Matador Resources Co

NOTE 1 —NATURE OF OPERATIONS

Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company 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. The Company’s 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. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, the Company conducts midstream operations primarily through its midstream joint venture, San Mateo Midstream, LLC and its subsidiaries (“San Mateo”) in support of, and to provide flow assurance for, the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.

NOTE 2 —SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated financial statements include the accounts of Matador and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries and joint ventures that are less-than-wholly-owned and are not involved in oil and natural gas exploration, including San Mateo, and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately as required by Accounting Standards Codification (“ASC”), Consolidation (Topic 810). The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates in the purchase price allocations and of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.

Restricted Cash

Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.

Accounts Receivable

The Company sells its operated oil, natural gas and natural gas liquids (“NGL”) production to various purchasers (see “—Revenues” below). In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from purchasers of oil, natural gas and NGLs, participants in oil and natural gas wells for which the Company serves as the operator, customers of San Mateo or the Company’s derivative counterparties. Accounts receivable are typically due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts.

The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues associated with the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company hasno allowance for doubtful accounts related to its accounts receivable for any reporting period presented.

For the year ended December 31, 2024, three significant purchasers accounted for 79% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. (53%), Exxon Mobil Corporation (15%) and Enterprise Products Partners L.P. (11%). For the year ended December 31, 2023, three significant purchasers accounted for 76% of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. (42%), Exxon Mobil Corporation (24%), and Enterprise Products Partners L.P. (10%). For the year ended December 31, 2022, three significant purchasers accounted for 70% of the Company’s total oil, natural gas and NGL revenues: Exxon Mobil Corporation (34%), Plains Marketing, L.P. (27%) and BP America Production Company (9%). If any one of Matador’s major customers were to stop purchasing its production, the Company believes there are a number of other purchasers to whom the Company could sell Matador’s production. If multiple significant customers were to discontinue purchasing Matador’s production abruptly, the Company believes it would have the resources needed to access alternative customers or markets and avoid or materially mitigate associated sales disruptions. At December 31, 2024, 2023 and 2022, approximately 32%,38% and 29%, respectively, of the Company’s accounts receivable, including joint interest billings, related to the top three purchasers.

Lease and Well Equipment Inventory

Lease and well equipment inventory is stated at the lower of cost or net realizable value and consists entirely of materials or equipment scheduled for use in future well or midstream operations.

Oil and Natural Gas Properties

The Company uses the full-cost method of accounting for its 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 the Company’s 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. The Company capitalized $66.6 million, $54.2 million and $47.8 million of its general and administrative costs into oil and natural gas properties in 2024, 2023 and 2022, respectively. The Company capitalized $17.5 million, $20.2 million and $10.1 million of its interest expense into oil and natural gas properties for the years ended December 31, 2024, 2023 and 2022, respectively.

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. For the years ended December 31, 2024, 2023 and 2022, the Company recorded depletion expense of $925.6 million, $672.0 million and $428.9 million, respectively. 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 determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized.

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 the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The Company’s derivative instruments are not considered in the ceiling test computations as the Company does not designate these instruments as hedge instruments for accounting purposes.

The estimated present value of after-tax 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. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. 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. For the period from January through December 2024, these average oil and natural gas prices were $71.96 per Bbl and $2.13 per MMBtu, respectively. For the period from January through December 2023, these average oil and natural gas prices were $74.70 per Bbl and $2.64 per MMBtu, respectively. For the period from January through December 2022, these average oil and natural gas prices were $90.15 per Bbl and $6.36 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials.

During the years ended December 31, 2024, 2023 and 2022, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the years ended December 31, 2024, 2023 and 2022. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods.

Midstream Properties and Other Property and Equipment

Midstream properties and other property and equipment are recorded at historical cost or acquisition date fair value and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and produced water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life (five to 30 years) using the straight-line method. The Company capitalized $3.4 million, $2.9 million and $2.2 million of general and administrative costs into midstream properties in 2024, 2023 and 2022, respectively. The Company capitalized $12.2 million and $2.1 million of interest expense into midstream properties for the years ended December 31, 2024 and 2023, respectively. The Company didnot capitalize any interest expense into midstream properties for the year ended December 31, 2022. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of midstream properties and other property and equipment.

The Company evaluates midstream properties and other property and equipment for potential impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the future cash flows expected to result from the use and eventual disposition of the asset. Expected future cash flows represent management’s estimates based on reasonable and supportable assumptions.

Gains and losses associated with the disposition of midstream properties and other property and equipment are recognized as a component of other income (expense) in the consolidated statements of income.

Asset Retirement Obligations

The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties, midstream properties or other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of income.

Derivative Financial Instruments

From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of income. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported as a component of revenues in the consolidated statements of income. See Note 12 for additional information about the Company’s derivative instruments.

Revenues

The Company enters into contracts with customers to sell its oil and natural gas production. Revenue from these contracts is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under oil and natural gas marketing contracts is typically received from the purchaserone totwo months after production.

The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead or a central delivery point, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing, which price is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred at or after the transfer of control of the oil, the differentials are included in oil revenues on the statements of income, as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of income, as they represent payment for services performed outside of the contract with the customer.

The Company’s natural gas is sold at the lease location, at the inlet or outlet of a natural gas processing plant or at an interconnect near a marketing hub following transportation from a processing plant. The majority of the Company’s natural gas is sold under fee-based contracts. When the natural gas is sold at the lease, the purchaser gathers the natural gas via pipeline to natural gas processing plants where, if necessary, NGLs are extracted. The NGLs and remaining residue natural gas are then sold by the purchaser, or if the Company elects to take in-kind the natural gas or the NGLs, the Company sells the natural gas or the NGLs to a third party. Under the fee-based contracts, the Company receives NGL and residue natural gas value, less the fee component, or is invoiced the fee component. To the extent control of the natural gas transfers upstream of the gathering and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those services, revenue is recognized on a gross basis, and the related costs are included in production taxes, transportation and processing expenses on the Company’s consolidated statements of income.

The Company recognizes midstream services revenues at the time services have been rendered and the price is fixed and determinable. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues related to the Company’s working interest are eliminated in consolidation. Since the Company has a right to payment from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, the Company applies the practical expedient in Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606)

(“ASC 606”) that allows recognition of revenue in the amount for which there is a right to invoice the customer without estimating a transaction price for each contract and allocating that transaction price to the performance obligations within each contract.

The Company periodically enters into natural gas purchase transactions with third parties whereby the Company (i) purchases the third party’s natural gas and subsequently sells the natural gas to other purchasers or (ii) processes the third party’s natural gas at San Mateo’s Marlan cryogenic natural gas processing plant in Eddy County, New Mexico (the “Marlan Processing Plant”) or Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and then purchases, and subsequently sells, the residue natural gas and NGLs to other purchasers. Revenues and expenses from these transactions are presented on a gross basis on the Company’s consolidated statements of income as the Company acts as a principal in the transactions by assuming the risk and rewards of ownership, including credit risk, of the natural gas purchased and by assuming the responsibility to deliver and process the natural gas volumes to be sold.

From time to time, the Company, as an owner of mineral interests, may enter into or extend a lease to a third-party lessee to develop the oil and natural gas attributable to certain of its mineral interests in return for a specified payment or lease bonus. In those instances, revenue is recognized in the period when the lease is signed and the Company has no further obligation to the lessee. The Company records these payments as “Lease bonus - mineral acreage” revenues on its consolidated statements of income.

The following table summarizes the Company’s total revenues and revenues from contracts with customers on a disaggregated basis for the years ended December 31, 2024, 2023 and 2022 (in thousands).

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Stock-Based Compensation

The Company may grant equity-based and liability-based common stock, stock options, restricted stock, restricted stock units, performance stock units and other awards permitted under any long-term incentive plan of the Company then in effect to members of its Board of Directors (the “Board”) and certain employees, contractors and advisors. All equity-based awards are measured at fair value on the date of grant and are recognized on a straight-line basis over the awards’ vesting periods as either a component of general and administrative expenses in the consolidated statements of income or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration, development and midstream activities. Awards that are expected to be settled in cash are liability-based awards, which are measured at fair value at each reporting date and are recognized over the awards’ vesting periods either as a component of general and administrative expenses in the consolidated statements of income or capitalized in accordance with the Company’s policy on capitalizing general and administrative expenses for employees involved in acquisition, exploration, development and midstream activities.

The Company uses the Monte Carlo simulation method to measure the fair value of performance units. The closing price of Matador’s common stock on the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”), while the closing price of Matador’s common stock on the trading day prior to the grant date is used to measure the fair value of restricted stock and restricted stock unit awards granted under the 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”).

The Company’s consolidated statements of income for the years ended December 31, 2024, 2023 and 2022 include an equity-based compensation (non-cash) expense of $15.0 million, $13.7 million and $15.1 million, respectively. This equity-based compensation expense includes common stock issuances and restricted stock units expense totaling $1.3 million, $1.2 million and $1.0 million for the years ended December 31, 2024, 2023 and 2022, respectively, paid to independent members of the Board and advisors as compensation for their services to the Company.

Income Taxes

The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized.

The Company recognizes tax benefits from an uncertain tax position on the basis of a two-step process in which (i) the Company determines whether it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based upon the technical merits of the position and (ii) for those tax positions that meet the more-likely-than-not recognition threshold, the Company recognizes the largest amount of tax benefit that is more than 50% likely to be realized upon ultimate settlement with the related tax authority.

When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of income. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2024, 2023 and 2022.

Allocation of Purchase Price in Business Combinations

As part of the Company’s business strategy, it periodically pursues the acquisition of midstream assets and oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

Earnings Per Common Share

The Company reports basic earnings attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive.

The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2024, 2023 and 2022 (in thousands, except per share data).

Credit Risk

The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected.

The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and NGL price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, the Company’s commodity derivative contracts at December 31, 2024 were with Bank of America, PNC Bank, Truist Bank, The Bank of Nova Scotia, Royal Bank of Canada, Comerica Bank and BOKF (or affiliates thereof), which are all lenders under the Company’s reserves-based revolving credit agreement (the “Credit Agreement”).

Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners.

Recent Accounting Pronouncements

Segments. In November 2023, the Financial Accounting Standards Board (“FASB”) issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which enhances the disclosures required for operating segments in the Company’s annual and interim consolidated financial statements. This ASU is effective retrospectively for fiscal years beginning after December 15, 2023 and for interim periods within fiscal years beginning after December 15, 2024. During the fourth quarter of 2024, the Company adopted this ASU, which modified the Company’s disclosures but did not have an impact on the Company’s consolidated balance sheets, or statements of income or cash flows in its consolidated financial statements. See Note 16 for additional disclosures related to segments.

Income Taxes. In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which is intended to enhance the transparency and decision usefulness of income tax disclosures. The amendments in this standard provide for enhanced income tax information primarily through changes to the rate reconciliation and income taxes paid. This ASU is effective for the Company prospectively to all annual periods beginning after December 15, 2024. The Company is currently evaluating the impact of this standard on its disclosures.

Climate-Related Disclosures. On March 6, 2024, the SEC adopted a new set of rules that require a wide range of climate-related disclosures, including material climate-related risks, information on any climate-related targets or goals that are material to the registrant’s business, results of operations or financial condition, Scope 1 and Scope 2 greenhouse gas emissions on a phased-in basis by certain larger registrants when those emissions are material and the filing of an attestation report covering the same, and disclosure of the financial statement effects of severe weather events and other natural conditions including costs and losses. Compliance dates under the final rule are phased in by registrant category. Multiple lawsuits have been filed challenging the SEC’s new climate rules, and on April 4, 2024, the SEC issued an order staying implementation of the final rules until judicial review is complete. The Company is currently evaluating the impact of the final rules, if implemented, on its disclosures.

Disaggregation of Income Statement Expenses. In November 2024, the FASB issued ASU 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The amendments in this update require disclosure in the Company’s annual and interim consolidated financial statements of specified information about certain costs and expenses, including depreciation, depletion and amortization recognized as part of oil and gas producing activities and employee compensation. This ASU is effective for the Company to all annual periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The Company is currently evaluating the impact of this standard on its disclosures.

NOTE 3 —PROPERTY AND EQUIPMENT

The following table presents a summary of the Company’s property and equipment balances as of December 31, 2024 and 2023 (in thousands).

NOTE 3 — PROPERTY AND EQUIPMENT — Continued

The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2024 and the year in which these costs were incurred (in thousands).

Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions.

Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2024 are related to the Company’s leasehold and mineral acquisitions in the Delaware Basin in Southeast New Mexico and West Texas. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties that are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base.

Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $109.3 million at December 31, 2024. Of this total, $47.8 million was associated with exploration wells and $61.5 million was associated with development wells. The Company anticipates that most of the $109.3 million associated with these wells in progress at December 31, 2024 will be transferred to the amortization base during 2025. Unproved and unevaluated property costs for exploration and development wells incurred in years prior to 2024 are costs related to the advanced preparation for wells that the Company intends to drill in the future.

NOTE 4 —LEASES

The Company determines if an arrangement is a lease at inception of the contract. If an arrangement is a lease, the present value of the related lease payments is recorded as a liability, and an equal amount is capitalized as a right of use asset on the Company’s consolidated balance sheets. The Company elected to include payments for non-lease components associated with certain leases when determining the present value of the lease payments. Right of use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. The Company’s estimated incremental borrowing rate, determined at the lease commencement date using the Company’s average secured borrowing rate, is used to calculate present value. The weighted average estimated incremental borrowing rates used for the year ended December 31, 2024 were 5.48% and 7.23% for operating leases and financing leases, respectively. For these purposes, the lease term includes options to extend the lease when it is reasonably certain that the Company will exercise such option. Leases with terms of 12 months or less at inception are not recorded on the consolidated balance sheets unless there is a significant cost to terminate the lease, including the cost of removal of the leased asset. As the Company is the responsible party under these arrangements, the Company records the resulting assets and liabilities on a gross basis in its consolidated balance sheets.

The following table presents supplemental consolidated statement of income information related to lease expenses, on a gross basis, for the years ended December 31, 2024 and 2023, respectively (in thousands). Lease payments represent gross payments to vendors, which, for certain of the Company’s operating assets, are partially offset by amounts received from other working interest owners in the Company’s operated wells.

(1) Does not include gross payments related to drilling rig leases of $87.8 million and $84.1 million for the years ended December 31, 2024 and 2023, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2024 and 2023, respectively.

(2) These costs are related to leases that are not recorded as right of use assets or lease liabilities in the consolidated balance sheets as they are short-term leases.

(3) Does not include gross payments related to short-term drilling rig leases and other equipment rentals of $231.8 million and $159.7 million for the years ended December 31, 2024 and 2023, respectively, that were capitalized and recorded in “Oil and natural gas properties, full-cost method” in the consolidated balance sheets at December 31, 2024 and 2023, respectively.

The following table presents supplemental consolidated balance sheet information related to leases as of December 31, 2024 and 2023, respectively (in thousands).

The following table presents supplemental consolidated cash flow information related to lease payments for the years ended December 31, 2024 and 2023, respectively (in thousands).

The following table presents the maturities of lease liabilities at December 31, 2024 (in years).

The following table presents a schedule of future minimum lease payments required under all lease agreements as of December 31, 2024 (in thousands).

NOTE 5 —ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations primarily relate to future costs associated with plugging and abandonment of its oil, natural gas and salt water disposal wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability.

The following table summarizes the changes in the Company’s asset retirement obligations for the years ended

December 31, 2024 and 2023 (in thousands).

(1)Included in “Accrued liabilities” in the Company’s consolidated balance sheets at December 31, 2024 and 2023.

NOTE 6 —BUSINESS COMBINATIONS AND DIVESTITURES

Business Combinations

Joint Venture

On December 18, 2024, the Company completed a transaction with Five Point Energy, LLC and its affiliates (“Five Point”) in which the Company contributed Pronto Midstream, LLC and its subsidiary (“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 (the “Pronto Transaction”). 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 afive-year period. San Mateo continues to be owned 51% by the Company and 49% by Five Point with Five Point’s interest in San Mateo being accounted for as a non-controlling interest.

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 Midstream Partners LLC (“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.

Ameredev Acquisition

On September 18, 2024, a wholly-owned subsidiary of the Company completed the acquisition (the “Ameredev Acquisition”) of Ameredev Stateline II, LLC (“Ameredev”) from affiliates of EnCap Investments L.P., including (i) certain oil and natural gas producing properties and undeveloped acreage located in Lea County, New Mexico and Loving and Winkler Counties, Texas, and (ii) an approximate 19% stake (the “Piñon Investment”) in the parent company of Piñon Midstream, LLC (“Piñon”). The Ameredev Acquisition had an effective date of June 1, 2024 and an aggregate as-adjusted closing purchase price of approximately $1.83 billion in cash, which amount is subject to customary post-closing adjustments. The purchase price for the Ameredev Acquisition was funded by a combination of cash on hand and borrowings under the Company’s Credit Agreement, which was amended on September 18, 2024 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 commitments under the revolving credit facility from $1.50 billion to $2.25 billion. On September 25, 2024, the Company completed the sale of $750.0 million in aggregate principal amount of the Company’s 6.25% senior unsecured notes due 2033 (the “2033 Notes”) 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.

The Ameredev Acquisition was accounted for under the acquisition method of accounting as a business combination in accordance with Accounting Standards Codification Topic 805, Business Combinations (“ASC Topic 805”). Under ASC Topic 805, the purchase price is allocated to the underlying tangible and intangible assets acquired and liabilities assumed based upon their estimated fair values as of the respective acquisition date, with any excess purchase price allocated to goodwill. As the Company acquired 100% of the membership interests of Ameredev, the acquisition was treated as an asset acquisition for tax purposes. The Company concluded that the Piñon Investment was an equity method investment.

The preliminary allocation of the total purchase price for the Ameredev Acquisition is set forth below (in thousands). As of the date of this filing, the valuation of the Piñon Investment and certain working capital adjustments in connection with the final settlement remain ongoing and adjustments may be made. The Company expects to complete the final purchase price allocation during the 12-month period subsequent to the Ameredev Acquisition closing date.

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of evaluated oil and natural gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation.

Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) future production volumes, (ii) future commodity prices and (iii) recent market comparable transactions for unproved acreage. These inputs require significant judgments and estimates and are the most sensitive and subject to change.

The results of operations for the Ameredev Acquisition since the closing date have been included in the Company’s consolidated financial statements for the year ended December 31, 2024. The oil and natural gas production from Ameredev increased the Company’s revenues and net income for the period from September 18, 2024 through December 31, 2024 by $118.0 million and $34.8 million, respectively.

Pro Forma Information

The following unaudited pro forma financial information represents a summary of the condensed consolidated results of operations for the years ended December 31, 2024 and 2023, assuming the Ameredev Acquisition had been completed as of January 1, 2023. The pro forma financial information is provided for illustrative purposes only and does not purport to represent what the actual consolidated results of operations or the consolidated financial position of the Company would have been had the Ameredev Acquisition occurred on the dates noted above, nor is it necessarily indicative of the future results of operations or consolidated financial position of the Company. Future results may vary significantly from the results reflected because of various factors.

The information below reflects certain nonrecurring pro forma adjustments that were directly related to the business combination based on currently available information and certain estimates and assumptions that the Company believes provide a reasonable basis for presenting the significant effects of the Ameredev Acquisition, including (i) the increase in depletion reflecting the relative fair values and production volumes attributable to Ameredev’s properties and the revision to the depletion rate reflecting the reserve volumes acquired, (ii) adjustments to interest expense as a result of the incremental borrowings necessary to finance the Ameredev Acquisition and (iii) the estimated tax impacts of the pro-forma adjustments. The pro forma financial information does not reflect the benefits of projected synergies, potential cost savings or the costs that may be necessary to achieve such savings, opportunities to increase revenue generation or other factors that may result from the Ameredev Acquisition and, accordingly, does not attempt to predict or suggest future results. Management cannot identify the timing, nature and amount of such savings, costs or other factors, any of which could affect the future consolidated results of operations or consolidated financial position of the Company.

Q1 2024 Acquisition

On February 15, 2024, a wholly-owned subsidiary of the Company acquired oil and natural gas producing properties and undeveloped acreage located in Lea County, New Mexico (the “Q1 2024 Acquisition”). The Q1 2024 Acquisition had an effective date of October 1, 2023 and consideration for the acquisition consisted of an amount in cash equal to approximately $154.8 million.

The Q1 2024 Acquisition was accounted for under the acquisition method of accounting as a business combination in accordance with ASC Topic 805. Under ASC Topic 805, the purchase price is allocated to the underlying tangible and intangible assets acquired and liabilities assumed based upon their estimated fair values as of the acquisition date, with any excess purchase price allocated to goodwill.

The final allocation of the total purchase price for the Q1 2024 Acquisition is set forth below (in thousands).

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of evaluated oil and natural gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation.

Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) future production volumes, (ii) future commodity prices and (iii) recent market comparable transactions for unproved acreage. These inputs require significant judgments and estimates and are the most sensitive and subject to change.

The results of operations for the Q1 2024 Acquisition since the closing date have been included in the Company’s consolidated financial statements for the year ended December 31, 2024. The pro forma impact of this business combination to revenues and net income for 2024 and 2023 would not be material to the Company’s 2024 or 2023 revenues and net income as reported.

Advance Acquisition

On April 12, 2023, a wholly-owned subsidiary of the Company completed the acquisition of Advance Energy Partners Holdings, LLC (“Advance”) from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties, undeveloped acreage and midstream assets located primarily in Lea County, New Mexico and Ward County, Texas (the “Initial Advance Acquisition”). The Initial Advance Acquisition had an effective date of January 1, 2023 and an aggregate purchase price consisting of (i) an amount in cash equal to approximately $1.60 billion (which amount was subject to certain customary post-closing adjustments) (the “Cash Consideration”) and (ii) potential additional cash consideration of $7.5 million for each month of 2023 in which the average oil price (as defined in the securities purchase agreement) exceeded $85 per barrel (all such payments for the 12 months in 2023, the “Contingent Consideration”). The Cash Consideration was paid upon the closing of the Initial Advance Acquisition and was funded by a combination of cash on hand and borrowings under the Credit Agreement. The Company madeno payments related to the Contingent Consideration during the first, second, or third quarters of 2023. In the fourth quarter of 2023, the Company paid Contingent Consideration of $15.0 million, as the average oil price for the months of September and October 2023 exceeded $85 per barrel.

The Company recorded the Contingent Consideration at fair value on the date of the business combination and recorded the change in the fair value in future periods as “Other income (expense)” in its consolidated statements of income. The fair value of the Contingent Consideration was $21.2 million at April 12, 2023. The change in fair value of the Contingent Consideration included in “Other income (expense)” during the year ended December 31, 2023 was income of $6.2 million. The Company used the Monte Carlo simulation method to measure the fair value of the Contingent Consideration, which has unobservable inputs and is thus classified at Level 3 in the fair value hierarchy (see Note 13 for discussion of the fair value hierarchy).

On December 1, 2023, the Company acquired additional interests from affiliates of EnCap Investments L.P., including overriding royalty interests and royalty interests in certain oil and natural gas properties located primarily in Lea County, New Mexico, most of which were included in the Initial Advance Acquisition (the “Advance Royalty Acquisition”). The Advance Royalty Acquisition had an effective date of October 1, 2023 and an aggregate purchase price of approximately $81.0 million (which amount was subject to certain customary post-closing adjustments), and was funded by cash on hand.

The Initial Advance Acquisition and Advance Royalty Acquisition (collectively, the “Advance Acquisition”) were accounted for under the acquisition method of accounting as a business combination in accordance with ASC Topic 805. Under ASC Topic 805, the purchase price is allocated to the underlying tangible and intangible assets acquired and liabilities assumed based upon their estimated fair values as of the respective acquisition dates, with any excess purchase price allocated to goodwill. The Advance Acquisition was treated as an asset acquisition for tax purposes, as the Company acquired 100% of the membership interests of Advance in the Initial Advance Acquisition, and acquired additional overriding royalty interests and royalty interests in the Advance Royalty Acquisition.

The final allocation of the total purchase price for the Advance Acquisition is set forth below (in thousands).

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and natural gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation.

Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) future production volumes, (ii) expected operating and development costs, (iii) future commodity prices, (iv) recent market comparable transactions for unproved acreage and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates and are the most sensitive and subject to change.

Divestitures

During 2024 and 2023, the Company converted approximately $12.4 million and $0.7 million, respectively, of non-core assets to cash. These properties were primarily located in South Texas and Northwest Louisiana.

On October 28, 2024, Piñon was acquired by an affiliate of Enterprise Products Partners L.P. The Company received $113.6 million from the sale of Piñon during the fourth quarter of 2024 and used these proceeds to reduce borrowings under the Credit Agreement. The Company currently expects to receive an additional $4.8 million from the sale of Piñon in the first half of 2025.

NOTE 7 — DEBT

The components of debt, including the effects of issuance costs and discounts, net as of December 31, 2024 and 2023, are set forth below (in thousands).

Credit Agreements

MRC Energy Company

On November 18, 2021, the Company entered into its Fourth Amended and Restated Credit Agreement with the lenders party thereto, then led by Truist Bank as administrative agent. MRC Energy Company (“MRC”), a subsidiary of Matador that directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 85% of MRC’s and the Restricted Subsidiaries’ (as defined in the Credit Agreement) proved oil and natural gas properties and by the equity interests of certain of MRC’s wholly-owned subsidiaries, which are also guarantors. San Mateo is not a guarantor of the Credit Agreement. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC. The outstanding borrowings under the Credit Agreement mature on March 22, 2029 or, if earlier, the date that is up to 180 days prior to the earliest stated redemption date of any senior notes of the Company if unused availability under the revolving credit facility on such date is less than 20% of the aggregate revolving commitments, on a pro forma basis after giving effect to the repayment of such senior notes.

The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. The Company and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates.

On March 22, 2024, the Company and its 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 commitments 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 reaffirmation of the borrowing base constituted the regularly scheduled May 1 redetermination.

On September 18, 2024, the Company and its 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 commitments under the revolving credit facility from $1.50 billion to $2.25 billion. On September 25, 2024, the Company completed the sale of $750.0 million in aggregate principal amount of the 2033 Notes and used the proceeds to partially repay borrowings under the Credit Agreement, including all of the $250.0 million in outstanding borrowings under the term loan.

On November 21, 2024, the Company 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 the Company’s proved oil and natural gas reserves and unanimously determined to increase the borrowing base from $2.50 billion to $3.25 billion. The Company chose to maintain the elected borrowing commitments at $2.25 billion.

In the event of an increase in the elected borrowing commitment, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the increase. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at such time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period ofsix months.

Total deferred loan costs were $28.2 million at December 31, 2024, and these costs are being amortized over the term of the Credit Agreement. At December 31, 2024, the Company 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 Company’s effective interest rate under the Credit Agreement was 6.19% at December 31, 2024.

The applicable interest rate margin for borrowings under the Credit Agreement ranges from 1.75% to 2.75% for borrowings bearing interest with reference to the Adjusted Term SOFR Rate (as defined in the Credit Agreement) and from 0.75% to 1.75% for borrowings bearing interest with reference to the Alternate Base Rate (as defined in the Credit Agreement), in each case depending on the level of borrowings under the Credit Agreement. In addition, the Adjusted Term SOFR Rate includes a credit spread adjustment of 0.10% for all interest periods. The interest period for Adjusted Term SOFR Rate borrowings may beone, three orsix months as designated by MRC. If MRC has outstanding borrowings under the Credit Agreement and interest rates increase, so will MRC’s interest costs, which may have a material adverse effect on the Company’s results of operations and financial condition.

A commitment fee of 0.375% to 0.50%, depending on the level of borrowings under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company 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.

Subject to certain exceptions, the Credit Agreement contains various covenants that limit MRC’s and its Restricted Subsidiaries’ (as defined in the Credit Agreement) ability to take certain actions, including the following:

•incur indebtedness or grant liens on any of its assets;

•enter into commodity hedging agreements or interest rate agreements;

•declare or pay dividends, distributions or redemptions;

•merge or consolidate;

•make any loans or investments;

•engage in transactions with affiliates;

•engage in certain asset dispositions, including a sale of all or substantially all of MRC’s assets; and

•take certain actions with respect to the Company’s senior unsecured notes.

If an event of default exists under the Credit Agreement, the lenders will be able to terminate their commitments, accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include the following:

•failure to pay any principal on the outstanding borrowings when due or any interest on the outstanding borrowings, any reimbursement obligation under any letter of credit or any fees or other amounts within certain grace periods;

•failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;

•bankruptcy or insolvency events involving the Company or any of the Restricted Subsidiaries; and

•a change of control, as defined in the Credit Agreement.

The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2024.

San Mateo Midstream, LLC

On December 19, 2018, San Mateo entered into a secured revolving credit facility (the “San Mateo Credit Facility”) with the lenders party thereto, currently led by Truist Bank as administrative agent. 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) addsix new banks to San Mateo’s lending group. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in lender commitments 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.

Total deferred loan costs were $8.9 million at December 31, 2024, and these costs are being amortized over the term of the San Mateo Credit Facility. San Mateo’s effective interest rate under the San Mateo Credit Facility was 6.44% at December 31, 2024. At December 31, 2024, San Mateo had $615.0 million in borrowings outstanding under the San Mateo Credit Facility and $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.

Borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or an Adjusted Term SOFR Rate loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50%, and (iii) the Adjusted Term SOFR Rate (as defined in the San Mateo Credit Facility) for a one month tenor plus 1.0%, plus, in each case, an amount ranging from 1.00% to 2.00% depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility). If San Mateo borrows funds as an Adjusted Term SOFR Rate loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate for the chosen interest period plus (y) an amount ranging from 2.00% to 3.00% depending on San Mateo’s Consolidated Total Leverage Ratio. If San Mateo has outstanding borrowings under the San Mateo Credit Facility and interest rates increase, so will San Mateo’s interest costs, which may have a material adverse effect on San Mateo’s results of operations and financial condition.

A commitment fee of 0.30% to 0.50%, depending on San Mateo’s Consolidated Total Leverage Ratio, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. 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.

Subject to certain exceptions, the San Mateo Credit Facility contains various covenants that limit San Mateo’s and its restricted subsidiaries’ ability to take certain actions, including the following:

•incur indebtedness or grant liens on any of San Mateo’s assets;

•enter into hedging agreements;

•declare or pay dividends, distributions or redemptions;

•merge or consolidate;

•make any loans or investments;

•engage in transactions with affiliates;

•engage in certain asset dispositions, including a sale of all or substantially all of San Mateo’s assets; and

•issue equity interests in San Mateo or its restricted subsidiaries.

If an event of default exists under the San Mateo Credit Facility, the lenders will be able to terminate their commitments, accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include the following:

•failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods;

•failure to perform or otherwise comply with the covenants and obligations in the San Mateo Credit Facility or other loan documents, subject, in certain instances, to certain grace periods;

•bankruptcy or insolvency events involving San Mateo or its subsidiaries; and

•a change of control, as defined in the San Mateo Credit Facility.

The Company believes that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2024.

Senior Unsecured Notes

2026 Notes Tender Offer and Redemption

On April 2 and April 4, 2024, the Company completed the repurchase of an aggregate principal amount of approximately $556.3 million of the $699.2 million of outstanding senior notes due 2026 (the “2026 Notes”) pursuant to the Company’s cash tender offer for the 2026 Notes announced on March 26, 2024 (the “2026 Notes Tender Offer”). On April 2, 2024, the Company exercised its optional right, under the indenture governing the 2026 Notes, to redeem the remaining aggregate principal amount of approximately $142.9 million of 2026 Notes outstanding on September 15, 2024 (the “2026 Notes Redemption”) and, in connection therewith, to satisfy and discharge the Company’s obligations under such indenture with respect to the 2026 Notes. In connection with the 2026 Notes Tender Offer and 2026 Notes Redemption, the Company incurred a loss of approximately $3.0 million included in interest expense for the year ended December 31, 2024.

2028 Notes

At December 31, 2024, the Company had $500.0 million in aggregate principal amount of senior unsecured notes due 2028 (the “2028 Notes”), which have a 6.875% coupon rate and mature on April 15, 2028. Interest on the 2028 Notes is payable semi-annually in arrears on each April 15 and October 15. The 2028 Notes are jointly and severally guaranteed on a senior unsecured basis by certain subsidiaries of the Company (the “Guarantors”). San Mateo is not a Restricted Subsidiary (as defined in the indenture governing the 2028 Notes (the “2028 Notes Indenture”)) or Guarantor of the 2028 Notes.

At any time prior to April 15, 2025, the Company may redeem up to 35% in aggregate principal amount of 2028 Notes at a redemption price of 106.875% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, in an amount not greater than the net proceeds of certain equity offerings, so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the 2028 Notes remains outstanding after such redemption. In addition, at any time prior to April 15, 2025, the Company may redeem all or part of the 2028 Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest, if any, to the applicable redemption date.

On or after April 15, 2025, the Company may redeem all or a part of the 2028 Notes at any time or from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on April 15 of the years indicated below:

Subject to certain exceptions, the 2028 Notes Indenture contains various covenants that limit the Company’s and its Restricted Subsidiaries’ ability to take certain actions, including the following:

In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the 2028 Notes Indenture) that is a Significant Subsidiary (as defined in the 2028 Notes Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding 2028 Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2028 Notes may declare all the 2028 Notes to be due and payable immediately. Events of default include the following:

•default for 30 days in the payment when due of interest on the 2028 Notes;

•default in the payment when due of the principal of, or premium, if any, on the 2028 Notes;

•failure by the Company to comply with its obligations to offer to purchase or purchase 2028 Notes pursuant to the change of control or asset sale covenants of the 2028 Notes Indenture or to comply with the covenant relating to mergers;

•failure by the Company for 180 days after notice to comply with its reporting obligations under the 2028 Notes Indenture;

•failure by the Company for 60 days after notice to comply with any of the other agreements in the 2028 Notes Indenture;

•certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

2032 Notes

On April 2, 2024, the Company completed the sale of $900.0 million in aggregate principal amount of senior unsecured notes due 2032 (the “2032 Notes”), which have a 6.50% coupon rate and mature on April 15, 2032. Interest on the 2032 Notes is payable in arrears on each April 15 and October 15. The 2032 Notes are jointly and severally guaranteed on a senior unsecured basis by the Guarantors. San Mateo is not a Restricted Subsidiary (as defined in the indenture governing the 2032 Notes (the “2032 Notes Indenture”)) or Guarantor of the 2032 Notes.

At any time prior to April 15, 2027, the Company may redeem up to 40% in aggregate principal amount of 2032 Notes at a redemption price of 106.500% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, in an amount not greater than the net proceeds of certain equity offerings, so long as the redemption occurs within 180 days of completing such equity offering and at least 60% of the aggregate principal amount of the 2032 Notes remains outstanding after such redemption. In addition, at any time prior to April 15, 2027, the Company may redeem all or part of the 2032 Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest, if any, to the applicable redemption date.

On or after April 15, 2027, the Company may redeem all or a part of the 2032 Notes at any time or from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on April 15 of the years indicated below:

Subject to certain exceptions, the 2032 Notes Indenture contains various covenants that limit the Company’s and its Restricted Subsidiaries’ ability to take certain actions, including the following:

In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the 2032 Notes Indenture) that is a Significant Subsidiary (as defined in the 2032 Notes Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding 2032 Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2032 Notes may declare all the 2032 Notes to be due and payable immediately. Events of default include the following:

•default for 30 days in the payment when due of interest on the 2032 Notes;

•default in the payment when due of the principal of, or premium, if any, on the 2032 Notes;

•failure by the Company to comply with its obligations to offer to purchase or purchase 2032 Notes pursuant to the change of control or asset sale covenants of the 2032 Notes Indenture or to comply with the covenant relating to mergers;

•failure by the Company for 180 days after notice to comply with its reporting obligations under the 2032 Notes Indenture;

•failure by the Company for 60 days after notice to comply with any of the other agreements in the 2032 Notes Indenture;

•certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

2033 Notes

On September 25, 2024, the Company completed the sale of $750.0 million in aggregate principal amount of the 2033 Notes, which have a 6.25% coupon rate and mature on April 15, 2033. Interest on the 2033 Notes is payable in arrears on each April 15 and October 15. The first interest payment date for the 2033 Notes will be April 15, 2025. The 2033 Notes are jointly and severally guaranteed on a senior unsecured basis by the Guarantors. San Mateo is not a Restricted Subsidiary (as defined in the indenture governing the 2033 Notes (the “2033 Notes Indenture”)) or Guarantor of the 2033 Notes.

At any time prior to April 15, 2028, the Company may redeem up to 40% in aggregate principal amount of 2033 Notes at a redemption price of 106.250% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, in an amount not greater than the net proceeds of certain equity offerings, so long as the redemption occurs within 180 days of completing such equity offering and at least 60% of the aggregate principal amount of the 2033 Notes remains outstanding after such redemption. In addition, at any time prior to April 15, 2028, the Company may redeem all or part of the 2033 Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest, if any, to the applicable redemption date.

On or after April 15, 2028, the Company may redeem all or a part of the 2033 Notes at any time or from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on April 15 of the years indicated below:

Subject to certain exceptions, the 2033 Notes Indenture contains various covenants that limit the Company’s and its Restricted Subsidiaries’ ability to take certain actions, including the following:

In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary (as defined in the 2033 Notes Indenture) that is a Significant Subsidiary (as defined in the 2033 Notes Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding 2033 Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2033 Notes may declare all the 2033 Notes to be due and payable immediately. Events of default include the following:

•default for 30 days in the payment when due of interest on the 2033 Notes;

•default in the payment when due of the principal of, or premium, if any, on the 2033 Notes;

•failure by the Company to comply with its obligations to offer to purchase or purchase 2032 Notes pursuant to the change of control or asset sale covenants of the 2033 Notes Indenture or to comply with the covenant relating to mergers;

•failure by the Company for 180 days after notice to comply with its reporting obligations under the 2033 Notes Indenture;

•failure by the Company for 60 days after notice to comply with any of the other agreements in the 2033 Notes Indenture;

•certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

NOTE 8 —INCOME TAXES

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2024 and 2023 is as follows (in thousands).

The current income tax provision and the deferred income tax provision for the years ended December 31, 2024, 2023 and 2022 were comprised of the following (in thousands).

NOTE 8 — INCOME TAXES — Continued

Reconciliations of the tax expense computed at the statutory federal rate to the Company’s total income tax provision for the years ended December 31, 2024, 2023 and 2022 is as follows (in thousands).

(1)The statutory federal tax rate was 21% for the years ended December 31, 2024, 2023 and 2022.

The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the federal, the State of New Mexico and the State of Louisiana tax returns is 2021. The earliest tax year open for examination for the State of Texas tax return is 2020.

As of December 31, 2024 and 2023, the Company had unrecognized tax benefits (“UTBs”) of $34.3 million and $35.3 million, respectively, as a result of research and experimental expenditures, which would reduce the Company’s effective tax rate in future periods if and when realized. There wereno UTBs as of December 31, 2022. As of December 31, 2024 and 2023, $31.1 million and $27.0 million, respectively, of the Company’s UTBs were recorded as other long-term liabilities on the consolidated balance sheets. Although the Company does not anticipate a material change in UTBs within the next 12 months, the timing as to when the Company will substantially resolve the uncertainties associated with the UTBs is unknown.

A reconciliation of UTBs for the years ended December 31, 2024, 2023 and 2022 is as follows (in thousands).

(1)At December 31, 2024, the UTBs related to the U.S. federal and state of Texas jurisdictions were $30.2 million and $4.1 million, respectively. At December 31, 2023, the UTBs related to the U.S. federal and state of Texas jurisdictions were $30.7 million and $4.6 million, respectively.

NOTE 9 —STOCK-BASED COMPENSATION

In 2012, the Company’s Board adopted and shareholders approved the 2012 Incentive Plan. The 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that could be issued pursuant to options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants.

In 2019, the Board adopted and shareholders approved the 2019 Incentive Plan. In 2022, the Board adopted and shareholders approved the first amendment to the 2019 Incentive Plan authorizing an additional 3,725,000 shares of common stock for issuance to employees, directors, contractors or advisors of the Company. As of December 31, 2024, the 2019 Incentive Plan provided for a maximum of 3,959,799 shares of common stock in the aggregate that may be issued pursuant to grants of options, restricted stock, stock appreciation rights, restricted stock units or other performance award grants. The persons eligible to receive awards under the 2019 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2019 Incentive Plan is to attract and retain key employees, directors, contractors or advisors of the Company. With the adoption of the 2019 Incentive Plan, the Company does not expect to make any future

NOTE 9 — STOCK-BASED COMPENSATION — Continued

awards under the 2012 Incentive Plan, but the 2012 Incentive Plan will remain in place until all awards outstanding under that plan have been settled.

The 2012 Incentive Plan and 2019 Incentive Plan (collectively, the “LTIPs”) are administered by the independent members of the Board, who, upon recommendation of the Strategic Planning and Compensation Committee of the Board, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants.

During the years ended December 31, 2024, 2023 and 2022, the Company granted both equity-based and liability-based awards under the 2019 Incentive Plan. The fair value of equity-based awards is fixed at the grant date, while the fair value of liability-based awards is remeasured at each reporting period.

In 2022, the Board adopted and shareholders approved an Employee Stock Purchase Plan (the “ESPP”), which authorizes a maximum of 4.0 million shares of common stock to be purchased. The purpose of the ESPP is to encourage and enable the Company’s eligible employees to acquire an interest in the Company through the ownership of common stock. At December 31, 2024, the Company had 3,891,108 remaining shares available for issuance under the ESPP.

Service-Based Restricted Stock, Restricted Stock Units and Common Stock

The Company has granted stock, restricted stock and restricted stock unit awards to employees, consultants, outside directors and advisors of the Company under the LTIPs. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The equity-based restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. Liability-based restricted stock units are settled in cash upon vesting. Restricted stock and restricted stock units granted in 2024, 2023 and 2022 were service-based awards, which will settle in cash or equity, and vest over aone-year tothree-year period. Performance-based restricted stock units granted in 2024 and 2023 vest in an amount between zero and 200% of the target units granted based on the Company’s relative total shareholder return over thethree-year periods ending December 31, 2026 and 2025, respectively, as compared to a designated peer group, and will be settled in equity.

Equity-Based

A summary of the non-vested equity-based restricted stock and restricted stock units as of December 31, 2024 is presented below (in thousands, except fair value).

(1)On January 8, 2025 upon certification by the Board,179,074 of the performance-based awards that were granted in 2022 vested. The vested units earned 172% for each vested award representing 307,992 aggregate shares of common stock, which were issued on January 8, 2025.

NOTE 9 — STOCK-BASED COMPENSATION — Continued

Liability-Based

A summary of the non-vested liability-based restricted stock units as of December 31, 2024 is presented below (in thousands).

During the years ended December 31, 2024, 2023 and 2022, the Company settled 222,948,378,852 and 587,251 liability-based awards, respectively, for $13.4 million, $20.5 million and $30.8 million in cash, respectively.

At December 31, 2024, the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $95.2 million, of which $27.4 million is expected to be settled in cash as calculated based on the maximum number of shares of restricted stock units vesting, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs.

At December 31, 2024, the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $55.9 million, of which $18.3 million is expected to be settled in cash, based on the closing price of Matador’s common stock on the appropriate date under the LTIPs. The weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 1.9 years.

The fair value of restricted stock and restricted stock units vested during 2024, 2023 and 2022 was $29.4 million, $64.8 million and $99.6 million, respectively.

Summary

During the years ended December 31, 2024, 2023 and 2022, the total expense attributable to restricted stock and restricted stock units was $37.3 million, $33.0 million and $51.6 million, respectively. During the years ended December 31, 2024, 2023 and 2022, the Company capitalized $11.8 million, $7.4 million and $5.0 million, respectively, related to stock-based compensation and expensed the remaining $25.5 million, $25.6 million and $47.1 million, respectively.

The total tax benefit recognized for all stock-based compensation was $8.0 million, $7.0 million and $11.0 million for the years ended December 31, 2024, 2023 and 2022, respectively.

NOTE 10 —EMPLOYEE BENEFIT PLANS

401(k) Plan

All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan that equals 3% of the employee’s annual compensation, up to the maximum allowable under the Internal Revenue Code, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled $2.6 million, $2.2 million and $1.8 million in 2024, 2023 and 2022, respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $3.3 million, $2.8 million and $2.3 million in 2024, 2023 and 2022, respectively. The Company madeno additional contributions in any reporting period presented.

NOTE 11 —EQUITY

Equity Offering

On March 28, 2024, the Company completed an underwritten public offering of 5,250,000 shares of its common stock. After deducting underwriting discounts and offering expenses, the Company received net proceeds of approximately $342.1 million. The net proceeds from this offering were used for general corporate purposes, including the funding of acquisitions and the repayment of borrowings outstanding under the Credit Agreement.

NOTE 11 — EQUITY— Continued

Common Stock Dividend

The Board declared a quarterly cash dividend of $0.20 per share of common stock in each of the first, second and third quarters of 2024. The first quarter dividend, which totaled $23.9 million, was paid on March 13, 2024 to shareholders of record as of February 23, 2024. The second quarter dividend, which totaled $24.9 million, was paid on June 7, 2024 to shareholders of record as of May 17, 2024. The third quarter dividend, which totaled $24.9 million, was paid on September 5, 2024 to shareholders of record as of August 15, 2024. On October 16, 2024, the Board amended the Company’s dividend policy to increase the quarterly dividend to $0.25 per share of common stock for future dividend payments and also declared a quarterly cash dividend of $0.25 per share of common stock. The fourth quarter dividend, which totaled $31.3 million, was paid on December 6, 2024 to shareholders of record as of November 15, 2024.

The Board declared a quarterly cash dividend of $0.15 per share of common stock in each of the first three quarters of 2023 and the Board declared a quarterly cash dividend of $0.20 per share of common stock in the fourth quarter of 2023.

Total cash dividends declared and paid totaled $104.9 million and $77.2 million, respectively, during the years ended December 31, 2024 and 2023.

On February 18, 2025, the Board amended the Company’s dividend policy to increase the quarterly dividend to $0.3125 per share of common stock for future dividend payments and declared a 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.

Treasury Stock

On October 17, 2024, October 19, 2023 and October 20, 2022, Matador’s Board canceled all of the shares of treasury stock outstanding as of September 30, 2024, 2023 and 2022, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company.

The shares of treasury stock outstanding at December 31, 2024, 2023 and 2022 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees.

Preferred Stock

The Company’s Amended and Restated Certificate of Formation authorizes 2,000,000 shares of preferred stock. Before any such shares are issued, the Board shall fix and determine the designations, preferences, limitations and relative rights, including voting rights of the shares of each such series.

San Mateo Distributions and Contributions

During the years ended December 31, 2024, 2023 and 2022, San Mateo distributed $321.2 million, $81.4 million and $89.5 million, respectively, to the Company and $97.5 million, $78.3 million and $86.0 million, respectively, to Five Point, the Company’s joint venture partner in San Mateo.

During the years ended December 31, 2024 and 2023, the Company contributed $19.9 million and $25.5 million, respectively, and Five Point contributed $190.6 million and $24.5 million, respectively, of cash to San Mateo. During the year ended December 31, 2022, neither the Company nor Five Point contributed cash to San Mateo.

San Mateo’s 2024 distributions to the Company included a special distribution of approximately $219.8 million, of which $171.5 million represented a special contribution by Five Point recorded within the Company’s statement of changes in shareholders’ equity in connection with the Pronto Transaction. San Mateo’s remaining special distribution to the Company of $48.3 million represented a reimbursement of certain capital expenditures for the Marlan Processing Plant expansion that were previously funded by Matador. See Note 6 for additional details.

NOTE 11 — EQUITY— Continued

Performance Incentives

As part of the joint venture with Five Point, the Company has had the potential to earn three different sets of performance incentives. These performance incentives are recorded as additional contributions related to the formation of San Mateo as they are received. Beginning in 2017, the Company had the potential to earn up to $73.5 million in performance incentives related to the Company’s performance in its Rustler Breaks asset area in Eddy County and the Wolf portion of its West Texas asset area in Loving County over afive-year period, which in October 2020 was extended by an additional year to January 31, 2023. Through January 31, 2023, the Company had earned all of the potential $73.5 million in performance incentives. Five Point paid the Company $14.7 million in performance incentives in each of the first quarters of 2018, 2019, 2020, 2021 and 2023. Beginning in 2019, the Company had the potential to earn up to $150.0 million in additional performance incentives in its Stebbins area and surrounding leaseholds in the southern portion of its Arrowhead asset area (the “Greater Stebbins Area”) and Stateline asset area through mid-2024. Through September 30, 2024, the Company earned $108.2 million of these performance incentives.

In connection with the Pronto Transaction, the Company has the potential to earn up to $75.0 million in additional incentive payments from Five Point over afive-year period, of which $1.3 million was paid by Five Point during the fourth quarter of 2024.

During the years ended December 31, 2024 and 2023, Five Point paid the Company $23.8 million and $38.2 million, respectively, in performance incentives. These performance incentives are recorded when received, net of the $5.0 million and $8.0 million deferred tax impact to Matador for the years ended December 31, 2024 and 2023, respectively, in “Additional paid-in-capital” in the Company’s consolidated balance sheets.

NOTE 12 —DERIVATIVE FINANCIAL INSTRUMENTS

From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and NGL prices. The Company records derivative financial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of income as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments.

At December 31, 2024, the Company had various costless collar contracts open and in place to mitigate its exposure to oil price volatility, each with an established price floor and ceiling. At December 31, 2024, the Company had natural gas basis differential swap contracts open and in place to mitigate its exposure to natural gas price volatility, with a specific term (calculation period), notional quantity (volume hedged) and fixed price. The Company had no open contracts associated with NGL prices at December 31, 2024.

The following is a summary of the Company’s open costless collar contracts at December 31, 2024.

NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued

The following is a summary of the Company’s open basis differential swap contracts at December 31, 2024.

The Company’s derivative financial instruments are subject to master netting arrangements, and the Company’s counterparties allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheets.

The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2024 and December 31, 2023 (in thousands).

The following table summarizes the location and aggregate gain (loss) of all derivative financial instruments recorded in the consolidated statements of income for the periods presented (in thousands).

NOTE 13 —FAIR VALUE MEASUREMENTS

The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories.

Level 1 Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets.

Level 2 Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs, including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.

Level 3 Unobservable inputs that are not corroborated by market data that reflect a company’s own market assumptions.

Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2024 and 2023 (in thousands).

Additional disclosures related to derivative financial instruments are provided in Note 12.

Other Fair Value Measurements

At December 31, 2024 and 2023, the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners and other current liabilities approximated their fair values due to their short-term maturities.

At December 31, 2024 and 2023, the carrying value of borrowings under the Credit Agreement and the San Mateo Credit Facility approximated their fair value as both are subject to short-term floating interest rates that reflect market rates available to the Company at the time and are classified at Level 2 in the fair value hierarchy.

At December 31, 2024 and 2023, the fair value of the 2028 Notes was $505.4 million and $510.9 million, respectively, based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.

At December 31, 2024, the fair value of the 2032 Notes was $890.7 million based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.

NOTE 13 — FAIR VALUE MEASUREMENTS — Continued

At December 31, 2024, the fair value of the 2033 Notes was $730.6 million based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.

Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination, lease and well equipment inventory when the market value is determined to be lower than the cost of the inventory and other property and equipment that are reduced to fair value when they are impaired or held for sale. The Company recordedno impairment to its lease and well equipment inventory or other property and equipment in 2024 and 2023.

NOTE 14 —COMMITMENTS AND CONTINGENCIES

Processing, Transportation and Produced Water Disposal Commitments

Firm Commitments

From time to time, the Company enters into agreements with third parties whereby the Company commits to deliver anticipated natural gas and oil production and produced water from certain portions of its acreage for gathering, transportation, processing, fractionation, sales and disposal. The Company paid approximately $68.3 million and $51.5 million for deliveries under these agreements during the years ended December 31, 2024 and 2023, respectively. Certain of these agreements contain minimum volume commitments, including certain agreements with Northwind that were entered into in connection with the Pronto Transaction in 2024. See Note 6 for additional details. If the Company does not meet the minimum volume commitments under these agreements, it will be required to pay certain deficiency fees. If the Company ceased operations in the areas subject to these agreements at December 31, 2024, the total deficiencies required to be paid by the Company under these agreements would be approximately $692.6 million.

San Mateo Commitments

The Company dedicated to San Mateo its 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 the 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, the Company dedicated to San Mateo its 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 (collectively with the transportation, gathering and produced water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments, including certain agreements with Pronto that were entered into in connection with the Pronto Transaction in 2024. See Note 6 for additional details. The remaining minimum contractual obligation under the Operational Agreements at December 31, 2024 was approximately $804.3 million.

Other Commitments

The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $20.4 million at December 31, 2024.

At December 31, 2024, the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s undiscounted minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $60.8 million at December 31, 2024. The Company expects these costs to be incurred within the next year.

At December 31, 2024, San Mateo had outstanding midstream commitments of $67.7 million for the construction and installation of the Marlan Processing Plant expansion with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities. The Company expects the majority of these costs to be incurred within the next year.

Legal Proceedings

The Company is a party to several legal proceedings encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote

NOTE 14 — COMMITMENTS AND CONTINGENCIES — Continued

that these legal proceedings will have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

NOTE 15 — SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at December 31, 2024 and 2023 (in thousands).

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2024, 2023 and 2022 (in thousands).

(1)Represents tax payments of $34.4 million, $13.5 million and $63.5 million for the years ended December 31, 2024, 2023 and 2022, respectively.

The following table provides a reconciliation of cash and restricted cash recorded in the consolidated balance sheets to cash and restricted cash as presented on the consolidated statements of cash flows (in thousands).

NOTE 16 —SEGMENT INFORMATION

The Company hastwo reportable business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States and is currently 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. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. The midstream segment conducts midstream operations in support of, and provides flow assurance for, the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. The majority of the Company’s midstream operations in the Delaware Basin are conducted through San Mateo.

The Company’s chief operating decision maker (“CODM”) is the Chairman and Chief Executive Officer. The CODM uses operating income to assess income generated from each segment to allocate resources by either reinvesting profits as midstream or drilling and completion capital expenditures, or for determining the appropriate amounts for acquisition spend, the repayment of debt and the payment of dividends.

The following tables present selected financial information for the periods presented regarding the Company’s business segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.”

(2)Includes depletion, depreciation and amortization expenses of $929.0 million and $43.9 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $1.4 million. Other expenses for each reportable segment also includes (i) production taxes, transportation and processing, (ii) general and administrative expenses, (iii) accretion of asset retirement obligations and (iv) purchased natural gas.

(3)Includes $86.0 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(5)Includes $2.08 billion attributable to land and seismic acquisition expenditures related to the exploration and production segment, $236.2 million in midstream acquisition expenditures and $29.5 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

NOTE 16 — SEGMENT INFORMATION — Continued

(2)Includes depletion, depreciation and amortization expenses of $675.0 million and $40.4 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $1.3 million. Other expenses for each reportable segment also includes (i) production taxes, transportation and processing, (ii) general and administrative expenses, (iii) accretion of asset retirement obligations and (iv) purchased natural gas.

(3)Includes $64.3 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(5)Includes $1.81 billion attributable to land and seismic acquisition expenditures related to the exploration and production segment, $63.6 million in midstream acquisition expenditures and $42.2 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

NOTE 16 — SEGMENT INFORMATION — Continued

(2)Includes depletion, depreciation and amortization expenses of $429.7 million and $34.7 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $2.0 million. Other expenses for each reportable segment also includes (i) production taxes, transportation and processing, (ii) general and administrative expenses, (iii) accretion of asset retirement obligations and (iv) purchased natural gas.

(3)Includes $72.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.

(5)Includes $131.0 million attributable to land and seismic acquisition expenditures related to the exploration and production segment, $75.8 million in midstream acquisition expenditures and $39.6 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.