Matador Resources Co (MTDR)

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement and the San Mateo Credit Facility, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.”

For a comparison of our results of operations for the years ended December 31, 2023 and December 31, 2022, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 27, 2024.

Overview

We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of, and to provide flow assurance for, our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.

2024 Operational Highlights

We began 2024 operating seven drilling rigs in the Delaware Basin. We added an eighth operated drilling rig in the first quarter of 2024 and a ninth operated drilling rig late in the second quarter of 2024. Upon the consummation of the Ameredev Acquisition, we continued operating a total of nine drilling rigs for the combined Matador and Ameredev properties. 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. We were able to achieve D/C/E capital expenditures for 2024 of $1.32 billion, which was within our estimated range for 2024 D/C/E capital expenditures of $1.15 to $1.35 billion, as provided on October 22, 2024.

During the year ended December 31, 2024, we completed and began producing oil and natural gas from 124 gross (101.9 net) operated and 127 gross (8.3 net) horizontal non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2024, although we did participate in the drilling and completion of eight gross (0.1 net) non-operated Haynesville shale wells that began producing in 2024.

Substantially all of our 2024 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, including properties acquired in the Ameredev Acquisition, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin, including the Ameredev Acquisition.

Our average daily oil equivalent production for the year ended December 31, 2024 was 170,751 BOE per day, including 99,808 Bbl of oil per day and 425.7 MMcf of natural gas per day, an increase of 30%, as compared to 131,813 BOE per day, including 75,457 Bbl of oil per day and 338.1 MMcf of natural gas per day, for the year ended December 31, 2023. Our average daily oil production in 2024 was 99,808 Bbl of oil per day, an increase of 32%, as compared to 75,457 Bbl of oil per day in 2023. This increase in oil production was primarily a result of the Ameredev Acquisition and our ongoing delineation and

73

Table of Contents

development drilling activities in the Delaware Basin. Our average daily natural gas production for the year ended December 31, 2024 was 425.7 MMcf per day, an increase of 26%, as compared to 338.1 MMcf per day in 2023. This increase in natural gas production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised 58% and 57% of our total production for the years ended December 31, 2024 and 2023, respectively.

For the year ended December 31, 2024, our oil and natural gas revenues were $3.14 billion, an increase of 24% from oil and natural gas revenues of $2.55 billion for the year ended December 31, 2023. Our oil revenues increased 29% to 2.77 billion, as compared to $2.14 billion for the year ended December 31, 2023. The increase in oil revenues resulted from the 33% increase in our oil production noted above, which was partially offset by a 3% decrease in the weighted average oil price realized for the year ended December 31, 2024 to $75.89 per Bbl, as compared to $77.88 per Bbl realized for the year ended December 31, 2023. Our natural gas revenues decreased 7% to $371.5 million, as compared to $400.7 million for the year ended December 31, 2023. The decrease in natural gas revenues resulted from a decrease in our weighted average realized natural gas price of $2.38 per Mcf in 2024, as compared to $3.25 per Mcf in 2023, which was partially offset by the 26% increase in natural gas production for the year ended December 31, 2024 noted above.

We reported net income attributable to Matador shareholders of approximately $885.3 million, or $7.14 per diluted common share, on a GAAP basis for the year ended December 31, 2024, as compared to a net income of $846.1 million, or $7.05 per diluted common share, for the year ended December 31, 2023. Adjusted EBITDA for the year ended December 31, 2024 was $2.30 billion, as compared to Adjusted EBITDA of $1.85 billion for the year ended December 31, 2023. 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.”

At December 31, 2024, our estimated total proved oil and natural gas reserves were 611.5 million BOE, including 361.8 million Bbl of oil and 1.50 Tcf of natural gas, with a Standardized Measure of $7.38 billion and a PV-10 of $9.23 billion. At December 31, 2023, our estimated total proved oil and natural gas reserves were 460.1 million BOE, including 272.3 million Bbl of oil and 1.13 Tcf of natural gas, with a Standardized Measure of $6.11 billion and a PV-10 of $7.70 billion. Our estimated total proved reserves of 611.5 million BOE at December 31, 2024 represented a 33% year-over-year increase, as compared to 460.1 million BOE at December 31, 2023. Our estimated proved oil reserves were 361.8 million Bbl at December 31, 2024, an increase of 33%, as compared to 272.3 million Bbl at December 31, 2023, and our estimated proved natural gas reserves were 1.50 Tcf at December 31, 2024, an increase of 33%, as compared to 1.13 Tcf at December 31, 2023. Proved oil reserves comprised 59% of our total proved reserves at each of December 31, 2024 and 2023. At December 31, 2024, 60% of our total proved reserves were proved developed reserves, as compared to 63% at December 31, 2023. At December 31, 2024, approximately 99% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin.

At both December 31, 2024 and December 31, 2023, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business—Estimated Proved Reserves.”

74

Table of Contents

2024 Midstream Highlights

On September 18, 2024, we completed the Ameredev Acquisition, which included approximately 180 miles of gas gathering, water gathering and oil transportation and gathering pipeline assets.

San Mateo achieved strong operating results in 2024, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point.

On December 18, 2024, we completed the Pronto Transaction, pursuant to which we contributed Pronto, a wholly-owned subsidiary of the Company, to San Mateo, and Five Point made a cash contribution to San Mateo of $171.5 million. In connection with the Pronto Transaction, the Company received a special distribution from San Mateo of approximately $219.8 million. In addition, the Company has the potential to earn up to $75.0 million in incentive payments from Five Point over a five-year period. San Mateo continues to be owned 51% by the Company and 49% by Five Point.

Pronto owns and operates the Marlan Processing Plant, which has a designed inlet capacity of 60 MMcf of natural gas per day. Pronto is expanding the Marlan Processing Plant to add an additional plant with a designed inlet capacity of 200 MMcf of natural gas per day, which would increase the total capacity of the Marlan Processing Plant to 260 MMcf of natural gas per day.

In connection with the Pronto Transaction, the Company dedicated to Pronto its current and certain future leasehold interests in the Ranger and Antelope Ridge asset areas pursuant to 15-year, fixed fee natural gas gathering, compression, treating and processing agreements whereby Pronto will gather, compress, treat and process natural gas produced from the Company’s operated wells in northern Lea County, New Mexico. In addition, Pronto entered into certain agreements with Northwind, an affiliate of Five Point, whereby Northwind will treat certain sour gas gathered and delivered by Pronto in northern Lea County, New Mexico. Under these agreements, Northwind will redeliver the treated sweet gas from Pronto and other third-party customers to Pronto for processing.

In March 2024, we completed our natural gas pipeline connections between Pronto and San Mateo and between Pronto and Matador’s acreage obtained in the Advance Acquisition. These connector pipelines provide further flow assurance and options for Matador and third-party customer natural gas, and resulted in Pronto and San Mateo’s plants operating at or above nameplate capacity at times during 2024.

During 2024, San Mateo and Pronto also closed new midstream transactions with oil and natural gas producers and other counterparties in Eddy and Lea Counties, New Mexico, which are expected to generate additional natural gas gathering and processing and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo and Pronto by existing customers, which we believe is indicative of the quality of service San Mateo and Pronto provides to all of its customers in the Delaware Basin.

At December 31, 2024, following the Pronto Transaction, San Mateo’s midstream system included:

•Natural Gas Assets: 520 MMcf per day of designed natural gas cryogenic processing capacity and approximately 295 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico;

•Oil Assets: three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 110 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and

•Produced Water Assets: 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 180 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.

75

Table of Contents

2025 Capital Expenditure Budget

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2025 and currently operate nine drilling rigs in the Delaware Basin. 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 2025 estimated capital expenditure budget consists of $1.28 to $1.47 billion for D/C/E capital expenditures and $120.0 to $180.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2025 capital expenditures as well as the estimated 2025 capital expenditures for other wholly-owned midstream projects. Substantially all of these 2025 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 2025 Delaware Basin operated drilling program 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.

At December 31, 2024, we had $23.0 million in cash (excluding restricted cash) and $1.60 billion in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $2.25 billion). We expect to fund our 2025 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2025, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or 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.

As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, during 2025, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2025 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2025.

76

Table of Contents

Revenues

The following table summarizes our revenues and production data for the periods indicated.

________________

(1)We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with NGLs are included with our natural gas revenues.

(2)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

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

Oil and natural gas revenues. Our oil and natural gas revenues increased $598.2 million, or 24%, to $3.14 billion for the year ended December 31, 2024, as compared to $2.55 billion for the year ended December 31, 2023. Our oil revenues increased $627.5 million, or 29%, to $2.77 billion for the year ended December 31, 2024, as compared to $2.14 billion for the year ended December 31, 2023. This increase in oil revenues resulted from a 33% increase in our oil production to 36.5 million Bbl of oil for the year ended December 31, 2024, as compared to 27.5 million Bbl of oil for the year ended December 31, 2023, which was partially offset by a 3% decrease in the weighted average oil price realized for the year ended December 31, 2024 to $75.89 per Bbl, as compared to $77.88 per Bbl realized for the year ended December 31, 2023. The increase in oil production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues decreased by $29.2 million, or 7%, to $371.5 million for the year ended December 31, 2024, as compared to $400.7 million for the year ended December 31, 2023. The decrease in natural gas revenues was primarily attributable to the 27% decrease in the weighted average natural gas price realized for the year ended December 31, 2024 to $2.38 per Mcf, as compared to $3.25 per Mcf realized for the year ended December 31, 2023, which was partially offset by a 26% increase in our natural gas production to 155.8 Bcf for the year ended December 31, 2024, as compared to 123.4 Bcf for the year ended December 31, 2023. The increase in natural gas production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin.

Third-party midstream services revenues. Our third-party midstream services revenues increased $18.9 million, or 15%, to $141.0 million for the year ended December 31, 2024, as compared to $122.2 million for the year ended December 31, 2023. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in third-party produced water disposal revenues to $56.3 million for the year ended December 31, 2024, as compared to $45.3 million for the year ended December 31, 2023 and (ii) an increase in our oil transportation revenues to $17.3 million for the year ended December 31, 2024, as compared to $11.0 million for the year ended December 31, 2023.

Sales of purchased natural gas. Our sales of purchased natural gas increased $44.2 million, or 30%, to $194.1 million for the year ended December 31, 2024, as compared to $149.9 million for the year ended December 31, 2023. This increase was primarily the result of a 45% increase in natural gas volumes sold, which was partially offset by an 11% decrease in natural gas

77

Table of Contents

prices realized. Sales of purchased natural gas primarily 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 consolidated statements of income.

Realized gain (loss) on derivatives. Our realized net gain on derivatives was $12.7 million for the year ended December 31, 2024, as compared to a realized net loss of approximately $9.6 million for the year ended December 31, 2023. We realized a net gain of approximately $12.7 million related to our natural gas basis differential swap contracts for the year ended December 31, 2024, resulting primarily from natural gas basis differentials that were below the fixed prices of our natural gas basis differential swap contracts. We realized a net loss of approximately $9.6 million related to our natural gas costless collar and natural gas basis differential swap contracts for the year ended December 31, 2023, resulting primarily from natural gas basis differentials that were above the strike price of our natural gas basis differential swap contracts, offset by natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. We realized an average gain on our natural gas derivatives of approximately $0.09 per Mcf of natural gas produced during the year ended December 31, 2024, as compared to an average loss on our natural gas derivatives of approximately $0.08 per Mcf of natural gas produced during the year ended December 31, 2023.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $13.3 million for the year ended December 31, 2024, as compared to an unrealized loss of $1.3 million for the year ended December 31, 2023. During the year ended December 31, 2024, the aggregate net fair value of our open oil costless collar and natural gas basis differential swap contracts changed from a net asset of approximately $2.7 million to a net asset of approximately $16.0 million, resulting in an unrealized gain on derivatives of approximately $13.3 million for the year ended December 31, 2024. During the year ended December 31, 2023, the aggregate net fair value of our open natural gas derivative contracts changed from a net asset of approximately $3.9 million to a net asset of approximately $2.7 million, resulting in an unrealized loss on derivatives of approximately $1.3 million for the year ended December 31, 2023.

78

Table of Contents

Expenses

The following table summarizes our operating expenses and other income (expense) for the periods indicated.

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

Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased $42.3 million, or 16%, to $306.8 million for the year ended December 31, 2024, as compared to $264.5 million for the year ended December 31, 2023. This increase was primarily attributable to the $43.4 million increase in our production taxes to $243.6 million for the year ended December 31, 2024, as compared to $200.2 million for the year ended December 31, 2023, primarily due to the $598.2 million increase in oil and natural gas revenues for the year ended December 31, 2024, as compared to the year ended December 31, 2023. On a unit-of-production basis, our production taxes and transportation and processing expenses decreased 11% to $4.91 per BOE for the year ended December 31, 2024, as compared to $5.50 per BOE for the year ended December 31, 2023. This decrease was primarily attributable to a decrease in transportation and processing expense per BOE that resulted from a mix of revenue contracts, including from San Mateo, between the two periods.

Lease operating expenses. Our lease operating expenses increased $97.9 million, or 40%, to $341.5 million for the year ended December 31, 2024, as compared to $243.7 million for the year ended December 31, 2023. On a unit-of-production basis, our lease operating expenses increased 8% to $5.47 per BOE for the year ended December 31, 2024, as compared to $5.06 per BOE for the year ended December 31, 2023. These increases for the year ended December 31, 2024 were primarily attributable to the increased number of wells being operated by us, including 204 wells from the Ameredev Acquisition, and other operators (where we own a working interest) and to operating cost inflation during the year ended December 31, 2024, as compared to the year ended December 31, 2023.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $42.6 million, or 33%, to $171.5 million for the year ended December 31, 2024, as compared to $128.9 million for the year ended December 31, 2023. This increase was primarily attributable to increased throughput volumes at San Mateo from Matador and other customers, which resulted in (i) increased expenses associated with our expanded pipeline operations,

79

Table of Contents

including assets acquired in the Ameredev Acquisition, of $73.9 million for the year ended December 31, 2024, as compared to $41.4 million for the year ended December 31, 2023 and (ii) increased expenses associated with our commercial produced water disposal operations of $63.0 million for the year ended December 31, 2024, as compared to $53.6 million for the year ended December 31, 2023.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $257.6 million, or 36%, to $974.3 million for the year ended December 31, 2024, as compared to $716.7 million for the year ended December 31, 2023, primarily as a result of the Ameredev Acquisition and a 30% increase in our total oil equivalent production between the respective periods. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 5% to $15.59 per BOE for the year ended December 31, 2024, as compared to $14.90 per BOE for the year ended December 31, 2023, primarily as a result of the Ameredev Acquisition.

General and administrative. Our general and administrative expenses increased $17.1 million, or 15%, to $127.5 million for the year ended December 31, 2024, as compared to $110.4 million for the year ended December 31, 2023, primarily due to

increased compensation expenses for our existing employees as well as the addition of new employees to support the continued

growth in our land, geoscience, drilling, completion, production, midstream and administration functions. Our general and administrative expenses on a unit-of-production basis decreased 11% to $2.04 per BOE for the year ended December 31, 2024, as compared to $2.29 per BOE for the year ended December 31, 2023, primarily as a result of the 30% increase in our total oil equivalent production between the two periods.

Interest expense. For the year ended December 31, 2024, we incurred total interest expense of approximately $201.5 million. We capitalized approximately $29.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2024 and expensed the remaining $171.7 million to operations. For the year ended December 31, 2023, we incurred total interest expense of approximately $143.7 million. We capitalized approximately $22.2 million of our interest expense on certain qualifying projects for the year ended December 31, 2023 and expensed the remaining $121.5 million to operations. The increase in interest expense for the year ended December 31, 2024 was primarily attributable to an increase in our average debt outstanding between the two periods. In April 2024, we completed the 2026 Notes Repurchase and the 2032 Notes Offering and in September 2024 we completed the 2033 Notes Offering, resulting in a net increase in our total senior notes outstanding to $2.15 billion at December 31, 2024 as compared to $1.20 billion at December 31, 2023. In connection with the 2026 Notes Repurchase, the amendment of our Credit Agreement in March 2024 and the amendment of the San Mateo Credit Facility in November 2024, we also incurred a loss of approximately $6.2 million included in interest expense for the year ended December 31, 2024.

Total income tax provision. We recorded a current income tax provision of $27.1 million and a deferred income tax provision of $265.3 million for the year ended December 31, 2024. Our effective income tax rate of 25% for the year ended December 31, 2024 differed from the U.S. federal statutory rate due primarily to state taxes, primarily in New Mexico. We recorded a current income tax provision of $13.9 million and a deferred income tax provision of $172.1 million for the year ended December 31, 2023. Our effective income tax rate of 18% for the year ended December 31, 2023 differed from the U.S. federal statutory rate due primarily to recognizing research and experimental expenditure tax credits of $74.0 million, which were partially offset by permanent differences between book and taxable income and state taxes, primarily in New Mexico.

Liquidity and Capital Resources

Our primary use of capital has been, and we expect will continue during 2025 and for the foreseeable future to be, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. We expect to fund our 2025 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2025, we expect to fund any excess capital expenditures, including for significant acquisitions, through borrowings under the Credit Agreement or 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.

At December 31, 2024, we had cash totaling $23.0 million and restricted cash totaling $71.7 million, which was primarily associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

At December 31, 2024, we had (i) $500.0 million of outstanding 6.875% senior notes due 2028 (the “2028 Notes”), (ii) $900.0 million of outstanding 2032 Notes, (iii) $750.0 million of outstanding 2033 Notes, (iv) $595.5 million of borrowings

80

Table of Contents

outstanding under the Credit Agreement and (v) approximately $52.9 million in outstanding letters of credit issued pursuant to the Credit Agreement.

On March 22, 2024, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) reaffirm the borrowing base at $2.50 billion, (ii) increase the elected borrowing commitment from $1.325 billion to $1.50 billion, (iii) increase the maximum facility amount from $2.00 billion to $3.50 billion, (iv) extend the maturity date from October 31, 2026 to March 22, 2029, (v) appoint PNC Bank, National Association as administrative agent thereunder and (vi) add five new banks to the lending group. This March 2024 redetermination constituted the regularly scheduled May 1 redetermination.

On March 28, 2024, we completed the 2024 Equity Offering and used the net proceeds for general corporate purposes, including the funding of acquisitions and the repayment of borrowings outstanding under the Credit Agreement.

On April 2, 2024, we completed the 2032 Notes Offering and used the net proceeds to fund the 2026 Notes Repurchase and for general corporate purposes, including the funding of acquisitions and the repayment of borrowings outstanding under the Credit Agreement.

On September 18, 2024, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) provide for a term loan of $250.0 million, the full amount of which was borrowed to fund the Ameredev Acquisition, and (ii) increase the elected borrowing commitment from $1.50 billion to $2.25 billion.

On September 25, 2024, we completed the 2033 Notes Offering and used the net proceeds to partially repay borrowings outstanding under the Credit Agreement including all of the $250.0 million in outstanding borrowings under the term loan.

On October 28, 2024, Piñon was acquired by an affiliate of Enterprise Products Partners L.P. During the fourth quarter of 2024, we received $113.6 million from the sale of Piñon resulting from our approximate 19% interest in the parent company of Piñon that we acquired as part of the Ameredev Acquisition and used these proceeds to reduce borrowings under our Credit Agreement. We currently expect to receive an additional $4.8 million from the sale of Piñon in the first half of 2025.

On November 21, 2024, we received notice from PNC Bank, National Association, as administrative agent under the Credit Agreement, that the lenders under the Credit Agreement completed their scheduled semi-annual review of our proved oil and natural gas reserves and unanimously determined to increase the borrowing base from $2.50 billion to $3.25 billion. We chose to maintain the elected borrowing commitments at $2.25 billion.

The Credit Agreement requires us to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities of debt, of not less than 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to the greater of $150 million or 10% of the elected borrowing commitments of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 or less at the end of each fiscal quarter. We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2024.

At December 31, 2024, San Mateo had $615.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. On November 26, 2024, San Mateo and its lenders entered into an amendment to the San Mateo Credit Facility to, among other things: (i) extend the maturity date of the facility from December 9, 2026 to November 26, 2029, (ii) increase the lender commitments from $535.0 million to $800.0 million and (iii) add six new banks to San Mateo’s lending group. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in the commitments of the lenders to up to $1.05 billion.

The San Mateo Credit Facility is non-recourse with respect to Matador and its other subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s debt to EBITDA ratio is greater than 4.50 or San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2024.

In February 2024, April 2024 and July 2024, our Board declared quarterly cash dividends of $0.20 per share of common stock. In October 2024, the Board amended our dividend policy to increase the quarterly dividend to $0.25 per share of common stock and also declared a quarterly cash dividend of $0.25 per share of common stock. In February 2025, the Board amended our dividend policy to increase the quarterly dividend to $0.3125 per share of common stock and also declared a

81

Table of Contents

quarterly cash dividend of $0.3125 per share of common stock payable on March 14, 2025 to shareholders of record as of February 28, 2025.

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2025. We currently operate nine drilling rigs in the Delaware Basin. 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 2025 estimated capital expenditure budget consists of $1.28 to $1.47 billion for D/C/E capital expenditures and $120.0 to $180.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2025 capital expenditures as well as the estimated 2025 capital expenditures for other wholly-owned midstream projects. Substantially all of these 2025 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 2025 Delaware Basin operated drilling program 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.

As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, during 2025, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2025 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2025.

Our 2025 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control.

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 2025 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays 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 2025 and the hedges we currently have in place. For a 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 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2024. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”

82

Table of Contents

Our cash flows for the years ended December 31, 2024, 2023 and 2022 are presented below.

__________________

(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.

Net Cash Provided by Operating Activities

Net cash provided by operating activities increased by $379.1 million to $2.25 billion for the year ended December 31, 2024, as compared to net cash provided by operating activities of $1.87 billion for the year ended December 31, 2023. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $2.23 billion for the year ended December 31, 2024 from $1.82 billion for the year ended December 31, 2023. This increase was primarily attributable to the 30% increase in total oil equivalent production during 2024, as compared to 2023, which was partially offset by lower realized oil and natural gas prices for the year ended December 31, 2024, as compared to the year ended December 31, 2023. Changes in our operating assets and liabilities between December 31, 2023 and December 31, 2024 resulted in a net decrease of approximately $36.9 million in net cash provided by operating activities for the year ended December 31, 2024, as compared to the year ended December 31, 2023.

Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-controlled oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. From time to time, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors—Risks Related to Our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”

Net Cash Used in Investing Activities

Net cash used in investing activities increased by $460.9 million to $3.67 billion for the year ended December 31, 2024 from $3.21 billion for the year ended December 31, 2023. This increase in net cash used in investing activities was primarily due to (i) expenditures related to the Ameredev Acquisition of $1.83 billion in 2024, which was $155.1 million higher than expenditures related to the Advance Acquisition of $1.68 billion in 2023, (ii) an increase between the periods of $266.8 million in acquisitions of oil and natural gas properties, (iii) an increase between the periods of $118.2 million in midstream capital expenditures and (iv) an increase of $30.0 million in D/C/E capital expenditures primarily attributable to our operated and non-operated drilling, completion and equipping activities in the Delaware Basin. These increases were partially offset by proceeds from the sale of our equity method investment in Piñon of $113.6 million for the year ended December 31, 2024.

Net Cash Provided by (Used in) Financing Activities

Net cash provided by financing activities increased $511.3 million to $1.41 billion for the year ended December 31, 2024, from net cash provided by financing activities of $902.3 million for the year ended December 31, 2023. During the year ended December 31, 2024, our net cash provided by financing activities was primarily attributable to (i) proceeds from the 2032 Notes Offering of $900.0 million, (ii) proceeds from the 2033 Notes Offering of $750.0 million, (iii) proceeds from the 2024 Equity Offering of $344.7 million, (iv) net contributions to San Mateo of $116.9 million, which included a contribution of $171.5 million from Five Point to San Mateo related to the Pronto Transaction, (v) net borrowings under the Credit Agreement of $95.5 million and (vi) net borrowings under the San Mateo Credit Facility of $93.0 million. These increases were partially offset by (i) the repurchase of an aggregate principal amount of approximately $699.2 million of 2026 Notes in the 2026 Notes Repurchase, (ii) dividends paid of $104.9 million, (iii) costs associated with the 2032 Notes Offering and 2033 Notes Offering of $28.2 million, (iv) costs to amend the Credit Agreement and the San Mateo Credit Facility of $33.4 million and (v) payment of taxes related to stock-based compensation of $17.0 million. During the year ended December 31, 2023, our net cash provided

83

Table of Contents

by financing activities was primarily attributable to (i) proceeds from the issuance of the 2028 Notes of $494.8 million, (ii) net borrowings under our Credit Agreement of $500.0 million and (iii) net borrowings under the San Mateo Credit Facility of $57.0 million, which were partially offset by (x) dividends paid of $77.2 million and (y) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $15.6 million.

See Note 7 to the consolidated financial statements in this Annual Report for a summary of our debt, including the Credit Agreement, the San Mateo Credit Facility, the 2028 Notes, the 2032 Notes and the 2033 Notes.

Non-GAAP Financial Measures

We define Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”) as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, non-recurring transaction costs for certain acquisitions, certain other non-cash items and non-cash stock-based compensation expense and net gain or loss on asset sales and impairment. Adjusted EBITDA is not a measure of net income (loss) 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.

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 (loss) 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.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) 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.

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.

84

Table of Contents

For the year ended December 31, 2024, we reported net income attributable to Matador shareholders of $885.3 million, as compared to $846.1 million for the year ended December 31, 2023. This increase primarily resulted from significantly higher oil and natural gas production for the year ended December 31, 2024, as compared to the year ended December 31, 2023. These increases were partially offset by increased depletion, depreciation and amortization expenses of $974.3 million for the year ended December 31, 2024, as compared to $716.7 million for the year ended December 31, 2023, increased interest expense of $171.7 million for the year ended December 31, 2024, as compared to $121.5 million for the year ended December 31, 2023, an increased income tax provision of $292.4 million for the year ended December 31, 2024, as compared to an income tax provision of $186.0 million for the year ended December 31, 2023 and by lower realized oil and natural gas prices between the periods.

Adjusted EBITDA, a non-GAAP financial measure, increased $449.2 million to $2.30 billion for the year ended December 31, 2024, as compared to $1.85 billion for the year ended December 31, 2023. This increase was primarily attributable to higher oil and natural gas production noted above, partially offset by lower realized oil and natural gas prices for the year ended December 31, 2024, as compared to the year ended December 31, 2023.

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2024, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference.

85

Table of Contents

Obligations and Commitments

We had the following material contractual obligations and commitments at December 31, 2024.

__________________

(1)The amounts included in the table above represent principal maturities only. At December 31, 2024, we had $595.5 million in borrowings outstanding under the Credit Agreement and approximately $52.9 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 December 31, 2024 San Mateo had $615.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 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 6.19% and 6.44%, respectively, for the Credit Agreement and the San Mateo Credit Facility at December 31, 2024, the interest expense for such facilities is expected to be approximately $37.4 million and $40.2 million, respectively, each year until maturity.

(2)The amounts included in the table above represent principal maturities only. Interest expense on the $500.0 million of outstanding 2028 Notes as of December 31, 2024 is expected to be approximately $34.4 million each year until maturity. Interest expense on the $900.0 million of outstanding 2032 Notes as of December 31, 2024 is expected to be approximately $58.5 million each year until maturity. Interest expense on the $750.0 million of outstanding 2033 Notes as of December 31, 2024 is expected to be approximately $46.9 million each year until maturity.

(3)At December 31, 2024, we had outstanding commitments to participate in the drilling and completion of various non-operated wells.

(4)We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments.

(5)The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at December 31, 2024.

(6)From time to time, we enter into agreements with third parties whereby we commit to deliver anticipated natural gas and oil production and produced water from certain portions of our acreage for transportation, gathering, processing, fractionation, sales and disposal. Certain of these agreements contain minimum volume commitments, including certain agreements with Northwind that were entered into in connection with the Pronto Transaction. If we do not meet the minimum volume commitments under these agreements, we would be required to pay certain deficiency fees. See Note 14 to the consolidated financial statements in this Annual Report for more information about these contractual commitments.

(7)We dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and the Wolf portion of the West Texas asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements. In connection with the Pronto Transaction, we dedicated to Pronto our current and certain future leasehold interests in the Ranger and Antelope Ridge asset areas pursuant to 15-year, fixed fee natural gas gathering, compression, treating and processing agreements with Pronto whereby Pronto will gather, compress, treat and process natural gas produced from our operated wells in northern Lea County, New Mexico. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments.

(8)At December 31, 2024, we had outstanding commitments related to the construction and installation of San Mateo’s Marlan Processing Plant expansion with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities, in addition to commitments to purchase compressors to be utilized in San Mateo operations.

86

Table of Contents

General Outlook and Trends

Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. For example, the recent election of President Trump and a Republican-controlled Congress may alter our current regulatory framework and impact our business and the oil and gas industry generally. Commodity price volatility, in particular, is a significant risk to our business, cash flows and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, ongoing military conflicts, including the ongoing military conflicts between Russia and Ukraine and in the Middle East, political instability, particularly in China and in the Middle East, the actions of OPEC+, weather, pipeline capacity constraints, inventory storage levels, domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases, oil and natural gas price differentials and other factors.

The prices we receive for oil, natural gas and NGLs heavily influence our revenues, profitability, cash flow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil, natural gas and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or NGL prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and NGLs we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves and our ability to comply with the financial covenants under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”

For the year ended December 31, 2024, oil prices averaged $75.76 per Bbl, as compared to $77.60 per Bbl in 2023, ranging from a high of $86.91 per Bbl in early April to a low of $65.75 per Bbl in mid-September, based upon the WTI oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $75.89 per Bbl (with no realized gains or losses from oil derivatives) for our oil production for the year ended December 31, 2024, as compared to $77.88 per Bbl (with no realized gains or losses from oil derivatives) for the year ended December 31, 2023. At February 18, 2025, the WTI oil futures contract price for the earliest delivery date had increased slightly from year-end 2024, closing at $71.85 per Bbl, but was lower compared to $79.19 per Bbl on February 16, 2024.

For the year ended December 31, 2024, natural gas prices averaged $2.40 per MMBtu, as compared to $2.66 per MMBtu in 2023, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2024, natural gas prices ranged from a low of $1.58 per MMBtu in late March to a high of $3.95 per MMBtu in late December. As a result of expected winter weather, increased demand for LNG exports, tightening storage levels and concerns about potential supply disruptions, natural gas prices increased over the course of the fourth quarter of 2024, finishing the year at $3.63 per MMBtu. We report production volumes in two streams, oil and natural gas (which includes both dry gas and NGLs). NGL prices were also lower in 2024 as compared to 2023, which contributed to lower realized weighted average natural gas prices for the year ended December 31, 2024. We realized a weighted average natural gas price of $2.38 per Mcf ($2.47 per Mcf including realized gains from natural gas derivatives) for our natural gas production for the year ended December 31, 2024, as compared to $3.25 per Mcf ($3.17 per Mcf including realized losses from natural gas derivatives) for the year ended December 31, 2023. At February 18, 2025, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had increased from year-end 2024, closing at $4.01 per MMBtu, and was higher as compared to $1.61 per MMBtu at February 16, 2024.

The prices we receive for oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. At December 31, 2024, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and a significant portion of our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the Waha hub in far West Texas.

The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years. At February 18, 2025, this oil price differential was approximately +$1.33 per Bbl. At February 18, 2025, we had no derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential for 2025.

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 a result, the Waha-Henry Hub basis differential began to widen. The Waha-Henry Hub basis differential averaged ($2.20) per MMBtu for the year ended December 31, 2024. Between December 31, 2024 and February 18, 2025, this natural gas price differential widened to approximately ($2.70) per MMBtu. A significant portion of our

87

Table of Contents

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 5% of our reported natural gas production for the year ended December 31, 2024 was attributable to the Haynesville and Eagle Ford shale plays, which are not exposed to Waha pricing. In addition, as a two-stream reporter, 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.

From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under the Credit Agreement and through the capital markets. During the year ended December 31, 2024, we realized gains on our natural gas basis differential derivative contracts of approximately $12.7 million resulting primarily from natural gas basis differentials that were below the fixed prices of our natural gas basis differential swap contracts. At December 31, 2024, we had derivative natural gas basis differential swap contracts in place to mitigate our exposure to the Waha-Henry Hub basis differential for approximately 11.0 Bcf of our anticipated natural gas production in 2025.

We have at times experienced pipeline-related interruptions to our oil, natural gas or NGL production or produced water disposal. In certain recent periods, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware Basin. Although we did not encounter such fractionation capacity problems, we can provide no assurances that such problems will not arise. If we do experience any material interruptions with produced water disposal, takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. Should we experience future periods of negative pricing for natural gas as we have experienced historically, including in 2024, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results.

We have at times experienced inflation in the costs of certain oilfield services, including diesel, steel, labor, trucking, sand, personnel and completion costs, among others. Should oil prices remain at their current levels or increase, we may be subject to additional service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. In addition, supply chain disruptions, tariffs and trade restrictions and other inflationary pressures experienced in recent periods throughout the United States and global economy and in the oil and natural gas industry may limit our ability to procure the necessary products and services we need for drilling, completing and producing wells in a timely and cost-effective manner, which could result in reduced margins and delays to our operations and could, in turn, adversely affect our business, financial condition, results of operations and cash flows.

We recorded a current income tax provision of $27.1 million and a deferred income tax provision of $265.3 million for the year ended December 31, 2024. Our effective income tax rate of 25% for the year ended December 31, 2024 differed from the U.S. federal statutory rate due primarily to state taxes, primarily in New Mexico. At February 18, 2025, given our current projections, we expect to continue to pay federal income taxes and state income taxes in New Mexico of between 5% and 10% of 2025 pretax book income, but we do not expect to be subject to the Corporate Alternative Minimum Tax (the “CAMT”) in 2025. We could be subject to the CAMT in future years, which would require us to pay minimum cash tax payments of 15% of annual adjusted pretax book income.

Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are proposed or promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. For more information about the Company’s regulatory matters, see “Business—Regulation” and “Risk Factors—Risks Related to Laws and Regulations”.

Certain segments of the investor community have at times expressed negative sentiment towards investing in the oil and natural gas industry and some investors, including certain pension funds, sovereign wealth funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. See “Risk Factors—Risks Related to our Common Stock—Attention to ESG and conservation matters and a negative shift in market perception towards the oil and natural gas industry could adversely affect demand for oil and natural gas and our stock price.”

Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production

88

Table of Contents

declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A significant reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and the availability under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth”.

We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable and that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2024.

Oil and Natural Gas Properties

We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive.

Ceiling Test

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of:

(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus

(b) unproved and unevaluated property costs not being amortized, plus

(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less

(d) any income tax effects related to the properties involved.

Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. Our derivative instruments are not considered in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes.

89

Table of Contents

Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue

Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time.

Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including assumptions related to oil and natural gas prices, development expenditures, operating expenses, capital expenditures, taxes and availability of funds. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors—Risks Related to our Financial Condition—Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves” and “Risk Factors—Risks Related to our Financial Condition—We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition.”

Estimates of proved oil and natural gas reserves are key inputs used for the calculations of depletion, the ceiling test and the fair value assigned to proved oil and natural gas reserves acquired in a business combination. The estimated present value of future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The associated commodity prices and the applicable discount rate used to determine the fair value assigned to proved oil and natural gas reserves acquired in a business combination are based upon a variety of factors on the date of acquisition. The associated commodity prices and the applicable discount rate used in estimates for depletion and the ceiling test are in accordance with guidelines established by the SEC. Under these guidelines, future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues.

Income Taxes

We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition.

We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.

Purchase Accounting

Periodically we acquire assets and assume liabilities in transactions accounted for as business combinations, such as the Advance Acquisition in 2023 and the Ameredev Acquisition in 2024.

90

Table of Contents

In estimating the fair value of assets acquired and liabilities assumed in these transactions, including the Advance Acquisition and the Ameredev Acquisition, we must make a number of estimates and assumptions and may engage third-party valuation experts. The most significant assumptions relate to the estimated fair values of oil and natural gas properties. Significant judgments and assumptions are inherent in these estimates and include, among other things, estimates of future production volumes, estimates of future commodity prices, expected development and operating costs, an estimate of a market-based weighted average cost of capital rate and recent market comparable transactions for unproved acreage.

Recent Accounting Pronouncements

See Note 2 to the consolidated financial statements in this Annual Report for a description of recent accounting pronouncements.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement and the San Mateo Credit Facility, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.”

For a comparison of our results of operations for the years ended December 31, 2022 and December 31, 2021, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on March 1, 2023.

Overview

We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.

2023 Operational Highlights

We began 2023 operating seven drilling rigs in the Delaware Basin. Following the closing of the Initial Advance Acquisition on April 12, 2023, we continued operating the drilling rig that Advance had been operating. Near the end of June 2023, we released this eighth operated drilling rig and continued operating seven drilling rigs in the Delaware Basin for the remainder of 2023. We added back an eighth operated drilling rig in the first quarter of 2024. 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. We were able to achieve D/C/E capital expenditures for 2023 of $1.16 billion, which was below our estimated range for 2023 D/C/E capital expenditures of $1.18 to $1.32 billion as provided on February 21, 2023, and was in the middle of the revised estimated range of $1.10 to $1.22 billion, as provided on July 25, 2023.

During the year ended December 31, 2023, we completed and began producing oil and natural gas from 119 gross (94.0 net) operated and 103 gross (5.6 net) horizontal non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2023, although we did participate in the drilling and completion of 22 gross (0.4 net) non-operated Haynesville shale wells and one gross (0.4 net) non-operated South Texas well that began producing in 2023.

Substantially all of our 2023 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, including properties acquired in the Advance Acquisition, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells drilled and completed in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions, including certain non-operated well opportunities, and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin.

73

Table of Contents

Our average daily oil equivalent production for the year ended December 31, 2023 was 131,813 BOE per day, including 75,457 Bbl of oil per day and 338.1 MMcf of natural gas per day, an increase of 25%, as compared to 105,465 BOE per day, including 60,119 Bbl of oil per day and 272.1 MMcf of natural gas per day, for the year ended December 31, 2022. Our average daily oil production in 2023 was 75,457 Bbl of oil per day, an increase of 26%, as compared to 60,119 Bbl of oil per day in 2022. This increase in oil production was primarily a result of the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining oil production in the Eagle Ford shale where we have not turned to sales any new operated wells since the second quarter of 2019. Our average daily natural gas production for the year ended December 31, 2023 was 338.1 MMcf per day, an increase of 24%, as compared to 272.1 MMcf per day in 2022. This increase in natural gas production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised 57% of our total production for each of the years ended December 31, 2023 and 2022.

For the year ended December 31, 2023, our oil and natural gas revenues were $2.55 billion, a decrease of 12% from oil and natural gas revenues of $2.91 billion for the year ended December 31, 2022. Our oil revenues increased 1% to $2.14 billion, as compared to $2.11 billion for the year ended December 31, 2022. The increase in oil revenues resulted from the 26% increase in our oil production noted above, which was partially offset by a 19% decrease in the weighted average oil price realized for the year ended December 31, 2023 to $77.88 per Bbl, as compared to $96.32 per Bbl realized for the year ended December 31, 2022. Our natural gas revenues decreased 49% to $400.7 million, as compared to $792.1 million for the year ended December 31, 2022. The decrease in natural gas revenues resulted from a decrease in our weighted average realized natural gas price of $3.25 per Mcf in 2023, as compared to $7.98 per Mcf in 2022, which was partially offset by the 24% increase in natural gas production for the year ended December 31, 2023 noted above.

We reported net income attributable to Matador shareholders of approximately $846.1 million, or $7.05 per diluted common share, on a GAAP basis for the year ended December 31, 2023, as compared to a net income of $1.21 billion, or $10.11 per diluted common share, for the year ended December 31, 2022. Adjusted EBITDA for the year ended December 31, 2023 was $1.85 billion, as compared to Adjusted EBITDA of $2.13 billion for the year ended December 31, 2022. 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.”

At December 31, 2023, our estimated total proved oil and natural gas reserves were 460.1 million BOE, including 272.3 million Bbl of oil and 1.13 Tcf of natural gas, with a Standardized Measure of $6.11 billion and a PV-10 of $7.70 billion. At December 31, 2022, our estimated total proved oil and natural gas reserves were 356.7 million BOE, including 196.3 million Bbl of oil and 962.6 Bcf of natural gas, with a Standardized Measure of $6.98 billion and a PV-10 of $9.13 billion. Our estimated total proved reserves of 460.1 million BOE at December 31, 2023 represented a 29% year-over-year increase, as compared to 356.7 million BOE at December 31, 2022. Our estimated proved oil reserves were 272.3 million Bbl at December 31, 2023, an increase of 39%, as compared to 196.3 million Bbl at December 31, 2022, and our estimated proved natural gas reserves were 1.13 Tcf at December 31, 2023, an increase of 17%, as compared to 962.6 Bcf at December 31, 2022. Proved oil reserves comprised 59% of our total proved reserves at December 31, 2023, as compared to 55% at December 31, 2022. At December 31, 2023, 63% of our total proved reserves were proved developed reserves, as compared to 62% at December 31, 2022.

Our proved oil and natural gas reserves in the Delaware Basin increased 31% to 452.6 million BOE at December 31, 2023, as compared to 346.8 million BOE at December 31, 2022, primarily as a result of the Advance Acquisition and our ongoing delineation and development operations there. At December 31, 2023, approximately 98% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin increased 40% to 270.1 million Bbl at December 31, 2023, as compared to 193.5 million Bbl at December 31, 2022, and our proved natural gas reserves in the Delaware Basin increased 19% to 1.09 Tcf, as compared to 919.7 Bcf at December 31, 2022. Proved oil reserves comprised 60% of our Delaware Basin total proved reserves at December 31, 2023, as compared to 56% at December 31, 2022.

At both December 31, 2023 and December 31, 2022, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business—Estimated Proved Reserves.”

74

Table of Contents

2023 Midstream Highlights

San Mateo achieved strong operating results in 2023, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes. Volumes for the years ended December 31, 2023 and 2022 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues during the years ended December 31, 2023 and 2022. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point.

During 2023, San Mateo closed new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin.

At December 31, 2023, San Mateo’s midstream system included:

•Natural Gas Assets: 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 160 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico;

•Oil Assets: three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 100 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and

•Produced Water Assets: 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 175 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.

During 2023, Pronto closed new natural gas gathering and processing transactions with counterparties in Eddy and Lea Counties, New Mexico, which are expected to generate additional natural gas gathering and processing volumes in future periods. At December 31, 2023, Pronto’s midstream system included the Marlan Processing Plant, three compressor stations and approximately 70 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico, spanning from the northeastern portion of the Arrowhead asset area into the Ranger asset area. Pronto has also contracted to construct an additional natural gas processing plant with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities to be located near the Marlan Processing Plant.

2024 Capital Expenditure Budget

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2024. We began 2023 operating seven drilling rigs in the Delaware Basin. Following the closing of the Initial Advance Acquisition on April 12, 2023, we continued operating the drilling rig that Advance had been operating. Near the end of June 2023, we released this eighth operated drilling rig and continued operating seven drilling rigs in the Delaware Basin for the remainder of 2023. We added back an eighth operated drilling rig in the first quarter of 2024. We have built significant optionality into our 2024 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 2024 estimated capital expenditure budget consists of $1.10 to $1.30 billion for D/C/E capital expenditures and $200.0 to $250.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2024 capital expenditures as well as the estimated 2024 capital expenditures for other wholly-owned midstream projects, including projects completed by Pronto. The midstream capital expenditure budget includes 100% of the costs associated with the Marlan Processing Plant expansion noted above, although, at February 20, 2024, we were continuing to evaluate potential partners in Pronto that would share in these capital expenditures and strategic opportunities. Substantially all of these 2024 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 in the Delaware Basin, South Texas and Haynesville shale. Our 2024 Delaware Basin operated drilling program 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 in 2024, including 99% with anticipated completed lateral lengths of one mile or greater.

75

Table of Contents

At December 31, 2023, we had $52.7 million in cash (excluding restricted cash) and $772.6 million in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $1.325 billion). We expect to fund our 2024 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2024, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or 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.

As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, during 2024, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2024 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2024.

76

Table of Contents

Revenues

The following table summarizes our revenues and production data for the periods indicated.

________________

(1)We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with NGLs are included with our natural gas revenues.

(2)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Year Ended December 31, 2023 as Compared to Year Ended December 31, 2022

Oil and natural gas revenues. Our oil and natural gas revenues decreased $360.1 million, or 12%, to $2.55 billion for the year ended December 31, 2023, as compared to $2.91 billion for the year ended December 31, 2022. Our oil revenues increased $31.3 million, or 1%, to $2.14 billion for the year ended December 31, 2023, as compared to $2.11 billion for the year ended December 31, 2022. This increase in oil revenues resulted from a 26% increase in our oil production to 27.5 million Bbl of oil for the year ended December 31, 2023, as compared to 21.9 million Bbl of oil for the year ended December 31, 2022, which was partially offset by a 19% decrease in the weighted average oil price realized for the year ended December 31, 2023 to $77.88 per Bbl, as compared to $96.32 per Bbl realized for the year ended December 31, 2022. The increase in oil production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues decreased by $391.4 million, or 49%, to $400.7 million for the year ended December 31, 2023, as compared to $792.1 million for the year ended December 31, 2022. The decrease in natural gas revenues was primarily attributable to the 59% decrease in the weighted average natural gas price realized for the year ended December 31, 2023 to $3.25 per Mcf, as compared to $7.98 per Mcf realized for the year ended December 31, 2022, which was partially offset by a 24% increase in our natural gas production to 123.4 Bcf for the year ended December 31, 2023, as compared to 99.3 Bcf for the year ended December 31, 2022. The increase in natural gas production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin.

Third-party midstream services revenues. Our third-party midstream services revenues increased $31.5 million, or 35%, to $122.2 million for the year ended December 31, 2023, as compared to $90.6 million for the year ended December 31, 2022. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in our third-party natural gas gathering, transportation and processing revenues to $65.9 million for the year ended December 31, 2023, as compared to $45.1 million for the year ended December 31, 2022, which includes $15.9 million associated with operating our Pronto midstream assets for the year ended December 31, 2023, as compared to $4.4 million for the year ended December 31, 2022, and (ii) an increase in third-party produced water disposal revenues to $45.3 million for the year ended December 31, 2023, as compared to $35.6 million for the year ended December 31, 2022.

77

Table of Contents

Sales of purchased natural gas. Our sales of purchased natural gas decreased $50.5 million, or 25%, to $149.9 million for the year ended December 31, 2023, as compared to $200.4 million for the year ended December 31, 2022. This decrease was primarily the result of the 65% decrease in realized natural gas prices, which was partially offset by a 117% increase in natural gas volumes sold during the year ended December 31, 2023. Sales of purchased natural gas primarily 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 Pronto’s Marlan Processing Plant or San Mateo’s Black River Processing Plant and subsequently sell the residue 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 consolidated statements of income.

Realized loss on derivatives. Our realized net loss on derivatives was $9.6 million for the year ended December 31, 2023, as compared to a realized net loss of approximately $157.5 million for the year ended December 31, 2022. We realized a net loss of approximately $9.6 million related to our natural gas costless collar and natural gas basis differential swap contracts for the year ended December 31, 2023, resulting primarily from natural gas basis differentials that were above the strike price of our natural gas basis differential swap contracts, offset by natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. We realized a net loss of approximately $81.7 million related to our natural gas costless collar contracts for the year ended December 31, 2022, resulting primarily from natural gas prices that were above the ceiling prices of certain of our natural gas costless collar contracts. We realized a net loss of $73.9 million related to our oil costless collar contracts for the year ended December 31, 2022, resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts. We realized a net loss of $1.9 million from our oil basis differential swap contracts for the year ended December 31, 2022, resulting from oil basis differentials that were above the fixed prices of certain of our oil basis differential swap contracts. We realized an average loss on our natural gas derivatives of approximately $0.08 per Mcf of natural gas produced during the year ended December 31, 2023, as compared to an average loss on our natural gas derivatives of approximately $0.83 per Mcf of natural gas produced during the year ended December 31, 2022. Our total natural gas volumes hedged represented 2% and 61% of our total natural gas production for the years ended December 31, 2023 and 2022, respectively.

Unrealized (loss) gain on derivatives. Our unrealized loss on derivatives was approximately $1.3 million for the year ended December 31, 2023, as compared to an unrealized gain of $18.8 million for the year ended December 31, 2022. During the year ended December 31, 2023, the aggregate net fair value of our open natural gas derivative contracts changed from a net asset of approximately $3.9 million to a net asset of approximately $2.7 million, resulting in an unrealized loss on derivatives of approximately $1.3 million for the year ended December 31, 2023. During the year ended December 31, 2022, the aggregate net fair value of our open oil and natural gas derivatives and oil basis differential swap contracts changed from a net liability of approximately $14.9 million to a net asset of approximately $3.9 million, resulting in an unrealized gain on derivatives of approximately $18.8 million for the year ended December 31, 2022.

78

Table of Contents

Expenses

The following table summarizes our operating expenses and other income (expense) for the periods indicated.

Year Ended December 31, 2023 as Compared to Year Ended December 31, 2022

Production taxes, transportation and processing. Our production taxes and transportation and processing expenses decreased $17.7 million, or 6%, to $264.5 million for the year ended December 31, 2023, as compared to $282.2 million for the year ended December 31, 2022. On a unit-of-production basis, our production taxes and transportation and processing expenses decreased 25% to $5.50 per BOE for the year ended December 31, 2023, as compared to $7.33 per BOE for the year ended December 31, 2022. These decreases were primarily attributable to the $22.7 million decrease in our production taxes to $200.2 million for the year ended December 31, 2023, as compared to $222.9 million for the year ended December 31, 2022, resulting from the $360.1 million decrease in oil and natural gas revenues for the year ended December 31, 2023, as compared to the year ended December 31, 2022, which was partially offset by the $5.0 million increase in transportation and processing expenses to $64.3 million for the year ended December 31, 2023, as compared to $59.3 million for the year ended December 31, 2022, primarily resulting from the 25% increase in total oil equivalent production between the respective periods.

Lease operating expenses. Our lease operating expenses increased $86.6 million, or 55%, to $243.7 million for the year ended December 31, 2023, as compared to $157.1 million for the year ended December 31, 2022. On a unit-of-production basis, our lease operating expenses increased 24% to $5.06 per BOE for the year ended December 31, 2023, as compared to $4.08 per BOE for the year ended December 31, 2022. These increases for the year ended December 31, 2023 were primarily attributable to the increased number of wells being operated by us, including 127 wells from the Advance Acquisition, and other operators (where we own a working interest) and to operating cost inflation during the year-ended December 31, 2023, as compared to the year ended December 31, 2022.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $33.4 million, or 35%, to $128.9 million for the year ended December 31, 2023, as compared to $95.5 million for the year ended December 31, 2022. This increase was primarily attributable to increased throughput volumes at San Mateo and Pronto

79

Table of Contents

from Matador and other customers, which resulted in (i) increased expenses associated with our expanded pipeline operations of $36.7 million for the year ended December 31, 2023, as compared to $24.9 million for the year ended December 31, 2022, (ii) increased expenses associated with our commercial produced water disposal operations of $53.6 million for the year ended December 31, 2023, as compared to $46.5 million for the year ended December 31, 2022, and (iii) increased expenses in connection with operating our Pronto midstream assets of $18.3 million for the year ended December 31, 2023, which assets were purchased on June 30, 2022, as compared to $8.3 million for the year ended December 31, 2022.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $250.3 million, or 54%, to $716.7 million for the year ended December 31, 2023, as compared to $466.3 million for the year ended December 31, 2022, primarily as a result of the Advance Acquisition and a 25% increase in our total oil equivalent production between the respective periods. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 23% to $14.90 per BOE for the year ended December 31, 2023, as compared to $12.11 per BOE for the year ended December 31, 2022, primarily as a result of the Advance Acquisition and an increase in actual costs and estimated future costs to drill, complete and equip our wells between the two periods.

General and administrative. Our general and administrative expenses decreased $5.9 million, or 5%, to $110.4 million for the year ended December 31, 2023, as compared to $116.2 million for the year ended December 31, 2022. Our general and administrative expenses on a unit-of-production basis decreased 24% to $2.29 per BOE for the year ended December 31, 2023, as compared to $3.02 per BOE for the year ended December 31, 2022, primarily as a result of the 25% increase in our total oil equivalent production between the two periods.

Interest expense. For the year ended December 31, 2023, we incurred total interest expense of approximately $143.7 million. We capitalized approximately $22.2 million of our interest expense on certain qualifying projects for the year ended December 31, 2023 and expensed the remaining $121.5 million to operations. For the year ended December 31, 2022, we incurred total interest expense of approximately $77.2 million. We capitalized approximately $10.1 million of our interest expense on certain qualifying projects for the year ended December 31, 2022 and expensed the remaining $67.2 million to operations. The increase in interest expense for the year ended December 31, 2023 is a result of borrowings under the Credit Agreement that were used in connection with the Advance Acquisition, borrowings under the San Mateo Credit Facility, the issuance of the 2028 Notes in April 2023 and the significant increase in interest rates between the two periods.

Total income tax provision. We recorded a current income tax provision of $13.9 million and a deferred income tax provision of $172.1 million for the year ended December 31, 2023. Our effective income tax rate of 18% for the year ended December 31, 2023 differed from the U.S. federal statutory rate due primarily to recognizing research and experimental expenditure tax credits of $74.0 million, which were partially offset by permanent differences between book and taxable income and state taxes, primarily in New Mexico. We recorded a current income tax provision of $54.9 million and a deferred income tax provision of $344.5 million for the year ended December 31, 2022. Our effective income tax rate of 25% for the year ended December 31, 2022 differed from the U.S. federal statutory rate due primarily to permanent differences between book and taxable income and state taxes, primarily in New Mexico.

Liquidity and Capital Resources

Our primary use of capital has been, and we expect will continue during 2024 and for the foreseeable future to be, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. In April 2023, we closed the Initial Advance Acquisition that was funded through a combination of cash on hand and borrowings under our Credit Agreement. In addition, on April 11, 2023, we issued and sold $500.0 million in aggregate principal amount of 2028 Notes. We used the net proceeds from the sale of the 2028 Notes of approximately $487.6 million, after deducting the initial purchasers’ discounts and estimated offering expenses, to partially repay borrowings under our Credit Agreement. We expect to fund our 2024 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2024, we expect to fund any excess capital expenditures, including for significant acquisitions, through borrowings under the Credit Agreement or 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.

At December 31, 2023, we had cash totaling $52.7 million and restricted cash totaling $53.6 million, which was primarily associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

80

Table of Contents

At December 31, 2023, we had (i) $699.2 million of outstanding 5.875% senior notes due September 2026 (the “2026 Notes”), (ii) $500.0 million of outstanding 2028 Notes, (iii) $500.0 million of borrowings outstanding under the Credit Agreement and (iv) approximately $52.3 million in outstanding letters of credit issued pursuant to the Credit Agreement.

In March 2023, the lenders under our Credit Agreement completed their review of our proved oil and natural gas reserves, and, as a result, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) reaffirm the borrowing base at $2.25 billion, (ii) increase the elected borrowing commitment from $775.0 million to $1.25 billion and (iii) maintain the maximum facility amount at $1.50 billion. This March 2023 redetermination constituted the regularly scheduled May 1 redetermination.

In October 2023, the lenders under our Credit Agreement completed their review of the our proved oil and natural gas reserves, and, as a result, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) increase the borrowing base from $2.25 billion to $2.50 billion, (ii) increase the elected borrowing commitment from $1.25 billion to $1.325 billion and (iii) increase the maximum facility amount from $1.50 billion to $2.00 billion. This October 2023 redetermination constituted the regularly scheduled November 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment (subject to compliance with the covenants noted below). The Credit Agreement matures October 31, 2026.

The Credit Agreement requires us to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75 million of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less at the end of each fiscal quarter. We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2023.

At December 31, 2023, San Mateo had $522.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. In October 2023, the lenders under the San Mateo Credit Facility increased the lender commitments from $485.0 million to $535.0 million. The San Mateo Credit Facility matures December 9, 2026.

The San Mateo Credit Facility is non-recourse with respect to Matador and its other subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2023.

In February 2023, April 2023 and July 2023, our Board declared quarterly cash dividends of $0.15 per share of common stock. In October 2023, the Board amended our dividend policy to increase the quarterly dividend to $0.20 per share of common stock and also declared a quarterly cash dividend of $0.20 per share of common stock. On February 13, 2024, the Board declared a quarterly cash dividend of $0.20 per share of common stock payable on March 13, 2024 to shareholders of record as of February 23, 2024.

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2024. We began 2024 operating seven contracted drilling rigs in the Delaware Basin and added an eighth operated drilling rig in the first quarter of 2024. 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 2024 estimated capital expenditure budget consists of $1.10 to $1.30 billion for D/C/E capital expenditures and $200.0 to $250.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2024 capital expenditures as well as the estimated 2024 capital expenditures for other wholly-owned midstream projects, including projects completed by Pronto. The midstream capital expenditure budget includes 100% of the costs associated with the Marlan Processing Plant expansion noted above, although, at February 20, 2024, we were continuing to evaluate potential partners in Pronto that would share in these capital expenditures and strategic opportunities. Substantially all of these 2024 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 in the Delaware Basin, South Texas and the Haynesville shale. Our 2024 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware

81

Table of Contents

Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells, including 99% with anticipated completed lateral lengths of greater than one mile.

As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, during 2024, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2024 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2024.

Our 2024 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control.

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 2024 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we are forecasting 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 2024 and the hedges we currently have in place. For a 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 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2023. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”

82

Table of Contents

Our cash flows for the years ended December 31, 2023, 2022 and 2021 are presented below.

__________________

(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.

Cash Flows Provided by Operating Activities

Net cash provided by operating activities decreased by $110.9 million to $1.87 billion for the year ended December 31, 2023, as compared to net cash provided by operating activities of $1.98 billion for the year ended December 31, 2022. Excluding changes in operating assets and liabilities, net cash provided by operating activities decreased to $1.82 billion for the year ended December 31, 2023 from $2.10 billion for the year ended December 31, 2022. This decrease was primarily attributable to lower realized oil and natural gas prices for the year ended December 31, 2023, as compared to the year ended December 31, 2022, which was partially offset by the 25% increase in total oil equivalent production during 2023, as compared to 2022. Changes in our operating assets and liabilities between December 31, 2022 and December 31, 2023 resulted in a net increase of approximately $168.0 million in net cash provided by operating activities for the year ended December 31, 2023, as compared to the year ended December 31, 2022.

Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-controlled oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. From time to time, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors—Risks Related to Our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”

Cash Flows Used in Investing Activities

Net cash used in investing activities increased by $2.17 billion to $3.21 billion for the year ended December 31, 2023 from $1.04 billion for the year ended December 31, 2022. This increase in net cash used in investing activities was primarily due to (i) an increase between the periods of $1.68 billion in expenditures related to the Advance Acquisition, (ii) an increase between the periods of $421.0 million in D/C/E capital expenditures primarily attributable to our operated and non-operated drilling, completion and equipping activities in the Delaware Basin and (iii) an increase between the periods of $85.7 million in midstream capital expenditures. These increases were partially offset by a decrease of $75.8 million related to the Pronto Acquisition in 2022.

Cash Flows Provided by (Used in) Financing Activities

Net cash provided by financing activities increased $1.38 billion to $902.3 million for the year ended December 31, 2023, from net cash used in financing activities of $480.9 million for the year ended December 31, 2022. During the year ended December 31, 2023, our net cash provided by financing activities was primarily attributable to (i) proceeds from the issuance of the 2028 Notes of $494.8 million, (ii) net borrowings under our Credit Agreement of $500.0 million and (iii) net borrowings under the San Mateo Credit Facility of $57.0 million, which were partially offset by (x) dividends paid of $77.2 million and (y) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $15.6 million. During the year ended December 31, 2022, our net cash used in financing activities was primarily attributable to (i) the repurchase of an aggregate principal of $350.8 million of the 2026 Notes for $344.3 million, (ii) net repayments under our Credit Agreement of $100.0 million, (iii) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $57.7 million and (iv) dividends paid of $35.2 million, which were partially offset by net borrowings under the San Mateo Credit Facility of $80.0 million.

83

Table of Contents

See Note 7 to the consolidated financial statements in this Annual Report for a summary of our debt, including the Credit Agreement, the San Mateo Credit Facility, the 2026 Notes and the 2028 Notes.

Guarantor Financial Information

As of December 31, 2023, Matador’s outstanding senior notes registered under the Securities Act consisted of the 2026 Notes. The 2026 Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At December 31, 2023, the Guarantor Subsidiaries were each 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. Neither San Mateo nor Pronto is a Guarantor Subsidiary of the 2026 Notes.

The following tables present summarized financial information of Matador (as issuer of the 2026 Notes) and the Guarantor Subsidiaries on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the Guarantor Subsidiaries and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. This financial information is presented in accordance with the amended requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations or financial position had the Guarantor Subsidiaries operated as independent entities.

Non-GAAP Financial Measures

We define Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”) as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, non-recurring transaction costs for certain acquisitions, certain other non-cash items and non-cash stock-based compensation expense and net gain or loss on asset sales and impairment. Adjusted EBITDA is not a measure of net income (loss) 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.

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 (loss) 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.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) 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

84

Table of Contents

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.

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.

For the year ended December 31, 2023, we reported net income attributable to Matador shareholders of $846.1 million, as compared to $1.21 billion for the year ended December 31, 2022. This decrease primarily resulted from lower realized oil and natural gas prices, partially offset by higher oil and natural gas production, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. In addition, we had increased depletion, depreciation and amortization expenses of $716.7 million for the year ended December 31, 2023, as compared to $466.3 million for the year ended December 31, 2022, and increased interest expense of $121.5 million for the year ended December 31, 2023, as compared to $67.2 million for the year ended December 31, 2022. This was partially offset by an income tax provision of $186.0 million for the year ended December 31, 2023, as compared to an income tax provision of $399.4 million for the year ended December 31, 2022.

Adjusted EBITDA, a non-GAAP financial measure, decreased $277.6 million to $1.85 billion for the year ended December 31, 2023, as compared to $2.13 billion for the year ended December 31, 2022. This decrease was primarily attributable to lower realized oil and natural gas prices, partially offset by higher oil and natural gas production noted above for the year ended December 31, 2023, as compared to the year ended December 31, 2022.

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2023, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the

85

Table of Contents

Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference.

Obligations and Commitments

We had the following material contractual obligations and commitments at December 31, 2023.

__________________

(1)The amounts included in the table above represent principal maturities only. At December 31, 2023, we had $500.0 million in borrowings outstanding under the Credit Agreement and approximately $52.3 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement matures October 31, 2026. At December 31, 2023 San Mateo had $522.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo Credit Facility matures December 9, 2026. Assuming the amounts outstanding and interest rates of 7.21% and 7.71%, respectively, for the Credit Agreement and the San Mateo Credit Facility at December 31, 2023, the interest expense for such facilities is expected to be approximately $36.6 million and $40.8 million, respectively, each year until maturity.

(2)The amounts included in the table above represent principal maturities only. Interest expense on the $699.2 million of outstanding 2026 Notes as of December 31, 2023 is expected to be approximately $41.1 million each year until maturity. Interest expense on the $500.0 million of outstanding 2028 Notes as of December 31, 2023 is expected to be approximately $34.4 million each year until maturity.

(3)At December 31, 2023, we had outstanding commitments to participate in the drilling and completion of various non-operated wells.

(4)We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments.

(5)The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at December 31, 2023.

(6)From time to time, we enter into agreements with third parties whereby we commit to deliver anticipated natural gas and oil production and produced water from certain portions of our acreage for transportation, gathering, processing, fractionation, sales and disposal. Certain of these agreements contain minimum volume commitments. If we do not meet the minimum volume commitments under these agreements, we would be required to pay certain deficiency fees. See Note 14 to the consolidated financial statements in this Annual Report for more information about these contractual commitments.

(7)We dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and the Wolf portion of the West Texas asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments.

(8)At December 31, 2023, we had outstanding commitments related to the construction and installation of Pronto’s additional natural gas processing plant with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities, in addition to commitments to purchase 11 compressors to be utilized in San Mateo and Pronto operations.

86

Table of Contents

General Outlook and Trends

Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk to our business, cash flows and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, the ongoing military conflicts between Russia and Ukraine and Israel and Hamas, political instability in China, military conflict and political instability in the Middle East, the actions of OPEC+, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors.

The prices we receive for oil, natural gas and NGLs heavily influence our revenues, profitability, cash flow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil, natural gas and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or NGL prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and NGLs we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves and our ability to comply with the financial covenants under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”

For the year ended December 31, 2023, oil prices averaged $77.60 per Bbl, as compared to $94.33 per Bbl in 2022, ranging from a low of $66.74 per Bbl in mid-March to a high of $93.68 per Bbl in late September, based upon the WTI oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $77.88 per Bbl (with no realized gains or losses from oil derivatives) for our oil production for the year ended December 31, 2023, as compared to $96.32 per Bbl ($92.87 per Bbl including realized losses from oil derivatives) for the year ended December 31, 2022. At February 20, 2024, the WTI oil futures contract price for the earliest delivery date had increased from year-end 2023, closing at $78.18 per Bbl, and was also higher compared to $76.34 per Bbl on February 17, 2023.

Natural gas prices decreased significantly during 2023. For the year ended December 31, 2023, natural gas prices averaged $2.66 per MMBtu, as compared to $6.54 per MMBtu in 2022, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2023, natural gas prices ranged from a high of $4.17 per MMBtu in early January to a low of $1.99 per MMBtu in late March. As a result of milder-than-expected winter weather and high storage levels, natural gas prices declined over the course of the fourth quarter of 2023, finishing the year at $2.51 per MMBtu. We report production volumes in two streams, oil and natural gas (which includes both dry gas and NGLs). NGL prices were also lower in 2023 as compared to 2022, which contributed to lower realized weighted average natural gas prices for the year ended December 31, 2023. We realized a weighted average natural gas price of $3.25 per Mcf ($3.17 per Mcf including realized losses from natural gas derivatives) for our natural gas production for the year ended December 31, 2023, as compared to $7.98 per Mcf ($7.15 per Mcf including realized losses from natural gas derivatives) for the year ended December 31, 2022. At February 20, 2024, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had decreased further from year-end 2023, closing at $1.58 per MMBtu, and was also lower as compared to $2.28 per MMBtu at February 17, 2023.

The prices we receive for oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. At December 31, 2023, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and a significant portion of our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the Waha hub in far West Texas.

The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years. At February 20, 2024, this oil price differential was approximately +$1.64 per Bbl. At February 20, 2024, we had no derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential for 2024.

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 2022, concerns about natural gas pipeline takeaway capacity out of the Delaware Basin began to increase, particularly beginning in the latter half of 2022 and into 2023. As a result, the Waha-Henry Hub basis differential began to widen. The Waha-Henry Hub basis differential averaged ($1.00) per MMBtu for the year ended December 31, 2023. Between December 31, 2023 and February 20, 2024, this natural gas price differential narrowed to approximately ($0.80) 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 2022 and 2023, we typically realized a narrower

87

Table of Contents

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 8% of our reported natural gas production for the year ended December 31, 2023 was attributable to the Haynesville and Eagle Ford shale plays, which are not exposed to Waha pricing. In addition, as a two-stream reporter, 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.

From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under the Credit Agreement and through the capital markets. During year ended December 31, 2023, we incurred realized losses on our natural gas basis differential derivative contracts of approximately $9.6 million resulting primarily from natural gas basis differentials that were above the strike price of our natural gas basis differential swap contracts, offset by natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. At December 31, 2023, we had derivative natural gas basis differential swap contracts in place to mitigate our exposure to the Waha-Henry Hub basis differential for approximately 11.0 Bcf of our anticipated natural gas production in each of 2024 and 2025.

We have at times experienced pipeline-related interruptions to our oil, natural gas or NGL production or produced water disposal. In certain recent periods, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware Basin. Although we did not encounter such fractionation capacity problems, we can provide no assurances that such problems will not arise. If we do experience any material interruptions with produced water disposal, takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. Should we experience future periods of negative pricing for natural gas as we have experienced historically, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results.

As a result of the increases in oil prices during 2022 and 2023, we have at times experienced inflation in the costs of certain oilfield services, including diesel, steel, labor, trucking, sand, personnel and completion costs, among others. Should oil prices remain at their current levels or increase, we may be subject to additional service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. In addition, supply chain disruptions and other inflationary pressures experienced in recent periods throughout the United States and global economy and in the oil and natural gas industry may limit our ability to procure the necessary products and services we need for drilling, completing and producing wells in a timely and cost-effective manner, which could result in reduced margins and delays to our operations and could, in turn, adversely affect our business, financial condition, results of operations and cash flows.

We recorded a current income tax provision of $13.9 million and a deferred income tax provision of $172.1 million for the year ended December 31, 2023. Our effective income tax rate of 18% for the year ended December 31, 2023 differed from the U.S. federal statutory rate due primarily to recognizing research and experimental expenditure tax credits of $74.0 million, which were partially offset by permanent differences between book and taxable income and state taxes, primarily in New Mexico. At February 20, 2024, given our current projections, we expect to continue to pay federal income taxes and state income taxes in New Mexico of between 5% and 10% of 2024 pretax book income, but we do not expect to be subject to the Corporate Alternative Minimum Tax (the “CAMT”) in 2024. We could be subject to the CAMT in future years, which would require us to pay minimum cash tax payments of 15% of annual adjusted pretax book income.

Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are proposed or promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. For example, although such bills have not passed, in recent years, various bills have been introduced in the New Mexico legislature proposing to add a surtax on natural gas processors and proposing to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream

88

Table of Contents

operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The NMED has implemented similar rules and regulations. These and other laws, rules and regulations, including any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have a material adverse impact on our business, financial condition, results of operations and cash flows. See “Business—Regulation.”

In January 2021, President Biden signed an executive order instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices, which has lapsed. In 2019, 2020 and 2021, an environmental group filed multiple lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico. In 2021, ten states, led by the State of Louisiana, filed a lawsuit in federal district court in Louisiana against President Biden and various other federal government officials and agencies challenging an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making. The BLM indicated that the Lease Sale Litigation or the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits. The impact of federal actions and lawsuits related to the oil and natural gas industry remains unclear, and should other limitations or prohibitions be imposed or continue to be applied, our operations on federal lands could be adversely impacted. Such limitations or prohibitions would almost certainly impact our future drilling and completion plans and could materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”

We and San Mateo dispose of large volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for produced water disposal and the increased occurrence of seismic activity, also known as “induced seismicity.” This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regarding waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. The adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, and could result in increased costs and additional operating restrictions or delays, that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. The adoption of such legislation and regulations could also decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions for San Mateo as well.

Certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. In recent years prior to 2021, equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices and some investors, including certain pension funds, sovereign wealth funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations.

Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A significant reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and the availability under our Credit Agreement. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth”.

89

Table of Contents

We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable and that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2023.

Oil and Natural Gas Properties

We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive.

Ceiling Test

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of:

(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus

(b) unproved and unevaluated property costs not being amortized, plus

(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less

(d) any income tax effects related to the properties involved.

Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. Our derivative instruments are not considered in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes.

Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue

Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time.

90

Table of Contents

Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors—Risks Related to our Financial Condition—Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves” and “Risk Factors—Risks Related to our Financial Condition—We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition.”

Estimates of proved oil and natural gas reserves are key inputs used for the calculations of depletion, the ceiling test and the fair value assigned to proved oil and natural gas reserves acquired in a business combination. The estimated present value of future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The associated commodity prices and the applicable discount rate used to determine the fair value assigned to proved oil and natural gas reserves acquired in a business combination are based upon a variety of factors on the date of acquisition. The associated commodity prices and the applicable discount rate used in estimates for depletion and the ceiling test are in accordance with guidelines established by the SEC. Under these guidelines, future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues.

Income Taxes

We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition.

We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.

Purchase Accounting

Periodically we acquire assets and assume liabilities in transactions accounted for as business combinations, such as the Advance Acquisition in 2023.

In estimating the fair value of assets acquired and liabilities assumed in these transactions, including the Advance Acquisition, we must make a number of estimates and assumptions and may engage third-party valuation experts. The most significant assumptions relate to the estimated fair values of oil and natural gas properties. Significant judgments and assumptions are inherent in these estimates and include, among other things, estimates of future production volumes, estimates of future commodity prices, expected development and operating costs, an estimate of a market-based weighted average cost of capital rate and recent market comparable transactions for unproved acreage.

Recent Accounting Pronouncements

See Note 2 to the consolidated financial statements in this Annual Report for a description of recent accounting pronouncements.

91

Table of Contents

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement and the San Mateo Credit Facility, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well as our ability to access them, the ongoing impact of COVID-19 on oil and natural gas demand, oil and natural gas prices and our business, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.”

For a comparison of our results of operations for the years ended December 31, 2021 and December 31, 2020, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 28, 2022.

Overview

We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.

2022 Operational Highlights

We began 2022 operating five drilling rigs in the Delaware Basin but contracted a sixth drilling rig during the first quarter of 2022 to begin development of certain acquired assets in the western portion of the Ranger asset area in Lea County, New Mexico. We added a seventh drilling rig in September 2022 and operated seven drilling rigs throughout the remainder of 2022. 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. We were able to achieve D/C/E capital expenditures for 2022 of $772.5 million, which was at the low end of our revised estimated range for 2022 D/C/E capital expenditures of $765.0 to $835.0 million as provided on July 26, 2022 and affirmed on October 25, 2022.

During the year ended December 31, 2022, we completed and began producing oil and natural gas from 81 gross (64.5 net) operated and 63 gross (5.4 net) non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2022, although we did participate in the drilling and completion of 11 gross (1.0 net) non-operated Haynesville shale wells that began producing in 2022.

Substantially all of our 2022 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells drilled and completed in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions, including certain non-operated well opportunities, and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin.

Our average daily oil equivalent production for the year ended December 31, 2022 was 105,465 BOE per day, including 60,119 Bbl of oil per day and 272.1 MMcf of natural gas per day, an increase of 22%, as compared to 86,176 BOE per day, including 48,876 Bbl of oil per day and 223.8 MMcf of natural gas per day, for the year ended December 31, 2021. Our average

73

Table of Contents

daily oil production in 2022 was 60,119 Bbl of oil per day, an increase of 23%, as compared to 48,876 Bbl of oil per day in 2021. This increase in oil production was primarily a result of our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining oil production in the Eagle Ford shale where we have not turned to sales any new operated wells since the second quarter of 2019. Our average daily natural gas production of 272.1 MMcf per day in 2022, an increase of 22%, as compared to 223.8 MMcf per day in 2021. This increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised 57% of our total production for each of the years ended December 31, 2022 and 2021.

For the year ended December 31, 2022, our oil and natural gas revenues were $2.91 billion, an increase of 71% from oil and natural gas revenues of $1.70 billion for the year ended December 31, 2021. Our oil revenues increased 75% to $2.11 billion, as compared to $1.21 billion for the year ended December 31, 2021. The increase in oil revenues resulted from a significantly higher weighted average realized oil price of $96.32 per Bbl in 2022, as compared to $67.58 per Bbl in 2021, as well as the 23% increase in oil production for the year ended December 31, 2022 noted above. Our natural gas revenues increased 60% to $792.1 million, as compared to $494.9 million for the year ended December 31, 2021. The increase in natural gas revenues resulted from an increase in our weighted average realized natural gas price of $7.98 per Mcf in 2022, as compared to $6.06 per Mcf in 2021, as well as the 22% increase in natural gas production for the year ended December 31, 2022 noted above.

We reported net income attributable to Matador shareholders of approximately $1.21 billion, or $10.11 per diluted common share, on a GAAP basis for the year ended December 31, 2022, as compared to a net income of $585.0 million, or $4.91 per diluted common share, for the year ended December 31, 2021. Adjusted EBITDA for the year ended December 31, 2022 was $2.13 billion, as compared to Adjusted EBITDA of $1.05 billion for the year ended December 31, 2021. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data—Non-GAAP Financial Measures.”

At December 31, 2022, our estimated total proved oil and natural gas reserves were 356.7 million BOE, including 196.3 million Bbl of oil and 962.6 Bcf of natural gas, with a Standardized Measure of $6.98 billion and a PV-10 of $9.13 billion. At December 31, 2021, our estimated total proved oil and natural gas reserves were 323.4 million BOE, including 181.3 million Bbl of oil and 852.5 Bcf of natural gas, with a Standardized Measure of $4.38 billion and a PV-10 of $5.35 billion. Our estimated total proved reserves of 356.7 million BOE at December 31, 2022 represented a 10% year-over-year increase, as compared to 323.4 million BOE at December 31, 2021. Our estimated proved oil reserves were 196.3 million Bbl at December 31, 2022, an increase of 8%, as compared to 181.3 million Bbl at December 31, 2021, and our estimated proved natural gas reserves were 962.6 Bcf at December 31, 2022, an increase of 13%, as compared to 852.5 Bcf at December 31, 2021. Proved oil reserves comprised 55% of our total proved reserves at December 31, 2022, as compared to 56% at December 31, 2021. At December 31, 2022, 62% of our total proved reserves were proved developed reserves, as compared to 60% at December 31, 2021.

Our proved oil and natural gas reserves in the Delaware Basin increased 11% to 346.8 million BOE at December 31, 2022, as compared to 312.0 million BOE at December 31, 2021, primarily as a result of our ongoing delineation and development operations there. At December 31, 2022, approximately 97% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin increased 9% to 193.5 million Bbl at December 31, 2022, as compared to 177.1 million Bbl at December 31, 2021, and our proved natural gas reserves in the Delaware Basin increased 14% to 919.7 Bcf, as compared to 809.3 Bcf at December 31, 2021. Proved oil reserves comprised 56% of our Delaware Basin total proved reserves at December 31, 2022, as compared to 57% at December 31, 2021.

At both December 31, 2022 and December 31, 2021, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business—Estimated Proved Reserves.”

74

Table of Contents

2022 Midstream Highlights

On June 30, 2022, our wholly-owned subsidiary acquired the Marlan Processing Plant, three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico as part of the Pronto Acquisition. We assumed certain takeaway capacity on a FERC-regulated natural gas pipeline. As consideration for the business combination, we paid approximately $77.8 million in cash, subject to certain customary post-closing purchase price adjustments.

San Mateo achieved strong operating results in 2022, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes, all as compared to 2021. Volumes for the years ended December 31, 2022 and 2021 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues during the years ended December 31, 2022 and 2021. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point.

During 2022, San Mateo closed seven new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing, oil gathering and transportation and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin. For example, San Mateo was able to keep its gathering, processing and disposal systems operational throughout the historically prolonged cold weather conditions experienced in New Mexico and Texas during Winter Storm Uri in February 2021.

At December 31, 2022, San Mateo’s midstream system included:

•Natural Gas Assets: 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 150 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico;

•Oil Assets: Three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 100 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and

•Produced Water Assets: 15 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 445,000 Bbl per day and approximately 165 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.

2023 Capital Expenditure Budget

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2023. We began 2022 operating five drilling rigs in the Delaware Basin but contracted a sixth drilling rig during the first quarter of 2022 to begin development of certain acquired assets in the western portion of the Ranger asset area in Lea County, New Mexico. We added a seventh drilling rig in September 2022 and operated seven drilling rigs throughout the remainder of 2022. We have built significant optionality into our 2023 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 2023 estimated capital expenditure budget consists of $1.18 to $1.32 billion for D/C/E capital expenditures, which includes expected D/C/E capital expenditures on acreage acquired in the Advance Acquisition, and $150.0 to $200.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2023 capital expenditures as well as the estimated 2023 capital expenditures for other wholly-owned midstream projects, including projects completed by Pronto. Substantially all of these 2023 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 in the Delaware Basin, South Texas and Haynesville shale. Our 2023 Delaware Basin operated drilling program 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 in 2023, including 96% with anticipated completed lateral lengths of one mile or greater.

75

Table of Contents

On January 24, 2023, our wholly-owned subsidiary entered into a definitive agreement to acquire Advance from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties and undeveloped acreage primarily located in Lea County, New Mexico and Ward County, Texas. The consideration for the Advance Acquisition is expected to consist of $1.6 billion in cash, subject to customary closing adjustments, including for working capital and title and environmental defects, plus additional cash consideration of $7.5 million for each month during 2023 in which the average price of crude oil (as defined in the securities purchase agreement) exceeds $85 per barrel. The consummation of the Advance Acquisition is subject to customary closing conditions and is expected to close early in the second quarter of 2023 with an effective date of January 1, 2023.

At December 31, 2022, we had $505.2 million in cash (excluding restricted cash) and $729.4 million in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $775.0 million). We intend to fund the Advance Acquisition with a combination of cash on hand, free cash flow prior to closing and borrowings under our Credit Agreement, under which we expect to increase our elected commitment in connection with this transaction. Excluding the Advance Acquisition and any other significant acquisitions, we expect to fund our 2023 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2023, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or 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.

We may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana (as we have done in recent years), as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin, during 2023. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2023 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2023.

76

Table of Contents

Revenues

The following table summarizes our revenues and production data for the periods indicated.

________________

(1)We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with NGLs are included with our natural gas revenues.

(2)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

Year Ended December 31, 2022 as Compared to Year Ended December 31, 2021

Oil and natural gas revenues. Our oil and natural gas revenues increased $1.21 billion, or 71%, to $2.91 billion for the year ended December 31, 2022, as compared to $1.70 billion for the year ended December 31, 2021. Our oil revenues increased $908.0 million, or 75%, to $2.11 billion for the year ended December 31, 2022, as compared to $1.21 billion for the year ended December 31, 2021. This increase in oil revenues resulted from a 43% increase in the weighted average oil price realized for the year ended December 31, 2022 to $96.32 per Bbl, as compared to $67.58 per Bbl realized for the year ended December 31, 2021, and the 23% increase in our oil production to 21.9 million Bbl of oil for the year ended December 31, 2022, as compared to 17.8 million Bbl of oil for the year ended December 31, 2021. The increase in oil production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues increased by $297.2 million, or 60%, to $792.1 million for the year ended December 31, 2022, as compared to $494.9 million for the year ended December 31, 2021. The increase in natural gas revenues was primarily attributable to the 32% increase in the weighted average natural gas price realized for the year ended December 31, 2022 to $7.98 per Mcf, as compared to $6.06 per Mcf realized for the year ended December 31, 2021, and the 22% increase in our natural gas production to 99.3 Bcf for the year ended December 31, 2022, as compared to 81.7 Bcf for the year ended December 31, 2021. The increase in natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin.

Third-party midstream services revenues. Our third-party midstream services revenues increased $15.1 million, or 20%, to $90.6 million for the year ended December 31, 2022, as compared to $75.5 million for the year ended December 31, 2021. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in our third-party natural gas gathering, transportation and processing revenues to $45.1 million for the year ended December 31, 2022, which includes $4.4 million associated with operating our Pronto midstream assets that were purchased on June 30, 2022 as part of the Pronto Acquisition, as compared to $37.6 million for the year ended December 31, 2021, and (ii) an increase in third-party produced water disposal revenues to $35.6 million for the year ended December 31, 2022, as compared to $27.6 million for the year ended December 31, 2021.

77

Table of Contents

Sales of purchased natural gas. Our sales of purchased natural gas increased $114.3 million, or 133%, to $200.4 million for the year ended December 31, 2022, as compared to $86.0 million for the year ended December 31, 2021. This increase was primarily the result of the increase in realized natural gas prices and an increase in natural gas volumes sold during the year ended December 31, 2022. Sales of purchased natural gas primarily 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 Pronto’s Marlan Processing Plant or San Mateo’s Black River Processing Plant and subsequently sell the residue 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 consolidated statements of operations.

Realized (loss) gain on derivatives. Our realized net loss on derivatives was $157.5 million for the year ended December 31, 2022, as compared to a realized net loss of approximately $220.1 million for the year ended December 31, 2021. We realized a net loss of $73.9 million related to our oil costless collar for the year ended December 31, 2022, resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts and above the strike price of certain of our oil swap contracts. We also realized a net loss of approximately $81.7 million related to our natural gas costless collar contracts for the year ended December 31, 2022, resulting primarily from natural gas prices that were above the ceiling prices of certain of our natural gas costless collar contracts. We realized a net gain of $1.9 million from our oil basis swap contracts for the year ended December 31, 2022, resulting from oil basis prices that were lower than the fixed prices of certain of our oil basis swap contracts. We realized a net loss of $197.5 million related to our oil costless collar and swap contracts for the year ended December 31, 2021, resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts and above the strike price of certain of our oil swap contracts. We also realized a net loss of approximately $26.1 million related to our natural gas costless collar contracts for the year ended December 31, 2021, resulting primarily from natural gas prices that were above the ceiling prices of certain of our natural gas costless collar contracts. We realized a net gain of $3.5 million from our oil basis swap contracts for the year ended December 31, 2021, resulting from oil basis prices that were lower than the fixed prices of certain of our oil basis swap contracts. We realized an average loss on our oil derivatives of approximately $3.45 per Bbl of oil produced during the year ended December 31, 2022, as compared to an average loss of $10.88 per Bbl of oil produced during the year ended December 31, 2021. We realized an average gain on our natural gas derivatives of approximately $0.83 per Mcf of natural gas produced during the year ended December 31, 2022, as compared to an average loss on our natural gas derivatives of approximately $0.32 per Mcf of natural gas produced during the year ended December 31, 2021. Our total oil volumes hedged represented 42% and 61% of our total oil production for the years ended December 31, 2022 and 2021, respectively. Our total natural gas volumes hedged represented 61% and 62% of our total natural gas production the years ended December 31, 2022 and 2021, respectively.

Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $18.8 million for the year ended December 31, 2022, as compared to an unrealized gain of $21.0 million for the year ended December 31, 2021. During the year ended December 31, 2022, the aggregate net fair value of our open oil and natural gas derivatives and oil basis swap contracts changed from a net liability of approximately $14.9 million to an asset of approximately $3.9 million, resulting in an unrealized gain on derivatives of approximately $18.8 million for the year ended December 31, 2022. During the year ended December 31, 2021, the aggregate net fair value of our open oil and natural gas derivative and oil basis swap contracts decreased from a net liability of approximately $35.9 million to a net liability of approximately $14.9 million, resulting in an unrealized gain on derivatives of approximately $21.0 million for the year ended December 31, 2021.

78

Table of Contents

Expenses

The following table summarizes our operating expenses and other income (expense) for the periods indicated.

Year Ended December 31, 2022 as Compared to Year Ended December 31, 2021

Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased $103.2 million, or 58%, to $282.2 million for the year ended December 31, 2022, as compared to $179.0 million for the year ended December 31, 2021. On a unit-of-production basis, our production taxes and transportation and processing expenses increased 29% to $7.33 per BOE for the year ended December 31, 2022, as compared to $5.69 per BOE for the year ended December 31, 2021. These increases were primarily attributable to the $93.0 million increase in our production taxes to $222.9 million for the year ended December 31, 2022, as compared to $129.8 million for the year ended December 31, 2021, resulting from the $1.21 billion increase in oil and natural gas revenues for the year ended December 31, 2022, as compared to the year ended December 31, 2021, and the $10.2 million increase in transportation and processing expenses to $59.3 million for the year ended December 31, 2022, as compared to $49.2 million for the year ended December 31, 2021, primarily resulting from the 22% increase in total oil equivalent production between the respective periods.

Lease operating expenses. Our lease operating expenses increased $48.1 million, or 44%, to $157.1 million for the year ended December 31, 2022, as compared to $109.0 million for the year ended December 31, 2021. On a unit-of-production basis, our lease operating expenses increased 18% to $4.08 per BOE for the year ended December 31, 2022, as compared to $3.46 per BOE for the year ended December 31, 2021. These increases in our lease operating expenses for the year ended December 31, 2022 were primarily attributable to the increased number of wells being operated by us and other operators (where we own a working interest) and to operating cost inflation during the year-ended December 31, 2022, as compared to the year ended December 31, 2021.

Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $34.1 million, or 55%, to $95.5 million for the year ended December 31, 2022, as compared to $61.5 million for the year ended

79

Table of Contents

December 31, 2021. This increase was primarily attributable to increased throughput volumes at San Mateo from Matador and other San Mateo customers, which resulted in (i) increased expenses associated with our commercial produced water disposal operations of $46.5 million for the year ended December 31, 2022, as compared to $30.8 million for the year ended December 31, 2021, (ii) increased expenses associated with our expanded pipeline operations of $28.0 million for the year ended December 31, 2022, as compared to $17.5 million for the year ended December 31, 2021, and (iii) increased expenses associated with operating the Black River Processing Plant of $15.8 million for the year ended December 31, 2022, as compared to $13.1 million for the year ended December 31, 2021. In addition, $5.2 million for the year ended December 31, 2022 was associated with operating our Pronto midstream assets, which were purchased on June 30, 2022 as part of the Pronto Acquisition.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $121.4 million, or 35%, to $466.3 million for the year ended December 31, 2022, as compared to $344.9 million for the year ended December 31, 2021, primarily as a result of the 22% increase in our total oil equivalent production between the respective periods. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 10% to $12.11 per BOE for the year ended December 31, 2022, as compared to $10.97 per BOE for the year ended December 31, 2021, primarily as a result of the increase in actual costs and estimated future costs to drill, complete and equip our wells between the two periods.

General and administrative. Our general and administrative expenses increased $19.8 million, or 21%, to $116.2 million for the year ended December 31, 2022, as compared to $96.4 million for the year ended December 31, 2021, primarily due to increased compensation expenses for our existing employees as well as the addition of new employees to support the continued growth in our land, geoscience, drilling, completion, production, midstream and administration functions. While our general and administrative expenses increased 21% on an absolute basis, our general and administrative expenses on a unit-of-production basis decreased 1% to $3.02 per BOE for the year ended December 31, 2022, as compared to $3.06 per BOE for the year ended December 31, 2021, primarily as a result of the 22% increase in our total oil equivalent production between the two periods.

Interest expense. For the year ended December 31, 2022, we incurred total interest expense of approximately $77.2 million. We capitalized approximately $10.1 million of our interest expense on certain qualifying projects for the year ended December 31, 2022 and expensed the remaining $67.2 million to operations. For the year ended December 31, 2021, we incurred total interest expense of approximately $79.5 million. We capitalized $4.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2021 and expensed the remaining $74.7 million to operations.

Total income tax provision (benefit). As a result of the full-cost ceiling impairments recorded during 2020, we recognized a valuation allowance against our federal net deferred tax assets as of September 30, 2020. Due to a variety of factors, including our significant net income during 2021, our federal valuation allowance was reversed in the third quarter of 2021. As a result, we recorded a deferred income tax provision of $74.7 million for the year ended December 31, 2021. Our effective tax rate was 11% for the year ended December 31, 2021, which differed from amounts computed by applying the U.S. federal statutory rate to the pre-tax income due to reversing the valuation allowance against our U.S. federal net deferred tax assets, differences between book and taxable income and state taxes, primarily in New Mexico. We recorded a total income tax provision of $399.4 million for the year ended December 31, 2022. Our effective tax rate was 25% for the year ended December 31, 2022, which differed from the U.S. federal statutory rate due primarily to permanent differences between book and taxable income and state taxes, primarily in New Mexico.

Liquidity and Capital Resources

Our primary use of capital has been, and we expect will continue to be during 2023 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. In January 2023, we announced the Advance Acquisition. We intend to fund the Advance Acquisition with a combination of cash on hand, free cash flow prior to closing and borrowings under our Credit Agreement, under which we expect to increase our elected commitment in connection with this transaction. Excluding the Advance Acquisition and any other significant acquisitions, we expect to fund our 2023 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2023, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or 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.

80

Table of Contents

At December 31, 2022, we had cash totaling $505.2 million and restricted cash totaling $42.2 million, which was primarily associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

At December 31, 2022, we had (i) $699.2 million of outstanding 5.875% senior notes due September 2026 (the “Notes”), (ii) no borrowings outstanding under the Credit Agreement and (iii) approximately $45.6 million in outstanding letters of credit issued pursuant to the Credit Agreement. During the first quarter of 2022, our approximately $7.5 million unsecured U.S. Small Business Administration loan, which was issued through Iberiabank in April 2020 as part of the Paycheck Protection Program, was forgiven in full under the terms of the loan agreement and recorded as a gain on the extinguishment of debt within “Other expense” on the consolidated statement of operations. During the year ended December 31, 2022, we repurchased an aggregate principal amount of $350.8 million of our Notes for $344.3 million.

In April 2022, the lenders under the Credit Agreement completed their review of our proved oil and natural gas reserves, and, as a result, the borrowing base was increased from $1.35 billion to $2.00 billion, the borrowing commitment was increased from $700.0 million to $775.0 million and the maximum facility amount remained $1.50 billion. In addition, the terms of the Credit Agreement were amended to increase the sublimit for issuances of letters of credit under the Credit Agreement from $50 million to $100 million and replace the London Interbank Offered Rate (“LIBOR”) interest rate benchmark with an Adjusted Term SOFR (as defined in the Credit Agreement) interest rate benchmark. This April 2022 redetermination constituted the regularly scheduled May 1 redetermination. In November 2022, the lenders completed their review of the our proved oil and natural gas reserves, and, as a result, the borrowing base was increased from $2.00 billion to $2.25 billion. We elected to keep the borrowing commitment at $775.0 million, and the maximum facility amount remained $1.50 billion. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected commitment (subject to compliance with the covenants noted below). The Credit Agreement requires us to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75 million of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less at the end of each fiscal quarter. We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2022.

At December 31, 2022, San Mateo had $465.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. In December 2022, the lenders under the San Mateo Credit Facility extended the maturity of the facility from December 19, 2023 to December 9, 2026 and increased the lender commitments from $450.0 million to $485.0 million. In addition, the lenders agreed to refresh the San Mateo Credit Facility’s accordion feature, which could expand lender commitments to up to $735.0 million. The San Mateo Credit Facility is non-recourse with respect to Matador and its wholly-owned subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2022. Between December 31, 2022 and February 21, 2023, we repaid an additional $30.0 million of borrowings outstanding under the San Mateo Credit Facility.

We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2023. We began 2023 operating seven contracted drilling rigs in the Delaware Basin. Upon the consummation of the Advance Acquisition, which we anticipate to occur in the second quarter of 2023, we expect to operate the drilling rig that Advance was operating during the first quarter of 2023, bringing our total contracted drilling rigs to eight. We expect to operate eight contracted drilling rigs for the remainder of 2023. 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 2023 estimated capital expenditure budget consists of $1.18 to $1.32 billion for D/C/E capital expenditures, which includes expected D/C/E capital expenditures on acreage acquired in the Advance Acquisition, and $150.0 to $200.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2023 capital expenditures as well as the estimated 2023 capital expenditures for other wholly-owned midstream projects, including projects completed by Pronto. Substantially all of these 2023 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 in the Delaware Basin, South Texas and Haynesville shale. Our 2023 Delaware Basin operated drilling program 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

81

Table of Contents

high percentage of longer horizontal wells in 2023, including 96% with anticipated completed lateral lengths of greater than one mile.

We may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana (as we have done in recent years), as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin, during 2023. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2023 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2023.

Our 2023 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control.

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 2023 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we are forecasting 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 2023 and the hedges we currently have in place. For a discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below. We use commodity derivative financial instruments at times 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 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2022. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil and natural gas are highly speculative and involve a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 31% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”

82

Table of Contents

Our cash flows for the years ended December 31, 2022, 2021 and 2020 are presented below.

__________________

(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 (loss) and net cash provided by operating activities, see “—Non-GAAP Financial Measures” below.

Cash Flows Provided by Operating Activities

Net cash provided by operating activities increased by $925.4 million to $1.98 billion for the year ended December 31, 2022, as compared to net cash provided by operating activities of $1.05 billion for the year ended December 31, 2021. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $2.10 billion for the year ended December 31, 2022 from $1.05 billion for the year ended December 31, 2021. This increase was primarily attributable to significantly higher realized oil and natural gas prices for the year ended December 31, 2022, as compared to the year ended December 31, 2021, as well as the 22% increase in total oil equivalent production during 2022, as compared to 2021. Changes in our operating assets and liabilities between December 31, 2021 and December 31, 2022 resulted in a net decrease of approximately $117.0 million in net cash provided by operating activities for the year ended December 31, 2022, as compared to the year ended December 31, 2021.

Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-controlled oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. For example, the effects of COVID-19 and the corresponding decline in oil demand significantly impacted the prices we received for our oil production in recent periods, particularly in 2020. These factors are beyond our control and are difficult to predict. From time to time, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors—Risks Related to Our Financial Condition—Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”

Cash Flows Used in Investing Activities

Net cash used in investing activities increased by $308.2 million to $1.04 billion for the year ended December 31, 2022 from $729.3 million for the year ended December 31, 2021. This increase in net cash used in investing activities was primarily attributable an increase of $340.7 million in D/C/E capital expenditures as compared to the year ended December 31, 2021 and the Pronto Acquisition for $75.8 million. These increases were partially offset by an $83.5 million decrease in acquisitions of oil and natural gas properties and a $42.3 million increase in proceeds from the sale of primarily non-core oil and natural gas assets. Cash used for D/C/E capital expenditures for the year ended December 31, 2022 was primarily attributable to our operated and non-operated drilling and completion activities in the Delaware Basin.

Cash Flows (Used in) Provided by Financing Activities

Net cash used in financing activities increased by $152.3 million to $480.9 million for the year ended December 31, 2022, as compared to $328.6 million for the year ended December 31, 2021. The net cash used in financing activities for the year ended December 31, 2022 was primarily attributable to (i) the repurchase of an aggregate principal amount of $350.8 million of the Notes for $344.3 million, (ii) net repayments under our Credit Agreement of $100.0 million, (iii) net borrowings under the San Mateo Credit Facility of $80.0 million, (iv) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $57.7 million and (v) dividends paid of $35.2 million.

See Note 7 to the consolidated financial statements in this Annual Report for a summary of our debt, including the Credit Agreement, the San Mateo Credit Facility and the Notes.

Guarantor Financial Information

83

Table of Contents

The Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At December 31, 2022, the Guarantor Subsidiaries were each 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. Neither San Mateo nor Pronto is a guarantor of the Notes.

The following tables present summarized financial information of Matador (as issuer of the Notes) and the Guarantor Subsidiaries on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the Guarantor Subsidiaries and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. This financial information is presented in accordance with the amended requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations or financial position had the Guarantor Subsidiaries operated as independent entities.

Non-GAAP Financial Measures

We define Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”) as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense and net gain or loss on asset sales and impairment. Adjusted EBITDA is not a measure of net income (loss) 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.

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 (loss) 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.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) 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.

84

Table of Contents

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

For the year ended December 31, 2022, we reported net income attributable to Matador shareholders of $1.21 billion, as compared to $585.0 million for the year ended December 31, 2021. This increase primarily resulted from significantly higher realized oil and natural gas prices and higher oil and natural gas production, for the year ended December 31, 2022, as compared to the year ended December 31, 2021. These increases were partially offset by an increase in operating expenses, depletion, depreciation and amortization and income tax expense between the two periods.

Adjusted EBITDA, a non-GAAP financial measure, increased $1.08 billion to $2.13 billion for the year ended December 31, 2022, as compared to $1.05 billion for the year ended December 31, 2021. This increase was primarily attributable to the significantly higher realized oil and natural gas prices and higher oil and natural gas production noted above for the year ended December 31, 2022, as compared to the year ended December 31, 2021. These increases were partially offset by an increase in operating expenses between the two periods.

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2022, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference.

85

Table of Contents

Obligations and Commitments

We had the following material contractual obligations and commitments at December 31, 2022.