What changed in this filing

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Item 2. Management’s Discussion and Analysis

2026-07-29 compared with 2026-04-29 · 310 added, 98 removed, 261 unchanged (61% 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 March 31, 2026, we held approximately 855,000 net acres in the Appalachian Basin.

As of June 30, 2026, we held approximately 858,000 net acres in the Appalachian Basin.

HG Acquisition

1 unchanged sentence

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.

This acquisition closed on the Closing Date.

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.

The Company’s condensed consolidated statement of operations for the six months ended June 30, 2026 included results of operations from the assets and operations acquired in the HG Acquisition from the Closing Date through June 30, 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 well 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.

5 unchanged sentences

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

Martica Hurdle Achievement and Dissolution

On May 1, 2026, Sixth Street achieved its Hurdle for Martica.

As such, beginning May 1, 2026, 85% of the distributions in respect of the ORRIs to which Sixth Street was entitled immediately prior to the Hurdle being achieved reverted to us.

On June 30, 2026, we elected to dissolve Martica and make in-kind liquidating distributions to Sixth Street and ourselves, which included conveyance of the ORRIs to Sixth Street and Antero Resources after giving effect to the Reversion, after which Martica was deconsolidated for our condensed consolidated financial statements.

On July 1, 2026, after the deconsolidation of Martica, our condensed consolidated financial statements will reflect the ORRIs conveyed to us by Martica after giving effect to the Reversion, including the related earnings and cash flows.

See Note 2—Summary of Significant Accounting Policies for additional information.

Financing Highlights

4 unchanged sentences

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.

See Note 3—Transactions and Note 7—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.

2 unchanged sentences

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.

As of June 30, 2026, we have $1.1 billion outstanding on the Term Loan.

See Note 3—Transactions and Note 7—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.

On February 24, 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—Debt to our unaudited condensed consolidated financial statements for additional information.

Commercial Paper Program

On June 16, 2026, we established the Commercial Paper Program pursuant to which we may issue short-term, unsecured commercial paper notes.

The Commercial Paper may be issued and redeemed from time to time, with the aggregate face or principal amount of the notes outstanding under the Commercial Paper Program at any time not to exceed $1.65 billion.

Our Credit Facility will serve as a liquidity backstop for any issuances under the Commercial Paper Program, and we intend to maintain available capacity under the Credit Facility in an amount at least equal to the aggregate outstanding borrowings under the Commercial Paper Program.

See Note 7—Debt to our 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.

During the three and six months ended June 30, 2026, we repurchased approximately 1.1 million shares of our common stock at a total cost of $38 million through our share repurchase program.

As of June 30, 2026, we have approximately $877 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.

Market Conditions and Business Trends

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

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.

Benchmark prices for C3+ NGLs and oil increased significantly, while benchmark prices for natural gas and ethane decreased during the three months ended June 30, 2026 as compared to the same period of 2025.

Benchmark prices for natural gas and oil increased significantly, while benchmark prices for ethane decreased and C3+ NGLs remained consistent during the six months ended June 30, 2026 as compared to the same period of 2025.

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, Venezuela and in the Middle East, among others.

4 unchanged sentences

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

Three Months Ended March 31,

Three Months Ended June 30,

Six Months Ended June 30,

Henry Hub ($/Mcf) (1)

10 unchanged sentences

Hedge Position

Antero Resources

We are exposed to certain commodity price risks relating to our ongoing business operations, and we use derivative instruments when circumstances warrant to manage such risks.

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

For the three months ended June 30, 2025 and 2026, 4% and 47%, respectively, of our production was hedged through commodity derivatives, excluding basis swaps.

For the six months ended June 30, 2025 and 2026, 4% and 44%, 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.

In addition, for the three and six months ended June 30, 2026, 18% and 15%, respectively, of our production was hedged with basis swap commodity derivatives.

We did not have any basis swap commodity derivatives for the three and six months ended June 30, 2025.

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.

As such, all gains and losses attributable to Martica’s derivative portfolio were fully attributable to the noncontrolling interests in Martica.

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

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

As of June 30, 2026, the estimated fair value of our commodity derivative contracts was a net asset of $228 million.

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

4 unchanged sentences

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 conflicts, including those in the Middle East and Venezuela, 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.

8 unchanged sentences

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

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

Three Months Ended June 30, 2025 Compared to Three Months Ended June 30, 2026

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

Three Months Ended March 31, 2025

Three Months Ended June 30, 2025

Equity Method

6 unchanged sentences

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

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.

Three Months Ended June 30, 2026

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.

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

Three Months Ended

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.

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 June 30, 2025 includes $0.5 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 June 30, 2025 would have been $11.27 per Bbl.

Exploration and Production Segment

Natural gas sales .

Revenues from sales of natural gas remained relatively consistent at $689 million and $688 million for the three months ended June 30, 2025 and 2026, respectively, primarily due to $143 million of natural gas sales revenue attributable to the HG Acquisition properties and higher natural gas production volumes between periods, partially offset by the Utica Shale Divestiture and lower natural gas commodity prices between periods.

Higher natural gas production volumes accounted for an approximate $190 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).

Lower commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2026 accounted for an approximate $189 million decrease 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 NGLs increased from $481 million for the three months ended June 30, 2025 to $588 million for the three months ended June 30, 2026, an increase of $107 million, or 22%, primarily due to an additional $38 million of NGLs revenue attributable to the HG Acquisition properties and higher NGLs commodity prices and production volumes between periods, partially offset by the Utica Shale Divestiture.

Higher commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2026 accounted for an approximate $80 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Higher NGLs production volumes accounted for an approximate $27 million increase in year-over-year revenues (calculated as the change in year-to-year volumes times the prior year average price).

Revenues from sales of oil increased from $34 million for the three months ended June 30, 2025 to $60 million for the three months ended June 30, 2026, an increase of $26 million, or 77%, primarily due to an additional $10 million of oil revenue attributable to the HG Acquisition properties and higher oil commodity prices between periods, partially offset by the Utica Shale Divestiture.

Higher commodity prices (excluding the effects of derivative settlements) during the three months ended June 30, 2026 accounted for an approximate $22 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Higher oil production volumes during the three months ended June 30, 2026 accounted for an approximate $4 million increase 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.

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.

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.

For the three months ended June 30, 2025 and 2026, our commodity hedges resulted in derivative fair value gains of $53 million and $161 million, respectively.

For the three months ended June 30, 2025, commodity derivative fair value gains included $6 million of net cash payments for settled commodity derivative losses.

For the three months ended June 30, 2026, commodity derivative fair value gains included $134 million of net cash proceeds for settled derivative gains.

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 remained consistent at $6 million for the three months ended June 30, 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 per Mcfe increased 8% from $0.12 per Mcfe for the three months ended June 30, 2025 to $0.13 per Mcfe for the three months ended June 30, 2026 primarily due to higher wastewater trucking and disposal costs due to the timing of well completions activity between periods.

Lease operating expense increased from $37 million for the three months ended June 30, 2025 to $48 million for the three months ended June 30, 2026, an increase of $11 million, or 29%, primarily due to incremental expense of $8 million related to the HG Acquisition properties and higher wastewater trucking and disposal costs due to the timing of well completions activity between periods, partially offset by the Utica Shale Divestiture.

Gathering, compression, processing and transportation expense.

Gathering, compression, processing and transportation expense per Mcfe decreased 12% from $2.25 per Mcfe for the three months ended June 30, 2025 to $1.99 per Mcfe, for the three months ended June 30, 2026 primarily due to the HG Acquisition properties that have a lower compression, processing and transportation costs.

Gathering, compression, processing and transportation expense increased from $702 million for the three months ended June 30, 2025 to $748 million for the three months ended June 30, 2026, an increase of $46 million, or 7%, primarily due to incremental expense of $70 million related to the HG Acquisition properties and higher production volumes between periods, partially offset the Utica Shale Divestiture.

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 decreased from $0.76 per Mcfe for the three months ended June 30, 2025 to $0.72 per Mcfe for the three months ended June 30, 2026, primarily due to lower gathering and compression expense on a per unit basis for the HG Acquisition properties and decreased fuel costs as a result of lower natural gas prices, partially offset by annual CPI-based adjustments between periods.

● Processing costs decreased from $0.91 per Mcfe for the three months ended June 30, 2025 to $0.78 per Mcfe for the three months ended June 30, 2026, primarily due to lower NGLs transportation fees related to the HG Acquisition properties between periods.

● Transportation costs decreased from $0.58 per Mcfe for the three months ended June 30, 2025 to $0.49 per Mcfe for the three months ended June 30, 2026, primarily due to lower fuel costs as a result of lower natural gas prices between periods and lower demand fees for certain pipelines during the three months ended June 30, 2026.

Production and ad valorem tax expense.

Production and ad valorem taxes as a percentage of natural gas revenues remained consistent at 5% for the three months ended June 30, 2025 and 2026.

Production and ad valorem taxes increased from $35 million for the three months ended June 30, 2025 to $38 million for the three months ended June 30, 2026, an increase of $3 million, or 8%, primarily due to incremental expense of $6 million related to the HG Acquisition properties and higher production volumes between periods, partially offset by the Utica Shale Divestiture and lower natural gas prices during the three months ended June 30, 2026.

General and administrative expense .

General and administrative expense (excluding equity-based compensation expense) per Mcfe decreased 8% from $0.13 per Mcfe for the three months ended June 30, 2025 to $0.12 per Mcfe for the three months ended June 30, 2026 primarily due to higher production volumes from our HG Acquisition, partially offset by higher overall general and administrative costs between periods.

General and administrative expense (excluding equity-based compensation expense) increased from $41 million for the three months ended June 30, 2025 to $45 million for the three months ended June 30, 2026, an increase of $4 million, or 8%, primarily due to higher salary and wage expense, software license costs and professional service fees between periods.

Equity-based compensation expense .

Non-cash equity-based compensation expense decreased from $16 million for the three months ended June 30, 2025 to $13 million for the three months ended June 30, 2026, a decrease of $3 million or 16%.

This decrease was primarily due to lower RSU and PSU award expense of $2 million and $1 million, respectively, 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”) .

DD&A expense per Mcfe remained relatively consistent at $0.60 per Mcfe and $0.61 per Mcfe for the three months ended June 30, 2025 and 2026, respectively.

DD&A expense increased from $188 million for the three months ended June 30, 2025 to $227 million for the three months ended June 30, 2026, an increase of $39 million, or 21%, primarily due to higher production volumes between periods related to our HG Acquisition properties, partially offset by the Utica Shale Divestiture.

Impairment of property and equipment .

Impairment of oil and gas properties decreased from $6 million for the three months ended June 30, 2025 to $4 million for the three months ended June 30, 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 place into service.

Contract termination, loss contingency and settlements .

Contract termination, loss contingency and settlements decreased from $14 million for the three months ended June 30, 2025 to $2 million for the three months ended June 30, 2026, a decrease of $12 million.

This decrease was primarily due to lower loss contingencies recorded.

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

Loss (gain) on sale of assets.

Loss on sale of assets was less than $1 million for the three months ended June 30, 2025.

Gain on sale of assets was $15 million for the three months ended June 30, 2026 primarily due to the release of certain proceeds from the Utica Shale Divestiture that were held in escrow at closing.

See Note 3—Transactions 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 decreased from $0.06 per Mcfe, or $18 million, for the three months ended June 30, 2025 to $0.04 per Mcfe, or $16 million, for the three months ended June 30, 2026, primarily due to higher pipeline utilization and lower fuel costs between periods, partially offset by higher demand fees on certain pipelines.

Marketing revenue.

Marketing revenue increased from $34 million for the three months ended June 30, 2025 to $56 million for the three months ended June 30, 2026, an increase of $22 million, or 66%.

This fluctuation primarily resulted from the following:

● Natural gas marketing revenue decreased by $5 million between periods primarily due to lower natural gas marketing volumes.

● Oil marketing revenue increased by $28 million between periods primarily due to higher oil prices and marketing volumes.

Higher oil prices accounted for a $17 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes), and higher oil marketing volumes accounted for an $11 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price).

● NGLs marketing revenues increased by $3 million for the three months ended June 30, 2026 primarily due to higher C3+ NGLs marketing volumes.

Marketing expense.

Marketing expense increased from $52 million for the three months ended June 30, 2025 to $72 million for the three months ended June 30, 2026, an increase of $20 million, or 39%.

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 purchases increased $23 million between periods primarily due to higher oil marketing prices and volumes during the three months ended June 30, 2026, partially offset by lower natural gas marketing volumes during the three months ended June 30, 2026.

Firm transportation costs decreased $3 million between periods primarily due to higher pipeline utilization between periods and lower fuel costs during the three months ended June 30, 2026.

Antero Midstream Segment

Antero Midstream revenue.

Revenue from the Antero Midstream segment increased from $305 million for the three months ended June 30, 2025 to $327 million for the three months ended June 30, 2026, an increase of $22 million.

This increase is primarily due to higher gathering and processing revenues of $18 million and higher water handling revenues of $4 million.

The increased gathering and processing revenues between periods is primarily due to higher low pressure gathering and compression volumes from the HG Acquisition and 80 wells connected to their system between periods and increased gathering and centralized compression rates as a result of annual CPI-based adjustments, partially offset by the Utica Shale Divestiture and natural production decline of the wells connected to their system between periods.

The increased water handling revenues between periods is primarily due to fresh water delivery volumes for our acreage acquired in the HG Acquisition that are charged at cost plus 3% during the three months ended June 30, 2026, as well as higher blending cost of service fees, increased costs for wastewater trucking and disposal volumes 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 $119 million for the three months ended June 30, 2025 to $145 million for the three months ended June 30, 2026, an increase of $26 million.

This increase is primarily due to higher direct operating expenses as a result of gathering and well pad compression costs related to assets acquired with the HG Acquisition during the three months ended June 30, 2026, as well as increased fresh water delivery services on our acreage acquired in the HG Acquisition during the three month ended June 30, 2026, increased wastewater trucking and disposal volumes between periods and increased blending volumes and costs between periods, partially offset by the Utica Shale Divestiture.

Items Not Allocated to Segments

Interest expense.

Interest expense increased from $20 million for the three months ended June 30, 2025 to $38 million for the three months ended June 30, 2026, an increase of $18 million, or 88%, primarily due to borrowings to fund our HG Acquisition under the Term Loan and issuance of the 2036 Notes during the first quarter of 2026, partially offset by the redemption of the 2029 Notes on February 24, 2026 and lower Credit Facility borrowings and rates between periods.

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

Loss on early extinguishment of debt.

During the three months ended June 30, 2025, we repurchased $23 million aggregate principal amount of our 2029 Notes through open market transactions at a weighted average premium of approximately 102% of the principal amount thereof, plus accrued and unpaid interest, and recognized a loss on early debt extinguishment of $1 million.

There was no loss on early extinguishment of debt for the three months ended June 30, 2026.

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

Income tax expense .

Income tax expense increased from $48 million, with an effective tax rate of 22%, for the three months ended June 30, 2025 to $79 million, with an effective tax rate of 22%, for the three months ended June 30, 2026 primarily due to the increase in income before income taxes between periods.

Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2026

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

Six Months Ended June 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

20 unchanged sentences

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

Three Months Ended March 31, 2026

Six Months Ended June 30, 2026

Equity Method

28 unchanged sentences

(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:

Three Months Ended

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

Six Months Ended

Production data (1) (2) :

30 unchanged sentences

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.

(4) The average realized price for the six months ended June 30, 2025 includes $0.5 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 six months ended June 30, 2025 would have been $12.01 per Bbl.

Exploration and Production Segment

Natural gas sales .

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).

Revenues from sales of natural gas increased from $1.5 billion for the six months ended June 30, 2025 to $2.0 billion for the six months ended June 30, 2026, an increase of $0.5 billion, or 36%, primarily due to an additional $321 million of natural gas revenue attributable to the HG Acquisition properties and higher natural gas production volumes and commodity prices between periods, partially offset by the Utica Shale Divestiture.

Higher natural gas production volumes accounted for an approximate $358 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 $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).

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).

Higher commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, 2026 accounted for an approximate $173 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 NGLs increased from $1.0 billion for the six months ended June 30, 2025 to $1.1 billion for the six months ended June 30, 2026, an increase of $0.1 billion, or 5%, primarily due to an additional $54 million of NGLs revenue attributable to the HG Acquisition properties, higher NGLs production volumes and higher ethane commodity prices between periods, partially offset by the Utica Shale Divestiture and lower C3+ NGLs commodity prices during the six months ended June 30, 2026.

Higher NGLs production volumes during the six months ended June 30, 2026 accounted for an approximate $49 million increase 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 six months ended June 30, 2026 accounted for an approximate $14 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Lower C3+ NGLs commodity prices (excluding the effects of derivative settlements) during the six months ended June 30, 2026 accounted for an approximate $13 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Revenues from sales of oil increased from $84 million for the six months ended June 30, 2025 to $106 million for the six months ended June 30, 2026, an increase of $22 million, or 26%, primarily due to an additional $12 million of oil revenue attributable to the HG Acquisition properties and higher oil prices between periods, partially offset by the Utica Shale Divestiture.

Higher oil prices (excluding the effects of derivative settlements) accounted for an approximate $19 million increase in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes).

Higher oil production volumes accounted for an approximate $3 million increase 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).

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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.

For the six months ended June 30, 2025 and 2026, our commodity hedges resulted in derivative fair value losses of $18 million and fair value gains of $196 million, respectively.

For the six months ended June 30, 2025, commodity derivative fair value losses included $17 million of net cash payments for settled derivative losses.

For the six months ended June 30, 2026, commodity derivative fair value gains included $31 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 $6 million for the three months ended March 31, 2025 and 2026.

Amortization of deferred revenues associated with the VPP remained relatively consistent at $13 million and $12 million for the six months ended June 30, 2025 and 2026, respectively.

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 $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.

Lease operating expense per Mcfe increased 8% from $0.12 per Mcfe for the six months ended June 30, 2025 to $0.13 per Mcfe for the six months ended June 30, 2026 primarily due to higher wastewater trucking and disposal costs due to the timing of well completions activity between periods.

Lease operating expense increased from $71 million for the six months ended June 30, 2025 to $93 million for the six months ended June 30, 2026, an increase of $22 million, or 30%, primarily due to incremental expense of $14 million related to the HG Acquisition properties and higher wastewater trucking and disposal costs due to the timing of well completions activity between periods, partially offset by the Utica Shale Divestiture.

Gathering, compression, processing and transportation expense.

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.

Gathering, compression, processing and transportation expense per Mcfe decreased 6% from $2.26 per Mcfe for the six months ended June 30, 2025 to $2.13 per Mcfe for the six months ended June 30, 2026 primarily due to the HG Acquisition properties that have a lower compression, processing and transportation costs.

Gathering, compression, processing and transportation expense increased from $1.4 billion for the six months ended June 30, 2025 to $1.5 billion for the six months ended June 30, 2026, an increase of $0.1 billion, or 10%, primarily due to incremental expense of $109 million related to the HG Acquisition properties and higher production volumes between periods, partially offset the Utica Shale Divestiture.

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.

● Gathering and compression costs on a per unit basis decreased from $0.77 per Mcfe for the six months ended June 30, 2025 to $0.75 per Mcfe for the six months ended June 30, 2026, primarily due to lower gathering and compression expense on a per unit basis for the HG Acquisition properties, partially offset by 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 decreased from $0.88 per Mcfe for the six months ended June 30, 2025 to $0.80 per Mcfe for the six months ended June 30, 2026, primarily due to lower NGLs transportation fees related to the HG Acquisition properties between periods.

● Transportation costs on a per unit basis decreased from $0.61 per Mcfe for the six months ended June 30, 2025 to $0.58 per Mcfe for the six months ended June 30, 2026, primarily due to lower transportation expense on a per unit basis for the HG Acquisition properties, partially offset by increased fuel costs as a result of higher natural gas prices between periods.

Production and ad valorem tax expense.

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.

Production and ad valorem taxes as a percentage of natural gas revenues remained consistent at 6% for each of the six months ended June 30, 2025 and 2026.

Production and ad valorem taxes increased from $90 million for the six months ended June 30, 2025 to $119 million for the six months ended June 30, 2026, an increase of $29 million, or 32%, primarily due to higher natural gas prices between periods and incremental expense of $15 million related to the HG Acquisition properties, partially offset by the Utica Shale Divestiture.

General and administrative expense .

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.

General and administrative expense (excluding equity-based compensation) per Mcfe decreased 7% from $0.14 per Mcfe for the six months ended June 30, 2025 to $0.13 per Mcfe for the six months ended June 30, 2026 primarily due to increased production volumes related to our HG Acquisition, partially offset by higher overall general and administrative costs between periods.

General and administrative expense (excluding equity-based compensation expense) increased from $89 million for the six months ended June 30, 2025 to $96 million for the six months ended June 30, 2026, an increase of $7 million, or 8%, primarily due to higher salary and wage expense, software license costs and professional service fees between periods.

Equity-based compensation expense .

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.

Non-cash equity-based compensation expense decreased from $31 million for the six months ended June 30, 2025 to $25 million for the six months ended June 30, 2026, a decrease of $6 million or 19%.

This decrease was primarily due to lower RSU and PSU award expense of $5 million and $1 million, respectively, 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 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.

DD&A expense per Mcfe remained relatively consistent at $0.61 per Mcfe and $0.60 per Mcfe for the six months ended June 30, 2025 and 2026, respectively.

DD&A expense increased from $374 million for the six months ended June 30, 2025 to $433 million for the six months ended June 30, 2026, an increase of $59 million, or 16%, primarily due to higher production volumes between periods related to our HG Acquisition properties, partially offset by the Utica Shale Divestiture.

Impairment of property and equipment .

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.

Impairment of oil and gas properties decreased from $12 million for the six months ended June 30, 2025 to $5 million for the six months ended June 30, 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.

Contract termination, loss contingency, settlements and other operating expenses increased from $12 million for the six months ended June 30, 2025 to $14 million for the six months ended June 30, 2026, an increase of $2 million.

This increase was primarily due to contract termination expense related to certain HG Acquisition contracts during the six months ended June 30, 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.

Gain on sale of assets was less than $1 million for the six months ended June 30, 2025.

Gain on sale of assets was $61 million for the six months ended June 30, 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.

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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 $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 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%.

Net marketing expense decreased from $0.06 per Mcfe for the six months ended June 30, 2025 to $0.05 per Mcfe for the six months ended June 30, 2026, primarily due higher production volumes from our HG Acquisition, partially offset by higher net marketing expense between periods.

Net marketing expense increased from $35 million for the six months ended June 30, 2025 to $37 million for the six months ended June 30, 2026 primarily due to higher demand fees on certain pipelines and lower pipeline utilization due to maintenance between periods.

Marketing revenue.

Marketing revenue increased from $59 million for the six months ended June 30, 2025 to $98 million for the six months ended June 30, 2026, an increase of $39 million, or 65%.

This fluctuation primarily resulted from the following:

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

● Natural gas marketing revenue decreased by $5 million between periods primarily due to lower natural gas marketing volumes.

● Oil marketing revenue increased by $42 million between periods primarily due to higher oil marketing volumes and prices.

Higher oil marketing volumes accounted for a $23 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 $19 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.

● NGLs marketing revenue increased by $4 million between periods primarily due to higher ethane marketing volumes and prices for the six months ended June 30, 2026.

Marketing expense.

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 increased from $95 million for the six months ended June 30, 2025 to $135 million for the six months ended June 30, 2026, an increase of $40 million, or 42%.

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.

The cost of third-party purchases increased $34 million between periods primarily due to higher oil marketing prices and volumes during the six months ended June 30, 2026, partially offset by lower natural gas marketing volumes during the six months ended June 30, 2026.

Firm transportation costs increased $7 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 six months ended June 30, 2026.

Antero Midstream Segment

Antero Midstream revenue.

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.

Revenue from the Antero Midstream segment increased from $597 million for the six months ended June 30, 2025 to $641 million for the six months ended June 30, 2026, an increase of $44 million.

This increase is primarily due to higher gathering and processing revenues of $39 million and higher water handling revenues of $5 million.

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.

The increased water handling revenues between periods is primarily due to fresh water delivery volumes for our acreage acquired in the HG Acquisition that are charged at cost plus 3% during the six months ended June 30, 2026, higher blending cost of service fees, increased wastewater trucking and disposal volumes and costs and a higher fresh water delivery fee as a result of an annual CPI-based adjustment, 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 $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.

Total operating expense related to the Antero Midstream segment increased from $233 million for the six months ended June 30, 2025 to $271 million for the six months ended June 30, 2026, an increase of $38 million.

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

Items Not Allocated to Segments

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.

Interest expense, net increased from $43 million for the six months ended June 30, 2025 to $74 million for the six months ended June 30, 2026, an increase of $31 million or 72%, primarily due to borrowings to fund our HG Acquisition under the Term Loan and issuance of the 2036 Notes during the first quarter of 2026, partially offset by the redemption of the 2029 Notes on February 24, 2026 and lower Credit Facility borrowings and rates between periods.

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

Loss on early extinguishment of debt.

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.

During the six months ended June 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.

During the six months ended June 30, 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—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.

There were no transaction expenses incurred during the six months ended June 30, 2025.

During the six months ended June 30, 2026, we incurred $24 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.

Income tax expense increased from $103 million, with an effective tax rate of 21%, for the six months ended June 30, 2025 to $225 million, with an effective tax rate of 21%, for the six months ended June 30, 2026 primarily due to the increase in income before income taxes between periods.

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 and Term Loan, 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, including issuances of notes under our Commercial Paper Program, 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.

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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.

Based on strip prices as of June 30, 2026, we believe that net cash provided by operating activities, issuances of notes under our Commercial Paper Program 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):

Three Months Ended March 31,

Six Months Ended June 30,

Net cash provided by operating activities

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Operating activities.

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.

Net cash provided by operating activities was $950 million and $1.3 billion for the six months ended June 30, 2025 and 2026, respectively.

Net cash provided by operating activities increased between periods primarily due to higher natural gas, NGLs and oil revenues for our HG Acquisition properties, lower lease operating, gathering, compression, processing, transportation, production and ad valorem taxes for the Utica Shale Divestiture and changes in working capital, partially offset by higher lease operating, gathering, compression, processing, transportation and production and ad valorem taxes for our HG Acquisition properties, lower natural gas, NGLs and oil revenues for the Utica Shale Divestiture and higher marketing and interest expense during the six months ended June 30, 2026.

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 $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.

Net cash used in investing activities increased from $405 million for the six months ended June 30, 2025 to $2.6 billion for the six months ended June 30, 2026, primarily due to cash paid for our HG Acquisition of $2.8 billion during the six months ended June 30, 2026, increased drilling and completions activity of $136 million between periods and acquisitions of oil and gas properties during the six months ended June 30, 2026 of $8 million, partially offset by proceeds from the Utica Shale Divestiture of $757 million during the six months ended June 30, 2026 and decreased oil and gas leasing activity of $11 million between periods.

Financing activities.

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.

Net cash used in financing activities was $545 million for the six months ended June 30, 2025.

Net cash provided by financing activities was $1.1 billion for the six months ended June 30, 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, the issuance of our 2036 Notes of $750 million and net borrowings on our Commercial Paper Program of $182 million during the six months ended June 30, 2026, partially offset by higher net repayments on our Credit Facility of $183 million between periods, repayments on the Term Loan of $400 million during the six months ended June 30, 2026, higher repayments and redemptions of our senior notes of $228 million between periods and increased payments of employee tax withholdings for the settlement of equity-based compensation awards of $8 million between periods.

2026 Capital Budget, Capital Spending and Acquisition s

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.

$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 the Closing Date and the 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 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.

For the three months ended June 30, 2026, our total consolidated capital expenditures were $332 million, including drilling and completion costs of $297 million, leasehold acquisitions of $29 million, and other capital expenditures of $6 million.

For the six months ended June 30, 2026, our total consolidated capital expenditures were $584 million, including drilling and completion costs of $518 million, leasehold acquisitions of $54 million, and other capital expenditures of $12 million.

Debt Agreements

See Note 7—Long-Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q and to “Item 7.

See Note 7—Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q and to “Item 7.

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

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The preparation of our unaudited condensed consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingent liabilities.

Accounting estimates and assumptions are considered to be critical if there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used.

estimates and assumptions are considered to be critical if there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used.

We evaluate our estimates and assumptions on a regular basis.

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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 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.

Based on future prices as of June 30, 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 six months ended June 30, 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.

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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-Q

Item 2. Management’s Discussion and Analysis