note 3—Transactions to our unaudited condensed consolidated financial statements for additional information.

Financing Highlights

Credit Facility Maturity Date Extension

Effective July 30, 2025, we obtained the consent of each of the lenders under our Unsecured Credit Facility to extend the Maturity Date from July 30, 2029 to July 30, 2030.

The terms of the Unsecured Credit Facility otherwise remain unchanged.

Under the terms of the Unsecured Credit Facility, we may request two one-year extensions of the Maturity Date, subject to the satisfaction of certain conditions.

This is the first such extension.

Debt Repurchase Program

During the nine months ended September 30, 2025, we redeemed the remaining $97 million aggregate principal amount of our 2026 Notes at a redemption price of 102.094% of the principal amount thereof, plus accrued and unpaid interest.

In addition, we repurchased $42 million aggregate principal amount of our 2029 Notes through open market transactions at a weighted average price of approximately 103% of the principal amount thereof, plus accrued and unpaid interest.

See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for additional information.

Share Repurchase Program

During 2022, our Board of Directors authorized a share repurchase program that allows us to repurchase up to $2.0 billion of outstanding common stock.

Through our share repurchase program, during the three and nine months ended September 30, 2025, we repurchased and retired approximately 1.5 million and 4 million shares of our common stock, respectively, at a total cost of $51 million and $136 million, respectively.

As of September 30, 2025, we have approximately $915 million of capacity remaining under our share repurchase program.

The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws.

The timing, as well as the number and value of shares repurchased under the program, will be determined by us at our discretion and will depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements.

Issuance of 2036 Notes

On January 28, 2026, we issued $750 million of 5.400% senior notes due February 1, 2036 at a price of 99.869% of par.

The 2036 Notes are unsecured and rank pari passu to our Credit Facility, Term Loan and other outstanding senior notes.

The 2036 Notes are not guaranteed by any of our subsidiaries.

The net proceeds from this offering were used to partially fund the HG Acquisition.

See Note 3—Transactions and Note 7—Long-Term Debt to our unaudited condensed consolidated financial statements for additional information.

On February 3, 2026, substantially concurrently with the consummation of the HG Acquisition, we entered into an unsecured three year term loan facility in an aggregate principal amount of $1.5 billion with the lenders party thereto and Royal Bank of Canada, as administrative agent.

Borrowings are unsecured and are not guaranteed by any of our subsidiaries.

On February 3, 2026, we borrowed $1.5 billion in a single borrowing to partially fund the HG Acquisition.

The Term Loan is scheduled to mature on February 3, 2029.

See Note 3—Transactions and Note 7—Long-Term Debt to our unaudited condensed consolidated financial statements for additional information.

Redemption of 2029 Notes

During the three months ended March 31, 2026, we redeemed the remaining $365 million principal amount of the 2029 Notes at 101.271% of the principal amount thereof, plus accrued and unpaid interest, and the 2029 Notes were fully retired on such date.

See Note 7—Long-Term Debt to our unaudited condensed consolidated financial statements for additional information.

Market Conditions and Business Trends

1 unchanged sentence

Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows.

Benchmark prices for natural gas and ethane increased significantly, while benchmark prices for C3+ NGLs and oil decreased during the three and nine months ended September 30, 2025 as compared to the same periods of 2024.

As a result of the higher benchmark natural gas and ethane prices during the three and nine months ended September 30, 2025, we experienced an increase in price realization for natural gas and ethane products, partially offset by the effects of decreased benchmark NGLs and oil prices as compared to the three and nine months ended September 30, 2024.

We monitor the economic factors that impact natural gas, NGLs and oil prices, including domestic and foreign supply and demand indicators, domestic and foreign commodity inventories, the actions of Organization of Petroleum Exporting Countries and other large producing nations and the current conflicts in Ukraine and in the Middle East, among others.

Benchmark prices for natural gas increased significantly, while benchmark prices for ethane and C3+ NGLs decreased and benchmark prices for oil remained relatively consistent during the three months ended March 31, 2026 as compared to the same period of 2025.

As a result of the higher benchmark natural gas prices during the three months ended March 31, 2026, we experienced an increase in price realization for natural gas products, partially offset by the effects of decreased benchmark ethane and C3+ NGLs prices as compared to the three months ended March 31, 2025.

In the current economic environment, we expect that commodity prices for some or all of the commodities we produce could remain volatile.

1 unchanged sentence

However, we use derivative instruments when circumstances warrant to manage our exposure to commodity price risk.

See “—Hedge Position” and Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for additional information on our derivative instruments.

See “—Hedge Position” and Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements for additional information on our derivative instruments.

The following table details the average benchmark natural gas, NGLs and oil prices:

Three Months Ended September 30,

Nine Months Ended September 30,

Three Months Ended March 31,

Henry Hub ($/Mcf) (1)

13 unchanged sentences

In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives.

For the three months ended September 30, 2024 and 2025, 2% and 4%, respectively, of our production was hedged through commodity derivatives.

For the nine months ended September 30, 2024 and 2025, 4% of our production was hedged through commodity derivatives.

Assuming our 2025 and 2026 production is the same as our production in 2024, approximately 8% and 29%, respectively, of our total production for such years is hedged through commodity derivatives.

As of September 30, 2025, the estimated fair value of our commodity derivative contracts was a net liability of $7 million.

See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for additional information.

For the three months ended March 31, 2025 and 2026, 4% and 42%, respectively, of our production was hedged through commodity derivatives, excluding basis swaps.

Assuming our 2026 production is the same as our production in 2025, approximately 54% of our total production for 2026 is hedged through commodity derivatives, excluding basis swaps.

In addition, for the three months ended March 31, 2025 and 2026, zero and 12%, respectively, of our production was hedged with basis swap commodity derivatives.

Assuming our 2026 production is the same as our production in 2025, approximately 20% of our total production for 2026 is hedged with basis swap commodity derivatives.

As of March 31, 2026, the estimated fair value of our commodity derivative contracts was a net asset of $202 million.

See Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements for additional information.

Our consolidated VIE, Martica, previously maintained a portfolio of fixed swap natural gas, NGLs and oil derivatives for the benefit of the noncontrolling interests in Martica.

1 unchanged sentence

During the three months ended March 31, 2025, all of Martica’s derivative contracts expired.

As of September 30, 2025, Martica had no derivative instruments.

See Note 11—Derivative Instruments to the unaudited condensed consolidated financial statements for additional information.

As of March 31, 2026, Martica had no derivative instruments.

See Note 11—Derivative Instruments to our unaudited condensed consolidated financial statements for additional information.

Economic Indicators

The economy experienced elevated inflation levels as a result of global supply and demand imbalances, where global demand outpaced supplies beginning in 2021 and continuing through 2026.

In order to manage the inflation risk present in the United States’ economy, the Federal Reserve utilized monetary policy in the form of interest rate increases beginning in 2022 in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis.

Between 2022 and 2023, the Federal Reserve increased the federal funds interest rate by 5.25%.

During the second half of 2024, inflation rates began to approach the Federal Reserve’s stated goal of 2%, and the Federal Reserve decreased the federal funds rate by 1.75% in 2024 and 2025.

While inflationary pressures in the United States’ economy have begun to subside, it is uncertain what impact recent tariff activity by the United States and foreign governments will have on inflation.

Annual inflation rates have remained generally consistent at approximately 3% since 2023.

The economy also continues to be impacted by the effects of global events.

These events have often caused global supply chain disruptions with additional pressure due to trade sanctions, tariffs, other global trade restrictions and the outbreak of armed conflict, including in the Middle East and Iran, among others.

These events have often caused global supply chain disruptions with additional pressure due to trade sanctions, tariffs, other global trade restrictions and conflicts, including those in the Middle East and Venezuela, among others.

While our supply chain has not experienced any significant interruptions as a result of such events, there can be no assurance that we will not experience interruptions in the future.

3 unchanged sentences

We have three reportable segments:

(i) the exploration, development and production of natural gas, NGLs and oil;

(ii) marketing and utilization of excess firm transportation capacity;

and (iii) midstream services through our equity method investment in Antero Midstream.

exploration and production, our equity method investment in Antero Midstream and marketing.

Revenues from Antero Midstream’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream.

2 unchanged sentences

See Note 16—Reportable Segments to our unaudited condensed consolidated financial statements for additional information.

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2025

Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2026

The operating results of our reportable segments were as follows (in thousands):

Three Months Ended September 30, 2024

Three Months Ended March 31, 2025

Equity Method

6 unchanged sentences

Natural gas liquids sales

Commodity derivative fair value gains

Commodity derivative fair value losses

Gathering, compression and water handling

19 unchanged sentences

(1) Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements.

Three Months Ended September 30, 2025

Three Months Ended March 31, 2026

Equity Method

22 unchanged sentences

Accretion of asset retirement obligations

Loss on sale of assets

Gain on sale of assets

Contract termination, loss contingency, settlements and other operating expenses

6 unchanged sentences

Three Months Ended

September 30,

Production data (1) (2) :

29 unchanged sentences

(3) Average prices reflect the before and after effects of our settled commodity derivatives.

Our calculation of such after effects includes gains (losses) on settlements of commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes.

(4) The average realized price for the three months ended September 30, 2025 includes less than $1 million of proceeds related to a take-or-pay contract.

Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the three months ended September 30, 2025 would have been $11.02 per Bbl.

Our calculation of such after effects includes gains or losses on settlements of commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes.

Natural gas sales .

Revenues from sales of natural gas increased from $426 million for the three months ended September 30, 2024 to $631 million for the three months ended September 30, 2025, an increase of $205 million, or 48%.

Higher commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2025 accounted for an approximate $200 million increase in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes).

Revenues from sales of natural gas increased from $0.8 billion for the three months ended March 31, 2025 to $1.3 billion for the three months ended March 31, 2026, an increase of $0.5 billion, or 68%, primarily due to an additional $178 million of natural gas revenue attributable to the HG Acquisition properties, as well as higher commodity prices and natural gas production volumes between periods.

Higher commodity prices (excluding the effects of derivative settlements) during the three months ended March 31, 2026 accounted for an approximate $367 million increase in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes).

Higher natural gas production volumes accounted for an approximate $164 million increase in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price).

Revenues from sales of NGLs decreased from $504 million for the three months ended September 30, 2024 to $470 million for the three months ended September 30, 2025, a decrease of $34 million, or 7%.

This decrease is primarily due to lower C3+ NGLs commodity prices and production volumes, partially offset by higher ethane commodity prices and production volumes between periods.

Lower C3+ NGLs commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2025 accounted for an approximate $50 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

C3+ NGLs production volumes accounted for an approximate $12 million decrease in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price).

Higher ethane commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2025 accounted for an approximate $24 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Higher ethane production volumes accounted for an approximate $4 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price).

Revenues from sales of oil decreased from $53 million for the three months ended September 30, 2024 to $31 million for the three months ended September 30, 2025, a decrease of $22 million, or 41%.

Lower oil production volumes during the three months ended September 30, 2025 accounted for an approximate $15 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price).

Lower commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2025 accounted for an approximate $7 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Commodity derivative fair value gains.

Our commodity derivatives included fixed price swaps, collars, basis swaps, call options and embedded put options.

Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment.

Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our unaudited condensed consolidated statements of operations and comprehensive income (loss).

For the three months ended September 30, 2024 and 2025, our commodity hedges resulted in derivative fair value gains of $18 million and $39 million, respectively.

For the three months ended September 30, 2024, commodity derivative fair value gains included $4 million of net cash proceeds on settled commodity derivative gains.

For the three months ended September 30, 2025, commodity derivative fair value gains included $2 million of net cash payments for settled derivative losses.

Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled or monetized prior to settlement.

Derivative asset or liability positions at the end of any accounting period may reverse to the extent future commodity prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement.

We expect continued volatility in commodity prices and the related fair value of our derivative instruments in the future.

Amortization of deferred revenue, VPP.

Amortization of deferred revenues associated with the VPP decreased from $7 million for the three months ended September 30, 2024 to $6 million for the three months ended September 30, 2025, a decrease of $1 million, or 7%, primarily due to lower production volumes attributable to the VPP properties between periods.

Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term.

Lease operating expense .

Lease operating expense increased from $30 million, or $0.09 per Mcfe, for the three months ended September 30, 2024 to $32 million, or $0.10 per Mcfe, for the three months ended September 30, 2025, an increase of $2 million primarily due to increased produced water trucking and disposal costs as a result of our completion activity timing during the three months ended September 30, 2025, as well as higher oilfield service and workover costs between periods.

Gathering, compression, processing and transportation expense.

Gathering, compression, processing and transportation expense increased from $685 million for the three months ended September 30, 2024 to $711 million for the three months ended September 30, 2025, an increase of $26 million, or 4%.

This was primarily a result of the following:

● Gathering and compression costs increased from $0.72 per Mcfe for the three months ended September 30, 2024 to $0.73 per Mcfe for the three months ended September 30, 2025, primarily due to increased fuel costs as a result of higher natural gas prices and annual CPI-based adjustments between periods.

● Processing costs increased from $0.88 per Mcfe for the three months ended September 30, 2024 to $0.92 per Mcfe for the three months ended September 30, 2025, primarily due to increased costs for NGLs processing, which includes an annual CPI-based adjustment during the first quarter of 2025 and higher NGLs transportation fees.

● Transportation costs increased from $0.58 per Mcfe for the three months ended September 30, 2024 to $0.60 per Mcfe for the three months ended September 30, 2025, primarily due to higher fuel costs as a result of higher

natural gas prices between periods and higher demand fees for certain pipelines during the three months ended September 30, 2025.

Production and ad valorem tax expense.

Production and ad valorem taxes decreased from $47 million for the three months ended September 30, 2024 to $29 million for the three months ended September 30, 2025, a decrease of $18 million, or 39%, primarily due to lower ad valorem taxes, partially offset by higher severance taxes as a result of increased natural gas prices during the three months ended September 30, 2025.

Production and ad valorem taxes as a percentage of natural gas revenues decreased from 11% for the three months ended September 30, 2024 to 5% for the three months ended September 30, 2025, primarily as a result of lower ad valorem taxes.

West Virginia ad valorem taxes in 2024 were based on commodity prices during 2022, and West Virginia ad valorem taxes in 2025 are based on commodity prices during 2023.

General and administrative expense .

General and administrative expense (excluding equity-based compensation expense) increased from $39 million for the three months ended September 30, 2024 to $41 million for the three months ended September 30, 2025, an increase of $2 million, or 7%, primarily due to higher professional service fees between periods.

General and administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.12 per Mcfe for the three months ended September 30, 2024 to $0.13 per Mcfe for the three months ended September 30, 2025 primarily as a result of higher overall costs between periods .

Equity-based compensation expense .

Non-cash equity-based compensation expense remained consistent at $16 million for the three months ended September 30, 2024 and 2025.

See Note 9—Equity-Based Compensation to the unaudited condensed consolidated financial statements for additional information.

Depletion, depreciation and amortization expense (“DD&A expense”) .

DD&A expense remained consistent at $189 million for each of the three months ended September 30, 2024 and 2025.

DD&A expense per Mcfe also remained relatively consistent for the three months ended September 30, 2024 and 2025 at $0.61 and $0.60, respectively.

Impairment of property and equipment .

Impairment of oil and gas properties remained relatively consistent at $13 million and $12 million for the three months ended September 30, 2024 and 2025, respectively.

During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to place into service.

Contract termination, loss contingency, settlements and other operating expenses .

Contract termination, loss contingency, settlements and other operating expenses was a gain of $1 million for the three months ended September 30, 2024 primarily due to our receipt of 0.1 million shares of Antero Midstream common stock as part of a judgment in a legal proceeding with an unaffiliated third-party.

Contract termination, loss contingency, settlements and other operating expenses was a loss of $13 million for the three months ended September 30, 2025 primarily due to loss contingencies recorded during the third quarter of 2025.

See Note 14—Contingencies to the unaudited condensed consolidated financial statements for additional information.

Marketing Segment

Where feasible, we purchase and sell third-party natural gas and NGLs and market our excess firm transportation capacity, or engage third parties to conduct these activities on our behalf, in order to optimize the revenues from these transportation agreements.

We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure guaranteed capacity to favorable markets.

Net marketing expense remained relatively consistent at $15 million, or $0.05 per Mcfe, for the three months ended September 30, 2024 and $16 million, or $0.05 per Mcfe, for the three months ended September 30, 2025.

Marketing revenue.

Marketing revenue decreased from $47 million for the three months ended September 30, 2024 to $35 million for the three months ended September 30, 2025, a decrease of $12 million, or 26%.

This fluctuation primarily resulted from the following:

● Natural gas marketing revenue decreased by $9 million between periods primarily due to lower natural gas marketing volumes, partially offset by higher natural gas prices.

Lower natural gas marketing volumes accounted for an $11 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher natural gas prices accounted for a $2 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

● Oil marketing revenue decreased by $9 million between periods primarily due to lower oil marketing volumes and prices.

Lower oil marketing volumes accounted for a $5 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower oil prices accounted for a $4 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

● NGLs marketing revenues increased by $5 million for the three months ended September 30, 2025 primarily due to higher C3+ NGLs marketing volumes.

Marketing expense.

Marketing expense decreased from $62 million for the three months ended September 30, 2024 to $51 million for the three months ended September 30, 2025, a decrease of $11 million, or 18%.

Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity.

The costs of third-party natural gas and oil purchases each decreased $9 million between periods, and the cost of third-party NGLs purchases increased $4 million between periods.

The total cost of third-party commodity purchases decreased primarily due to lower marketing volumes between periods, partially offset by higher natural gas prices during the three months ended September 30, 2025.

Firm transportation costs increased $3 million between periods primarily due to higher fuel costs and lower pipeline utilization due to maintenance during the three months ended September 30, 2025.

Antero Midstream Segment

Antero Midstream revenue.

Revenue from the Antero Midstream segment increased from $270 million for the three months ended September 30, 2024 to $295 million for the three months ended September 30, 2025, an increase of $25 million.

This increase is primarily due to higher gathering and processing revenues of $15 million and higher water handling revenues of $10 million.

The increased gathering and processing revenues between periods is primarily a result of increased throughput and annual CPI-based gathering and compression rate adjustments between periods.

The increased water handling revenues between periods is primarily due to higher fresh water delivery volumes during the three months ended September 30, 2025, as well as increased blending volumes, increased wastewater handling costs and an increase to the fresh water delivery rate as a result of an annual CPI-based rate adjustment between periods.

Antero Midstream operating expense.

Total operating expense related to the Antero Midstream segment increased from $107 million for the three months ended September 30, 2024 to $114 million for the three months ended September 30, 2025, an increase of $7 million.

This increase is primarily due to higher direct operating expenses as a result of increased gathering and compression and fresh water delivery volumes between periods, as well as higher heavy maintenance expense and increased wastewater handling costs during the three months ended September 30, 2025.

Items Not Allocated to Segments

Interest expense.

Interest expense decreased from $28 million for the three months ended September 30, 2024 to $18 million for the three months ended September 30, 2025, a decrease of $10 million, or 36%, primarily due to the redemption or repurchase of $139 million aggregate principal amount of our Senior Notes during the nine months ended September 30, 2025 and lower average Credit Facility borrowings and interest rates during the three months ended September 30, 2025.

See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Loss on early extinguishment of debt.

During the three months ended September 30, 2024, we recognized a loss on early debt extinguishment of $1 million related to the amendment and restatement of our senior revolving credit facility.

There was no loss on early extinguishment of debt for the three months ended September 30, 2025.

See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Income tax benefit (expense) .

For the three months ended September 30, 2024, we recognized an income tax benefit of $3 million, with an effective tax rate of 10%, due to a loss before income taxes of $28 million.

For the three months ended September 30, 2025, we recognized income tax expense of $43 million, with an effective tax rate of 34%, due to income before income taxes of $129 million.

The increase in the effective tax rate between periods was primarily due to the effects of noncontrolling interests and stock compensation expense.

See Note 2—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements for additional information on the effects of the OBBB.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2025

The operating results of our reportable segments were as follows (in thousands):

Nine Months Ended September 30, 2024

Equity Method

Investment in

Elimination of

Unconsolidated

Midstream (1)

Revenue and other:

Natural gas sales

Natural gas liquids sales

Commodity derivative fair value gains

Gathering, compression and water handling

Amortization of deferred revenue, VPP

Other revenue and income

Total revenue

Operating expenses:

Lease operating

Gathering and compression

Transportation

Water handling

Production and ad valorem taxes

General and administrative (excluding equity-based compensation)

Equity-based compensation

Depletion, depreciation and amortization

Impairment of property and equipment

Accretion of asset retirement obligations

Gain on sale of assets

Contract termination, loss contingency, settlements and other operating expenses

Total operating expenses

Operating income (loss)

Equity in earnings of unconsolidated affiliates

(1) Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements.

Nine Months Ended September 30, 2025

Equity Method

Investment in

Elimination of

Unconsolidated

Midstream (1)

Revenue and other:

Natural gas sales

Natural gas liquids sales

Commodity derivative fair value losses

Gathering, compression and water handling

Amortization of deferred revenue, VPP

Other revenue and income

Total revenue

Operating expenses:

Lease operating

Gathering and compression

Transportation

Water handling

Production and ad valorem taxes

General and administrative (excluding equity-based compensation)

Equity-based compensation

Depletion, depreciation and amortization

Impairment of property and equipment

Accretion of asset retirement obligations

Loss on sale of assets

Contract termination, loss contingency, settlements and other operating expenses

Total operating expenses

Operating income (loss)

Equity in earnings of unconsolidated affiliates

(1) Amounts reflect those recorded in Antero Midstream’s unaudited condensed consolidated financial statements.

Exploration and Production Segment

The following table sets forth selected operating data of the exploration and production segment:

Nine Months Ended

September 30,

Production data (1) (2) :

Natural gas (Bcf)

C2 Ethane (MBbl)

C3+ NGLs (MBbl)

Combined (Bcfe)

Daily combined production (MMcfe/d)

Average prices before effects of derivative settlements (3) :

Natural gas (per Mcf)

C2 Ethane (per Bbl) (4)

C3+ NGLs (per Bbl)

Oil (per Bbl)

Weighted Average Combined (per Mcfe)

Average realized prices after effects of derivative settlements (3) :

Natural gas (per Mcf)

C2 Ethane (per Bbl) (4)

C3+ NGLs (per Bbl)

Oil (per Bbl)

Weighted Average Combined (per Mcfe)

Average costs (per Mcfe):

Lease operating

Gathering and compression

Transportation

Production and ad valorem taxes

Marketing expense, net

General and administrative (excluding equity-based compensation)

Depletion, depreciation, amortization and accretion

* Not meaningful

(1) Production data excludes volumes related to the VPP.

(2) Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts.

This ratio is an estimate of the equivalent energy content of the products and may not reflect their relative economic value.

(3) Average prices reflect the before and after effects of our settled commodity derivatives.

(4) The average realized price for the nine months ended September 30, 2024 and 2025 includes $2 million and $1 million, respectively, of proceeds related to a take-or-pay contract.

Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the nine months ended September 30, 2024 and 2025 would have been $8.48 per Bbl and $11.66 per Bbl, respectively.

Natural gas sales .

Revenues from sales of natural gas increased from $1.3 billion for the nine months ended September 30, 2024 to $2.1 billion for the nine months ended September 30, 2025, an increase of $0.8 billion, or 65%.

Higher commodity prices (excluding the effects of derivative settlements) during the nine months ended September 30, 2025 accounted for an approximate $0.8 billion increase in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes).

Natural gas production volumes remained relatively consistent between periods.

Revenues from sales of NGLs remained consistent at $1.5 billion for each of the nine months ended September 30, 2024 and 2025.

Higher commodity prices (excluding the effects of derivative settlements) during the nine months ended September 30, 2025 accounted for an approximate $21 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Lower NGLs production volumes accounted for an approximate $20 million decrease in year-over-year NGLs revenues, respectively (calculated as the change in year-to-year volumes times the prior year average price).

Revenues from sales of oil decreased from $181 million for the nine months ended September 30, 2024 to $115 million for the nine months ended September 30, 2025, a decrease of $66 million, or 36%.

Lower oil production volumes during the nine months ended September 30, 2025 accounted for an approximate $45 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price).

Revenues from sales of NGLs decreased from $561 million for the three months ended March 31, 2025 to $504 million for the three months ended March 31, 2026, a decrease of $57 million, or 10%, primarily due to lower commodity prices, partially offset by higher production volumes between periods and $16 million of NGLs revenue attributable to the HG Acquisition properties.

Lower commodity prices (excluding the effects of derivative settlements) during the three months ended March 31, 2026 accounted for an approximate $79 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Higher C3+ production

volumes accounted for an approximate $22 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price).

Revenues from sales of oil decreased from $50 million for the three months ended March 31, 2025 to $47 million for the three months ended March 31, 2026, a decrease of $3 million, or 7%, primarily due to lower oil prices and production volumes, partially offset by $3 million of oil revenue attributable to the HG Acquisition properties.

Lower oil prices, excluding the effects of derivative settlements, accounted for an approximate $2 million decrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes).

Commodity derivative fair value gains.

Our commodity derivatives included fixed price swaps, collars, basis swaps, call options and embedded put options.

Lower oil production volumes accounted for an approximate $1 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price).

Commodity derivative fair value gains (losses).

Our commodity derivatives included fixed price swaps, collars, basis swaps and three-way collars, among others.

Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment.

For the nine months ended September 30, 2024 and 2025, our commodity hedges resulted in derivative fair value gains of $22 million and $21 million, respectively.

For the nine months ended September 30, 2024, commodity derivative fair value gains included $12 million of net cash proceeds for settled derivative gains.

For the nine months ended September 30, 2025, commodity derivative fair value gains included $19 million of net cash payments for settled derivative losses.

For the three months ended March 31, 2025 and 2026, our commodity hedges resulted in derivative fair value losses of $72 million and fair value gains of $35 million, respectively.

For the three months ended March 31, 2025, commodity derivative fair value losses included $11 million of net cash payments for settled derivative losses.

For the three months ended March 31, 2026, commodity derivative fair value gains included $165 million of net cash payments for settled derivative losses.

Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled or monetized prior to settlement.

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Amortization of deferred revenue, VPP.

Amortization of deferred revenues associated with the VPP remained relatively consistent at $20 million and $19 million for the nine months ended September 30, 2024 and 2025, respectively.

Amortization of deferred revenues associated with the VPP remained relatively consistent at $6 million for the three months ended March 31, 2025 and 2026.

Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term.

Lease operating expense .

Lease operating expense increased from $88 million, or $0.09 per Mcfe, for the nine months ended September 30, 2024 to $104 million, or $0.11 per Mcfe, for the nine months ended September 30, 2025, an increase of $16 million primarily due to higher oilfield service and workover costs between periods, as well as increased produced water trucking and disposal costs as a result of our completion activity timing during the nine months ended September 30, 2025.

Lease operating expense increased from $34 million, or $0.11 per Mcfe, for the three months ended March 31, 2025 to $45 million, or $0.13 per Mcfe, for the three months ended March 31, 2026, an increase of $11 million primarily due to incremental lease operating expense of $6 million related to the HG Acquisition properties and higher wastewater trucking and disposal costs due to the timing of well completions activity between periods.

Gathering, compression, processing and transportation expense.

Gathering, compression, processing and transportation expense increased from $2.0 billion for the nine months ended September 30, 2024 to $2.1 billion for the nine months ended September 30, 2025, an increase of $0.1 billion, or 4%.

This fluctuation was primarily a result of the following:

● Gathering and compression costs on a per unit basis increased from $0.72 per Mcfe for the nine months ended September 30, 2024 to $0.75 per Mcfe for the nine months ended September 30, 2025, primarily due to increased fuel costs as a result of higher natural gas prices and annual CPI-based adjustments between periods.

● Processing costs on a per unit basis increased from $0.86 per Mcfe for the nine months ended September 30, 2024 to $0.89 per Mcfe for the nine months ended September 30, 2025, primarily due to increased costs for NGLs processing and transportation, which includes an annual CPI-based adjustment during the first quarter of 2025, and higher NGLs transportation fees between periods.

● Transportation costs on a per unit basis increased from $0.58 per Mcfe for the nine months ended September 30, 2024 to $0.61 per Mcfe for the nine months ended September 30, 2025, primarily due to higher fuel costs as a result of higher natural gas prices between periods and higher demand fees for certain pipelines during the nine months ended September 30, 2025.

Gathering, compression, processing and transportation expense increased from $695 million, or $2.27 per Mcfe, for the three months ended March 31, 2025 to $789 million, or $2.28 per Mcfe, for the three months ended March 31, 2026, an increase of $94 million primarily due to higher production volumes between periods and incremental gathering, compression, processing and transportation expense of $39 million related to the HG Acquisition properties.

The fluctuation of our gathering, compression, processing and transportation expense on a per unit basis was primarily a result of the following:

● Gathering and compression costs on a per unit basis increased from $0.77 per Mcfe for the three months ended March 31, 2025 to $0.78 per Mcfe for the three months ended March 31, 2026, primarily due to increased fuel costs as a result of higher natural gas prices and annual CPI-based adjustments between periods, partially offset by lower gathering and compression expense on a per unit basis for the HG Acquisition properties.

● Processing costs on a per unit basis decreased from $0.85 per Mcfe for the three months ended March 31, 2025 to $0.83 per Mcfe for the three months ended March 31, 2026, primarily due to lower NGLs transportation fees related to the HG Acquisition properties between periods.

● Transportation costs on a per unit basis increased from $0.65 per Mcfe for the three months ended March 31, 2025 to $0.67 per Mcfe for the three months ended March 31, 2026, primarily due to higher fuel costs as a result of higher natural gas prices between periods and higher demand fees for certain pipelines during the three months ended March 31, 2026, partially offset by lower transportation expense on a per unit basis for the HG Acquisition properties.

Production and ad valorem tax expense.

Production and ad valorem taxes decreased from $148 million for the nine months ended September 30, 2024 to $119 million for the nine months ended September 30, 2025, a decrease of $29 million, or 19%, primarily due to lower ad valorem taxes, partially offset by higher severance taxes as a result of increased natural gas prices during the nine months ended September 30, 2025.

Production and ad valorem taxes as a percentage of natural gas revenues decreased from 12% for the nine months ended September 30, 2024 to 6% for the nine months ended September 30, 2025, primarily as a result of lower ad valorem taxes.

West Virginia ad valorem taxes in 2024 were based on commodity prices during 2022, and West Virginia ad valorem taxes in 2025 are based on commodity prices during 2023.

Production and ad valorem taxes increased from $55 million for the three months ended March 31, 2025 to $81 million for the three months ended March 31, 2026, an increase of $26 million, or 46%,

primarily due to higher severance taxes as a result of increased natural gas prices during the three months ended March 31, 2026.

Production and ad valorem taxes as a percentage of natural gas revenues remained relatively consistent at 7% and 6% for the three months ended March 31, 2025 and 2026, respectively.

General and administrative expense .

General and administrative expense (excluding equity-based compensation expense) increased from $121 million for the nine months ended September 30, 2024 to $130 million for nine months ended September 30, 2025, an increase of $9 million, or 8%, primarily due to higher professional service fees and increased salary and wage expense as a result of increased employee headcount between periods.

General and administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.13 per Mcfe for the nine months ended September 30, 2024 to $0.14 per Mcfe for the nine months ended September 30, 2025 primarily as a result of higher overall costs between periods.

General and administrative expense (excluding equity-based compensation expense) increased from $47 million for the three months ended March 31, 2025 to $52 million for the three months ended March 31, 2026, an increase of $5 million, or 9%, primarily due to higher salary and wage expense, software license costs and professional service fees between periods.

General and administrative expense on a per unit basis (excluding equity-based compensation) remained consistent at $0.15 per Mcfe for the three months ended March 31, 2025 and 2026.

Equity-based compensation expense .

Non-cash equity-based compensation expense remained relatively consistent at $49 million and $47 million for the nine months ended September 30, 2024 and 2025, respectively.

Non-cash equity-based compensation expense decreased from $15 million for the three months ended March 31, 2025 to $12 million for the three months ended March 31, 2026, a decrease of $3 million or 23%.

This decrease was primarily due to lower RSU award expense of $3 million between periods.

See Note 9—Equity-Based Compensation to the unaudited condensed consolidated financial statements for additional information.

Depletion, depreciation and amortization expense.

DD&A expense remained relatively consistent at $568 million, or $0.61 per Mcfe, and $563 million, or $0.61 per Mcfe, for the nine months ended September 30, 2024 and 2025, respectively.

DD&A expense increased from $186 million for the three months ended March 31, 2025 to $206 million for the three months ended March 31, 2026, an increase of $20 million, or 11%, primarily due to higher production volumes between periods related to our HG Acquisition properties.

On a per-unit basis, DD&A expense remained relatively consistent at $0.61 per Mcfe and $0.60 per Mcfe for the three months ended March 31, 2025 and 2026, respectively.

Impairment of property and equipment .

Impairment of oil and gas properties increased from $19 million for the nine months ended September 30, 2024 to $24 million for the nine months ended September 30, 2025, primarily due to higher impairments of expiring leases between periods.

During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to place into service.

Contract termination, loss contingency, settlements and other operating expenses .

Contract termination, loss contingency, settlements and other operating expenses increased from $4 million for the nine months ended September 30, 2024 to $25 million for the nine months ended September 30, 2025, an increase of $21 million.

This increase was primarily due to loss contingencies recorded during the nine months ended September 30, 2025.

Impairment of oil and gas properties decreased from $6 million for the three months ended March 31, 2025 to $1 million for the three months ended March 31, 2026, primarily due to lower impairments of expiring leases between periods.

During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to utilize.

Contract termination, loss contingency and settlements .

Contract termination, loss contingency and settlements was a gain of $1 million for the three months ended March 31, 2025.

Contract termination, loss contingency and settlements was a loss of $12 million for the three months ended March 31, 2026 primarily due to loss contingencies and settlements recorded during the first quarter of 2026.

See Note 14—Contingencies to the unaudited condensed consolidated financial statements for additional information.

Gain on sale of assets.

Gain on sale of assets was less than $1 million for the three months ended March 31, 2025.

Gain on sale of assets was $46 million for the three months ended March 31, 2026 primarily due to the Utica Shale Divestiture that closed on February 23, 2026.

See Note 3—Transactions to the unaudited condensed consolidated financial statements for additional information.

Marketing Segment

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We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure guaranteed capacity to favorable markets.

Net marketing expense increased from $48 million, or $0.05 per Mcfe, for the nine months ended September 30, 2024 to $52 million, or $0.06 per Mcfe, for the nine months ended September 30, 2025, primarily due to higher fuel costs and lower pipeline utilization due to maintenance between periods.

Net marketing expense increased from $17 million, or $0.06 per Mcfe, for the three months ended March 31, 2025 to $21 million, or $0.06 per Mcfe, for the three months ended March 31, 2026, primarily due to higher demand fees on certain pipelines and lower pipeline utilization due to maintenance between periods.

M arketing revenue.

Marketing revenue decreased from $145 million for the nine months ended September 30, 2024 to $94 million for the nine months ended September 30, 2025, a decrease of $51 million, or 35%.

Marketing revenue increased from $26 million for the three months ended March 31, 2025 to $42 million for the three months ended March 31, 2026, an increase of $16 million, or 63%.

This fluctuation primarily resulted from the following:

● Natural gas marketing revenue decreased by $19 million between periods primarily due to lower natural gas marketing volumes, partially offset by higher natural gas prices.

Lower natural gas marketing volumes accounted for a $23 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher natural gas prices accounted for a $4 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

● Oil marketing revenue decreased by $44 million between periods primarily due to lower oil marketing volumes and prices.

Lower oil marketing volumes accounted for a $28 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower oil prices accounted for an $16 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

● NGLs marketing revenue increased by $7 million between periods primarily due to higher C3+ NGLs marketing volumes and higher ethane prices.

● Natural gas marketing revenue remained consistent at $1 million for the three months ended March 31, 2025 and 2026.

● Oil marketing revenue increased by $14 million between periods primarily due to higher oil marketing volumes and prices.

Higher oil marketing volumes accounted for a $12 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher oil prices accounted for a $2 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

● NGLs marketing revenue increased by $2 million between periods primarily due to higher ethane marketing volumes and prices for the three months ended March 31, 2026.

Marketing expense.

Marketing expense decreased from $193 million for the nine months ended September 30, 2024 to $146 million for the nine months ended September 30, 2025, a decrease of $47 million, or 24%.

Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related

to current excess firm capacity.

The cost of third-party natural gas and oil purchases decreased $18 million and $42 million between periods, respectively, and the cost of third-party NGLs purchases increased $6 million between periods.

Firm transportation costs increased $7 million between periods primarily due to the increase in fuel costs and lower pipeline utilization due to maintenance during the nine months ended September 30, 2025.

Marketing expense increased from $43 million for the three months ended March 31, 2025 to $63 million for the three months ended March 31, 2026, an increase of $20 million, or 46%.

Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity.

The cost of third-party oil purchases increased $11 million between periods, primarily due to higher oil marketing volumes during the three months ended March 31, 2026.

Firm transportation costs increased $9 million between periods primarily due to lower pipeline utilization as a result of higher pricing in the Appalachian Basin and a pipeline force majeure during the three months ended March 31, 2026.

Antero Midstream Segment

Antero Midstream revenue.

Revenue from the Antero Midstream segment increased from $819 million for the nine months ended September 30, 2024 to $891 million for the nine months ended September 30, 2025, an increase of $72 million.

Revenue from the Antero Midstream segment increased from $291 million for the three months ended March 31, 2025 to $314 million for the three months ended March 31, 2026, an increase of $23 million.

This increase is primarily due to higher gathering and processing revenues of $21 million and higher water handling revenues of $2 million.

The increased gathering and processing revenues between periods is primarily a result of increased throughput and annual CPI-based gathering and compression rate adjustments between periods.

The increased water handling revenues between periods is primarily due to higher wastewater trucking and disposal volumes, increased wastewater trucking and disposal costs that are billed at cost plus 3%, higher fresh water delivery volumes and increased blending cost of service fees and volumes during the nine months ended September 30, 2025, as well as an increase to the fresh water delivery rate as a result of the annual CPI-based rate adjustment between periods.

The increased gathering and processing revenues between periods is primarily due to the HG Acquisition and increased gathering rates as a result of annual CPI-based adjustments.

The increased water handling revenues between periods is primarily due to higher blending cost of service fees, increased volumes and costs for wastewater trucking and disposal volumes, a higher fresh water delivery fee as a result of an annual CPI-based adjustment and fresh water delivery volumes for our acreage acquired in the HG Acquisition that are charged at cost plus 3% during the three months ended March 31, 2026, partially offset by decreased fresh water delivery volumes between periods due to the timing and location of our completions activity.

Antero Midstream operating expense.

Total operating expense related to the Antero Midstream segment increased from $337 million for the nine months ended September 30, 2024 to $347 million for the nine months ended September 30, 2025, an increase of $10 million.

This increase is primarily due to higher direct operating expenses as a result of higher wastewater trucking and disposal costs, increased blending costs, increased fresh water delivery volumes, increased throughput, higher gathering and compression costs for assets acquired during the second quarter of 2024 and increased heavy maintenance expense during the nine months ended September 30, 2025, partially offset by lower depreciation expense associated with Antero Midstream’s program to repurpose underutilized compressor units to expand existing or construct new compressor stations between periods.

Total operating expense related to the Antero Midstream segment increased from $114 million for the three months ended March 31, 2025 to $126 million for the three months ended March 31, 2026, an increase of $12 million.

This increase is primarily due to higher direct operating expenses as a result of increased gathering volumes between periods related to the HG Acquisition and fresh water delivery services on our acreage acquired in the HG Acquisition, as well as increased wastewater trucking and disposal volumes and higher blending costs between periods.

Items Not Allocated to Segments

Interest expense.

Interest expense decreased from $91 million for the nine months ended September 30, 2024 to $62 million for the nine months ended September 30, 2025, a decrease of $29 million or 32%, primarily due to the redemption or repurchase of $139 million aggregate principal amount of our Senior Notes and lower average Credit Facility borrowings and interest rates during the nine months ended September 30, 2025.

Interest expense, net.

Interest expense, net increased from $23 million for the three months ended March 31, 2025 to $37 million for the three months ended March 31, 2026, an increase of $14 million or 58%, primarily due to borrowings under the Term Loan and issuance of the 2036 Notes during the three months ended March 31, 2026, partially offset by the redemption of the 2029 Notes.

See Note 7—Long-Term Debt to our unaudited condensed consolidated financial statements for more information.

Loss on early extinguishment of debt.

During the nine months ended September 30, 2024, we recognized a loss on early debt extinguishment of $1 million related to the amendment and restatement of our senior revolving credit facility.

During the nine months ended September 30, 2025, we recognized a loss on early debt extinguishment of $4 million related to the redemption of the remaining $97 million aggregate principal amount of our 2026 Notes at a redemption price of 102.094% of the principal amount thereof, plus accrued and unpaid interest, and the repurchase of $42 million aggregate principal amount of our 2029 Notes through open market transactions at a weighted average price of approximately 103% of the principal amount thereof, plus accrued and unpaid interest.

See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements for more information.

Income tax expense (benefit) .

For the nine months ended September 30, 2024, we recognized an income tax benefit of $14 million, with an effective tax rate of 18%, related to our loss before income taxes of $79 million.

For the nine months ended September 30, 2025, we recognized income tax expense of $146 million, with an effective tax rate of 24%, related to our income before income taxes of $618 million.

The increase in the effective tax rate between periods was primarily due to the effects of noncontrolling interests and stock compensation expense.

See Note 2—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements for additional information on the effects of the OBBB.

During the three months ended March 31, 2025, we recognized a loss on early debt extinguishment of $3 million primarily related to the redemption of the remaining $97 million aggregate principal amount of our 2026 Notes at a redemption price of 102.094% of the principal amount thereof, plus accrued and unpaid interest.

During the three months ended March 31, 2026, we recognized a loss on early debt extinguishment of $7 million related to the redemption of the remaining $365 million principal amount of our 2029 Notes at 101.271% of the principal amount thereof, plus accrued and unpaid interest.

See Note 7—Long-Term Debt to our unaudited condensed consolidated financial statements for more information.

Transaction expense .

There were no transaction expenses incurred during the three months ended March 31, 2025.

During the three months ended March 31, 2026, we incurred $22 million of transaction expense related to the HG Acquisition.

See Note 3—Transactions to our unaudited condensed consolidated financial statements for more information.

Income tax expense .

For the three months ended March 31, 2025, we recognized an income tax expense of $54 million, with an effective tax rate of 20%, related to our income before income taxes of $274 million.

For the three months ended March 31, 2026, we recognized income tax expense of $146 million, with an effective tax rate of 21%, related to our income before income taxes of $694 million.

Capital Resources and Liquidity

Sources and Uses of Cash

Our primary sources of liquidity have been through net cash provided by operating activities, borrowings under our Credit Facility, issuances of debt and equity securities and additional contributions from our asset sales, including our drilling partnerships .

Our primary sources of liquidity have been through net cash provided by operating activities, borrowings under our Credit Facility and Term Loan, issuances of debt and equity securities and additional contributions from our asset sales, including our drilling partnerships .

Our primary use of cash has been for the exploration, development and acquisition of oil and natural gas properties.

As we develop our reserves, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements.

future success in developing our proved reserves and production will be highly dependent on net cash provided by operating activities and the capital resources available to us.

Based on strip prices as of September 30, 2025, we believe that net cash provided by operating activities and available borrowings under the Credit Facility will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures and commitments and contingencies for at least the next 12 months.

Our future success in developing our proved reserves and production will be highly dependent on net cash provided by operating activities and the capital resources available to us.

Based on strip prices as of March 31, 2026, we believe that net cash provided by operating activities and available borrowings under the Credit Facility will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures and commitments and contingencies for at least the next 12 months.

The following table summarizes our cash flows (in thousands):

Nine Months Ended September 30,

Three Months Ended March 31,

Net cash provided by operating activities

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Net cash provided by (used in) financing activities

Net increase in cash and cash equivalents

Net decrease in cash, cash equivalents and restricted cash

Operating activities.

Net cash provided by operating activities was $571 million and $1.3 billion for the nine months ended September 30, 2024 and 2025, respectively.

Net cash provided by operating activities increased between periods primarily due to higher natural gas revenues, lower ad valorem taxes, lower interest expense and changes in working capital, partially offset by lower oil revenues between periods and higher lease operating, gathering, compression, processing and transportation expenses during the nine months ended September 30, 2025.

Net cash provided by operating activities was $458 million and $859 million for the three months ended March 31, 2025 and 2026, respectively.

Net cash provided by operating activities increased between periods primarily due to higher natural gas revenues and changes in working capital, partially offset by lower NGLs and oil revenues, higher lease operating, gathering, compression, processing, transportation and marketing and production and ad valorem taxes between periods.

Our net operating cash flows are sensitive to many variables, the most significant of which is the volatility of natural gas, NGLs and oil prices, as well as volatility in the cash flows attributable to settlement of our commodity derivatives.

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Investing activities.

Net cash used in investing activities increased from $588 million for the nine months ended September 30, 2024 to $854 million for the nine months ended September 30, 2025, primarily due to asset acquisitions during the third quarter of 2025 of $241 million and increased drilling and leasing activity of $35 million between periods, partially offset by higher proceeds from asset sales and trades of $8 million between periods primarily due to oil and gas property trades during the nine months ended September 30, 2025.

Net cash used in investing activities increased from $208 million for the three months ended March 31, 2025 to $2.3 billion for the three months ended March 31, 2026, primarily due to cash paid for our HG Acquisition of $2.8 billion during the three months ended March 31, 2026, increased drilling activity of $9 million between periods and acquisitions of oil and gas properties during the three months ended March 31, 2026 of $8 million, partially offset by proceeds from the Utica Shale Divestiture of $737 million during the three months ended March 31, 2026 and decreased oil and gas leasing activity of $13 million between periods.

Financing activities.

Net cash provided by financing activities was $17 million for the nine months ended September 30, 2024.

Net cash used in financing activities was $406 million for the nine months ended September 30, 2025.

The increase in net cash used in financing activities between periods is primarily due to higher net repayments on our Credit Facility of $155 million, redemptions and repurchases of $142 million principal amount of our Senior Notes during the nine months ended September 30, 2025, share repurchases of $136 million during the nine months ended September 30, 2025, partially offset by lower payment of debt issuance costs for our Unsecured Credit Facility of $5 million and lower distributions to the noncontrolling interests in Martica of $5 million between periods.

Net cash used in financing activities was $250 million for the three months ended March 31, 2025.

Net cash provided by financing activities was $1.2 billion for the three months ended March 31, 2026.

The increase in net cash provided by financing activities between periods is primarily due to borrowings to fund our HG Acquisition on the Term Loan of $1.5 billion and the issuance of our 2036 Notes of $750 million, partially offset by higher net repayments on our Credit Facility of $277 million between periods, repayments on the Term Loan of $236 million for the three months ended March 31, 2026, higher repayments and redemptions of our senior notes of $252 million between periods, and increased payments of employee tax withholdings for the settlement of equity-based compensation awards of $18 million between periods.

2026 Capital Budget, Capital Spending and Acquisition s

On February 12, 2025, we announced a net capital budget for 2025 of $725 million to $800 million that included a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures.

During the nine months ended September 30, 2025, we decreased our drilling and completion budget range to $650 million to $675 million to reflect our operational efficiencies, and we increased our leasehold expenditures budget range to $125 million to $150 million to expand our acreage position in the Marcellus Shale in West Virginia.

Our revised net capital budget for 2025 is $775 million to $825 million.

On February 11, 2026, we announced our capital budget for 2026 is $1.1 billion to $1.3 billion and includes:

$1.0 billion for drilling and completions, $100 million for leasehold expenditures and up to $200 million for discretionary growth

capital that is dependent on commodity prices.

Our capital budget reflects the closing of the HG Acquisition on February 3, 2026 and closing of the Utica Shale Divestiture on February 23, 2026.

We do not budget for acquisitions.

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We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices.

For the three months ended September 30, 2025, our total consolidated capital expenditures were $217 million, including drilling and completion costs of $172 million, leasehold acquisitions of $42 million and other capital expenditures of $3 million.

For the nine months ended September 30, 2025, our total consolidated capital expenditures were $604 million, including drilling and completion costs of $500 million, leasehold acquisitions of $98 million and other capital expenditures of

In addition to our budgeted capital spending for the three and nine months ended September 30, 2025, we also acquired oil and gas properties for approximately $260 million during the third quarter of 2025.

See Note 3—Transactions to the unaudited condensed consolidated financial statements for additional information.

For the three months ended March 31, 2026, our total consolidated capital expenditures were $252 million, including drilling and completion costs of $222 million, leasehold acquisitions of $25 million, and other capital expenditures of $5 million.

Debt Agreements

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Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the 2025 Form 10-K for information on our critical accounting estimates.

Business Combinations

We recognize and measure the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date, with any remaining difference recorded as goodwill.

For acquisitions, management engages an independent valuation specialist to assist with the determination of fair value of the assets acquired, liabilities assumed, and goodwill, based on recognized valuation methodologies, including but not limited to income and cost approaches as circumstances warrant.

If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded.

Subsequent to the acquisition, and not later than one year from the Closing Date, we will record any material adjustments to the initial estimate based on new information obtained that would have existed as of the Closing Date.

An adjustment that arises from information obtained that did not exist as of the date of the acquisition will be recorded in the period of the adjustment.

The valuation of the assets acquired and liabilities assumed in a business combination requires significant judgement about commodity prices, projected reserve quantities, estimated future rates of production, projected reserve recovery factors, development plans (including timing and amount of development), future development costs, operating costs, among others, and such fair value approaches may rely on significant inputs that are not observable in the market.

These assumptions affect the fair value of assets acquired and liabilities assumed and, if changed, could have a material effect on the Company’s financial position or results of operations.

See Note 3—Transactions and Note 10—Fair Value Measurement to our unaudited condensed consolidated financial statements for more information.

Impairment of Proved Properties

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If the carrying amount of our proved properties exceeds the estimated undiscounted future net cash flows (measured using futures prices at the balance sheet date), we further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeds the estimated fair value of the properties.

Based on future prices as of September 30, 2025, the estimated undiscounted future net cash flows exceeded the carrying amount and no further evaluation was required.

We have not recorded any impairment expenses associated with our proved properties during the nine months ended September 30, 2024 and 2025.

Based on future prices as of March 31, 2026, the estimated undiscounted future net cash flows exceeded the carrying amount and no further evaluation was required.

We have not recorded any impairment expenses associated with our proved properties during the three months ended March 31, 2025 and 2026.

We believe that the estimates and assumptions related to our undiscounted future net cash flows and the fair value of our proved properties are critical because different natural gas, NGLs and oil pricing, cost assumptions or discount rates, as applicable, may affect the recognition, timing and amount of an impairment and, if changed, could have a material effect on the Company's financial position and results of operations.

New Accounting Pronouncements

See Note 2—Summary of Significant Accounting Policies to the unaudited condensed consolidated financial statements for information on new accounting pronouncements.

See Note 2—Summary of Significant Accounting Policies to our unaudited condensed consolidated financial statements for information on new accounting pronouncements.

Off-Balance Sheet Arrangements

See Note 13—Commitments to the unaudited condensed consolidated financial statements for information on off balance sheet arrangements.

See Note 13—Commitments to our unaudited condensed consolidated financial statements for information on off balance sheet arrangements.

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What changed 10-Q

Item 2. Management’s Discussion and Analysis