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; the operating results of and availability of any potential distributions from our joint ventures; weather conditions, environmental conditions and natural disasters; disruption from our acquisitions making it more difficult to maintain business and operational relationships; significant transaction costs associated with our acquisitions; evolving cybersecurity risks; the risk of litigation and/or regulatory actions related to our acquisitions; 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:

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 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.

Previous wording

•the integration of acquisitions with our business;

Current wording

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

Previous wording

For the three months ended March 31, 2026, our total oil equivalent production was 18.7 million BOE, and our average daily oil equivalent production was 207,594 BOE per day, of which 120,277 Bbl per day, or 58%, was oil and 523.9 MMcf per day, or 42%, was natural gas. Our average daily oil production of 120,277 Bbl per day for the three months ended March 31, 2026 increased 5% year-over-year from 115,030 Bbl per day for the three months ended March 31, 2025. Our average daily natural gas production of 523.9 MMcf per day for the three months ended March 31, 2026 increased 4% year-over-year from 501.6 MMcf per day for the three months ended March 31, 2025.

Current 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.

Previous wording

For the first quarter of 2026, we reported a net loss attributable to Matador shareholders of $35.9 million, or $0.29 per diluted common share, on a GAAP basis, primarily resulting from a $255.5 million unrealized loss on derivatives, as compared to net income attributable to Matador shareholders of $240.1 million, or $1.92 per diluted common share, for the first quarter of 2025. For the first quarter of 2026, our Adjusted EBITDA, a non‑GAAP financial measure, was $577.2 million, as compared to Adjusted EBITDA of $644.2 million during the first quarter of 2025.

Current 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.

Previous wording

For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net (loss) 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 months ended March 31, 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 six months ended June 30, 2026, see “—Results of Operations” below.

Previous wording

For a summary of our sources and availability of liquidity as of March 31, 2026, see “Liquidity and Capital Resources” in Part I, Item 2 of this Quarterly Report.

Current wording

For discussion of the funding for these acquisitions, see “—Liquidity and Capital Resources” in Part I, Item 2 of this Quarterly Report.

Previous wording

Our 2026 estimated capital expenditure budget consists of $1.35 to $1.44 billion for drilling, completing and equipping (“D/C/E”) capital expenditures and $100.0 to $110.0 million for midstream capital expenditures, 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 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.

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 $9.0 million increase in our third-party natural gas gathering and processing revenues during the three months ended March 31, 2026, as compared to the three months ended March 31, 2025, which was partially offset by a $0.7 million decrease in our third-party water disposal revenues during the three months ended March 31, 2026, as compared to the three months ended March 31, 2025.

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 $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.

Previous wording

Sales of purchased natural gas. The increase in sales of purchased natural gas was primarily the result of an 87% increase in natural gas volumes sold, which was partially offset by a 31% decrease in natural gas price realized in those sales. 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 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.

Previous wording

Realized (loss) gain on derivatives. Our realized loss on derivatives was $14.5 million for the three months ended March 31, 2026, as compared to a realized gain of $2.7 million for the three months ended March 31, 2025. For the three months ended March 31, 2026, we recorded a net loss of $51.8 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. This loss was partially offset by a net gain of $37.3 million primarily related to our natural gas costless collar and 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. For the three months ended March 31, 2025, we recorded a net gain of $2.7 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 $4.79 per Bbl produced during the three months ended March 31, 2026, as compared to no realized gains or losses from oil derivatives during the three months ended March 31, 2025. We realized an average gain on our natural gas derivatives of approximately $0.80 per Mcf produced during the three months ended March 31, 2026, as compared to an average gain of approximately $0.06 per Mcf produced during the three months ended March 31, 2025. See Note 7, Derivative Financial Instruments, for further details on our derivatives.

Current 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.

Previous wording

Unrealized (loss) gain on derivatives. During the three months ended March 31, 2026, the aggregate net fair value of our open oil and natural gas costless collar, natural gas swap and natural gas basis differential swap contracts changed to a net liability of $221.4 million from a net asset of $34.1 million at December 31, 2025, resulting in an unrealized loss on derivatives of $255.5 million for the three months ended March 31, 2026. During the three months ended March 31, 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 $21.0 million from a net asset of $16.0 million at December 31, 2024, resulting in an unrealized gain on derivatives of $5.1 million for the three months ended March 31, 2025. See Note 7, Derivative Financial Instruments, for further details on our derivatives.

Current 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.

Previous wording

Lease operating. The increase in lease operating expense was primarily attributable to the increased number of wells being operated by us and other operators (where we own a working interest) for the three months ended March 31, 2026, as compared to the three months ended March 31, 2025.

Current wording

Lease operating. The increase in lease operating expense was primarily attributable to the increased number of wells being operated by us and other operators (where we own a working interest).

Previous wording

Purchased natural gas. The decrease in purchased natural gas expense was primarily due to a decline of approximately 129% in average Waha pricing, which was partially offset by a 31% increase in volumes purchased due to the weaker market pricing, during the three months ended March 31, 2026, as compared to the three months ended March 31, 2025.

Current 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.

Previous wording

Depletion, depreciation and amortization. The increase in depletion, depreciation and amortization was primarily a result of the 5% increase in our total oil equivalent production for the three months ended March 31, 2026, as compared to the three months ended March 31, 2025.

Current 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.

Previous wording

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

Current 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.

Previous wording

General and administrative. The increase in general and administrative expense was largely attributable to employee compensation costs, including a $6.8 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.

Current 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.

Previous wording

Oil and natural gas revenues. The increase in oil revenues resulted from the 5% increase in our oil production and the 1% increase in the weighted average oil price realized for the three months ended March 31, 2026, as compared to the three months ended March 31, 2025. The decrease in natural gas revenues primarily resulted from the 82% decrease in the weighted average natural gas price realized for the three months ended March 31, 2026, as compared to the three months ended March 31, 2025, which was partially offset by 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 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.”

Previous wording

Loss on debt extinguishment. In connection with the 2028 Notes Tender Offer and 2028 Notes Redemption, we incurred a loss on debt extinguishment of $15.6 million, including a $9.7 million cash prepayment premium and a $5.9 million write-off of remaining unamortized deferred issuance costs and discounts.

Current wording

Loss on debt extinguishment. In connection with the 2028 Notes Tender Offer and 2028 Notes Redemption, both of which as defined in “—Liquidity and Capital Resources” below, we incurred a loss on debt extinguishment of $15.6 million, including a $9.7 million cash prepayment premium and a $5.9 million write-off of remaining unamortized deferred issuance costs and discounts.

Previous wording

Income tax (benefit) provision. The decreases in the current and deferred income tax provisions between the periods were primarily due to both lower book earnings and 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. Our effective income tax rate of 2% for the three months ended March 31, 2026 differed from the U.S. federal statutory rate primarily due to the impact of permanent differences between book and tax income recognized discretely in the current period relative to the loss before income taxes. Our effective tax rate of 26% for the three months ended March 31, 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 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.

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 Infrastructure LLC 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 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.

Previous wording

In March 2026, we completed the 2034 Notes Offering. We used the net proceeds from the 2034 Notes Offering of $737.9 million, after deducting initial purchasers’ discounts and estimated offering expenses, to fund the 2028 Notes Tender Offer and 2028 Notes Redemption and for general corporate purposes. See Note 4, Debt, for further details of these debt transactions.

Current wording

See Note 5, Debt, for further details of these debt transactions.

Previous wording

As further described in the Annual Report, we maintain a share repurchase program (the “Share Repurchase Program”) authorizing the repurchase of up to $400.0 million of common stock. During the three months ended March 31, 2026, we repurchased 17,702 shares of common stock under the Share Repurchase Program at a weighted average price of $39.92 per common share for a total cost of $0.7 million.

Current wording

As further described in the Annual Report, we maintain a share repurchase program (the “Share Repurchase Program”) authorizing the repurchase of up to $400.0 million of common stock. During the three and six months ended June 30, 2026, we repurchased 225,000 and 242,702 shares of common stock, respectively, under the Share Repurchase Program at a weighted average price of $49.59 and $48.88 per common share, respectively, for a total cost of $11.2 million and $11.9 million, respectively.

Previous wording

Matador’s Board of Directors (the “Board”) declared and paid quarterly cash dividends of $0.375 per share of common stock in the first quarter of 2026. On April 22, 2026, the Board declared a quarterly cash dividend of $0.375 per share of common stock payable on June 5, 2026 to shareholders of record as of May 8, 2026.

Current wording

Matador’s Board of Directors (the “Board”) declared and paid quarterly cash dividends of $0.375 per share of common stock in each of the first and second quarters of 2026. On July 22, 2026, the Board declared a quarterly cash dividend of $0.375 per share of common stock payable on September 8, 2026 to shareholders of record as of August 10, 2026.

Previous wording

Since March 31, 2026, we repaid $140.0 million of borrowings under the Credit Agreement, and at May 6, 2026, we had $45.0 million in borrowings outstanding under the Credit Agreement. Since March 31, 2026, San Mateo repaid $58.0 million of borrowings under the San Mateo Credit Facility, and at May 6, 2026, San Mateo had $860.0 million in borrowings outstanding under the San Mateo Credit Facility.

Current wording

Since June 30, 2026, our borrowings increased $243.0 million under the Credit Agreement, and at August 5, 2026, we had $1.18 billion in borrowings outstanding. Since June 30, 2026, San Mateo’s borrowings increased $25.0 million under the San Mateo Credit Facility, and at August 5, 2026, San Mateo had $936.0 million in borrowings outstanding.

Previous wording

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures for the remainder of 2026. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2026 estimated capital expenditure budget consists of $1.35 to $1.44 billion for D/C/E capital expenditures and $100.0 to $110.0 million for midstream capital expenditures, 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. Substantially all of these 2026 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities. Our Delaware Basin operated drilling program for the remainder of 2026 is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells.

Current wording

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures for the remainder of 2026. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. 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 the 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. Substantially all of these 2026 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities. Our Delaware Basin operated drilling program for the remainder of 2026 is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells.

Previous wording

Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for the remainder of 2026 is expected to come from producing wells and development activities on currently proved properties in the Delaware Basin and the Haynesville shale in Northwest Louisiana. Our existing operated and non-operated wells may not produce at the levels we are forecasting or may be temporarily shut in or restricted due to low commodity prices, and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2026 and the hedges we currently have in place. For further discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below. At times, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 7, Derivative Financial Instruments, in this Quarterly Report for a summary of our open derivative financial instruments.

Current wording

Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for the remainder of 2026 is expected to come from producing wells and development activities on currently proved properties in the Delaware Basin. Our existing operated and non-operated wells may not produce at the levels we are forecasting or may be temporarily shut in or restricted due to low commodity prices, and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2026 and the hedges we currently have in place. For further discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below. At times, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 8, Derivative Financial Instruments, in this Quarterly Report for a summary of our open derivative financial instruments.

Previous wording

Our unaudited cash flows for the three months ended March 31, 2026 and 2025 are presented below:

Current wording

Our unaudited cash flows for the six months ended June 30, 2026 and 2025 are presented below:

Previous wording

(1)Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net (loss) income and net cash provided by operating activities, see “—Non-GAAP Financial Measures” below.

Current wording

(1)Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “—Non-GAAP Financial Measures” below.

Previous wording

Excluding changes in operating assets and liabilities, net cash provided by operating activities decreased $44.3 million to $564.2 million for the three months ended March 31, 2026 from $608.5 million for the three months ended March 31, 2025. This decrease was primarily attributable to lower realized natural gas prices for the three months ended March 31, 2026, as compared to the three months ended March 31, 2025, which was partially offset by increased oil and natural gas production and higher realized oil prices for the three months ended March 31, 2026, as compared to the three months ended March 31, 2025. Changes in our operating assets and liabilities between the periods resulted in a $213.1 million decrease in net cash provided by operating activities for the three months ended March 31, 2026, as compared to the three months ended March 31, 2025.

Current wording

Excluding changes in operating assets and liabilities, net cash provided by operating activities increased $151.8 million to $1.33 billion for the six months ended June 30, 2026 from $1.18 billion for the six months ended June 30, 2025. This increase was primarily attributable to higher realized oil prices and increased oil production for the six months ended June 30, 2026, as compared to the six months ended June 30, 2025, partially offset by lower realized natural gas prices and higher natural gas production. Changes in our operating assets and liabilities between the periods resulted in a $27.0 million increase in net cash provided by operating activities for the six months ended June 30, 2026, as compared to the six months ended June 30, 2025.

Previous wording

The decrease in net cash used in investing activities between the periods was primarily due to (i) a $55.3 million decrease in midstream capital expenditures and (ii) a $20.0 million decrease in expenditures related to the acquisition of oil and natural gas properties, partially offset by a $21.4 million decrease in cash provided by proceeds from the sale of assets.

Current wording

The increase in net cash used in investing activities between the periods was primarily due to (i) a $1.10 billion increase in expenditures related to the acquisition of oil and natural gas properties, primarily the BLM Acquisition, (ii) a $37.6 million cash deposit related to the Cardinal Acquisition and (iii) a $21.4 million decrease in cash provided by proceeds from the sale of assets, partially offset by a $121.1 million decrease in midstream capital expenditures.

Previous wording

The decrease in net cash used in financing activities between the periods was primarily due to (i) $737.9 million of net proceeds received from the 2034 Notes Offering during the period and (ii) $24.0 million of proceeds from the sale-leaseback financing obligation, partially offset by (i) $509.7 million used to repurchase the principal amount of the 2028 Notes and (ii) a $22.5 million increase in net repayments under the Credit Agreement.

Current wording

The decrease in net cash used in financing activities between the periods was primarily due to (i) a $746.5 million increase in net borrowings under the Credit Agreement, (ii) $737.1 million of net proceeds received from the 2034 Notes Offering during the period, (iii) a $32.1 million decrease in repurchases of common stock, (iv) $23.7 million of net proceeds from a sale-leaseback financing obligation and (v) a $5.9 million increase in performance incentives received from Five Point, partially offset by (i) $509.7 million used to repurchase the principal amount of the 2028 Notes, (ii) a $135.0 million decrease in net borrowings under the San Mateo Credit Agreement and (iii) a $15.1 million increase in dividends paid.

Previous wording

We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, unrealized derivative gains and losses, non-recurring transaction costs for certain acquisitions, non-cash stock-based compensation expense, loss on debt extinguishment, net gain or loss on asset sales and impairments and certain other non-cash items. Adjusted EBITDA is not a measure of net (loss) income or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

Current wording

We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, unrealized derivative gains and losses, non-recurring transaction costs for certain acquisitions, non-cash stock-based compensation expense, loss on debt extinguishment, net gain or loss on asset sales and impairments and certain other non-cash items. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

Previous wording

Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net (loss) income in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired.

Current wording

Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired.

Previous wording

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net (loss) income or net cash provided by operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

Current wording

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or net cash provided by operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

Previous wording

The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net (loss) income and net cash provided by operating activities, respectively.

Current wording

The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities, respectively.

Previous wording

(1)The amounts included in the table above represent principal maturities only. At March 31, 2026, we had $185.0 million in borrowings outstanding under the Credit Agreement and approximately $53.8 million in outstanding letters of credit issued pursuant to the Credit Agreement. The outstanding borrowings under the Credit Agreement mature on March 22, 2029. At March 31, 2026, San Mateo had $918.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $15.4 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The outstanding borrowings under the San Mateo Credit Facility mature on November 26, 2029. Assuming the amounts outstanding and interest rates of 5.43% and 5.67% respectively, for the Credit Agreement and the San Mateo Credit Facility at March 31, 2026, the interest expense for such facilities is expected to be approximately $10.2 million and $52.8 million, respectively, each year until maturity.

Current wording

(1)The amounts included in the table above represent principal maturities only. At June 30, 2026, we had $939.0 million in borrowings outstanding under the Credit Agreement and approximately $53.8 million in outstanding letters of credit issued pursuant to the Credit Agreement. The outstanding borrowings under the Credit Agreement mature on March 22, 2029. At June 30, 2026, San Mateo had $911.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $15.4 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The outstanding borrowings under the San Mateo Credit Facility mature on November 26, 2029. Assuming the amounts outstanding and interest rates of 5.65% and 5.88%, respectively, for the Credit Agreement and the San Mateo Credit Facility at June 30, 2026, the interest expense for such facilities is expected to be approximately $53.7 million and $54.3 million, respectively, each year until maturity.

Previous wording

Oil prices were higher in the first quarter of 2026, as compared to the first quarter of 2025. For the three months ended March 31, 2026, oil prices averaged $73.09 per Bbl, ranging from a low of $55.99 per Bbl in early January to a high of $102.88 per Bbl in late March, based upon the West Texas Intermediate (“WTI”) oil futures contract price for the earliest delivery date. Oil prices averaged $71.42 per Bbl for the three months ended March 31, 2025. We realized a weighted average oil price of $72.83 per Bbl ($68.04 with realized losses from oil derivatives) for our oil production for the three months ended March 31, 2026, as compared to $72.38 per Bbl (with no realized gains or losses from oil derivatives) for our oil production for the three months ended March 31, 2025. Oil prices have remained volatile since March 31, 2026. At May 6, 2026, the WTI oil futures contract for the earliest delivery date had increased from the average price for the first quarter of 2026 of $73.09 per Bbl, settling at $95.08 per Bbl.

Current wording

Oil prices were higher in the second quarter of 2026, as compared to the second quarter of 2025. For the three months ended June 30, 2026, oil prices averaged $92.70 per Bbl, ranging from a high of $112.95 per Bbl in early April to a low of $69.23 per Bbl in late June, based upon the West Texas Intermediate (“WTI”) oil futures contract price for the earliest delivery date. Oil prices averaged $63.68 per Bbl for the three months ended June 30, 2025. We realized a weighted average oil price of $98.16 per Bbl ($83.19 with realized losses from oil derivatives) for our oil production for the three months ended June 30, 2026, as compared to $64.34 per Bbl (with no realized gains or losses from oil derivatives) for our oil production for the three months ended June 30, 2025. Oil prices have remained volatile since June 30, 2026. At August 5, 2026, the WTI oil futures contract for the earliest delivery date had decreased from the average price for the second quarter of 2026 of $92.70 per Bbl, settling at $75.22 per Bbl.

Previous wording

Natural gas prices were lower in the first quarter of 2026, as compared to the first quarter of 2025. For the three months ended March 31, 2026, natural gas prices averaged $3.47 per MMBtu, ranging from a high of $7.46 per MMBtu in late January to a low of $2.83 per MMBtu in late February, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Natural gas prices averaged $3.87 per MMBtu for the three months ended March 31, 2025. We report production volumes in two streams, oil and natural gas (which includes both dry gas and NGLs). We realized a weighted average natural gas price of $0.64 per Mcf ($1.44 per Mcf including realized gains from natural gas derivatives) for our natural gas production (including revenues attributable to NGLs) for the three months ended March 31, 2026, as compared to $3.56 per Mcf ($3.62 per Mcf including realized gains from natural gas derivatives) for our natural gas production (including revenues attributable to NGLs) for the three months ended March 31, 2025. Certain volumes of our natural gas production are sold at prices established at the beginning of each month by the various markets where we sell our natural gas production, and certain volumes of our natural gas production are sold at daily market prices. At May 6, 2026, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had decreased from the average price for the first quarter of 2026 of $3.47 per MMBtu, to $2.73 per MMBtu.

Current wording

Natural gas prices were lower in the second quarter of 2026, as compared to the second quarter of 2025. For the three months ended June 30, 2026, natural gas prices averaged $2.94 per MMBtu, ranging from a low of $2.52 per MMBtu in late April to a high of $3.34 per MMBtu in late June, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Natural gas prices averaged $3.51 per MMBtu for the three months ended June 30, 2025. We report production volumes in two streams, oil and natural gas (which includes both dry gas and NGLs). We realized a weighted average natural gas price of $(0.79) per Mcf ($1.24 per Mcf including realized gains from natural gas derivatives) for our natural gas production (including revenues attributable to NGLs) for the three months ended June 30, 2026, as compared to $2.05 per Mcf ($2.20 per Mcf including realized gains from natural gas derivatives) for our natural gas production (including revenues attributable to NGLs) for the three months ended June 30, 2025. Certain volumes of our natural gas production are sold at prices established at the beginning of each month by the various markets where we sell our natural gas production, and certain volumes of our natural gas production are sold at daily market prices. At August 5, 2026, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had decreased from the average price for the second quarter of 2026 of $2.94 per MMBtu, to $2.69 per MMBtu.

Previous wording

The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years. At May 6, 2026, this oil price differential was positive at approximately +$2.65 per Bbl. At May 6, 2026, we had no derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential for 2026.

Current wording

The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years. At August 5, 2026, this oil price differential was positive at approximately +$0.35 per Bbl. At August 5, 2026, we had no derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential for 2026.

Previous wording

Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years. In recent years, concerns about natural gas pipeline takeaway capacity out of the Delaware Basin began to increase and as a result, the Waha-Henry Hub basis differential began to widen. The Waha-Henry Hub basis differential averaged ($5.99) per MMBtu for the three months ended March 31, 2026. Between March 31, 2026 and May 6, 2026, this natural gas price differential remained wide at approximately ($6.57) per MMBtu. A significant portion of our Delaware Basin natural gas production, however, is sold at Houston Ship Channel pricing and is not exposed to Waha pricing. During 2023 and 2024, we typically realized a narrower differential to natural gas sold at the Waha hub despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our natural gas production into other markets to improve our realized natural gas pricing. Further, approximately 3% of our reported natural gas production for the three months ended March 31, 2026 was attributable to the Haynesville shale play, which is not exposed to Waha pricing. In addition, most of our natural gas volumes in the Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes exposed to Waha pricing.

Current wording

Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years. In recent years, concerns about natural gas pipeline takeaway capacity out of the Delaware Basin began to increase and as a result, the Waha-Henry Hub basis differential began to widen. The Waha-Henry Hub basis differential averaged ($6.03) per MMBtu for the six months ended June 30, 2026. Between June 30, 2026 and August 5, 2026, this natural gas price differential narrowed to approximately ($0.82) per MMBtu. A significant portion of our Delaware Basin natural gas production, however, is sold at Houston Ship Channel pricing and is not exposed to Waha pricing. During 2023 and 2024, we typically realized a narrower differential to natural gas sold at the Waha hub despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our natural gas production into other markets to improve our realized natural gas pricing. Further, approximately 3% of our reported natural gas production for the six months ended June 30, 2026 was attributable to the Haynesville shale play, which is not exposed to Waha pricing. In addition, most of our natural gas volumes in the Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes exposed to Waha pricing.