Matador Resources Co

Previous wording

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include those described in the “Risk Factors” section of the Annual Report, as well as the following factors, among others: general economic conditions, including the effects of inflation and interest rates; tariffs and trade tensions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids (“NGL”) prices and the demand for oil, natural gas and NGLs; our ability to replace reserves and efficiently develop current reserves; the operating results of our midstream business’s oil, natural gas and water gathering and transportation systems, pipelines and facilities, the acquiring of third-party business and the drilling of any additional salt water disposal wells; costs of operations; delays and other difficulties related to producing oil, natural gas and NGLs or the construction, expansion or operation of our midstream assets; delays and other difficulties related to regulatory and governmental approvals and restrictions; impact on our operations due to seismic events; availability of sufficient capital to execute our business plan, including from future cash flows, capital markets, available borrowing capacity under our revolving credit facilities and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate acquisitions, including the Cardinal Acquisition, the Paloma Acquisition and the Ridge Runner Acquisition (each as defined below); the operating results of and availability of any potential distributions from our joint ventures; weather conditions, environmental conditions and natural disasters; our ability to consummate the Paloma Acquisition and the Ridge Runner Acquisition in the anticipated timeframes or at all; risks related to the satisfaction or waiver of the conditions to closing the Paloma Acquisition and the Ridge Runner Acquisition in the anticipated timeframes or at all; risks related to obtaining the requisite regulatory approvals for the Paloma Acquisition and the Ridge Runner Acquisition; disruption from our acquisitions, including the Cardinal Acquisition, the Paloma Acquisition and the Ridge Runner Acquisition, making it more difficult to maintain business and operational relationships; significant transaction costs associated with our acquisitions, including the Cardinal Acquisition, the Paloma Acquisition and the Ridge Runner Acquisition; evolving cybersecurity risks; the risk of litigation and/or regulatory actions related to our acquisitions, including the Cardinal Acquisition, the Paloma Acquisition and the …

Excerpt shortened here; the source contains the full paragraph.

Current wording

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include those described in the “Risk Factors” section of the Annual Report, as well as the following factors, among others: general economic conditions, including the effects of inflation and interest rates; tariffs and trade tensions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids (“NGL”) prices and the demand for oil, natural gas and NGLs; our ability to replace reserves and efficiently develop current reserves; the operating results of our midstream business’s oil, natural gas and water gathering and transportation systems, pipelines and facilities, the acquisition of third-party businesses and the drilling of any additional salt water disposal wells; costs of operations; delays and other difficulties related to producing oil, natural gas and NGLs or the construction, expansion or operation of our midstream assets; delays and other difficulties related to regulatory and governmental approvals and restrictions; impact on our operations due to seismic events; availability of sufficient capital to execute our business plan, including from future cash flows, capital markets, available borrowing capacity under our revolving credit facilities and otherwise; our ability to make acquisitions on economically acceptable terms; disruption from our acquisitions, including the Cardinal Acquisition and the Paloma Acquisition (each as defined below), making it more difficult to maintain business and operational relationships; significant transaction costs associated with our acquisitions, including the Cardinal Acquisition and the Paloma Acquisition; evolving cybersecurity risks; the risk of litigation and/or regulatory actions related to our acquisitions, including the Cardinal Acquisition and the Paloma Acquisition; and the other factors discussed below and elsewhere in this Quarterly Report and in other documents that we file with or furnish to the SEC, all of which are difficult to predict. Forward-looking statements may include statements about:

Previous wording

•the integration of acquisitions, including the Cardinal Acquisition, the Paloma Acquisition and the Ridge Runner Acquisition, with our business;

Current wording

•the integration of acquisitions, including the Cardinal Acquisition and the Paloma Acquisition, with our business;

Previous wording

For the three months ended June 30, 2026, our total oil equivalent production was 19.6 million BOE, and our average daily oil equivalent production was 215,631 BOE per day, of which 126,106 Bbl per day, or 58%, was oil and 537.1 MMcf per day, or 42%, was natural gas. Our average daily oil production of 126,106 Bbl per day for the three months ended June 30, 2026 increased 3% year-over-year from 122,875 Bbl per day for the three months ended June 30, 2025. Our average daily natural gas production of 537.1 MMcf per day for the three months ended June 30, 2026 increased 4% year-over-year from 516.8 MMcf per day for the three months ended June 30, 2025. The Delaware Basin contributed 100% of our daily oil production and 97% of our daily natural gas production in each of the second quarters of 2026 and 2025.

Current wording

For the three months ended September 30, 2026, our total oil equivalent production was 21.2 million BOE, and our average daily oil equivalent production was 230,470 BOE per day, of which 132,019 Bbl per day, or 57%, was oil and 590.7 MMcf per day, or 43%, was natural gas. Our average daily oil production of 132,019 Bbl per day for the three months ended September 30, 2026 increased 10% year-over-year from 119,556 Bbl per day for the three months ended September 30, 2025. Our average daily natural gas production of 590.7 MMcf per day for the three months ended September 30, 2026 increased 10% year-over-year from 537.8 MMcf per day for the three months ended September 30, 2025. The Delaware Basin contributed 100% of our daily oil production and 97% of our daily natural gas production in the third quarter of 2026, as compared to 100% of our daily oil production and 94% of our daily natural gas production in the third quarter of 2025.

Previous wording

For the second quarter of 2026, we reported net income attributable to Matador shareholders of $390.7 million, or $3.15 per diluted common share, on a GAAP basis, as compared to net income attributable to Matador shareholders of $150.2 million, or $1.21 per diluted common share, for the second quarter of 2025. For the second quarter of 2026, our Adjusted EBITDA, a non‑GAAP financial measure, was $781.0 million, as compared to Adjusted EBITDA of $594.2 million during the second quarter of 2025.

Current wording

For the third quarter of 2026, we reported net income attributable to Matador shareholders of $172.1 million, or $1.39 per diluted common share, on a GAAP basis, as compared to net income attributable to Matador shareholders of $176.4 million, or $1.42 per diluted common share, for the third quarter of 2025. For the third quarter of 2026, our Adjusted EBITDA, a non‑GAAP financial measure, was $738.3 million, as compared to Adjusted EBITDA of $566.5 million during the third quarter of 2025.

Previous wording

For the six months ended June 30, 2026, we reported net income attributable to Matador shareholders of $354.8 million, or $2.86 per diluted common share, on a GAAP basis, as compared to net income attributable to Matador shareholders of $390.3 million, or $3.12 per diluted common share, for the six months ended June 30, 2025. For the six months ended June 30, 2026, our Adjusted EBITDA, a non‑GAAP financial measure, was $1.36 billion, as compared to Adjusted EBITDA of $1.24 billion for the six months ended June 30, 2025.

Current wording

For the nine months ended September 30, 2026, we reported net income attributable to Matador shareholders of $526.9 million, or $4.24 per diluted common share, on a GAAP basis, as compared to net income attributable to Matador shareholders of $566.7 million, or $4.54 per diluted common share, for the nine months ended September 30, 2025. For the nine months ended September 30, 2026, our Adjusted EBITDA, a non‑GAAP financial measure, was $2.10 billion, as compared to Adjusted EBITDA of $1.80 billion for the nine months ended September 30, 2025.

Previous wording

For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “—Liquidity and Capital Resources—Non-GAAP Financial Measures.” For more information regarding our financial results for the three and six months ended June 30, 2026, see “—Results of Operations” below.

Current wording

For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “—Liquidity and Capital Resources—Non-GAAP Financial Measures.” For more information regarding our financial results for the three and nine months ended September 30, 2026, see “—Results of Operations” below.

Previous wording

On July 31, 2026, San Mateo completed the acquisition of the operating subsidiaries of Cardinal Midstream Partners, LLC (“Cardinal”), a portfolio company of EnCap Flatrock Midstream, for total cash consideration of $752.0 million, subject to certain customary post-closing purchase price adjustments (the “Cardinal Acquisition”).

Current wording

In July 2026, San Mateo completed the acquisition of the operating subsidiaries of Cardinal Midstream Partners, LLC (“Cardinal”), a portfolio company of EnCap Flatrock Midstream, for total cash consideration of $761.0 million, subject to certain customary post-closing purchase price adjustments (the “Cardinal Acquisition”).

Previous wording

Subsequent to the end of the reporting period, on July 22, 2026, we entered into a definitive agreement to acquire Paloma Permian, LLC (“Paloma”) from a portfolio company of EnCap Investments L.P. (“EnCap”), including certain proved undeveloped acreage and oil and natural gas producing properties located in Eddy and Lea Counties, New Mexico (the “Paloma Acquisition”). The consideration for the Paloma Acquisition will consist of a cash payment of $1.275 billion, subject to customary closing adjustments, including for working capital and for title and environmental defects. The consummation of the Paloma Acquisition is subject to the satisfaction or waiver of a number of customary closing conditions and is expected to close in the fourth quarter of 2026, with an effective date of June 1, 2026.

Current wording

Subsequent to the end of the reporting period, on October 1, 2026, we completed the acquisition of Paloma Permian, LLC (“Paloma”) from a portfolio company of EnCap Investments L.P., including certain proved undeveloped acreage and oil and natural gas producing properties located in Eddy and Lea Counties, New Mexico (the “Paloma Acquisition”). The Paloma Acquisition has an effective date of June 1, 2026 and an aggregate as-adjusted closing purchase price of approximately $1.255 billion, subject to customary post-closing adjustments, including for working capital and for title defects.

Previous wording

On August 5, 2026, we increased our estimated drilling, completing and equipping (“D/C/E”) capital expenditures for 2026 to a range of $1.48 to $1.56 billion from a range of $1.35 to $1.44 billion, which includes our expected D/C/E capital expenditures on acreage acquired in the BLM Acquisition and expected to be acquired in the Paloma Acquisition and Ridge Runner Acquisition. On August 5, 2026, we also adjusted our estimated midstream capital expenditures for 2026 to a range of $145.0 to $165.0 million from a range of $100.0 to $110.0 million, which includes our proportionate share of San Mateo’s estimated 2026 capital expenditures as well as the estimated 2026 capital expenditures for other wholly-owned midstream projects.

Current wording

On November 3, 2026, we adjusted our estimated drilling, completing and equipping (“D/C/E”) capital expenditures for 2026 to a range of $1.50 to $1.54 billion from a range of $1.48 to $1.56 billion, which includes our expected D/C/E capital expenditures on acreage acquired in the BLM Acquisition and Paloma Acquisition.

Previous wording

There have been no changes to our critical accounting policies and estimates from those set forth in the Annual Report.

Current wording

As of September 30, 2026, there have been no changes to our critical accounting policies and estimates from those set forth in the Annual Report except as noted below.

Previous wording

Oil and natural gas revenues. The increase in oil revenues resulted from the 53% increase in the weighted average oil price realized and the 3% increase in oil production. The decrease in natural gas revenues primarily resulted from the 139% decrease in the weighted average natural gas price realized and the 4% increase in natural gas production. For further discussion of factors impacting commodity prices, see “—General Outlook and Trends.”

Current wording

Oil and natural gas revenues. The increase in oil revenues resulted from the 34% increase in the weighted average oil price realized and the 10% increase in oil production. The increase in natural gas revenues primarily resulted from the 53% increase in the weighted average natural gas price realized and the 10% increase in natural gas production. For further discussion of factors impacting commodity prices, see “—General Outlook and Trends.”

Previous wording

Third-party midstream services revenues. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. The increase in third-party midstream services revenues was primarily attributable to a $3.0 million increase in our third-party natural gas gathering and processing revenues, which was partially offset by a $0.7 million decrease in our third-party water disposal revenues.

Current wording

Third-party midstream services revenues. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. The increase in third-party midstream services revenues was primarily attributable to a $9.7 million increase in our third-party natural gas gathering and processing revenues, which was mostly driven by the Cardinal Acquisition, and a $3.8 million increase in our third-party water disposal revenues.

Previous wording

Sales of purchased natural gas. The decrease in sales of purchased natural gas was primarily the result of a 49% decrease in natural gas price realized, which was partially offset by a 20% increase in natural gas volumes sold. Sales of purchased natural gas reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at San Mateo’s cryogenic natural gas processing plants and subsequently sell the residue natural gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our interim unaudited condensed consolidated statements of operations.

Current wording

Sales of purchased natural gas. The increase in sales of purchased natural gas was primarily the result of a 50% increase in natural gas price realized and a 22% increase in purchased natural gas volumes sold. Sales of purchased natural gas reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at San Mateo’s cryogenic natural gas processing plants and subsequently sell the residue natural gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our interim unaudited condensed consolidated statements of operations.

Previous wording

Realized (loss) gain on derivatives. Our realized loss on derivatives was $72.5 million for the three months ended June 30, 2026, as compared to a realized gain of $6.9 million for the three months ended June 30, 2025. For the three months ended June 30, 2026, we recorded a net loss of $171.8 million related to our oil costless collars, resulting primarily from oil prices that were above the ceiling of certain of our oil costless collar contracts and the deferred call premiums on certain of our purchased oil call contracts. This loss was partially offset by a net gain of $99.3 million related to our natural gas costless collar and swap contracts, resulting primarily from natural gas prices that were below the floor of our natural gas costless collar contracts, natural gas prices that were below the fixed prices of certain of our natural gas swap contracts and natural gas basis differentials that were below the fixed prices of certain of our natural gas basis differential swap contracts. For the three months ended June 30, 2025, we recorded a net gain of $6.9 million related to our natural gas basis differential swap contracts, resulting primarily from natural gas basis differentials that were below the fixed prices of certain of our natural gas basis differential swap contracts. We realized an average loss on our oil derivatives of approximately $14.97 per Bbl produced during the three months ended June 30, 2026, as compared to no realized gains or losses from oil derivatives during the three months ended June 30, 2025. We realized an average gain on our natural gas derivatives of approximately $2.03 per Mcf produced during the three months ended June 30, 2026, as compared to an average gain of approximately $0.15 per Mcf produced during the three months ended June 30, 2025. See Note 8, Derivative Financial Instruments, for further details on our derivatives.

Current wording

Realized (loss) gain on derivatives. Our realized loss on derivatives was $160.2 million for the three months ended September 30, 2026, as compared to a realized gain of $3.9 million for the three months ended September 30, 2025. For the three months ended September 30, 2026, we recorded a net loss of $150.7 million related to our oil costless collars and deferred calls, resulting primarily from oil prices that were above the ceiling of certain of our oil costless collar contracts and the deferred call premiums on certain of our purchased oil call contracts. For the three months ended September 30, 2026, we recorded a net loss of $17.1 million related to our natural gas swap contracts, resulting primarily from natural gas basis differentials that were above the fixed prices of certain of our natural gas basis differential swap contracts and natural gas prices that were above the fixed prices of certain of our natural gas swap contracts. This loss was partially offset by a net gain of $7.5 million related to our natural gas costless collar contracts, resulting primarily from natural gas prices that were below the floor of our natural gas costless collar contracts. For the three months ended September 30, 2025, we recorded a net gain of $3.9 million related to our natural gas basis differential swap contracts, resulting primarily from natural gas basis differentials that were below the fixed prices of certain of our natural gas basis differential swap contracts. We realized an average loss on our oil derivatives of approximately $12.41 per Bbl produced during the three months ended September 30, 2026, as compared to no realized gains or losses from oil derivatives during the three months ended September 30, 2025. We realized an average loss on our natural gas derivatives of approximately $0.18 per Mcf produced during the three months ended September 30, 2026, as compared to an average gain of approximately $0.08 per Mcf produced during the three months ended September 30, 2025. See Note 9, Derivative Financial Instruments, for further details on our derivatives.

Previous wording

Unrealized gain (loss) on derivatives. During the three months ended June 30, 2026, the aggregate net fair value of our open oil and natural gas costless collar, oil price call, natural gas swap and natural gas basis differential swap contracts changed to a net liability of $136.0 million from a net liability of $221.4 million at March 31, 2026, resulting in an unrealized gain on derivatives of $85.5 million for the three months ended June 30, 2026. During the three months ended June 30, 2025, the aggregate net fair value of our open oil and natural gas costless collar and natural gas basis differential swap contracts changed to a net liability of $16.3 million from a net asset of $21.0 million at March 31, 2025, resulting in an unrealized loss on derivatives of $37.3 million for the three months ended June 30, 2025. See Note 8, Derivative Financial Instruments, for further details on our derivatives.

Current wording

Unrealized gain (loss) on derivatives. During the three months ended September 30, 2026, the aggregate net fair value of our open oil and natural gas costless collar, oil price call, natural gas swap and natural gas basis differential swap contracts changed to a net liability of $203.7 million from a net liability of $136.0 million at June 30, 2026, resulting in an unrealized loss on derivatives of $67.7 million for the three months ended September 30, 2026. During the three months ended September 30, 2025, the aggregate net fair value of our open oil and natural gas costless collar and natural gas basis differential swap contracts changed to a net asset of $3.7 million from a net liability of $16.3 million at June 30, 2025, resulting in an unrealized gain on derivatives of $20.0 million for the three months ended September 30, 2025. See Note 9, Derivative Financial Instruments, for further details on our derivatives.

Previous wording

Transportation and processing. The increase in transportation and processing expenses is primarily due to the 3% increase in our total oil equivalent production and a change in the mix of revenue contracts between the periods.

Current wording

Transportation and processing. The increase in transportation and processing expenses was primarily due to the 10% increase in our total oil equivalent production and a change in the mix of revenue contracts between the periods.

Previous wording

Midstream operating. The increase in midstream operating expense was primarily attributable to a $9.3 million increase in pipeline operation expenses as a result of increased inlet connections and a $6.0 million increase in plant processing expenses as a result of increased gas gathering and processing volumes.

Current wording

Midstream operating. The increase in midstream operating expense was primarily attributable to a $20.1 million increase in pipeline operation expenses as a result of increased inlet connections and a $9.0 million increase in plant processing expenses as a result of increased gas gathering and processing volumes, as well as the Cardinal Acquisition.

Previous wording

Purchased natural gas. The decrease in purchased natural gas expense was primarily due to a decline of approximately 910% in average Waha pricing resulting in negative prices during the current period, which was partially offset by a 55% increase in volumes purchased due to the weaker market pricing.

Current wording

Purchased natural gas. The increase in purchased natural gas expense was primarily due to an increase of approximately 167% in average Waha pricing during the current period and a 93% increase in volumes purchased.

Previous wording

Depletion, depreciation and amortization. The increase in depletion, depreciation and amortization was primarily a result of the 3% increase in our total oil equivalent production and the addition of $282.2 million of proved reserves to the full cost pool as a result of the BLM Acquisition.

Current wording

Depletion, depreciation and amortization. The increase in depletion, depreciation and amortization expense was primarily a result of the 10% increase in our total oil equivalent production and the addition of $248.1 million of proved reserves to the full cost pool as a result of the BLM Acquisition.

Previous wording

Taxes other than income. The increase in taxes other than income is primarily due to the increase in oil revenues, partially offset by the decrease in natural gas revenues.

Current wording

Taxes other than income. The increase in taxes other than income was primarily due to a $34.0 million increase in production taxes as a result of the increase in oil and natural gas revenues.

Previous wording

General and administrative. The increase in general and administrative expense was largely attributable to a $4.2 million increase in employee compensation costs as a result of increased headcount and a $1.4 million increase in stock-based compensation expense primarily associated with our cash-settled stock awards, the values of which are remeasured at each reporting period. Additionally, general and administrative expense increased due to a $1.3 million increase in director and officer insurance and approximately $1.1 million in transaction costs associated with the Cardinal Acquisition.

Current wording

General and administrative. The increase in general and administrative expense was largely attributable to $3.1 million in transaction costs associated with the Cardinal Acquisition, a $1.1 million increase in rent expense and $0.8 million in transaction costs associated with the Paloma Acquisition.

Previous wording

Interest expense. The increase in interest expense for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 was primarily due to a $175.8 million increase in average debt outstanding under the Credit Agreement, a $200.5 million increase in average debt outstanding under the San Mateo Credit Facility, and a $158.9 million increase in the weighted average of senior notes outstanding between the periods, partially offset by lower interest rates.

Current wording

Interest expense. The increase in interest expense was primarily due to a $607.5 million increase in average debt outstanding under the Credit Agreement, a $160.0 million increase in average debt outstanding under the San Mateo Revolving Credit Facility and a $250.0 million increase in the weighted average of senior notes outstanding between the periods, as well as the new $650.0 million San Mateo Term Loan (see “—Liquidity and Capital Resources” below for further discussion). These increases were partially offset by lower interest rates.

Previous wording

Income tax provision. The decrease in the current income tax provision and the increase in the deferred income tax provisions were primarily due to the OBBBA. See Note 8, Income Taxes, of our Annual Report for further details of the provisions of the OBBBA that most significantly affect our income taxes. Additionally, the decrease in the total income tax provision resulted from lower income before income taxes. Our effective income tax rate of 23% for the six months ended June 30, 2026 differed from the U.S. federal statutory rate primarily due to state taxes in New Mexico, partially offset by the impact of permanent differences between book and tax income recognized discretely in the current period. Our effective tax rate of 26% for the six months ended June 30, 2025 differed from the U.S. federal statutory rate primarily due to state taxes in New Mexico.

Current wording

Income tax provision. The decrease in the current income tax benefit and the decrease in the deferred income tax provision were primarily the result of the enactment of the OBBBA during the third quarter of 2025, which resulted in the recognition of the impacts of the OBBBA for the first two quarters of 2025 in the third quarter of 2025. There were no such legislation changes in the third quarter of 2026. See Note 8, Income Taxes, of our Annual Report for further details of the provisions of the OBBBA that most significantly affect our income taxes. Additionally, the increase in the total income tax provision resulted from higher income before income taxes. Our effective income tax rate of 32% for the three months ended September 30, 2026 differed from the U.S. federal statutory rate primarily due to state taxes in New Mexico and the impact of permanent differences between book and tax income recognized discretely in the current period.

Previous wording

Oil and natural gas revenues. The increase in oil revenues resulted from the 26% increase in the weighted average oil price realized and the 4% increase in our oil production. The decrease in natural gas revenues primarily resulted from the 103% decrease in the weighted average natural gas price realized and the 4% increase in our natural gas production. For further discussion of factors impacting commodity prices, see “—General Outlook and Trends.”

Current wording

Oil and natural gas revenues. The increase in oil revenues resulted from the 29% increase in the weighted average oil price realized and the 6% increase in our oil production. The decrease in natural gas revenues primarily resulted from the 59% decrease in the weighted average natural gas price realized, which was partially offset by the 6% increase in our natural gas production. For further discussion of factors impacting commodity prices, see “—General Outlook and Trends.”

Previous wording

Third-party midstream services revenues. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. The increase in third-party midstream services revenues was primarily attributable to a $12.0 million increase in our third-party natural gas gathering and processing revenues, which was partially offset by a $1.3 million decrease in our third-party water disposal revenues.

Current wording

Third-party midstream services revenues. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. The increase in third-party midstream services revenues was primarily attributable to a $21.7 million increase in our third-party natural gas gathering and processing revenues, $8.9 million of which was driven by the Cardinal Acquisition, and a $2.4 million increase in our third-party water disposal revenues.

Previous wording

Sales of purchased natural gas. The decrease in sales of purchased natural gas was primarily the result of a 37% decrease in natural gas price realized, which was partially offset by a 48% increase in natural gas volumes sold. Sales of purchased natural gas reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at San Mateo’s cryogenic natural gas processing plants and subsequently sell the residue natural gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our interim unaudited condensed consolidated statements of operations.

Current wording

Sales of purchased natural gas. The increase in sales of purchased natural gas was primarily the result of a 37% increase in purchased natural gas volumes sold, which was partially offset by a 11% decrease in natural gas price realized. Sales of purchased natural gas reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at San Mateo’s cryogenic natural gas processing plants and subsequently sell the residue natural gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our interim unaudited condensed consolidated statements of operations.

Previous wording

Realized loss on derivatives. Our realized loss on derivatives was $87.0 million for the six months ended June 30, 2026, as compared to a realized gain of $9.7 million for the six months ended June 30, 2025. For the six months ended June 30, 2026, we recorded a net loss of $223.6 million related to our oil costless collars, resulting primarily from oil prices that were above the ceiling of certain of our oil costless collar contracts and the deferred call premiums on certain of our purchased oil call contracts. This loss was partially offset by a net gain of $136.7 million related to our natural gas costless collar and swap contracts, resulting primarily from natural gas prices that were below the floor of our natural gas costless collar contracts, natural gas prices that were below the fixed prices of certain of our natural gas swap contracts and natural gas basis differentials that were below the fixed prices of certain of our natural gas basis differential swap contracts. For the six months ended June 30, 2025, we recorded a net gain of $9.7 million related to our natural gas basis differential swap contracts, resulting primarily from natural gas basis differentials that were below the fixed prices of certain of our natural gas basis differential swap contracts. We realized an average loss on our oil derivatives of approximately $10.03 per Bbl produced during the three months ended June 30, 2026, as compared to no realized gains or losses from oil derivatives during the six months ended June 30, 2025. We realized an average gain on our natural gas derivatives of approximately $1.42 per Mcf produced during the six months ended June 30, 2026, as compared to an average gain of approximately $0.10 per Mcf produced during the six months ended June 30, 2025. See Note 8, Derivative Financial Instruments, for further details on our derivatives.

Current wording

Realized (loss) gain on derivatives. Our realized loss on derivatives was $247.2 million for the nine months ended September 30, 2026, as compared to a realized gain of $13.6 million for the nine months ended September 30, 2025. For the nine months ended September 30, 2026, we recorded a net loss of $374.3 million related to our oil costless collars and deferred calls, resulting primarily from oil prices that were above the ceiling of certain of our oil costless collar contracts and the deferred call premiums on certain of our purchased oil call contracts. This loss was partially offset by a net gain of $127.1 million related to our natural gas costless collar and swap contracts, resulting primarily from natural gas prices that were below the floor of our natural gas costless collar contracts, natural gas prices that were below the fixed prices of certain of our natural gas swap contracts and natural gas basis differentials that were below the fixed prices of certain of our natural gas basis differential swap contracts. For the nine months ended September 30, 2025, we recorded a net gain of $13.6 million related to our natural gas basis differential swap contracts, resulting primarily from natural gas basis differentials that were below the fixed prices of certain of our natural gas basis differential swap contracts. We realized an average loss on our oil derivatives of approximately $10.87 per Bbl produced during the nine months ended September 30, 2026, as compared to no realized gains or losses from oil derivatives during the nine months ended September 30, 2025. We realized an average gain on our natural gas derivatives of approximately $0.85 and $0.10 per Mcf produced during the nine months ended September 30, 2026 and 2025, respectively. See Note 9, Derivative Financial Instruments, for further details on our derivatives.

Previous wording

Unrealized loss on derivatives. During the six months ended June 30, 2026, the aggregate net fair value of our open oil and natural gas costless collar, oil price call, natural gas swap and natural gas basis differential swap contracts changed to a net liability of $136.0 million from a net asset of $34.1 million at December 31, 2025, resulting in an unrealized loss on derivatives of $170.0 million for the six months ended June 30, 2026. During the six months ended June 30, 2025, the aggregate net fair value of our open oil and natural gas costless collar and natural gas basis differential swap contracts changed to a net liability of $16.3 million from a net asset of $16.0 million at December 31, 2024, resulting in an unrealized loss on derivatives of $32.2 million for the six months ended June 30, 2025. See Note 8, Derivative Financial Instruments, for further details on our derivatives.

Current wording

Unrealized loss on derivatives. During the nine months ended September 30, 2026, the aggregate net fair value of our open oil and natural gas costless collar, oil price call and natural gas basis differential swap contracts changed to a net liability of $203.7 million from a net asset of $34.1 million at December 31, 2025, resulting in an unrealized loss on derivatives of $237.7 million for the nine months ended September 30, 2026. During the nine months ended September 30, 2025, the aggregate net fair value of our open oil and natural gas costless collar and natural gas basis differential swap contracts changed to a net asset of $3.7 million from a net asset of $16.0 million at December 31, 2024, resulting in an unrealized loss on derivatives of $12.3 million for the nine months ended September 30, 2025. See Note 9, Derivative Financial Instruments, for further details on our derivatives.

Previous wording

Transportation and processing. The decrease in transportation and processing expenses is primarily due to additional allowable deductions identified in the state of New Mexico and a change in the mix of revenue contracts between the periods.

Current wording

Transportation and processing. The increase in transportation and processing expenses was primarily due to a change in the mix of revenue contracts between the periods.

Previous wording

Midstream operating. The increase in midstream operating expense was primarily attributable to an $11.2 million increase in plant processing expenses as a result of increased gas gathering and processing volumes and a $9.5 million increase in pipeline operation expenses as a result of increased inlet connections.

Current wording

Midstream operating. The increase in midstream operating expense was primarily attributable to a $29.6 million increase in pipeline operation expenses as a result of increased inlet connections and a $20.2 million increase in plant processing expenses as a result of increased gas gathering and processing volumes, as well as the Cardinal Acquisition.

Previous wording

Purchased natural gas. The decrease in purchased natural gas expense was primarily due to a decline of approximately 520% in average Waha pricing, partially offset by a 30% increase in volumes purchased due to the weaker market pricing.

Current wording

Purchased natural gas. The decrease in purchased natural gas expense was primarily due to a decline of approximately 291% in average Waha pricing, partially offset by a 85% increase in volumes purchased due to the weaker market pricing.

Previous wording

Depletion, depreciation and amortization. The increase in depletion, depreciation and amortization was primarily a result of the 4% increase in our total oil equivalent production and the addition of $282.2 million of proved reserves to the full cost pool as a result of the BLM Acquisition.

Current wording

Depletion, depreciation and amortization. The increase in depletion, depreciation and amortization expense was primarily a result of the 6% increase in our total oil equivalent production and the addition of $248.1 million of proved reserves to the full cost pool as a result of the BLM Acquisition.

Previous wording

Taxes other than income. The increase in taxes other than income was primarily due to the increase in oil revenues, partially offset by the decrease in natural gas revenues.

Current wording

Taxes other than income. The increase in taxes other than income was primarily due to a $59.2 million increase in production taxes as a result of the increase in oil revenues, partially offset by the decrease in natural gas revenues.

Previous wording

General and administrative. The increase in general and administrative expense was largely attributable to a $14.2 million increase in employee compensation costs, as a result of increased headcount and an $8.2 million increase in stock-based compensation expense primarily associated with our cash-settled stock awards, the values of which are remeasured at each reporting period. Additionally, the increase in general and administrative expense was due to a $1.3 million increase in director and officer insurance and approximately $1.1 million in transaction costs associated with the Cardinal Acquisition. These increases were partially offset by a $4.5 million increase in capitalized general and administrative expenses.

Current wording

General and administrative. The increase in general and administrative expense was largely attributable to a $13.4 million increase in employee compensation costs, as a result of increased headcount and a $5.5 million increase in stock-based compensation expense primarily associated with our cash-settled stock awards, the values of which are remeasured at each reporting period. Additionally, the increase in general and administrative expense was due to approximately $4.1 million in transaction costs associated with the Cardinal Acquisition, a $1.9 million increase in rent expense, a $1.3 million increase in director and officer insurance and $0.8 million in transaction costs associated with the Paloma Acquisition. These increases were partially offset by a $3.5 million increase in capitalized general and administrative expenses.

Previous wording

Interest expense. The increase in interest expense for the three months ended June 30, 2026 compared to the three months ended June 30, 2025 was primarily due to a $164.5 million increase in average debt outstanding under the Credit Agreement, a $198.0 million increase in average debt outstanding under the San Mateo Credit Facility, and a $250.0 million increase in the weighted average of senior notes outstanding between the periods, partially offset by lower interest rates.

Current wording

Interest expense. The increase in interest expense for the nine months ended September 30, 2026 compared to the nine months ended September 30, 2025 was primarily due to a $234.3 million increase in average debt outstanding under the Credit Agreement, a $227.5 million increase in average debt outstanding under the San Mateo Revolving Credit Facility and a $189.6 million increase in the weighted average of senior notes outstanding between the periods, as well as the new $650.0 million San Mateo Term Loan (see “—Liquidity and Capital Resources” below for further discussion). These increases were partially offset by lower interest rates.

Previous wording

Income tax provision. The decrease in the current income tax provision and the increase in the deferred income tax provision were primarily due to the OBBBA. See Note 8, Income Taxes, of our Annual Report for further details of the provisions of the OBBBA that most significantly affect our income taxes. Additionally, the increase in the total income tax provision resulted from higher income before income taxes. Our effective income tax rate was 21% for the three months ended June 30, 2026. Our effective tax rate was 27% for the three months ended June 30, 2025, which differed from the U.S. federal statutory rate primarily due to state taxes in New Mexico.

Current wording

Income tax provision. The decreases in the current, deferred and total income tax provisions were primarily the result of lower income before income taxes. Our effective income tax rate of 26% for the nine months ended September 30, 2026 differed from the U.S. federal statutory rate primarily due to state taxes in New Mexico and the impact of permanent differences between book and tax income recognized discretely in the current period.

Previous wording

Our primary use of capital has been, and we expect will continue to be during the remainder of 2026 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. We expect to fund our 2026 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point or its affiliates. If capital expenditures were to exceed these sources of cash during the remainder of 2026, we expect to fund any such excess capital expenditures, including for significant acquisitions, through borrowings under our secured revolving credit facility (the “Credit Agreement”) or San Mateo’s secured revolving credit facility (the “San Mateo Credit Facility”) (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital.

Current wording

Our primary use of capital has been, and we expect will continue to be during the remainder of 2026 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. We expect to fund our 2026 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point or its affiliates. If capital expenditures were to exceed these sources of cash during the remainder of 2026, we expect to fund any such excess capital expenditures, including for significant acquisitions, through borrowings under our secured revolving credit facility (the “Credit Agreement”) or the San Mateo Revolving Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital.

Previous wording

The table below reflects our sources and availability of liquidity at June 30, 2026. See Note 5, Debt, for further details.

Current wording

The table below reflects our sources and availability of liquidity at September 30, 2026.

Previous wording

(1)Reduced by approximately $53.8 million in outstanding letters of credit issued pursuant to the Credit Agreement.

Current wording

(1)Reduced by approximately $53.1 million in outstanding letters of credit issued pursuant to the Credit Agreement.

Previous wording

(2)Reduced by approximately $15.4 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility.

Current wording

(2)Reduced by approximately $22.9 million in outstanding letters of credit issued pursuant to the San Mateo Revolving Credit Facility.