What changed in this filing

/stocks — the workspaceLOADING

Item 2. Management’s Discussion and Analysis

2025-04-30 compared with 2024-10-30 · 104 added, 320 removed, 211 unchanged (67% of the section changed)

8 unchanged sentences

In this section, references to “Antero,” the “Company,” “we,” “us,” and “our” refer to Antero Resources Corporation and its subsidiaries, unless otherwise indicated or the context otherwise requires.

We are an independent oil and natural gas company engaged in the development, production, exploration and acquisition of natural gas, NGLs and oil properties located in the Appalachian Basin.

We have assembled a portfolio of long-lived properties that are characterized by what we believe to be high repeatability and low geologic risk.

We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations.

3 unchanged sentences

Our drilling opportunities are focused in the Appalachian Basin.

As of September 30, 2024, we held approximately 519,000 net acres in the Appalachian Basin.

As of March 31, 2025, we held approximately 526,000 net acres in the Appalachian Basin.

Financing Highlights

Unsecured Credit Facility

During the second quarter of 2024, we achieved an investment grade credit rating from S&P Global Inc.

As a result of this investment grade credit rating, on July 30, 2024, we entered into an amended and restated senior revolving credit facility with lender commitments of $1.65 billion that matures on July 30, 2029, subject to certain extension terms and conditions.

Borrowings under the amended and restated facility are unsecured and are not guaranteed by any of our subsidiaries.

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

Debt Repurchase Program

During the three months ended March 31, 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 $19 million aggregate principal amount of our 2029 Notes through open market transactions at a weighted average price of 102.725% 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.

During the three months ended March 31, 2025, we repurchased approximately 0.3 million shares of our common stock through our share repurchase program at a total cost of $10 million.

As of March 31, 2025, we have approximately $1.0 billion 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

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 decreased significantly, while benchmark prices for oil remained consistent and benchmark prices for NGLs increased during the nine months ended September 30, 2024 as compared to the same period of 2023.

As a result of the lower benchmark natural gas prices and higher benchmark NGLs prices in 2024, we experienced a decrease in price realizations for natural gas and ethane products and an increase in price realization for NGLs products during the three and nine months ended September 30, 2024.

Benchmark prices for natural gas and NGLs increased, while benchmark prices for oil decreased during the three months ended March 31, 2025 as compared to the same period of 2024.

As a result of the higher benchmark natural gas and NGLs prices during the three months ended March 31, 2025, we experienced increased price realizations for these products between periods, partially offset by the effects of decreased benchmark oil prices on our oil price realizations as compared to the three months ended March 31, 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.

2 unchanged sentences

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)

14 unchanged sentences

Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased.

For the three and nine months ended September 30, 2023 and 2024, substantially all of our production was unhedged.

The tables and narrative below exclude derivative instruments attributable to Martica, our consolidated VIE, since all gains or losses from such contracts are fully attributable to the noncontrolling interests in Martica.

As of September 30, 2024, our fixed price NGLs swap positions excluding Martica were as follows:

Commodity / Settlement Period

Contracted Volume

October-December 2024

Mont Belvieu Propane-OPIS TET

As of September 30, 2024, our natural gas basis swap positions settle on the pricing index to basis differential of the Columbia Gas Transmission pipeline (“TCO”) to the NYMEX Henry Hub natural gas price were as follows:

Weighted Average

Commodity / Settlement Period

Index to Basis Differential

Contracted Volume

Hedged Differential

October-December 2024

We have a call option and an embedded put option tied to NYMEX pricing for the production volumes associated with the Company’s retained interest in the VPP properties.

As of September 30, 2024, our call option and embedded put option arrangements were as follows:

Commodity / Settlement Period

Contracted Volume

October-December 2024

January-December 2025

January-December 2026

As of September 30, 2024, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of $24 million.

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

Our consolidated VIE, Martica, also maintains 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 are fully attributable to the noncontrolling interests in Martica.

As of September 30, 2024, Martica’s fixed price natural gas and oil swap positions were as follows:

Commodity / Settlement Period

Contracted Volume

October-December 2024

January-March 2025

October-December 2024

West Texas Intermediate

January-March 2025

West Texas Intermediate

As of September 30, 2024, the estimated fair value of Martica’s commodity derivative contracts was a net liability of $3 million.

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

For the three months ended March 31, 2024 and 2025, substantially all of our production was unhedged.

Assuming our 2025 production is the same as our production in 2024, approximately 2% of our total production for 2025 is hedged through fixed price commodity swaps.

As of March 31, 2025, the estimated fair value of our commodity derivative contracts was a net liability of $107 million.

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

Our consolidated VIE, Martica, also 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, and as of March 31, 2025, Martica’s had no derivative instruments.

See Note 11—Derivative Instruments to the 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 the third quarter of 2024.

For example, the Consumer Price Index (“CPI”) for all urban consumers increased 3.7% from September 2022 to September 2023 and an additional 2.4% from September 2023 to September 2024 as compared to the Federal Reserve’s stated goal of 2%.

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 2024.

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 March 2022 in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis.

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

During the three months ended September 30, 2024, inflation rates began to approach the Federal Reserve’s stated goal of 2%, and the Federal Reserve decreased the federal funds rate by 0.5% in September 2024.

While inflationary pressures in the United States’ economy have begun to subside, we continue to be impacted by the increased federal funds interest rate.

See “— Results of Operations” for more information.

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 1.0% between September and December 2024.

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.

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 on Russia and other global trade restrictions, among others.

However, our supply chain has not experienced any significant interruptions as a result of such events.

These events have often caused global supply chain disruptions with additional pressure due to trade sanctions, tariffs and other global trade restrictions, 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.

Inflationary pressures, particularly as they relate to certain of our long-term contracts with CPI-based adjustments, and supply chain disruptions have and could continue to result in increases to our operating and capital costs that are not fixed.

1 unchanged sentence

Results of Operations

We have three operating segments:

We have three reportable segments:

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

4 unchanged sentences

Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity.

See Note 16—Reportable Segments to the unaudited condensed consolidated financial statements for more information.

Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2024

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

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2025

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

Three Months Ended September 30, 2023

Three Months Ended March 31, 2024

Equity Method

2 unchanged sentences

Unconsolidated

Midstream (1)

Revenue and other:

12 unchanged sentences

Production and ad valorem taxes

Exploration and mine expenses

General and administrative (excluding equity-based compensation)

3 unchanged sentences

Accretion of asset retirement obligations

Loss on sale of assets

Contract termination, loss contingency, settlements and other operating expenses

Loss (gain) on sale of assets

Total operating expenses

1 unchanged sentence

Equity in earnings of unconsolidated affiliates

Three Months Ended September 30, 2024

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

Three Months Ended March 31, 2025

Equity Method

2 unchanged sentences

Unconsolidated

Midstream (1)

Revenue and other:

1 unchanged sentence

Natural gas liquids sales

Commodity derivative fair value gains

Commodity derivative fair value losses

Gathering, compression and water handling

18 unchanged sentences

Equity in earnings of unconsolidated affiliates

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

Exploration and Production Segment

1 unchanged sentence

Three Months Ended

September 30,

Production data (1) (2) :

30 unchanged sentences

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, 2023 includes $6 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, 2023 would have been $10.88 per Bbl.

Natural gas sales .

Revenues from sales of natural gas decreased from $516 million for the three months ended September 30, 2023 to $426 million for the three months ended September 30, 2024, a decrease of $90 million, or 18%.

Lower commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2024 accounted for an approximate $69 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).

Lower natural gas production volumes accounted for an approximate $21 million decrease 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 increased from $483 million for the three months ended September 30, 2023 to $504 million for the three months ended September 30, 2024, an increase of $21 million, or 4%.

Higher commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2024 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).

Revenues from sales of oil decreased from $63 million for the three months ended September 30, 2023 to $53 million for the three months ended September 30, 2024, a decrease of $10 million, or 16%.

Lower commodity prices (excluding the effects of derivative settlements) during the three months ended September 30, 2024 accounted for an approximate $6 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Lower oil production volumes during the three months ended September 30, 2024 accounted for an approximate $4 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.

Our commodity derivatives included fixed price swap contracts, basis swap contracts, 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 statements of operations and comprehensive income.

For the three months ended September 30, 2023 and 2024, our commodity hedges resulted in derivative fair value gains of $3 million and $18 million, respectively.

For the three months ended September 30, 2023, commodity derivative fair value gains included $6 million of cash payments on settled commodity derivative losses.

For the three months ended September 30, 2024, commodity derivative fair value gains included $4 million of net cash proceeds on settled commodity derivatives 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 decreased from $8 million for the three months ended September 30, 2023 to $7 million for the three months ended September 30, 2024, a decrease of $1 million, or 12%, 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 decreased from $33 million, or $0.10 per Mcfe, for the three months ended September 30, 2023 to $30 million, or $0.09 per Mcfe, for the three months ended September 30, 2024, a decrease of $3 million primarily due to lower water disposal costs and workover expense between periods.

Gathering, compression, processing and transportation expense.

Gathering, compression, processing and transportation expense increased from $672 million for the three months ended September 30, 2023 to $685 million for the three months ended September 30, 2024, an increase of $13 million, or 2%.

This was primarily a result of the following:

● Gathering and compression costs increased from $0.68 per Mcfe for the three months ended September 30, 2023 to $0.72 per Mcfe for the three months ended September 30, 2024, primarily due to the expiration of the growth incentive fee rebate program on December 31, 2023 and annual CPI-based adjustments between periods.

During the three months ended September 30, 2023, we earned a fee rebate of $12 million under this program.

● Processing costs increased from $0.83 per Mcfe for the three months ended September 30, 2023 to $0.88 per Mcfe for the three months ended September 30, 2024, primarily due to increased costs for NGLs processing, which includes an annual CPI-based adjustment during the first quarter of 2024 and higher NGLs transportation fees.

● Transportation costs decreased from $0.60 per Mcfe for the three months ended September 30, 2023 to $0.58 per Mcfe for the three months ended September 30, 2024 primarily due to lower demand fees, as well as lower fuel costs as a result of lower natural gas prices between periods.

Production and ad valorem tax expense.

Production and ad valorem taxes increased from $32 million for the three months ended September 30, 2023 to $47 million for the three months ended September 30, 2024, an increase of $15 million, or 47%, primarily due to higher ad valorem taxes, partially offset by lower natural gas prices during the three months ended September 30, 2024.

Production and ad valorem taxes as a percentage of natural gas revenues increased from 6% for the three months ended September 30, 2023 to 11% for the three months ended September 30, 2024, primarily as a result of higher ad valorem taxes, which 2024 ad valorem taxes are based on commodity prices during 2022.

General and administrative expense .

General and administrative expense (excluding equity-based compensation expense) decreased slightly from $40 million, or $0.13 per Mcfe, for the three months ended September 30, 2023 to $39 million, or $0.12 per Mcfe for the three months ended September 30, 2024 primarily as a result of lower pipeline bond and leased vehicle costs between periods .

Equity-based compensation expense .

Non-cash equity-based compensation expense decreased from $18 million for the three months ended September 30, 2023 to $16 million for the three months ended September 30, 2024, a decrease of $2 million, or 13%.

This decrease was primarily due to lower PSU award expense between periods, partially offset by increased RSU award expense attributable to awards granted in the first quarter of 2024.

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

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

DD&A expense decreased from $176 million, or $0.55 per Mcfe, for the three months ended September 30, 2023 to $170 million, or $0.55 per Mcfe, for the three months ended September 30 2024, a decrease of $6 million, or 3%.

The decrease in total DD&A expense is primarily due to lower production volumes between periods.

Impairment of property and equipment .

Impairment of oil and gas properties remained consistent at $13 million for the three months ended September 30, 2023 and 2024.

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 loss of $14 million for the three months ended September 30, 2023 primarily due to a loss contingency.

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.

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 for the three months ended September 30, 2023 and 2024 remained relatively consistent at $17 million and $15 million, respectively, or $0.05 per Mcfe.

Marketing revenue.

Marketing revenue decreased from $53 million for the three months ended September 30, 2023 to $47 million for the three months ended September 30, 2024, a decrease of $6 million, or 11%.

This fluctuation primarily resulted from the following:

● Natural gas marketing revenue decreased by $14 million between periods primarily due to lower natural gas marketing volumes and prices between periods.

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 lower natural gas prices accounted for a $3 million decrease 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 increased by $8 million between periods primarily due to higher oil marketing volumes, partially offset by lower oil prices.

Higher oil marketing volumes accounted for a $10 million increase 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 $2 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

Marketing expense.

Marketing expense decreased from $70 million for the three months ended September 30, 2023 to $62 million for the three months ended September 30, 2024, a decrease of $8 million, or 11%.

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, oil and NGLs purchases remained consistent at $43 million for the three months ended September 30, 2023 and 2024.

Firm transportation costs were $26 million for the three months ended September 30, 2023 and $18 million for the three months ended September 30, 2024, a decrease of $8 million due to the reduction in firm transportation commitments and higher third-party marketing volumes between periods.

Antero Midstream Segment

Antero Midstream revenue.

Revenue from the Antero Midstream segment increased from $264 million for the three months ended September 30, 2023 to $270 million for the three months ended September 30, 2024, an increase of $6 million.

This increase is primarily due to higher gathering and processing revenues of $20 million, partially offset by lower water handling revenues of $14 million.

The increased gathering and processing revenues between periods is primarily a result of the expiration of the growth incentive fee rebate program on December 31, 2023, annual CPI-based gathering and compression rate adjustments and increased high pressure gathering throughput between periods.

The decreased water handling revenues between periods was primarily due to lower fresh water delivery and other fluid handling volumes, partially offset by an increased fresh water delivery rate due to an annual CPI-based adjustment during the first quarter of 2024.

Antero Midstream operating expense.

Total operating expense related to the Antero Midstream segment increased from $102 million for the three months ended September 30, 2023 to $107 million for the three months ended September 30, 2024, an increase of $5 million.

This increase is primarily due to higher general and administrative expense, including equity-based compensation expense, and depreciation expense between periods.

Discussion of Items Not Allocated to Segments

Interest expense.

Interest expense decreased from $32 million for the three months ended September 30, 2023 to $28 million for the three months ended September 30, 2024, a decrease of $4 million, or 11%, primarily due to the conversion of $26 million aggregate principal amount of our 2026 Convertible Notes during the first quarter of 2024 and lower benchmark interest rates during the three months ended September 30, 2024, partially offset by higher average Credit Facility borrowings between periods.

Income tax expense .

For the three months ended September 30, 2023, we had an income tax expense of $14 million, with an effective tax rate of 30%, due to income before income taxes of $46 million.

For the three months ended September 30, 2024, we had an income tax expense of $1 million from a loss before income taxes of $9 million primarily due to the net loss before income taxes during the third quarter of 2024, which when taken together with the net loss before taxes during the six months ended June 30, 2024, resulted in a 9% effective tax rate for the nine months ended September 30, 2024.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2024

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

Nine Months Ended September 30, 2023

Equity Method

Investment in

Elimination of

Unconsolidated

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

Exploration and mine expenses

General and administrative (excluding equity-based compensation)

Equity-based compensation

Depletion, depreciation and amortization

Impairment of property and equipment

Accretion of asset retirement obligations

Contract termination, loss contingency, settlements and other operating expenses

Loss (gain) on sale of assets

Total operating expenses

Operating income (loss)

Equity in earnings of unconsolidated affiliates

Nine Months Ended September 30, 2024

Equity Method

Investment in

Elimination of

Unconsolidated

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

Loss (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

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.

Our calculation of such after effects includes gains (losses) on settlements of commodity derivatives (but do not include payments from the derivative monetizations in 2023), 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 nine months ended September 30, 2023 and 2024 includes $13 million and $2 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, 2023 and 2024 would have been $9.77 per Bbl and $8.48 per Bbl, respectively.

(4) The average realized price for the three months ended March 31, 2024 includes $2 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 March 31, 2024 would have been $9.07 per Bbl.

Natural gas sales .

Revenues from sales of natural gas decreased from $1.6 billion for the nine months ended September 30, 2023 to $1.3 billion for the nine months ended September 30, 2024, a decrease of $0.3 billion, or 21%.

Lower commodity prices (excluding the effects of derivative settlements) during the nine months ended September 30, 2024 accounted for an approximate $323 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 natural gas increased from $474 million for the three months ended March 31, 2024 to $780 million for the three months ended March 31, 2025, an increase of $306 million, or 65%.

Higher commodity prices (excluding the effects of derivative settlements) during the three months ended March 31, 2025 accounted for an approximate $322 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).

Lower natural gas production volumes accounted for an approximate $16 million decrease 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 increased from $1.4 billion for the nine months ended September 30, 2023 to $1.5 billion for the nine months ended September 30, 2024, an increase of $0.1 billion, or 10%.

Higher commodity prices (excluding the effects of derivative settlements) during the nine months ended September 30, 2024 accounted for an approximate $76 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 $60 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 increased from $172 million for the nine months ended September 30, 2023 to $181 million for the nine months ended September 30, 2024, an increase of $9 million, or 5%.

Higher oil prices, excluding the effects of derivative settlements, accounted for an approximate $1 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 during the nine months ended September 30, 2024 accounted for an approximate $8 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.

Revenues from sales of NGLs increased from $518 million for the three months ended March 31, 2024 to $561 million for the three months ended March 31, 2025, an increase of $43 million, or 8%.

Higher commodity prices (excluding the effects of derivative settlements) during the three months ended March 31, 2025 accounted for an approximate $51 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 production volumes accounted for an approximate $14 million decrease in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price), partially offset by

higher ethane production volumes that accounted for an approximate $6 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 $65 million for the three months ended March 31, 2024 to $50 million for the three months ended March 31, 2025, a decrease of $15 million, or 22%.

Lower oil production volumes during the three months ended March 31, 2025 accounted for an approximate $12 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price).

Lower oil prices, excluding the effects of derivative settlements, accounted for an approximate $3 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 (losses).

Our commodity derivatives included variable price swap contracts, swaptions, basis swap contracts, call options and embedded put options.

1 unchanged sentence

Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations.

For the nine months ended September 30, 2023 and 2024, our commodity hedges resulted in derivative fair value gains of $138 million and $22 million, respectively.

For the nine months ended September 30, 2023, commodity derivative fair value gains included $17 million of cash payments on settled commodity derivative losses and a $202 million cash payment for the early settlement of our swaption.

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 three months ended March 31, 2024 and 2025, our commodity hedges resulted in derivative fair value gains of $9 million and fair value losses of $72 million, respectively.

For the three months ended March 31, 2024, commodity derivative fair value gains included $1 million of net cash proceeds on settled commodity derivatives gains.

For the three months ended March 31, 2025, commodity derivative fair value losses included $11 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.

2 unchanged sentences

Amortization of deferred revenue, VPP.

Amortization of deferred revenues associated with the VPP decreased from $23 million for the nine months ended September 30, 2023 to $20 million for the nine months ended September 30, 2024, a decrease of $3 million or 11%, primarily due to lower production volumes attributable to the VPP properties between periods.

Amortization of deferred revenues associated with the VPP decreased from $7 million for the three months ended March 31, 2024 to $6 million for the three months ended March 31, 2025, a decrease of $1 million or 8%, 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 decreased from $92 million, or $0.10 per Mcfe, for the nine months ended September 30, 2023 to $88 million, or $0.09 per Mcfe, for the nine months ended September 30, 2024, primarily due to lower water disposal costs and workover expense during the nine months ended September 30, 2024, partially offset by higher oilfield service costs between periods.

Lease operating expense increased from $29 million, or $0.09 per Mcfe, for the three months ended March 31, 2024 to $34 million, or $0.11 per Mcfe, for the three months ended March 31, 2025, primarily due to higher oilfield service costs and workover expense during the three months ended March 31, 2025, partially offset by lower water disposal costs between periods.

Gathering, compression, processing and transportation expense.

Gathering, compression, processing and transportation expense remained consistent at $2.0 billion for the nine months ended September 30, 2023 and 2024.

This was primarily a result of the following:

● Gathering and compression costs on a per unit basis increased from $0.69 per Mcfe for the nine months ended September 30, 2023 to $0.72 per Mcfe for the nine months ended September 30, 2024, primarily due to the expiration of the growth incentive fee rebate program on December 31, 2023 and annual CPI-based adjustments between periods.

During the nine months ended September 30, 2023, we earned fee rebates of $36 million under this program.

● Processing costs on a per unit basis increased from $0.83 per Mcfe for the nine months ended September 30, 2023 to $0.86 per Mcfe for the nine months ended September 30, 2024, primarily due to increased costs for NGLs processing and transportation, which includes an annual CPI-based adjustment during the first quarter of 2024 and higher NGLs transportation fees.

● Transportation costs on a per unit basis decreased from $0.62 per Mcfe for the nine months ended September 30, 2023 to $0.58 per Mcfe for the nine months ended September 30, 2024 primarily due to lower demand fees and lower fuel costs as a result of lower natural gas prices between periods.

Gathering, compression, processing and transportation expense increased from $672 million for the three months ended March 31, 2024 to $695 million for the three months ended March 31, 2025, an increase of $23 million, or 3%.

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 three months ended March 31, 2024 to $0.77 per Mcfe for the three months ended March 31, 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 $0.82 per Mcfe for the three months ended March 31, 2024 to $0.85 per Mcfe for the three months ended March 31, 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 $0.62 per Mcfe for the three months ended March 31, 2024 to $0.65 per Mcfe for the three months ended March 31, 2025, primarily due to higher demand fees and higher 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 $118 million for the nine months ended September 30, 2023 to $148 million for the nine months ended September 30, 2024, an increase of $30 million, or 25%, primarily due to higher ad valorem taxes and production volumes between periods, partially offset by lower natural gas prices during the nine months ended September 30, 2024.

Production and ad valorem taxes as a percentage of natural gas revenues increased from 7% for the nine months ended September 30, 2023 to 12% for the nine months ended September 30,

2024, primarily as a result of higher ad valorem taxes, which 2024 West Virginia ad valorem taxes are based on commodity prices during 2022.

Production and ad valorem taxes decreased from $58 million for the three months ended March 31, 2024 to $55 million for the three months ended March 31, 2025, a decrease of $3 million, or 5%, primarily due to lower production volumes between periods, partially offset by higher natural gas prices during the three months ended March 31, 2025.

Production and ad valorem taxes as a percentage of natural gas revenues decreased from 12% for the three months ended March 31, 2024 to 7% for the three months ended March 31, 2025, primarily as a result of lower ad

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

General and administrative expense .

General and administrative expense (excluding equity-based compensation expense) decreased from $125 million for the nine months ended September 30, 2023 to $121 million for nine months ended September 30, 2024, a decrease of $4 million, or 3%, primarily due to lower professional service fees between periods.

General and administrative expense on a per unit basis (excluding equity-based compensation) remained consistent at $0.13 per Mcfe for the nine months ended September 30, 2023 and 2024.

General and administrative expense (excluding equity-based compensation expense) increased from $40 million for the three months ended March 31, 2024 to $47 million for three months ended March 31, 2025, an increase of $7 million, or 19%, primarily due to higher professional service fees between periods.

General and administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.13 per Mcfe for the three months ended March 31, 2024 to $0.15 per Mcfe for the three months ended March 31, 2025 primarily as a result of higher overall costs and lower production volumes between periods.

Equity-based compensation expense .

Non-cash equity-based compensation expense increased from $45 million for the nine months ended September 30, 2023 to $49 million for the nine months ended September 30, 2024, an increase of $4 million, or 10%.

This increase was primarily due to RSU award expense attributable to awards granted in the fourth quarter of 2023 and first quarter of 2024, partially offset by lower PSU award expense between periods and equity-based awards granted in prior years that were fully vested between periods.

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

Non-cash equity-based compensation expense remained relatively consistent at $16 million and $15 million for the three months ended March 31, 2024 and 2025, respectively.

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 $515 million, or $0.56 per Mcfe, and $514 million, or $0.55 per Mcfe, for the nine months ended September 30, 2023 and 2024, respectively.

DD&A expense remained relatively consistent at $190 million, or $0.61 per Mcfe, and $186 million, or $0.61 per Mcfe, for the three months ended March 31, 2024 and 2025, respectively.

Impairment of property and equipment .

Impairment of oil and gas properties decreased from $45 million for the nine months ended September 30, 2023 to $19 million for the nine months ended September 30, 2024, a decrease of $26 million, primarily due to lower impairments of expiring leases between periods.

Impairment of oil and gas properties remained relatively consistent at $5 million for the three months ended March 31, 2024 and $6 million for the three months ended March 31, 2025.

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 attributable to our exploration and production segment decreased from $24 million for the nine months ended September 30, 2023 to $4 million for the nine months ended September 30, 2024.

This decrease was primarily due to a loss contingency recorded in the third quarter of 2023 and lower expense associated with the early termination of certain completion contracts between periods, partially offset by our receipt of 0.1 million shares of Antero Midstream common stock during the third quarter of 2024 as part of a judgment in a legal proceeding with an unaffiliated third-party.

Marketing Segment

1 unchanged sentence

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 $62 million, or $0.07 per Mcfe, for the nine months ended September 30, 2023 to $48 million, or $0.05 per Mcfe, for the nine months ended September 30, 2024, primarily due to lower firm transportation commitments between periods.

Net marketing expense increased from $11 million, or $0.04 per Mcfe, for the three months ended March 31, 2024 to $17 million, or $0.06 per Mcfe, for the three months ended March 31, 2025, primarily due to higher firm transportation tariffs and pipeline maintenance between periods.

M arketing revenue.

Marketing revenue decreased from $155 million for the nine months ended September 30, 2023 to $145 million for the nine months ended September 30, 2024, a decrease of $10 million, or 7%.

Marketing revenue decreased from $49 million for the three months ended March 31, 2024 to $26 million for the three months ended March 31, 2025, a decrease of $23 million, or 47%.

This fluctuation primarily resulted from the following:

● Natural gas marketing revenue decreased by $59 million between periods primarily due to lower natural gas marketing volumes and prices.

Lower natural gas marketing volumes accounted for a $50 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 natural gas prices accounted for a $9 million decrease 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 increased by $45 million between periods primarily due to higher oil marketing volumes and prices.

Higher oil marketing volumes accounted for a $35 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 $10 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 revenues were $4 million for the nine months ended September 30, 2024.

There were no NGLs marketing revenues for the nine months ended September 30, 2023.

● Natural gas marketing revenue decreased by $8 million between periods primarily due to lower natural gas marketing volumes.

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

Lower oil marketing volumes accounted for a $8 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 $6 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 decreased by $1 million between periods primarily due lower C3+ NGLs marketing volumes, partially offset by higher ethane marketing volumes and prices.

Marketing expense.

Marketing expense decreased from $217 million for the nine months ended September 30, 2023 to $193 million for the nine months ended September 30, 2024, a decrease of $24 million, or 11%.

Marketing expense decreased from $60 million for the three months ended March 31, 2024 to $43 million for the three months ended March 31, 2025, a decrease of $17 million, or 28%.

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 purchases decreased $47 million between periods, partially offset by increased oil and NGLs purchases of $38 million and $4 million, respectively.

The total cost of third-party commodity purchases decreased primarily due to lower natural gas marketing volumes and prices between periods, partially offset by higher oil prices and marketing volumes during the nine months ended September 30, 2024.

Firm transportation costs decreased $19 million from $82 million for the nine months ended September 30, 2023 to $63 million for the nine months ended September 30, 2024, primarily due to the reduction in firm transportation commitments between periods.

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

Contract termination, loss contingency, settlements and other operating expenses attributable to our marketing segment for the nine months ended September 30, 2023, relate to a $24 million payment for the early termination of our firm transportation commitment of 200,000 MMBtu per day on the Equitrans pipeline.

Our marketing segment did not incur any contract termination, loss contingency, settlements and other operating expenses for the nine months ended September 30, 2024.

The cost of third-party natural gas, NGLs and oil purchases decreased $7 million, $1 million and $13 million between periods, respectively.

The total cost of third-party commodity purchases decreased primarily due to lower marketing volumes between periods, partially offset by higher natural gas, NGLs and oil prices during the three months ended March 31, 2025.

Firm transportation costs increased from $17 million for the three months ended March 31, 2024 to $21 million, an increase of $4 million or 23%, for the three months ended March 31, 2025, primarily due to the increase in firm transportation tariffs and pipeline maintenance between periods.

Antero Midstream Segment

Antero Midstream revenue.

Revenue from the Antero Midstream segment increased from $782 million for the nine months ended September 30, 2023 to $819 million for the nine months ended September 30, 2024, an increase of $37 million.

This increase is primarily due to higher gathering and processing revenues of $66 million, partially offset by lower water handling revenues of $29 million.

The increased gathering and processing revenues between periods is primarily a result of the expiration of the growth incentive fee rebate program on December 31, 2023, increased throughput and annual CPI-based gathering and compression rate adjustments between periods.

The decreased water handling revenues between periods is primarily due to lower fresh water delivery volumes and lower water handling volumes that are billed at cost plus 3%, partially offset by higher blending volumes and an increased fresh water delivery rate due to an annual CPI-based adjustment during the nine months ended September 30, 2024.

Revenue from the Antero Midstream segment increased from $279 million for the three months ended March 31, 2024 to $291 million for the three months ended March 31, 2025, an increase of $12 million.

This increase is primarily due to higher gathering and processing revenues of $11 million and higher water handling revenues of $1 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 other fluid handling volumes, cost of service fees for blending and high-rate transfer services and wastewater handling costs, partially offset by decreased fresh water delivery volumes during the three months ended March 31, 2025.

Antero Midstream operating expense.

Total operating expense related to the Antero Midstream segment increased from $325 million for the nine months ended September 30, 2023 to $337 million for the nine months ended September 30, 2024, an increase of $12 million.

This increase is primarily due to higher general and administrative expense, including equity-based compensation expense, and depreciation expense between periods as well as lower gains on asset sale during the nine months ended September 30, 2024.

Total operating expense related to the Antero Midstream segment remained relatively consistent at $113 million for the three months ended March 31, 2024 and $114 million for the three months ended March 31, 2025.

Items Not Allocated to Segments

Interest expense.

Interest expense increased from $85 million for the nine months ended September 30, 2023 to $91 million for the nine months ended September 30, 2024, an increase of $6 million or 7%, primarily due to higher average Credit Facility borrowings between periods and higher benchmark interest rates during the nine months ended September 30, 2024.

Income tax expense (benefit) .

For the nine months ended September 30, 2023, we had income tax expense of $46 million, with an effective tax rate of 17%, related to our income before income taxes of $272 million.

For the nine months ended September 30, 2024, we had an income tax benefit of $2 million, with an effective tax rate of 9%, related to our loss before income taxes of $25 million.

The decrease in the effective tax rate between periods was primarily due to the effects of noncontrolling interests and our loss before income taxes during the nine months ended September 30, 2024.

Interest expense decreased from $30 million for the three months ended March 31, 2024 to $23 million for the three months ended March 31, 2025, a decrease of $7 million or 23%, primarily due to the redemption or repurchase of $116 million aggregate principal amount of our Senior Notes and the conversion of $26 million aggregate principal amount of our 2026 Convertible Notes between periods and lower average Credit Facility borrowings and interest rates during the three months ended March 31, 2025.

Income tax expense .

For the three months ended March 31, 2024, we had income tax expense of $6 million, with an effective tax rate of 15%, related to our income before income taxes of $41 million.

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

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

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 partnership .

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

1 unchanged sentence

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 September 30, 2024, 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 March 31, 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.

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

Net cash used in investing activities

Net cash provided by financing activities

Net cash used in financing activities

Net increase in cash and cash equivalents

Operating activities.

Net cash provided by operating activities was $682 million and $571 million for the nine months ended September 30, 2023 and 2024, respectively.

Net cash provided by operating activities decreased between periods primarily due to lower natural gas prices, changes in working capital and higher interest expense, partially offset by lower net marketing expense and higher NGLs and oil revenues between periods and a $202 million payment for early settlement of our swaption agreement in the nine months ended September 30, 2023.

Net cash provided by operating activities was $262 million and $458 million for the three months ended March 31, 2024 and 2025, respectively.

Net cash provided by operating activities increased between periods primarily due to higher natural gas and NGLs prices and lower interest expense, partially offset by changes in working capital, higher net marketing expense and lower oil revenues 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.

3 unchanged sentences

Investing activities.

Net cash used in investing activities decreased from $914 million for the nine months ended September 30, 2023 to $588 million for the nine months ended September 30, 2024, primarily due to lower well completions between periods, decreased drilling activity as a result of a lower rig count during the nine months ended September 30, 2024 and decreased leasing activity during the nine months ended September 30, 2024.

Net cash used in investing activities decreased from $227 million for the three months ended March 31, 2024 to $208 million for the three months ended March 31, 2025, primarily due to lower well completions between periods and decreased drilling activity during the three months ended March 31, 2025.

Financing activities.

Net cash provided by financing activities decreased from $232 million for the nine months ended September 30, 2023 to $17 million for the nine months ended September 30, 2024.

The decrease between periods is primarily due to lower net borrowings on our Credit Facility of $330 million and payment of debt issuance costs for our Unsecured Credit Facility of $6 million, partially offset by decreased share repurchases of $75 million and decreased distributions to the noncontrolling interests in Martica of $46 million between periods.

Net cash used in financing activities increased from $35 million for the three months ended March 31, 2024 to $250 million for the three months ended March 31, 2025.

The increase in net cash used in financing activities between periods is primarily due to Senior Note redemptions and repurchases of $118 million during the three months ended March 31, 2025, higher net repayments on our Credit Facility of $87 million, share repurchases of $10 million during the three months ended March 31, 2025 and increased payments of employee tax withholdings for the settlement of equity-based compensation awards of $7 million, partially offset by decreased distributions to the noncontrolling interests in Martica of $7 million between periods.

2025 Capital Budget and Capital Spending

5 unchanged sentences

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

On October 30, 2024, we announced a decrease in our net capital budget for drilling and completion to a range of $640 million to $660 million to reflect operational efficiencies and the deferral of a drilled but uncompleted pad due to low natural gas prices.

Our revised net capital budget for 2024 is $715 million to $760 million.

For the three months ended September 30, 2024, our total consolidated capital expenditures were $172 million, including drilling and completion costs of $148 million, leasehold acquisitions of $23 million and other capital expenditures of $1 million.

For the nine months ended September 30, 2024, our total consolidated capital expenditures were $578 million, including drilling and completion costs of $499 million, leasehold acquisitions of $69 million and other capital expenditures of $10 million.

For the three months ended March 31, 2025, our total consolidated capital expenditures were $188 million, including drilling and completion costs of $157 million, leasehold acquisitions of $30 million and other capital expenditures of $1 million.

Debt Agreements

10 unchanged sentences

Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the 2024 Form 10-K for information on our critical accounting estimates.

We evaluate the carrying amount of our proved natural gas, NGLs and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable.

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, 2024, 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 and nine months ended September 30, 2023 and 2024.

Based on future prices as of March 31, 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 three months ended March 31, 2024 and 2025.

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.

2 unchanged sentences

Off-Balance Sheet Arrangements

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

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

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