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Item 7. Management’s Discussion and Analysis

2026-02-11 compared with 2025-02-12 · 160 added, 136 removed, 359 unchanged (45% of the section changed)

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Risk Factors.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

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.

Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays.

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.

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

Our drilling opportunities are focused in the Appalachian Basin.

As of December 31, 2025, we held approximately 537,000 net acres in the Appalachian Basin.

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These reserve estimates have been prepared by our internal reserve engineers and management and audited by our independent reserve engineers.

As of December 31, 2024, we had 1,137 potential horizontal well locations on our existing leasehold acreage that were classified as proved, probable and possible and excludes 339 locations based on such locations being uneconomic at the SEC reserves prices for the year ended December 31, 2024.

As of December 31, 2025, we had 1,279 potential horizontal well locations on our existing leasehold acreage that were classified as proved, probable and possible.

We have three reportable segments:

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

(ii) marketing of excess firm transportation capacity;

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

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

All of our operations are conducted in the United States.

See Note 17—Reportable Segments to our consolidated financial statements for additional information.

Financing Highlights

Unsecured Credit Facility

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

in addition to our investment grade credit rating from Fitch Ratings, 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 (the “Unsecured Credit Facility”).

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 our consolidated financial statements for additional information.

Drilling Partnerships

2021-2024 Drilling Partnership

On February 17, 2021, we announced the formation of a drilling partnership with QL, an affiliate of Quantum Energy Partners, for our 2021 through 2024 drilling program.

Under the terms of the arrangement, QL funded development capital of 20% for wells spud in 2021 and 2024 and 15% for wells spud in 2022 and 2023, which funding amounts represent QL’s proportionate working interest in such wells.

Additionally, we received a carry of $29 million for each of the 2021 and 2022 tranches during the years ended December 31, 2022 and 2023 and a carry of $32 million for the 2023 tranche during the year ended December 31, 2024.

HG Acquisition

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

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

Pursuant to the same agreement, Antero Midstream Partners agreed to acquire 100% of the issued and outstanding equity interests of HG Midstream from HG Energy for cash consideration of $1.1 billion, subject to the terms and conditions thereof.

The HG Midstream Acquisition includes gathering pipelines and integrated water handling assets in the core of the Marcellus Shale in West Virginia.

These acquisitions closed on February 3, 2026.

The HG Acquisition was funded with borrowings under the Term Loan A Facility, net proceeds of the 2036 Notes (as defined below), borrowings under the Credit Facility and restricted cash.

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

2025 Drilling Partnership

On December 11, 2024, we entered into a drilling partnership with an unaffiliated third-party.

Under the terms of the arrangement, the third-party will participate in and fund a share of total development capital expenses for wells spud by Antero during the 2025 calendar year.

For each well spud during the 2025 calendar year, the third-party will receive a 15% working interest in such wells and will fund greater than 15% of total development capital expenses for such wells.

Subject to the preceding sentence, for any wells spud in the calendar year 2025, the third-party is obligated and responsible for its working interest share of costs and liabilities, and is entitled to its working interest share of revenues, associated with such wells for the life of such wells.

Additionally, for each well in the partnership, we will enter into an assignment, bill of sale and conveyance pursuant to which the third-party will be conveyed a proportionate working interest percentage in such well, which conveyances will not be subject to any reversion.

We intend to make certain modifications to our existing commercial arrangements with Antero Midstream to provide for on-pad compression with respect to certain wells and to provide a transition period through 2026 before certain water services would be provided under the existing agreements with Antero Midstream.

Utica Shale Divestiture

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

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

The Utica Shale Divestiture is expected to close in February 2026, subject to the satisfaction of certain customary closing conditions.

The net proceeds from the Utica Shale Divestiture are expected to be used for the repayment of long-term debt.

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

Financing Highlights

Credit Facility Maturity Date Extension

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

The terms of the Unsecured Credit Facility otherwise remain unchanged.

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

This is the first such extension.

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

Issuance of the 2036 Senior Notes

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

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

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

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

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

Notice of Redemption of 2029 Notes

On February 9, 2026, we notified the holders of our 7.625% senior notes due February 1, 2029 (the “2029 Notes”) of our intent to redeem all $365 million aggregate principal amount of our 2029 Notes on February 24, 2026, subject to certain conditions, including the closing of the Utica Shale Divestiture, at a redemption price of 101.271%, plus accrued and unpaid interest.

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 Royal Bank of Canada, RBC Capital Markets and JPMorgan Chase Bank, N.A.

(collectively, the “Banks”).

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

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

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

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

Debt Repurchase Program

During the year ended December 31, 2025, we redeemed the remaining $97 million aggregate principal amount of our 8.375% senior notes due July 15, 2026 (the “2026 Notes”) at a redemption price of 102.094% of the principal amount thereof, plus accrued and unpaid interest.

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

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

Share Repurchase Program

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

Through our share repurchase program, during the year ended December 31, 2025, we repurchased and retired approximately 4 million shares of our common stock at a total cost of $136 million.

As of December 31, 2025, we have approximately $914 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 and ethane decreased significantly, while benchmark prices for oil remained consistent and benchmark prices for C3+ NGLs increased during the year ended December 31, 2024 as compared to the year ended December 31, 2023.

As a result of the lower benchmark natural gas and ethane prices and higher benchmark C3+ NGLs prices during the year ended December 31, 2024, we experienced a decrease in price realizations for natural gas and ethane products and an increase in price realization for C3+ NGLs products during the same period.

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

Benchmark prices for natural gas and ethane increased significantly, while benchmark prices for C3+ NGLs and oil decreased, during the year ended December 31, 2025 as compared to the year ended December 31, 2024.

As a result of the higher benchmark natural gas and ethane prices during the year ended December 31, 2025, we experienced an increase in price realization for natural gas and ethane products, partially offset by the effects of decreased benchmark NGLs and oil prices as compared to the year ended December 31, 2024.

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

This volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.

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

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

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

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Hedge Position

Antero Resources (Excluding Martica)

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.

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 2023 and 2024, substantially all of our production was unhedged.

Assuming our 2025 production is the same as our production in 2024, approximately 3% of our total production for 2025 is hedged through fixed price commodity swaps.

As of December 31, 2024, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of $45 million.

For the years ended December 31, 2024 and 2025, 4% and 8%, respectively, of our production was hedged through commodity derivatives.

Assuming our 2026 production is the same as our production in 2025, approximately 42% of our total production is hedged through commodity derivatives.

In addition, we also have derivative contracts in place for a portion of our 2027 production.

As of December 31, 2025, the estimated fair value of our commodity derivative contracts was a net asset of $81 million.

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

Our consolidated VIE, Martica, also maintains a portfolio of fixed price swap 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 December 31, 2024, the estimated fair value of Martica’s commodity derivative contracts was a net liability of $2 million.

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 December 31, 2025, Martica had no derivative instruments.

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

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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.

For example, CPI for all urban consumers increased 4.1% from December 2022 to December 2023 and an additional 2.9% from December 2023 to December 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 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, we continue to be impacted by the increased federal funds interest rate.

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

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

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

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

See “—Results of Operations” for additional information.

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, other global trade restrictions and conflicts, including those in the Middle East, Iran 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 .

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.

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We utilize derivative instruments to hedge future sales prices for our production when circumstances warrant.

We currently utilize call and embedded put options, collar contracts and fixed price contracts for a nominal portion of our natural gas in which we receive or pay the difference between a fixed price and the variable market price received.

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

Assuming our 2025 production is the same as our production in 2024, approximately 3% of our total production for 2025 is hedged through fixed price commodity swaps.

We currently utilize call and embedded put options, basis swap contracts that hedge the difference between the NYMEX index price and a local index price, collar contracts and fixed price contracts for a portion of our natural gas in which we receive or pay the difference between a fixed price and the variable market price received.

Assuming our 2026 production is the same as our production in 2025, approximately 42% of our total production for 2026 is hedged through commodity derivatives.

In addition, we have derivative contracts in place for a portion of our 2027 production.

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

At the end of each accounting period, we estimate the fair value of these derivative instruments, because we have not elected hedge accounting, we recognize changes in the fair value of these derivative instruments in earnings.

At the end of each accounting period, we estimate the fair value of these derivative instruments, and because we have not elected hedge accounting, we recognize changes in the fair value of these derivative instruments in earnings.

We expect continued volatility in the prices we receive for our production and the fair value of our derivative instruments.

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They also include costs to process and extract NGLs from our liquids-rich gas and to transport our natural gas, NGLs and oil to market.

We often enter into fixed price long- term contracts that secure transportation and processing capacity, which may include minimum volume commitments, the cost for which is included in these expenses to the extent that they are not associated with excess capacity.

We often enter into fixed price long-term contracts that secure transportation and processing capacity, which may include

minimum volume commitments, the cost for which is included in these expenses to the extent that they are not associated with excess capacity.

Costs associated with excess capacity are included in marketing expenses.

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We enter into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure capacity on major pipelines.

● Exploration and mine expenses.

These are primarily costs related to unsuccessful leasing efforts, as well as geological and geophysical costs, including seismic costs, costs of unsuccessful exploratory dry holes and costs of other exploratory activities, including costs associated with our sand mine.

● Exploration expenses.

● Impairment of property and equipment.

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As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions.

As of December 31, 2023 and 2024, we had fixed interest rates ranging from 5.375% to 8.375% on our Senior Notes with an aggregate principal balance of $1.1 billion.

As of December 31, 2024 and 2025, we had fixed interest rates on our Senior Notes ranging from 5.375% to 8.375% and 5.375% to 7.625%, respectively, with an aggregate principal balance of $1.1 billion and $1.0 billion, respectively.

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

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We have three reportable segments:

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

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

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

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

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

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Production and ad valorem taxes

Exploration and mine expenses

General and administrative (excluding equity-based compensation)

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Accretion of asset retirement obligations

Loss (gain) on sale of assets

Loss on sale of assets

Contract termination, loss contingency, settlements and other operating expenses

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Accretion of asset retirement obligations

Loss on sale of assets

Gain on sale of assets

Loss on long-lived assets

Contract termination, loss contingency, settlements and other operating expenses

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(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 for 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.

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 years ended December 31, 2024 and 2025 includes $2 million and $1 million, respectively, of proceeds related to a take-or-pay contract.

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Natural gas sales .

Revenues from sales of natural gas decreased from $2.2 billion for the year ended December 31, 2023 to $1.8 billion for the year ended December 31, 2024, a decrease of $0.4 billion, or 17%.

Lower commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2024 accounted for an approximate $313 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 $61 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 $1.8 billion for the year ended December 31, 2023 to $2.1 billion for the year ended December 31, 2024, an increase of $0.3 billion, or 13%.

Higher commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2024 accounted for an approximate $153 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 during the year ended December 31, 2024 accounted for an approximate $77 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 natural gas increased from $1.8 billion for the year ended December 31, 2024 to $2.9 billion for the year ended December 31, 2025, an increase of $1.1 billion, or 58%.

Higher commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2025 accounted for an approximate $1.0 billion increase in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes).

Higher natural gas production volumes accounted for an approximate $34 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 $2.1 billion for the year ended December 31, 2024 to $2.0 billion for the year ended December 31, 2025, a decrease of $0.1 billion, or 4%.

Lower C3+ NGLs commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2025 accounted for an approximate $143 million decrease in year-over-year NGLs revenues (calculated as the change in the year-to-year average price times current year production volumes), partially offset by higher ethane commodity prices during the year ended December 31, 2025 that accounted for an approximate $85 million increase in year-over-year NGLs revenues (calculated as the change in the year-to-year average price times current year production volumes).

Lower NGLs production volumes during the year ended December 31, 2025 accounted for an approximate $23 million decrease in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price).

Revenues from sale of oil decreased from $230 million for the year ended December 31, 2024 to $150 million for the year ended December 31, 2025, a decrease of $80 million, or 35%.

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For the years ended December 31, 2024 and 2025, our commodity hedges resulted in derivative fair value gains of $1 million and $111 million, respectively.

For the year ended December 31, 2023, commodity derivative fair value gains included $25 million of net cash payments for settled derivative losses, as well as $202 million for payments on derivatives that were settled prior to their contractual settlement dates.

For the year ended December 31, 2024, commodity derivative fair value gains included $10 million of net cash proceeds for settled derivative gains.

For the year ended December 31, 2025, commodity derivative fair value gains included $17 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, monetized or terminated 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.

Additionally, substantially all of our production is currently unhedged for 2025 and beyond, which limits our exposure to volatility in the fair value of our derivative instruments related to commodity price changes in the future.

Amortization of deferred revenue, VPP.

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Lease operating expense .

Lease operating expense remained relatively consistent for the years ended December 31, 2023 and 2024 at $118 million and $119 million, respectively.

On a per-unit basis, lease operating expense decreased from $0.10 per Mcfe for the year ended December 31, 2023 to $0.09 per Mcfe for the year ended December 31, 2024 primarily due to lower water disposal costs and workover expense between periods.

Lease operating expense increased from $119 million, or $0.09 per Mcfe, for the year ended December 31, 2024 to $135 million, or $0.11 per Mcfe, for the year ended December 31, 2025, an increase of $16 million primarily due to increased produced water volumes and trucking and disposal costs as a result of our completion activity timing during the year ended December 31, 2025, as well as higher oilfield service and workover costs between periods.

Gathering, compression, processing and transportation expense.

Gathering, compression, processing and transportation expense remained relatively consistent at $2.6 billion and $2.7 billion for the years ended December 31, 2023 and 2024, respectively.

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 year ended December 31, 2023 to $0.72 per Mcfe for the year ended December 31, 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 year ended December 31, 2023, we earned growth incentive fee rebates of $52 million.

● Processing costs on a per unit basis increased from $0.82 per Mcfe for the year ended December 31, 2023 to $0.85 per Mcfe for the year ended December 31, 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 on a per unit basis decreased from $0.62 per Mcfe for the year ended December 31, 2023 to $0.59 per Mcfe and for the year ended December 31, 2024, primarily due to lower fuel costs as a result of lower natural gas prices and lower demand fees between periods.

Gathering, compression, processing and transportation expense increased from $2.7 billion for the year ended December 31, 2024 to $2.9 billion for the year ended December 31, 2025, an increase of $0.2 billion, or 6%.

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 year ended December 31, 2024 to $0.75 per Mcfe for the year ended December 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 $0.85 per Mcfe for the year ended December 31, 2024 to $0.90 per Mcfe for the year ended December 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 $0.59 per Mcfe for the year ended December 31, 2024 to $0.62 per Mcfe for the year ended December 31, 2025, primarily due to higher fuel costs as a result of higher natural gas prices between periods and higher demand fees for certain pipelines during the year ended December 31, 2025.

Production and ad valorem tax expense.

Production and ad valorem taxes increased from $159 million for the year ended December 31, 2023 to $208 million for the year ended December 31, 2024, an increase of $49 million or 31%, primarily due to higher ad valorem taxes, partially offset by lower natural gas and oil prices during the year ended December 31, 2024.

Production and ad valorem taxes as a percentage of natural gas revenues increased from 7% for the year ended December 31, 2023 to 11% for the year ended December 31, 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 $208 million for the year ended December 31, 2024 to $163 million for the year ended December 31, 2025, a decrease of $45 million or 21%, primarily due to lower ad valorem taxes of $115 million between periods, partially offset by higher severance taxes of $70 million as a result of increased natural gas prices during the year ended December 31, 2025.

Production and ad valorem taxes as a percentage of natural gas revenues decreased from 11% for the year ended December 31, 2024 to 6% for the year ended December 31, 2025, primarily as a result of lower ad valorem taxes between periods.

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

General and administrative expense.

General and administrative expense (excluding equity-based compensation expense) remained relatively consistent at $165 million, or $0.13 per Mcfe and $163 million, or $0.13 per Mcfe, for the years ended December 31, 2023 and 2024, respectively.

General and administrative expense (excluding equity-based compensation expense) increased from $163 million for the year ended December 31, 2024 to $172 million for the year ended December 31, 2025, an increase of $9 million, or 5%, primarily due to higher professional service fees and increased salary and wage expense as a result of increased employee headcount between periods.

We had 616 and 632 employees as of December 31, 2024 and 2025, respectively.

General and administrative expense on a per unit basis (excluding equity-based compensation) increased from $0.13 per Mcfe for the year ended December 31, 2024 to $0.14 per Mcfe for the year ended December 31, 2025 primarily as a result of higher overall costs between periods.

Equity-based compensation expense .

Non-cash equity-based compensation expense increased from $60 million for the year ended December 31, 2023 to $66 million for the year ended December 31, 2024, an increase of $6 million or 12%.

This increase was primarily due to higher restricted stock unit (“RSU”) award expense of $9 million between periods, partially offset by lower performance share unit (“PSU”) award expense of $3 million between periods.

Non-cash equity-based compensation expense decreased from $66 million for the year ended December 31, 2024 to $61 million for the year ended December 31, 2025, a decrease of $5 million or 9%.

This decrease was primarily due to lower performance share unit (“PSU”) award grants between periods.

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

Depletion, depreciation and amortization expense .

DD&A expense increased from $747 million for the year ended December 31, 2023 to $762 million for the year ended December 31, 2024, an increase of $15 million or 2%, primarily due to higher production volumes between periods.

On a per-unit basis, DD&A expense remained consistent at $0.61 per Mcfe for the years ended December 31, 2023 and 2024.

DD&A expense decreased from $762 million for the year ended December 31, 2024 to $750 million for the year ended December 31, 2025, a decrease of $12 million or 2%, primarily as a result of increased proved reserve volumes due to higher commodity prices.

DD&A expense per Mcfe remained relatively consistent for the years ended December 31, 2024 and 2025 at $0.61 and $0.60, respectively.

Impairment of property and equipment .

Impairment of property and equipment decreased from $51 million for the year ended December 31, 2023 to $47 million for the year ended December 31, 2024, a decrease of $4 million, or 8%, primarily due to lower impairments of expiring leases between periods.

Impairment of property and equipment decreased from $47 million for the year ended December 31, 2024 to $29 million for the year ended December 31, 2025, a decrease of $18 million, or 38 %, primarily due to lower impairments of expiring leases between periods as a result of our maintenance capital program.

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, settlements and other operating expenses .

Contract termination, loss contingency, settlements and other operating expenses attributable to our exploration and production segment decreased from $29 million for the year ended December 31, 2023 to $5 million for the year ended December 31, 2024.

This decrease was primarily due to a loss contingency recorded during the year ended December 31, 2023 and lower expense associated with the early termination of certain drilling and completion contracts between periods.

Contract termination, loss contingency, settlements and other operating expenses attributable to our exploration and production segment increased from $5 million for the year ended December 31, 2024 to $28 million for the year ended December 31, 2025, an increase of $23 million.

This increase was primarily due to loss contingencies recorded during the year ended December 31, 2025.

See Note 15—Contingencies to our consolidated financial statements for additional information.

Marketing Segment

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

Net marketing expense decreased from $79 million, or $0.06 per Mcfe, for the year ended December 31, 2023 to $66 million, or $0.05 per Mcfe, for the year ended December 31, 2024, primarily due to lower firm transportation commitments between periods.

Net marketing expense remained relatively consistent at $66 million, or $0.05 per Mcfe, for the year ended December 31, 2024 and $64 million, or $0.05 per Mcfe, for the year ended December 31, 2025.

Marketing revenue.

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This fluctuation primarily resulted from the following:

● Natural gas marketing revenue decreased by $77 million between periods primarily due to lower natural gas marketing volumes and prices.

Lower natural gas marketing volumes accounted for a $68 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 $46 million between periods primarily due to higher oil marketing volumes and prices.

Higher oil marketing volumes accounted for a $39 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 an approximate $7 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 year ended December 31, 2024.

There were no NGLs marketing revenues for the year ended December 31, 2023.

● Natural gas marketing revenue decreased by $18 million between periods primarily due to lower natural gas marketing volumes, partially offset by higher natural gas prices.

Lower natural gas marketing volumes accounted for a $24 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher natural gas prices accounted for a $6 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

● Oil marketing revenue decreased by $53 million between periods primarily due to lower oil marketing volumes and prices.

Lower oil marketing volumes accounted for a $31 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower oil prices accounted for an $22 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).

● NGLs marketing revenue increased by $8 million between periods primarily due to higher ethane and C3+ NGLs marketing volumes and higher ethane prices.

Marketing expense.

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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 $62 million between periods, partially offset by increased oil and NGLs purchases of $37 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 and NGLs marketing volumes during the year ended December 31, 2024.

Firm transportation costs decreased $19 million from $105 million for the year ended December 31, 2023 to $86 million for the year ended December 31, 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 year ended December 31, 2023 relate to a $24 million payment for the early termination of our firm transportation commitment of 200,000 MMBtu/d on the Equitrans pipeline.

Our marketing segment did not incur any contract termination, loss contingency, settlements and other operating expenses for the year ended December 31, 2024.

Antero Midstream Segment

The cost of third-party commodity purchases decreased by $60 million between periods primarily due to lower marketing volumes and oil prices between periods, partially offset by higher natural gas prices during the year ended December 31, 2025.

Firm transportation costs increased $5 million between periods primarily due to the increase in fuel costs and lower pipeline utilization due to maintenance during the year ended December 31, 2025.

Equity Method Investment in Antero Midstream Segment

Antero Midstream revenue.

Revenue from the Antero Midstream segment increased from $1.0 billion for the year ended December 31, 2023 to $1.1 billion for the year ended December 31, 2024, an increase of $0.1 billion, or 6%.

This increase is primarily due to higher gathering and compression revenues of $84 million, partially offset by lower water handling revenues of $20 million.

The increased gathering and compression 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 and other fluid handling volumes, partially offset by an increased fresh water delivery rate due to an annual CPI-based adjustment during the year ended December 31, 2024.

Revenue from the Antero Midstream segment increased from $1.1 billion for the year ended December 31, 2024 to $1.2 billion for the year ended December 31, 2025, an increase of $0.1 billion.

This increase is primarily due to higher gathering and processing revenues of $61 million and higher water handling revenues of $21 million.

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

The increased water handling revenues between periods is primarily due to higher wastewater trucking and blending volumes, increased wastewater trucking and disposal costs that are billed at cost plus 3% higher fresh water delivery volumes and increased blending cost of service fees during the year ended December 31, 2025, as well as an increase to the fresh water delivery rate as a result of the annual CPI-based rate adjustment between periods.

Antero Midstream operating expense.

Total operating expense related to the Antero Midstream segment increased from $430 million for the year ended December 31, 2023 to $447 million for the year ended December 31, 2024, an increase of $17 million, or 4%.

This increase is primarily due to higher gathering and compression expense as a result of increased throughput during the year ended December 31, 2024, as well as higher general and administrative expense, including equity-based compensation expense, and depreciation expense between periods, partially offset by lower gains on asset sale during the year ended December 31, 2024.

Total operating expense related to the Antero Midstream segment increased from $447 million for the year ended December 31, 2024 to $544 million for the year ended December 31, 2025, an increase of $97 million.

This increase is primarily due to a loss on long-lived assets of $87 million related to the expected divestiture of its Utica Shale midstream assets, higher direct operating expenses of $14 million as a result of higher wastewater trucking and disposal costs, increased blending costs, increased fresh water delivery volumes, increased throughput, higher gathering and compression costs for assets acquired during the second quarter of 2024 and increased heavy maintenance expense during the year ended December 31, 2025, partially offset by lower depreciation expense of $5 million related to Antero Midstream’s program to repurpose underutilized compressor units to expand existing or construct new compressor stations between periods, partially offset by assets placed in service between periods.

Items Not Allocated to Segments

Interest expense.

Interest expense remained consistent at $118 million for the years ended December 31, 2023 and 2024.

Interest expense decreased from $118 million for the year ended December 31, 2024 to $84 million for the year ended December 31, 2025, a decrease of $34 million or 29%, primarily due to the redemption or repurchase of $139 million aggregate principal amount of our 2026 Notes and 2029 Notes, as well as lower average Credit Facility borrowings and interest rates during the year ended December 31, 2025.

Loss on early extinguishment of debt.

During the year ended December 31, 2024, we recognized a loss on early debt extinguishment of $1 million related to the amendment and restatement of our senior revolving credit facility.

During the year ended December 31, 2025, we recognized a loss on early debt extinguishment of $4 million related to the redemption of the remaining $97 million aggregate principal amount of our 2026 Notes at a redemption price of 102.094% of the principal amount thereof, plus accrued and unpaid interest, and the repurchase of $42 million aggregate principal amount of our 2029 Notes through open market transactions at a weighted average price of approximately 103% of the principal amount thereof, plus accrued and unpaid interest.

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

Transaction expense.

There were no transaction expenses incurred during the year ended December 31, 2024.

During the year ended December 31, 2025, we incurred $4 million of transaction expense related to the HG Acquisition.

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

Income tax (expense) benefit.

For the year ended December 31, 2023, we had income tax expense of $64 million, with an effective tax rate of 17.6%, due to income before income taxes of $361 million.

Our effective tax rate for the year ended December 31, 2023 was different than the statutory rate of 21% primarily due to the effects of state income taxes, the dividends received deduction, equity-based compensation expenses, noncontrolling interests, the effects of a West Virginia apportionment tax law change enacted in 2021 and changes in Pennsylvania’s corporate income tax rate.

For the year ended December 31, 2024, we had an income tax benefit of $118 million primarily due to R&D tax credits of $95 million, loss before income taxes of $24 million and a reduction to our state NOL carryforward valuation allowance of $12 million.

For the year ended December 31, 2024, we recognized an income tax benefit of $118 million primarily due to R&D tax credits of $95 million, loss before income taxes of $24 million and a reduction to our state NOL carryforward valuation allowance of $12 million.

For the year ended December 31, 2025, we recognized income tax expense of $216 million, with an effective tax rate of 24%, related to our income before income taxes of $890 million.

Our effective tax rate for the year ended December 31, 2025 was different than the federal statutory rate of 21% primarily due to the effects of state income taxes, equity-based compensation expenses, dividends received deduction and noncontrolling interests.

See Note 13—Income Taxes to our consolidated financial statements for additional information.

As of December 31, 2025, we had U.S.

federal and state NOL carryforwards of $0.6 billion and $1.9 billion, respectively.

federal and state NOL carryforwards of approximately $960 million and $1.9 billion, respectively.

Many of these NOL carryforwards expire at various dates between 2026 and 2044 while others have no expiration date.

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Capital Resources and Liquidity

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

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

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

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Our commodity hedge position can provide us with liquidity for the portion of our production that is hedged because it provides us with the relative certainty of our future expected revenues for such production despite potential declines in the price of natural gas.

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

Assuming our 2025 production is the same as our production in 2024, approximately 3% of our total production for 2025 is hedged through fixed price commodity swaps.

Our ability to make significant acquisitions for cash would require us to utilize borrowings on the Credit Facility or obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us, or at all.

Assuming our 2026 production is the same as our production in 2025, approximately 42% of our total production for 2026 is hedged through commodity derivatives.

Our ability to make significant acquisitions for cash would require us to utilize borrowings under the Credit Facility or obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us, or at all.

The Credit Facility is funded by a syndicate of 13 banks.

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We completed 61 net horizontal wells during the year ended December 31, 2025.

Our net capital budget for 2025 is $725 million to $800 million.

Our budget includes:

a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures.

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 assumes the closing of the Utica Shale Divestiture during February 2026.

We do not budget for acquisitions.

During 2026, we plan to complete 70 to 80 net horizontal wells in the Appalachian Basin.

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

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

Our capital budget may be adjusted as business conditions warrant as the amount, timing and allocation of capital expenditures is largely discretionary and within our control.

If natural gas, NGLs and oil prices decline, or costs increase, to levels that do not generate an acceptable level of corporate returns, we may defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity, and to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows.

Based on strip prices as of December 31, 2024, we believe that net cash provided from 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 December 31, 2025, we believe that net cash provided from operating activities and available borrowings under the Credit Facility, the net proceeds of the offering of the 2036 Notes, borrowings under the Term Loan A Facility and net proceeds from the Utica Shale Divestiture 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.

For more information on our outstanding indebtedness, see Note 7—Long-Term Debt to our consolidated financial statements.

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Net cash used in investing activities

Net cash provided by (used in) financing activities

Net increase in cash and cash equivalents

Net cash used in financing activities

Net increase in cash, cash equivalents and restricted cash

Year Ended December 31, 2024 Compared to Year Ended December 31, 2025

Operating activities.

Net cash provided by operating activities was $995 million and $849 million for the years ended December 31, 2023 and 2024, respectively.

Net cash provided by operating activities decreased primarily due to lower natural gas prices and changes in working capital, partially offset by increased NGLs revenue due to higher C3+ NGLs prices, lower contract termination, loss contingency and settlements expense and lower net marketing expense between periods and a $202 million payment for early settlement of our swaption agreement in the year ended December 31, 2023.

Net cash provided by operating activities was $0.8 billion and $1.6 billion for the years ended December 31, 2024 and 2025, respectively.

Net cash provided by operating activities increased between periods primarily due to higher natural gas revenues, lower ad valorem taxes, lower interest expense and changes in working capital, partially offset by lower NGLs and oil revenues, higher lease operating expense and higher gathering, compression, processing and transportation expense during the year ended December 31, 2025.

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 decreased from $1.1 billion for the year ended December 31, 2023 to $0.7 billion for the year ended December 31, 2024, primarily due to lower well completions between periods, decreased drilling activity as a result of a lower rig count between periods and decreased leasing activity during the year ended December 31, 2024.

During the years ended December 31, 2023 and 2024, we completed 70 wells and 41 wells, respectively.

Net cash used in investing activities increased from $0.7 billion for the year ended December 31, 2024 to $1.1 billion for the year ended December 31, 2025, primarily due to asset acquisitions of $253 million of during the year ended December 31, 2025 and increased drilling and completions and leasing activity of $71 million and $38 million, respectively, between periods, partially offset by higher proceeds from asset sales of $7 million between periods primarily due to oil and gas property trades during the year ended December 31, 2025.

The increase in our drilling and completions activity is primarily due to completing 20 additional net wells between periods.

Financing activities.

Net cash provided by financing activities was $146 million for the year ended December 31, 2023.

Net cash used in financing activities was $135 million for the year ended December 31, 2024.

This decrease in cash provided by financing activities between periods is primarily due lower net borrowings on our Credit Facility of $406 million, partially offset by decreased share repurchases of $75 million and lower distributions to the noncontrolling interests in Martica of $55 million between periods.

Net cash used in financing activities increased from $135 million for the year ended December 31, 2024 to $343 million for the year ended December 31, 2025, primarily due to redemptions and repurchases of our Senior Notes of $142 million during the year ended December 31, 2025, share repurchases of $136 million during the year ended December 31, 2025, net borrowings on our Credit Facility of $45 million during the year ended December 31, 2025 and higher payment of debt issuance costs for our Unsecured Credit Facility of $3 million, partially offset by lower distributions to the noncontrolling interests in Martica of $4 million between periods and net repayments on our Credit Facility of $24 million during the year ended December 31, 2024.

Year Ended December 31, 2023 Compared to Year Ended December 31, 2024

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Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in Note 2—Summary of Significant Accounting Policies to our consolidated financial statements.

The preparation of our 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.

The preparation of our 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.

We evaluate our estimates and assumptions on a regular basis.

We base our estimates on historical experience and various other assumptions that are believed to be reasonable under

the circumstances, the results of which form the basis for making judgments about the reported amounts in our consolidated financial statements that are not readily apparent from other sources.

We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the reported amounts in our consolidated financial statements that are not readily apparent from other sources.

Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements.

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Based on current future commodity prices, we currently do not anticipate having to record any impairment charge for our proved properties in the near future.

reporting period, which would require us to further evaluate if an impairment charge would be necessary.

Estimated undiscounted future net cash flows are sensitive to commodity price swings and a decline in prices could result in the carrying amount exceeding the estimated undiscounted future net cash flows at the end of a future reporting period, which would require us to further evaluate if an impairment charge would be necessary.

For our Utica and Marcellus properties, strip pricing would have to decline by more than 6% and 20%, respectively, from year end 2025 levels before further evaluation of those properties would be required in order to determine if an impairment charge is necessary.

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However, we are unable to predict commodity prices with any greater precision than the futures market.

We believe that the estimates and assumptions related to our undiscounted future net cash flows and the fair value of our proved properties is 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.

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.

Derivative Instruments

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We record a deferred income tax benefit to the extent our deferred income tax assets exceed our deferred income tax liabilities.

We are subject to state and federal income taxes, but are currently not in a cash tax paying position with respect to federal income taxes.

We are subject to state and U.S.

federal income taxes, but are currently not in a cash tax paying position with respect to U.S.

federal income taxes.

We record a valuation allowance or reserve for an uncertain tax position when we believe all or a portion of our deferred income tax assets will not be realized.

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The amount of deferred income tax assets considered realizable could change based upon the amounts of taxable income actually generated, or as estimates of future taxable income change.

As of December 31, 2024, we have recognized a valuation allowance of $43 million related to Colorado, Oklahoma and West Virginia state NOL carryforwards that we do not expect to realize due to expected future reduced income tax apportionment in those states.

As of December 31, 2025, we have recognized a valuation allowance of $39 million related to Colorado and Oklahoma state NOL carryforwards that we do not expect to realize due to expected future reduced income tax apportionment in those states.

In addition, as of December 31, 2025, we have recorded a reserve for uncertain tax positions of $51 million related to our R&D tax credits.

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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-K

Item 7. Management’s Discussion and Analysis