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Matador Resources Co - Annual Report: 2024 (Form 10-K)

__________________
(1)Includes 61 gross (41.0 net) wells from the Eagle Ford formation that were divested in 2024 and one well producing oil from the Austin Chalk formation in La Salle County, Texas that was divested in November 2024.
(2)Includes the Cotton Valley formation and shallower zones.
(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(4)Excludes impact of derivative settlements.
(5)Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.

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The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2023 from our operating areas, which we consider to be distinct fields for purposes of accounting for production. 
Southeast
 New Mexico/West Texas		South TexasNorthwest Louisiana
Delaware Basin
Eagle Ford(1)
Haynesville
Cotton Valley(2)
Total
Annual Net Production Volumes
Oil (MBbl)27,264 276 — 2 27,542 
Natural gas (Bcf)113.9 0.7 8.2 0.6 123.4 
Total oil equivalent (MBOE)(3)
46,253 390 1,373 96 48,112 
Percentage of total annual net production96.1 %0.8 %2.9 %0.2 %100.0 %
Average Net Daily Production Volumes
Oil (Bbl/d)74,697 755 — 5 75,457 
Natural gas (MMcf/d)312.1 1.9 22.6 1.5 338.1 
Total oil equivalent (BOE/d)126,720 1,068 3,761 264 131,813 
Average Sales Prices(4)
Oil (per Bbl)$77.90 $76.10 $— $74.53 $77.88 
Natural gas (per Mcf)$3.32 $3.54 $2.23 $2.09 $3.25 
Total oil equivalent (per BOE)$54.10 $60.01 $13.39 $13.61 $52.91 
Production Costs(5)
Lease operating, transportation and processing (per BOE)$5.99 $32.78 $4.59 $17.79 $6.19 
_________________
(1)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.
(2)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas that was divested in September 2023.
(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(4)Excludes impact of derivative settlements.
(5)Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.


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The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2022 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.
Southeast
 New Mexico/West Texas		South TexasNorthwest Louisiana
Delaware Basin
Eagle Ford(1)
Haynesville
Cotton Valley(2)
Total
Annual Net Production Volumes
Oil (MBbl)21,585 355 — 3 21,943 
Natural gas (Bcf)89.8 0.9 8.3 0.3 99.3 
Total oil equivalent (MBOE)(3)
36,550 501 1,383 61 38,495 
Percentage of total annual net production94.9 %1.3 %3.6 %0.2 %100.0 %
Average Net Daily Production Volumes
Oil (Bbl/d)59,139 971 — 9 60,119 
Natural gas (MMcf/d)246.0 2.4 22.7 1.0 272.1 
Total oil equivalent (BOE/d)100,135 1,373 3,789 168 105,465 
Average Sales Prices(4)
Oil (per Bbl)$96.34 $95.23 $— $91.53 $96.32 
Natural gas (per Mcf)$8.18 $9.04 $5.81 $5.71 $7.98 
Total oil equivalent (per BOE)$76.98 $83.24 $34.87 $37.23 $75.48 
Production Costs(5)
Lease operating, transportation and processing (per BOE)$5.10 $27.41 $5.37 $22.69 $5.43 
_________________
(1)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.
(2)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(4)Excludes impact of derivative settlements.
(5)Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.
Our total oil equivalent production of approximately 62.5 million BOE for the year ended December 31, 2024 increased 30% from our total oil equivalent production of approximately 48.1 million BOE for the year ended December 31, 2023. This increased production was primarily attributable to the Ameredev Acquisition and to our delineation and development operations in the Delaware Basin throughout 2024, which offset declining production in the Eagle Ford shale and Northwest Louisiana. Our average daily oil equivalent production for the year ended December 31, 2024 was 170,751 BOE per day, as compared to 131,813 BOE per day for the year ended December 31, 2023. Our average daily oil production for the year ended December 31, 2024 was 99,808 Bbl of oil per day, an increase of 32% from 75,457 Bbl of oil per day for the year ended December 31, 2023. Our average daily natural gas production for the year ended December 31, 2024 was 425.7 MMcf of natural gas per day, an increase of 26% from 338.1 MMcf of natural gas per day for the year ended December 31, 2023.
Our total oil equivalent production of approximately 48.1 million BOE for the year ended December 31, 2023 increased 25% from our total oil equivalent production of approximately 38.5 million BOE for the year ended December 31, 2022. This increased production was primarily due to the Advance Acquisition and to our delineation and development operations in the Delaware Basin throughout 2023, which offset declining production in the Eagle Ford shale. Our average daily oil equivalent production for the year ended December 31, 2023 was 131,813 BOE per day, as compared to 105,465 BOE per day for the year ended December 31, 2022. Our average daily oil production for the year ended December 31, 2023 was 75,457 Bbl of oil per day, an increase of 26% from 60,119 Bbl of oil per day for the year ended December 31, 2022. Our average daily natural gas production for the year ended December 31, 2023 was 338.1 MMcf of natural gas per day, an increase of 24% from 272.1 MMcf of natural gas per day for the year ended December 31, 2022.

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Producing Wells
The following table sets forth information relating to producing wells at December 31, 2024. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 85% in all wells that we operated at December 31, 2024. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. 
Oil WellsNatural Gas WellsTotal Wells
GrossNetGrossNetGrossNet
Southeast New Mexico/West Texas:
Delaware Basin(1)
1,769 927.4 180 92.4 1,949 1,019.8 
South Texas:
Eagle Ford31 30.3 — — 31 30.3 
Northwest Louisiana:
Haynesville— — 268 18.5 268 18.5 
Cotton Valley(2)
— — 66 39.0 66 39.0 
Area Total— — 334 57.5 334 57.5 
202123,965 96.6 40,071 $240,664 
202222,515 95.3 38,403 434,336 
202318,492 98.6 34,928 441,671 
202434,857 118.4 54,598 685,163 
Total99,829 408.9 168,000 $1,801,834 
__________________
(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.

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The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2024.
Net Proved Reserves(1)
OilNatural GasOil Equivalent
Standardized Measure(2)
PV-10(3)
(MBbl)(Bcf)
 (MBOE)(4)
(in millions)(in millions)
Southeast New Mexico/West Texas:
Delaware Basin360,396 1,474.8 606,196 $7,355.4 $9,207.3 
South Texas:
Eagle Ford1,441 1.4 1,667 21.2 26.7 
Northwest Louisiana
Haynesville— 19.7 3,286 5.4 6.8 
Cotton Valley(5)
4 2.3 387 (5.6)(7.0)
Area Total4 22.0 3,673 (0.2)(0.2)
Total361,842 1,498.2 611,536 $7,376.6 $9,233.8 
__________________
(1)Numbers in table may not total due to rounding.
(2)Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.
(3)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2024 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2024 were approximately $1.86 billion.
(4)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(5)Includes the Cotton Valley formation and shallower zones.
Technology Used to Establish Reserves
Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The term “reasonable certainty” means a high degree of confidence that the quantities of oil and/or natural gas will be recovered. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance methods. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either analogy and/or volumetric methods.
Internal Control Over Reserves Estimation Process
We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Individual asset teams are responsible for the day-to-day management of the oil and natural gas activities for each team’s asset area. These asset teams are staffed with reservoir engineers who prepare reserves estimates at the end of each calendar quarter for the assets they manage. Our Vice President of Reservoir Engineering and the Reserves Team was primarily responsible for overseeing the preparation of our reserves estimates in 2024. He received Bachelor of Science degrees in both Petroleum Engineering and Mechanical Engineering from Texas Tech University, is a licensed Professional Engineer in the state of Texas and has over ten years of industry experience.

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Our Vice President of Reservoir Engineering and the Reserves Team works under the direct supervision of our Executive Vice President of Reservoir Engineering and Senior Asset Manager, who received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and has over 15 years of industry experience. The Company has established internal controls over its reserves estimation processes and procedures to support the accurate and timely preparation and disclosure of reserves estimates in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation processes by our internal reserves group as well as accounting and finance personnel. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Members of our executive committee and members of the Operations and Engineering Committee of our Board of Directors (the “Board”) review the reserves report and our reserves estimation process, and the independent audit of our reserves is reviewed by other members of the Board as well.
Acreage Summary
The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2024.
 Developed Acres Undeveloped Acres Total Acres
 Gross Net GrossNet Gross Net
Southeast New Mexico/West Texas:
Delaware Basin271,300 156,900 56,700 41,800 328,000 198,700 
South Texas:
Eagle Ford 2,900 2,900 — — 2,900 2,900 
Northwest Louisiana:
Haynesville16,200 8,900 — — 16,200 8,900 
Cotton Valley15,700 14,800 — — 15,700 14,800 
Area Total(1)
18,500 17,300 — — 18,500 17,300 
   Total292,700 177,100 56,700 41,800 349,400 218,900 
__________________
(1)Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana.
Undeveloped Acreage Expiration
The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2024 that will expire over the next five years by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. Undeveloped acreage expiring in 2030 and beyond totals 2,400 net acres, all of which is in the Delaware Basin. All of our leasehold in the Eagle Ford shale in South Texas and in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2024.
AcresAcresAcresAcresAcres
Expiring 2025Expiring 2026Expiring 2027Expiring 2028Expiring 2029
GrossNetGrossNetGrossNetGrossNetGrossNet
Southeast New Mexico/West Texas:
Delaware Basin(1)
12,700 7,500 14,800 8,000 16,700 14,100 5,200 5,200 4,600 4,600 

2.1*
Securities Purchase Agreement, dated January 24, 2023, by and among MRC Hat Mesa, LLC, MRC Energy Company (solely for the limited purposes stated therein), AEP EnCap HoldCo, LLC, Ameradvance Management LLC and Advance Energy Partners Holdings, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on January 24, 2023).
2.2
Amendment No. 1 to Securities Purchase Agreement, dated April 5, 2023, by and among MRC Hat Mesa, LLC, AEP EnCap HoldCo, LLC, Ameradvance Management LLC and Advance Energy Partners Holdings, LLC (incorporated by reference to Exhibit 2.2 to the Annual Report on Form 10-K for the year ended December 31, 2023).
2.3*
Waiver and Release Agreement and Amendment No. 2 to Securities Purchase Agreement, dated December 1, 2023, by and among MRC Hat Mesa, LLC, AEP EnCap HoldCo, LLC, Ameradvance Management LLC and Advance Energy Partners Holdings, LLC (incorporated by reference to Exhibit 2.3 to the Annual Report on Form 10-K for the year ended December 31, 2023.).
2.4*
Securities Purchase Agreement, dated June 12, 2024, by and among MRC Toro, LLC, MRC Energy Company (solely for the limited purposes stated therein), Ameredev II Parent, LLC, Ameredev Intermediate II, LLC and Ameredev Stateline II, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on June 12, 2024).
2.5*
Amendment No. 1 to Securities Purchase Agreement, dated August 29, 2024, by and among MRC Toro, LLC, Ameredev II Parent, LLC, Ameredev Intermediate II, LLC and Ameredev Stateline II, LLC (incorporated by reference to Exhibit 2.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2024).
2.6
Amendment No. 2 to Securities Purchase Agreement, dated February 14, 2025, by and among MRC Toro, LLC, Ameredev II Parent, LLC, Ameredev Intermediate II, LLC (filed herewith).
3.1
Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).
3.2
Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company dated April 2, 2015 (incorporated by reference to Exhibit 3.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).
3.3
Certificate of Amendment to the Amended and Restated Certificate of Formation of Matador Resources Company effective June 2, 2017 (incorporated by reference to Exhibit 3.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2017).
3.4
Amended and Restated Bylaws of Matador Resources Company, as amended (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 22, 2018).
4.1
Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1 filed on January 19, 2012).
4.2
Indenture, dated as of April 11, 2023, by and among Matador Resources Company, the subsidiary guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on April 11, 2023).
4.3
First Supplemental Indenture, dated as of July 25, 2023, by and among Matador Resources Company, MRC Hat Mesa, LLC, the subsidiary guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2023).
4.4
Indenture, dated as of April 2, 2024, by and among Matador Resources Company, the subsidiary guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on April 2, 2024).
4.5
First Supplemental Indenture, dated as of September 20, 2024, by and among MRC Toro, LLC, the subsidiary guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2024).
4.6
Second Supplemental Indenture, dated as of September 20, 2024, by and among MRC Toro, LLC, the subsidiary guarantors party thereto and Computershare Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2024).

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4.7
4.8
10.1†
10.2†
10.3†
10.4†
10.5†
10.6†
First Amendment to the Employment Agreement between Matador Resources Company and G. Gregg Krug (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2019).
10.7†
10.8†
10.9†
10.10
10.11
10.12
10.13
10.14

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10.15
10.16
10.17
10.18
10.19†
10.20†
10.21†
10.22†
10.23†
10.24†
10.25†
10.26†
10.27†
10.28†
10.29†
10.30†
10.31†

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10.32†
10.33†
10.34†
10.35†
10.36†
10.37†
10.38†
10.39†
10.40†
10.41†
10.42†
10.43†
10.44†
19.1
21.1
23.1
23.2
31.1
31.2
32.1
32.2
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99.1
101
The following financial information from Matador Resources Company’s Annual Report on Form 10-K for the year ended December 31, 2024, formatted in Inline XBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Income, (iii) the Consolidated Statements of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith).
104Cover Page Interactive Data File, formatted in Inline XBRL (included as Exhibit 101).
†Indicates a management contract or compensatory plan or arrangement.
*This filing excludes certain schedules and exhibits pursuant to Item 601(a)(5) of Regulation S-K, which the Company agrees to furnish supplementally to the SEC upon request; provided, however, that the Company may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended, for any schedules or exhibits so furnished.


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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 MATADOR RESOURCES COMPANY
February 25, 2025 By:/s/ Joseph Wm. Foran
 Joseph Wm. Foran
 Chairman and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SignatureTitle Date
/s/ Joseph Wm. ForanChairman and Chief Executive Officer  February 25, 2025
Joseph Wm. Foran(Principal Executive Officer)
/s/ Brian J. WilleyExecutive Vice President and Chief Financial Officer February 25, 2025
Brian J. Willey(Principal Financial Officer)
/s/ Robert T. MacalikExecutive Vice President and Chief Accounting Officer  February 25, 2025
Robert T. Macalik(Principal Accounting Officer)
/s/ Shelley F. AppelDirectorFebruary 25, 2025
Shelley F. Appel
/s/ Reynald A. BaribaultDirector February 25, 2025
Reynald A. Baribault
/s/ R. Gaines BatyDirector February 25, 2025
R. Gaines Baty
/s/ William M. ByerleyDirector February 25, 2025
William M. Byerley
/s/ Monika U. EhrmanDirectorFebruary 25, 2025
Monika U. Ehrman
/s/ Paul W. HarveyDirectorFebruary 25, 2025
Paul W. Harvey
/s/ James M. HowardDirectorFebruary 25, 2025
James M. Howard
/s/ Timothy E. ParkerDirectorFebruary 25, 2025
Timothy E. Parker
/s/ Kenneth L. StewartDirectorFebruary 25, 2025
Kenneth L. Stewart
/s/ Susan M. WardDirectorFebruary 25, 2025
Susan M. Ward


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GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report.
Batch drilling. The process by which multiple horizontal wells are drilled from a single pad. In batch drilling, the surface holes for each well are drilled first and then the production holes, including the horizontal laterals for each well, are drilled.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil, other liquid hydrocarbons or produced water.
Bcf. One billion cubic feet of natural gas.
Bench. A geologic zone or formation or a subdivision of a geologic formation.
BOE. Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or NGLs to six Mcf of natural gas.
BOE/d. BOE per day.
Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Central delivery point or CDP. The point on an oil, natural gas or produced water system where such product is aggregated from one or more gathering or transportation pipelines, wells, tank batteries or leases. Custody is often transferred to a third party at a central delivery point.
Completion. The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Conventional reservoirs or resources. Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore.
Coring. The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined.
Developed acreage. The number of acres that are allocated or assignable to productive wells.
Developed oil and natural gas reserves. Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential. The difference between a particular oil or natural gas price and the applicable benchmark price, such as the NYMEX West Texas Intermediate oil price or the NYMEX Henry Hub natural gas price.
Dry hole. A well found to be incapable of producing hydrocarbons.
Economically producible. As it relates to a resource, a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
ESP. Electric submersible pump.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.
Extension well. A well drilled to extend the limits of a known reservoir.
Farmin or farmout. An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the

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assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.”
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
GAAP, or U.S. GAAP. United States, generally accepted accounting principles.
Gross acres or gross wells. The total acres or wells in which a working interest is owned.
Held by production. An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property.
Horizontal drilling or well. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption.
Hydraulic fracturing. The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to prop the channel open, so that fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as fracture stimulation.
Lateral length. Length of the drilled or completed portion of a horizontal well.
Liquids. Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane, pentane and natural gasoline resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility.
MBbl. One thousand barrels of crude oil, other liquid hydrocarbons or produced water.
MBOE. One thousand BOE.
Mcf. One thousand cubic feet of natural gas.
MMBtu. One million British thermal units.
MMcf. One million cubic feet of natural gas.
NGL. Natural gas liquids.
Net acres or net wells. The sum of the fractional working interest owned in gross acres or wells.
Net revenue interest. The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well.
NYMEX. New York Mercantile Exchange.
Organization of Petroleum Exporting Countries or OPEC. An intergovernmental group of 13 of the world’s major oil-exporting countries, which was founded in 1960 to coordinate the petroleum policies of its members and to provide member countries with technical and economic aid.
OPEC+. A loose affiliation of the member countries of OPEC and 10 of the world’s other major oil-exporting countries, including Russia.
Overriding royalty interest. A fractional interest in the gross production of oil and natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest.
Pad. The surface constructed to accommodate the drilling, completion and production operations of an oil or natural gas well.
Pad drilling. The process by which multiple horizontal wells are drilled from a single pad. In pad drilling, each well on the pad is drilled to total depth before the next well is initiated.
Permeability. A reference to the ability of oil and/or natural gas to flow through a reservoir.

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Petrophysical analysis. The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties.
Play. A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type.
Possible reserves. Additional reserves that are less certain to be recovered than probable reserves.
Probable reserves. Additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
Producing well, or productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes.
Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining such wells and related equipment and facilities.
Properties. Natural gas and oil wells, production and related equipment and facilities and oil, natural gas, or other mineral fee, leasehold and related interests.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons.
Prospectivity. Having the potential for the discovery and/or future development of commercial hydrocarbons in a specific geographic area or formation.
Proved area. The part of a property to which proved reserves have been specifically attributed.
Proved developed non-producing. Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved developed but non-producing reserves.
Proved developed reserves. Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.
Proved properties. Properties with proved reserves.
Proved reserves. The quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Reasonable certainty. A high degree of confidence that the quantities of oil and/or natural gas will be recovered.
Recompletion. Completing in the same wellbore to reach a new reservoir after production from the original reservoir has been abandoned.
Repeatability. The potential ability to drill multiple wells within a prospect or trend.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Reserves. Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.
Royalty interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

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2-D seismic. The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflection seismic data collected along a single source profile.
3-D seismic. The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production.
Service well. A well drilled or completed for the purpose of supporting production in an existing field.
Simul-Frac (Simultaneous Fracturing). Simul-Frac is a hydraulic fracturing technique in which two wells are fractured simultaneously using one hydraulic fracturing fleet. This differs from traditional zipper-frac where only one well is hydraulically stimulated.
Spud. The act of beginning to drill an oil or natural gas well.
Stratigraphic test well. A drilling effort, geologically directed, to obtain information pertaining to specific geologic condition.
Tcf. One trillion cubic feet of natural gas.
Throughput. The volume of product transported or passing through a pipeline, plant or other facility.
Trend. A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations.
Trimul-Frac (Triple Simultaneous Fracturing). Trimul-Frac is an advanced hydraulic fracturing technique where three wells are fractured simultaneously using one hydraulic fracturing fleet. While similar to Simul-Frac in terms of treating multiple wells simultaneously, Trimul-Frac stimulates three wells versus two.
Unconventional resource play. A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells.
Unproved and unevaluated properties. Properties where no drilling or other actions have been undertaken that permit such properties to be classified as proved and to which no proved reserves have been assigned.
Vertical well. A hole drilled vertically into the earth from which oil, natural gas or water flows or is pumped.
Visualization. An exploration technique in which the size and shape of subsurface features are mapped and analyzed based upon information derived from well logs, seismic data and other well information.
Volumetric reserves analysis. A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation, formation volume factor and recovery factor.
WTI. West Texas Intermediate.
Wellbore. The hole made by a well.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

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Matador Resources Company and Subsidiaries
CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2024, 2023 and 2022
Index
 
F-2
Consolidated Financial Statements
Consolidated Balance Sheets as of December 31, 2024 and 2023
F-5
Consolidated Statements of Income for the Years Ended December 31, 2024, 2023 and 2022
F-6
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2024, 2023 and 2022
F-7
Consolidated Statements of Cash Flows for the Years Ended December 31, 2024, 2023 and 2022
F-8
F-9
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Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
Matador Resources Company:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Matador Resources Company and subsidiaries (the Company) as of December 31, 2024 and 2023, the related consolidated statements of income, changes in shareholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2024, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2024, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2025 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Impact of estimated proved oil and natural gas reserves related to evaluated oil and natural gas properties on depletion expense and the ceiling test calculation

As discussed in Note 2 to the consolidated financial statements, the Company uses the full-cost method of accounting for its investments in oil and natural gas properties and amortizes capitalized costs of oil and natural gas properties using the unit-of-production method based on production and estimates of proved reserves quantities. The Company is required to perform a ceiling test calculation on a quarterly basis and the applicable ceiling is equal to the sum of (1) 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 (2) unproved and unevaluated property costs not being amortized, plus (3) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (4) any income tax effects related to the properties involved. Any excess of the Company’s net capitalized costs above the cost center ceiling is charged to operations as a full-cost ceiling impairment. Estimates of economically recoverable oil and natural gas reserves depend upon a number of factors and assumptions, including quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the operating costs incurred, the amount of future development expenditures, and the price received for the production.

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For the year ended December 31, 2024, the Company recorded depletion expense of evaluated oil and natural gas properties of $925.6 million. Additionally, as discussed in Note 3 to the consolidated financial statements, the Company’s consolidated balance sheet includes $12.5 billion of gross evaluated oil and natural gas properties as of December 31, 2024. The Company’s internal reservoir engineers prepare an estimate of the proved oil and natural gas reserves, and the Company engages external reservoir engineers to independently evaluate the proved oil and natural gas reserves estimated by the Company.

We identified the assessment of the impact of estimated proved oil and natural gas reserves related to evaluated oil and natural gas properties on both depletion expense and the ceiling test calculation as a critical audit matter. There is a high degree of subjectivity in evaluating the estimate of proved oil and natural gas reserves as auditor judgment was required to evaluate the assumptions used by the Company related to future production volumes, development costs, operating costs, and forecasted oil and natural gas prices inclusive of price differentials.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s depletion and ceiling test processes. This included controls related to the development of the assumptions listed above used to estimate proved reserves used in the respective calculations. We evaluated (1) the professional qualifications of the Company’s internal reservoir engineers as well as the external reservoir engineers and external engineering firm, (2) the knowledge, skill, and ability of the Company’s internal and external reservoir engineers, and (3) the relationship of the external reservoir engineers and external engineering firm to the Company. We assessed the methodology used by the Company to estimate the reserves for consistency with industry and regulatory standards. We also compared the pricing assumptions, including price differentials, used in the reservoir engineers’ estimate of the proved reserves to publicly available oil and natural gas pricing data. We evaluated assumptions used in the reservoir engineers’ estimate regarding future operating and development costs based on historical actual results. In addition, we compared the Company’s historical production forecasts to actual production volumes to assess the Company’s ability to accurately forecast and compared the forecasted production assumption used by the Company in the current period to historical production. We read the findings of the Company’s external reservoir engineers in connection with our evaluation of the Company’s reserves estimates. We recalculated the depletion expense calculation and analyzed it for compliance with industry and regulatory standards. We also analyzed the ceiling test impairment calculation for compliance with industry and regulatory standards. In addition, we performed an independent calculation of the ceiling test impairment calculation and compared our results with the Company’s results.

Fair value measurement of evaluated oil and natural gas properties acquired in the Ameredev business combination

As discussed in Note 2 and Note 6 to the consolidated financial statements, on September 18, 2024, the Company completed the acquisition of Ameredev Stateline II, LLC. As a result of the transaction, the Company acquired evaluated oil and natural gas properties with an acquisition-date fair value of $1.83 billion. The acquisition was accounted for under the acquisition method of accounting. Under the acquisition method of accounting, the purchase price is allocated to the assets acquired and liabilities assumed at their estimated fair values as of the acquisition date, with any excess purchase price allocated to goodwill. The fair value of evaluated oil and natural gas properties were measured using the discounted cash flow method. Significant inputs to the valuation of evaluated oil and natural gas properties included estimates of future production volumes and future commodity prices. The Company’s internal reservoir engineers estimated evaluated future production volumes and the Company engages a third-party reservoir engineering firm to perform an independent assessment.

We identified the evaluation of the fair value measurement of the evaluated oil and natural gas properties acquired in the Ameredev business combination as a critical audit matter. Subjective auditor judgment was required to evaluate future production volumes and future commodity prices used to estimate the fair value of such properties as changes to these assumptions could have had a significant impact on the determination of the fair value. Additionally, the audit effort associated with evaluating the future commodity prices required specialized skills and knowledge.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s acquisition-date valuation process, including controls over the determination of the assumptions, as listed above, used to measure the initial fair value of the acquired evaluated oil and natural gas properties. We evaluated (1) the professional qualifications of the Company’s internal and external reservoir engineers and the external engineering firm, (2) the knowledge, skills, and ability of the Company’s internal and external reservoir engineers, and (3) the relationship of the external reservoir engineers and external engineering firm to the Company. We assessed compliance of the methodology used by the Company’s internal and external reservoir engineers to estimate future production volumes with industry and regulatory standards. We compared the historical production volumes of Ameredev used to estimate future production volumes to production volumes reported to third parties. We also compared the estimated future evaluated production

F-3
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volumes used by the Company to historical Ameredev production volumes and to the future production assumptions made on the Company’s comparable assets. We tested the relevant basis differentials that were applied to the future commodity price assumptions by comparing to historical realized basis differentials from both Ameredev and the Company. In addition, we involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the future commodity price assumptions by comparing to an independently developed range of forward price estimates from analysts and other industry sources.
/s/ KPMG LLP

We have served as the Company’s auditor since 2014.

Dallas, Texas
February 25, 2025


F-4
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Matador Resources Company and Subsidiaries
CONSOLIDATED BALANCE SHEETS
(In thousands, except par value and share data)

 December 31,
 20242023
ASSETS
Current assets
Cash$ $ 
Restricted cash  
Accounts receivable
Oil and natural gas revenues  
Joint interest billings  
Other  
Derivative instruments  
Lease and well equipment inventory  
Prepaid expenses and other current assets  
Total current assets  
Property and equipment, at cost
Oil and natural gas properties, full-cost method
Evaluated  
Unproved and unevaluated  
Midstream properties  
Other property and equipment  
Less accumulated depletion, depreciation and amortization()()
Net property and equipment  
Other assets
Derivative instruments  
Other long-term assets   
Total other assets  
Total assets$ $ 
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable$ $ 
Accrued liabilities  
Royalties payable  
Amounts due to affiliates  
Advances from joint interest owners  
Other current liabilities  
Total current liabilities  
Long-term liabilities
Borrowings under Credit Agreement  
Borrowings under San Mateo Credit Facility  
Senior unsecured notes payable  
Asset retirement obligations  
Deferred income taxes  
Other long-term liabilities  
Total long-term liabilities  
Commitments and contingencies (Note 14)
Shareholders’ equity
Common stock — $ par value, shares authorized; and shares issued; and and shares outstanding, respectively
  
Additional paid-in capital  
Retained earnings  
Treasury stock, at cost, and shares, respectively
()()
Total Matador Resources Company shareholders’ equity  
Non-controlling interest in subsidiaries  
Total shareholders’ equity  
Total liabilities and shareholders’ equity$ $ 
The accompanying notes are an integral part of these consolidated financial statements.

F-5
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Matador Resources Company and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share data) 
) ) ) )   )) )   )
 Year Ended December 31,
 202420232022
Revenues
Oil and natural gas revenues$ $ $ 
Third-party midstream services revenues   
Sales of purchased natural gas   
Realized gain (loss) on derivatives ()()
Unrealized gain (loss) on derivatives () 
Total revenues   
Expenses
Production taxes, transportation and processing   
Lease operating   
Plant and other midstream services operating   
Purchased natural gas   
Depletion, depreciation and amortization   
Accretion of asset retirement obligations   
General and administrative   
Total expenses   
Operating income   
Other income (expense)
Net loss on asset sales and impairment ()()
Interest expense()()()
Amount
— — — ()— ()
— — —  —  
— — — — ()()
— — —  —  
— — —  —  
— — — —   
— — —  — — 
— — —  —  
— — — —   
— — — — ()()
 $  $()$ $ $ 



The accompanying notes are an integral part of these consolidated financial statements.

F-7
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Matador Resources Company and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
 Year Ended December 31,
 202420232022
Operating activities
Net income $ $ $ 
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Unrealized (gain) loss on derivatives() ()
Depletion, depreciation and amortization   
Accretion of asset retirement obligations   
Stock-based compensation expense   
Deferred income tax provision   
Amortization of debt issuance cost and other debt related costs  ()
Other non-cash changes()() 
Changes in operating assets and liabilities
Accounts receivable, prepaid expenses and other current assets() ()
Lease and well equipment inventory()()()
Other long-term assets   
Accounts payable, accrued liabilities and other current liabilities   
Royalties payable   
Advances from joint interest owners () 
Other long-term liabilities ()()
Net cash provided by operating activities   
Investing activities
Drilling, completion and equipping capital expenditures()()()
Acquisition of Advance () 
Acquisition of Ameredev()  
Acquisition of oil and natural gas properties()()()
Midstream capital expenditures()()()
Acquisition of midstream assets  ()
Expenditures for other property and equipment()()()
Proceeds from sale of assets and other   
Proceeds from sale of equity method investment   
Net cash used in investing activities()()()
Financing activities
Repayments of borrowings under Credit Agreement()()()
Borrowings under Credit Agreement   
Repayments of borrowings under San Mateo Credit Facility()()()
Borrowings under San Mateo Credit Facility   
Cost to enter into or amend credit facilities()()()
Proceeds from issuance of senior unsecured notes   
Issuance costs of senior unsecured notes()() 
Proceeds from issuance of common stock   
Purchase of senior unsecured notes() ()
Dividends paid()()()
Contribution related to Pronto Transaction   
Contributions related to formation of San Mateo   
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries   
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries()()()
Taxes paid related to net share settlement of stock-based compensation()()()
Other()()()
Net cash provided by (used in) financing activities  ()
(Decrease) increase in cash and restricted cash()() 
Cash and restricted cash at beginning of period   
Cash and restricted cash at end of period$ $ $ 
Supplemental disclosures of cash flow information (Note 15)
The accompanying notes are an integral part of these consolidated financial statements.

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Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2024, 2023 and 2022

NOTE 1 —
NOTE 2 —
to days of the production

F-9
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Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued
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 days or more. No interest is typically charged on past due amounts.
The Company has allowance for doubtful accounts related to its accounts receivable for any reporting period presented.
For the year ended December 31, 2024, significant purchasers accounted for % of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. (%), Exxon Mobil Corporation (%) and Enterprise Products Partners L.P. (%). For the year ended December 31, 2023, significant purchasers accounted for % of the Company’s total oil, natural gas and NGL revenues: Plains Marketing, L.P. (%), Exxon Mobil Corporation (%), and Enterprise Products Partners L.P. (%). For the year ended December 31, 2022, significant purchasers accounted for % of the Company’s total oil, natural gas and NGL revenues: Exxon Mobil Corporation (%), Plains Marketing, L.P. (%) and BP America Production Company (%). 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 %, % and %, respectively, of the Company’s accounts receivable, including joint interest billings, related to the top three purchasers.
million, $ million and $ million of its general and administrative costs into oil and natural gas properties in 2024, 2023 and 2022, respectively. The Company capitalized $ million, $ million and $ 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 $ million, $ million and $ 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:

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Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued
%, 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 -month period, and a % 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 $ per Bbl and $ per MMBtu, respectively. For the period from January through December 2023, these average oil and natural gas prices were $ per Bbl and $ per MMBtu, respectively. For the period from January through December 2022, these average oil and natural gas prices were $ per Bbl and $ 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 -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 years) using the straight-line method. The Company capitalized $ million, $ million and $ million of general and administrative costs into midstream properties in 2024, 2023 and 2022, respectively. The Company capitalized $ million and $ million of interest expense into midstream properties for the years ended December 31, 2024 and 2023, respectively. The Company did t 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.

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Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued
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)

F-12
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued
 $ $ Realized gain (loss) on derivatives ()()Unrealized gain (loss) on derivatives () Total revenues$ $ $ 

Year Ended December 31,
202420232022
Oil revenues$ $ $ 
Natural gas revenues   
Third-party midstream services revenues   
Sales of purchased natural gas   
Total revenues from contracts with customers$ $ $ 

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.

F-13
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued
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 $ million, $ million and $ million, respectively. This equity-based compensation expense includes common stock issuances and restricted stock units expense totaling $ million, $ million and $ 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.
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.

F-14
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued
 $ $ Weighted average common shares outstanding — denominatorBasic   Dilutive effect of options and restricted stock units   Diluted weighted average common shares outstanding   Earnings per common share attributable to Matador Resources Company shareholdersBasic $ $ $ Diluted $ $ $ 
 

F-15
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued
.
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 —
 $ Unproved and unevaluated (not subject to amortization)  Total oil and natural gas properties  Accumulated depletion()()Net oil and natural gas properties  Midstream propertiesMidstream equipment and facilities  Accumulated depreciation()()Net midstream properties  Other property and equipmentFurniture, fixtures and other equipment  Software  Leasehold improvements  Total other property and equipment  Accumulated depreciation()()Net other property and equipment  Net property and equipment$ $ 

F-16
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 3 — PROPERTY AND EQUIPMENT — Continued
 $ $ $ $ $ Exploration wells      Development wells                 $ 
_____________________
(1)     Does not include gross payments related to drilling rig leases of $ million and $ 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 $ million and $ 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.

F-18
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 4 — LEASES — Continued
 $ Other current liabilities$()$()Other long-term liabilities()()Total operating lease liabilities$()$()Financing leasesOther property and equipment, at cost$ $ Accumulated depreciation()()Net property and equipment$ $ Other current liabilities$()$()Other long-term liabilities()()Total financing lease liabilities$()$()

 $ Investing cash payments for operating leases$ $ Financing cash payments for financing leases$ $ Right of use assets obtained in exchange for lease obligations entered into during the periodOperating leases$ $ Financing leases$ $ Financing leases

F-19
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 4 — LEASES — Continued
 Oil and natural gas propertiesEvaluated Unproved and unevaluated Midstream assets Equity method investment Current liabilities()Asset retirement obligations()Net assets acquired$ 
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 $ million and $ 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.

F-22
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued
 $ Net income attributable to Matador Resources Company shareholders$ $ Earnings per share:Basic$ $ Diluted$ $ Cash consideration given$ Allocation of purchase priceCurrent assets$ Oil and natural gas propertiesEvaluatedUnproved and unevaluatedAsset retirement obligations()Net assets acquired$ 
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.

F-23
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued
 billion (which amount was subject to certain customary post-closing adjustments) (the “Cash Consideration”) and (ii) potential additional cash consideration of $ million for each month of 2023 in which the average oil price (as defined in the securities purchase agreement) exceeded $ 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 made 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 $ million, as the average oil price for the months of September and October 2023 exceeded $ 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 $ 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 $ 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 $ 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 % 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.

F-24
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 6 — BUSINESS COMBINATIONS AND DIVESTITURES — Continued
Working capital adjustments()Fair value of Contingent Consideration at April 12, 2023
Total consideration given
$
Allocation of purchase price
Current assets$
Oil and natural gas properties
Evaluated
Unproved and unevaluated
Midstream assets
Current liabilities()
Asset retirement obligations
()
Net assets acquired
$
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 $ million and $ 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 $ 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 $ million from the sale of Piñon in the first half of 2025.

F-25
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 7 — DEBT

 $ San Mateo Credit Facility due 2029  Senior unsecured notes:
% senior notes due 2026
  
% senior notes due 2028
  
% senior notes due 2032
  
% senior notes due 2033
  Issuance costs and discounts, net()()Total senior unsecured notes payable  Total long-term debt$ $ 

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 % 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 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 % 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 $ billion, (ii) increase the elected borrowing commitments from $ billion to $ billion, (iii) increase the maximum facility amount from $ billion to $ 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 $ 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 $ billion to $ billion. On September 25, 2024, the Company completed the sale of $ 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 $ million in outstanding borrowings under the term loan.

F-26
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 7 — DEBT — Continued
billion to $ billion. The Company chose to maintain the elected borrowing commitments at $ 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 of .
Total deferred loan costs were $ 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 $ million in borrowings outstanding under the Credit Agreement and approximately $ million in outstanding letters of credit issued pursuant to the Credit Agreement. The Company’s effective interest rate under the Credit Agreement was % at December 31, 2024.
The applicable interest rate margin for borrowings under the Credit Agreement ranges from % to % for borrowings bearing interest with reference to the Adjusted Term SOFR Rate (as defined in the Credit Agreement) and from % to % 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 % for all interest periods. The interest period for Adjusted Term SOFR Rate borrowings may be one, three or 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 % to %, 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 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 $ million or % of the elected borrowing commitments of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 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;

F-27
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 7 — DEBT — Continued
 million to $ million and (iii) add 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 $ 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 $ 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 % at December 31, 2024. At December 31, 2024, San Mateo had $ million in borrowings outstanding under the San Mateo Credit Facility and $ 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 %, and (iii) the Adjusted Term SOFR Rate (as defined in the San Mateo Credit Facility) for a one month tenor plus %, plus, in each case, an amount ranging from % to % 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 % to % 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 % to %, 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 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 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 or San Mateo’s liquidity is less than % 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;

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Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 7 — DEBT — Continued
 million of the $ 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 $ 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 $ million included in interest expense for the year ended December 31, 2024.
2028 Notes
At December 31, 2024, the Company had $ million in aggregate principal amount of senior unsecured notes due 2028 (the “2028 Notes”), which have a % 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 % in aggregate principal amount of 2028 Notes at a redemption price of % 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 days of completing such equity offering and at least % 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 % of their principal amount plus an applicable make-whole premium and accrued and unpaid interest, if any, to the applicable redemption date.
%2026%2027 and thereafter%


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Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 7 — DEBT — Continued
% 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 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 days after notice to comply with its reporting obligations under the 2028 Notes Indenture;
•failure by the Company for days after notice to comply with any of the other agreements in the 2028 Notes Indenture;
•payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principal amount of $ million or more;
•failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $ million within days;
•any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and
•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 $ million in aggregate principal amount of senior unsecured notes due 2032 (the “2032 Notes”), which have a % 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 % in aggregate principal amount of 2032 Notes at a redemption price of % 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 days of completing such equity offering and at least % 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 % of their principal amount plus an applicable make-whole premium and accrued and unpaid interest, if any, to the applicable redemption date.

F-30
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 7 — DEBT — Continued
%2028%2029 and thereafter%

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:
•incur additional indebtedness;
•sell assets;
•pay dividends or make certain investments;
•create liens that secure indebtedness;
•enter into transactions with affiliates; and
•merge or consolidate with another company.
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 % 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 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 days after notice to comply with its reporting obligations under the 2032 Notes Indenture;
•failure by the Company for days after notice to comply with any of the other agreements in the 2032 Notes Indenture;
•payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principal amount of $ million or more;
•failure by the Company or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $ million within days;
•any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and
•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.





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Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 7 — DEBT — Continued
 million in aggregate principal amount of the 2033 Notes, which have a % 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 % in aggregate principal amount of 2033 Notes at a redemption price of % 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 days of completing such equity offering and at least % 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 % of their principal amount plus an applicable make-whole premium and accrued and unpaid interest, if any, to the applicable redemption date.
%2029%2030 and thereafter%
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:
•incur additional indebtedness;
•sell assets;
•pay dividends or make certain investments;
•create liens that secure indebtedness;
•enter into transactions with affiliates; and
•merge or consolidate with another company.
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 % 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 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 days after notice to comply with its reporting obligations under the 2033 Notes Indenture;
•failure by the Company for days after notice to comply with any of the other agreements in the 2033 Notes Indenture;
•payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries in the aggregate principal amount of $ million or more;

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Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 7 — DEBT — Continued
 million within days;
•any subsidiary guarantee by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker; and
•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 —
 $ Compensation  Research and experimental tax credits, net of reserve  Lease liabilities  Interest expense carryforward  Other  Total deferred tax assets  Valuation allowance on deferred tax assets()()Total deferred tax assets, net of valuation allowance  Deferred tax liabilitiesProperty and equipment()()Less than wholly-owned subsidiaries()()Lease right of use assets()()Unrealized gain on derivatives()()Other()()Total deferred tax liabilities()()Net deferred tax liabilities$()$() $ $ State income tax   Net current income tax provision$ $ $ Deferred income tax provisionFederal income tax$ $ $ State income tax   Net deferred income tax provision$ $ $ 

F-33
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 8 — INCOME TAXES — Continued
 $ $ State income tax expense    Permanent differences() ()Non-controlling interest in subsidiaries()()()Research and experimental tax credits () Change in reserve on uncertain tax positions()  Change in state valuation allowance()  Total income tax provision$ $ $ 
__________________    
(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 $ million and $ 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 were UTBs as of December 31, 2022. As of December 31, 2024 and 2023, $ million and $ 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.
 $ $ Additions for tax positions of current period   Adjustment for tax positions of prior periods()  
Balance at end of period(1)
$ $ $ 
__________________    
(1)At December 31, 2024, the UTBs related to the U.S. federal and state of Texas jurisdictions were $ million and $ million, respectively. At December 31, 2023, the UTBs related to the U.S. federal and state of Texas jurisdictions were $ million and $ million, respectively.
NOTE 9 —
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 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 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

F-34
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 9 — STOCK-BASED COMPENSATION — Continued
 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 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 a to period. Performance-based restricted stock units granted in 2024 and 2023 vest in an amount between and % of the target units granted based on the Company’s relative total shareholder return over the periods ending December 31, 2026 and 2025, respectively, as compared to a designated peer group, and will be settled in equity.
Equity-Based
  $  $  $ )$  $  $ ()$  $  $ 
__________________    
(1)On January 8, 2025 upon certification by the Board, of the performance-based awards that were granted in 2022 vested. The vested units earned % for each vested award representing aggregate shares of common stock, which were issued on January 8, 2025.

F-35
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 9 — STOCK-BASED COMPENSATION — Continued
During the years ended December 31, 2024, 2023 and 2022, the Company settled , and liability-based awards, respectively, for $ million, $ million and $ million in cash, respectively.
At December 31, 2024, the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $ million, of which $ 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 $ million, of which $ 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 years.
The fair value of restricted stock and restricted stock units vested during 2024, 2023 and 2022 was $ million, $ million and $ 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 $ million, $ million and $ million, respectively. During the years ended December 31, 2024, 2023 and 2022, the Company capitalized $ million, $ million and $ million, respectively, related to stock-based compensation and expensed the remaining $ million, $ million and $ million, respectively.
The total tax benefit recognized for all stock-based compensation was $ million, $ million and $ million for the years ended December 31, 2024, 2023 and 2022, respectively.
NOTE 10 —
% 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 $ million, $ million and $ 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 $ million, $ million and $ million in 2024, 2023 and 2022, respectively. The Company made additional contributions in any reporting period presented.
NOTE 11 —
shares of its common stock. After deducting underwriting discounts and offering expenses, the Company received net proceeds of approximately $ 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.

F-36
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 11 — EQUITY— Continued

per share of common stock in each of the first, second and third quarters of 2024. The first quarter dividend, which totaled $ million, was paid on March 13, 2024 to shareholders of record as of February 23, 2024. The second quarter dividend, which totaled $ million, was paid on June 7, 2024 to shareholders of record as of May 17, 2024. The third quarter dividend, which totaled $ 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 $ per share of common stock for future dividend payments and also declared a quarterly cash dividend of $ per share of common stock. The fourth quarter dividend, which totaled $ million, was paid on December 6, 2024 to shareholders of record as of November 15, 2024.
The Board declared a quarterly cash dividend of $ per share of common stock in each of the first three quarters of 2023 and the Board declared a quarterly cash dividend of $ per share of common stock in the fourth quarter of 2023.
Total cash dividends declared and paid totaled $ million and $ 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 $ per share of common stock for future dividend payments and declared a quarterly cash dividend of $ 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 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 $ million, $ million and $ million, respectively, to the Company and $ million, $ million and $ 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 $ million and $ million, respectively, and Five Point contributed $ million and $ 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 $ million, of which $ 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 $ 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.

F-37
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 11 — EQUITY— Continued

 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 a 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 $ million in performance incentives. Five Point paid the Company $ 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 $ 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 $ million of these performance incentives.
In connection with the Pronto Transaction, the Company has the potential to earn up to $ million in additional incentive payments from Five Point over a period, of which $ 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 $ million and $ million, respectively, in performance incentives. These performance incentives are recorded when received, net of the $ million and $ 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 —
 $ $ Total open costless collar contracts$ 


F-38
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 12 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued
 $() Total open basis differential swap contracts$ 
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.
 $()$ Current liabilities()  Total$ $ $ December 31, 2023Current assets$ $()$ Other assets () Total$ $()$ 

 $ $()Natural GasRevenues: Realized gain (loss) on derivatives ()()Realized gain (loss) on derivatives ()()OilRevenues: Unrealized gain on derivatives   Natural GasRevenues: Unrealized gain (loss) on derivatives () Unrealized gain (loss) on derivatives () Total$ $()$()


F-39
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 13 —
 $ $ $ Natural gas basis differential swaps    Total$ $ $ $ 
Fair Value Measurements at
December 31, 2023 using
Description
Level 1Level 2Level 3Total
Assets (Liabilities)
Natural gas basis differential swaps$ $ $ $ 
Total$ $ $ $ 
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 $ million and $ 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 $ million based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.

F-40
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 13 — FAIR VALUE MEASUREMENTS — Continued
million based on quoted market prices, which represent Level 1 inputs in the fair value hierarchy.
impairment to its lease and well equipment inventory or other property and equipment in 2024 and 2023.
NOTE 14 —
million and $ 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 $ 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 -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 -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 $ 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 $ 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 $ 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 $ million for the construction and installation of the Marlan Processing Plant expansion with a designed inlet processing capacity of 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

F-41
Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 14 — COMMITMENTS AND CONTINGENCIES — Continued
NOTE 15 — SUPPLEMENTAL DISCLOSURES
 $ Accrued midstream properties costs  Accrued lease operating expenses  Accrued interest on debt  Accrued asset retirement obligations  Accrued partners’ share of joint interest charges  Accrued payable related to purchased natural gas  Other  Total accrued liabilities$ $ 
Supplemental Cash Flow Information
 $ $ Cash paid for interest expense, net of amounts capitalized$ $ $ Increase in asset retirement obligations related to mineral properties$ $ $ Increase in asset retirement obligations related to midstream properties$ $ $ Increase (decrease) in liabilities for drilling, completion and equipping capital expenditures$ $ $()Increase (decrease) in liabilities for acquisition of oil and natural gas properties$ $ $()(Decrease) increase in liabilities for midstream capital expenditures$()$ $ Stock-based compensation expense recognized as liability$ $ $ Transfer of inventory (to) from oil and natural gas properties$()$ $ 
_____________________
(1)Represents tax payments of $ million, $ million and $ 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).
 Year Ended December 31,
 202420232022
Cash$ $ $ 
Restricted cash   
Total cash and restricted cash$ $ $ 


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Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 16 —


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.
 $ $ $ $ Midstream services revenues   () Sales of purchased natural gas     Realized gain on derivatives     Unrealized gain on derivatives     
Operating expense(1)
   () 
Other expenses(2)
   () 
Operating income(3)
$ $ $()$ $ 
Total assets(4)
$ $ $ $ $ 
Capital expenditures(5)
$ $ $ $ $ _____________________
(1)Operating expense includes lease operating expense for the exploration and production segment and plant and other midstream operating expense for the midstream segment.
(2)Includes depletion, depreciation and amortization expenses of $ million and $ million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 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 $ million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.
(4)Excludes intercompany receivables and investments in subsidiaries.
(5)Includes $ billion attributable to land and seismic acquisition expenditures related to the exploration and production segment, $ million in midstream acquisition expenditures and $ million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

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Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 16 — SEGMENT INFORMATION — Continued
 $ $ $ $ Midstream services revenues   () Sales of purchased natural gas     Realized loss on derivatives()   ()Unrealized loss on derivatives()   ()
Operating expense(1)
   () 
Other expenses(2)
   () 
Operating income(3)
$ $ $()$ $ 
Total assets(4)
$ $ $ $ $ 
Capital expenditures(5)
$ $ $ $ $ _____________________
(1)Operating expense includes lease operating expense for the exploration and production segment and plant and other midstream operating expense for the midstream segment.
(2)Includes depletion, depreciation and amortization expenses of $ million and $ million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 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 $ million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.
(4)Excludes intercompany receivables and investments in subsidiaries.
(5)Includes $ billion attributable to land and seismic acquisition expenditures related to the exploration and production segment, $ million in midstream acquisition expenditures and $ million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.

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Table of Contents
Matador Resources Company and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2024, 2023 and 2022
NOTE 16 — SEGMENT INFORMATION — Continued
 $ $ $ $ Midstream services revenues   () Sales of purchased natural gas     Realized loss on derivatives()   ()Unrealized gain on derivatives     
Operating expense(1)
   () 
Other expenses(2)
   () 
Operating income(3)
$ $ $()$ $ 
Total assets(4)
$ $ $ $ $ 
Capital expenditures(5)
$ $ $ $ $ 
_____________________
(1)Operating expense includes lease operating expense for the exploration and production segment and plant and other midstream operating expense for the midstream segment.
(2)Includes depletion, depreciation and amortization expenses of $ million and $ million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $ 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 $ million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment.
(4)Excludes intercompany receivables and investments in subsidiaries.
(5)Includes $ million attributable to land and seismic acquisition expenditures related to the exploration and production segment, $ million in midstream acquisition expenditures and $ million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment.


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Table of Contents
Matador Resources Company and Subsidiaries
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2024, 2023 and 2022
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES

Costs Incurred
The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2024, 2023 and 2022 (in thousands).
 Year Ended December 31,
 202420232022
Property acquisition costs
Proved$1,488,033 $1,478,258 $36,985 
Unproved and unevaluated575,046 328,579 97,127 
Exploration costs71,381 230,712 136,209 
Development costs1,287,221 966,338 643,947 
Total costs incurred(1)
$3,421,681 $3,003,887 $914,268 
__________________
(1)Excludes midstream-related development and corporate costs of approximately $510.0 million, $258.0 million and $159.8 million for the years ended December 31, 2024, 2023 and 2022, respectively.
Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the year ended December 31, 2024, a majority of the Company’s property acquisition costs resulted from the Ameredev Acquisition. For the year ended December 31, 2023, a majority of the Company’s property acquisition costs resulted from the Advance Acquisition.
Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. For the year ended December 31, 2024, the Company capitalized $11.3 million of geological and geophysical costs, which are included as exploration costs in the table above. The Company did not capitalize any geological and geophysical costs in 2023 or 2022.
Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, completing and equipping development wells and acquiring, constructing and installing production facilities.
Costs incurred also include newly established asset retirement obligations, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were an increase of $25.1 million, an increase of $33.8 million and an increase of $10.7 million for the years ended December 31, 2024, 2023 and 2022, respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $66.6 million, $54.2 million and $47.8 million of these internal costs for the years ended December 31, 2024, 2023 and 2022, respectively, excluding midstream-related capitalized general and administrative expenses. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $17.5 million, $20.2 million and $10.1 million of its interest expense for the years ended December 31, 2024, 2023 and 2022, respectively, excluding midstream-related capitalized interest expense.
Oil and Natural Gas Reserves
Proved reserves are the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including assumptions related to oil and natural gas prices, drilling, completion and operating expenses, capital expenditures, taxes and

F-46
Table of Contents
Matador Resources Company and Subsidiaries
UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED
December 31, 2024, 2023 and 2022
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued
availability of funds. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates.
The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas and the Eagle Ford shale in South Texas, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where
the NGLs are extracted and sold. The Company’s oil and natural gas reserves estimates for the years ended December 31, 2024, 2023 and 2022 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period. 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.

F-47
Table of Contents
Matador Resources Company and Subsidiaries
UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED
December 31, 2024, 2023 and 2022
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued
The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas.
 Net Proved Reserves
 OilNatural GasOil
Equivalent
(MBbl)(MMcf)(MBOE)
Total at December 31, 2021
181,306 852,547 323,397 
Revisions of prior estimates(6,953)(4,324)(7,673)
Net acquisitions (divestitures) of minerals-in-place1,239 (1,332)1,017 
Extensions and discoveries42,640 215,011 78,476 
Production(21,943)(99,308)(38,495)
Total at December 31, 2022
196,289 962,594 356,722 
Revisions of prior estimates(31,184)(88,779)(45,981)
Net acquisitions of minerals-in-place78,550 183,311 109,102 
Extensions and discoveries56,164 193,054 88,339 
Production(27,542)(123,420)(48,112)
Total at December 31, 2023
272,277 1,126,760 460,070 
Revisions of prior estimates(11,264)32,640 (5,824)
Net acquisitions of minerals-in-place73,347 279,170 119,875 
Extensions and discoveries64,012 215,389 99,910 
Production(36,530)(155,790)(62,495)
Total at December 31, 2024
361,842 1,498,169 611,536 
Proved Developed Reserves
December 31, 2021102,233 546,173 193,262 
December 31, 2022116,030 632,858 221,507 
December 31, 2023161,642 782,733 292,097 
December 31, 2024206,269 963,170 366,797 
Proved Undeveloped Reserves
December 31, 202179,073 306,374 130,135 
December 31, 202280,259 329,736 135,215 
December 31, 2023110,635 344,026 167,973 
December 31, 2024155,573 534,999 244,740 
The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2024, 2023 and 2022.
The Company’s proved oil and natural gas reserves increased 33% from 460.1 million BOE at December 31, 2023 to 611.5 million BOE at December 31, 2024. The Company’s proved oil and natural gas reserves increased by 214.0 million BOE and the Company produced 62.5 million BOE during the year ended December 31, 2024, resulting in a net increase of 151.5 million BOE. This increase in proved oil and natural gas reserves was primarily attributable to the Ameredev Acquisition and the Company’s delineation and development operations in the Delaware Basin during 2024. The Company increased its total proved oil and natural gas reserves by 119.9 million BOE as a result of acquisitions and trades during 2024. The Company also added 99.9 million BOE in proved reserves through extensions and discoveries during 2024, of which 28.4 million BOE resulted from new well locations turned to sales during 2024 to establish proved developed reserves and 71.5 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on the Company’s existing acreage in the Delaware Basin during 2024. These increases were partially offset by net downward revisions of prior estimates

F-48
Table of Contents
Matador Resources Company and Subsidiaries
UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED
December 31, 2024, 2023 and 2022
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued
for proved oil and natural gas reserves, which primarily included the removal of 8.2 million BOE resulting from the 4% decrease in oil prices and the 19% decrease in natural gas prices used to estimate total proved reserves at December 31, 2024, as compared to December 31, 2023, and 15.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of the Company’s properties in the Delaware Basin. As the Company continues to develop its Delaware Basin assets, the Company may reclassify some or all of this 15.3 million BOE to proved reserves at a future date. These downward revisions at December 31, 2024 were partially offset by positive forecast updates of 21.7 million BOE.
The Company’s proved developed oil and natural gas reserves increased 26% from 292.1 million BOE at December 31, 2023 to 366.8 million BOE at December 31, 2024. The Company’s proved developed oil and natural gas reserves increased by 137.2 million BOE and the Company produced 62.5 million BOE during the year ended December 31, 2024, resulting in a net increase of 74.7 million BOE. The Company added 28.4 million BOE in proved developed reserves through extensions and discoveries during 2024, which resulted from new well locations drilled during 2024 to establish proved reserves. In addition, during 2024 the Company converted 54.6 million BOE of its proved undeveloped reserves to proved developed reserves primarily through its development activities in the Delaware Basin. The Company also increased its proved developed reserves by 59.3 million BOE at December 31, 2024 as a result of property acquisitions, including the Ameredev Acquisition, and trades completed during 2024. Additionally, the Company realized approximately 5.1 million BOE in net downward revisions of prior estimates in 2024, most of which was attributable to the lower commodity prices used to estimate proved reserves at December 31, 2024, which resulted in shorter estimated economic lives for certain of its producing properties.
The Company’s proved undeveloped oil and natural gas reserves increased 46% from 168.0 million BOE at December 31, 2023 to 244.7 million at December 31, 2024. The Company added 71.5 million BOE in proved undeveloped reserves through extensions and discoveries during 2024, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on the Company’s existing acreage in the Delaware Basin during 2024. In addition, the Company increased its proved undeveloped reserves by 60.6 million BOE at December 31, 2024 as a result of property acquisitions, including the Ameredev Acquisition, and trades completed during 2024. These increases were partially offset by net downward revisions of prior estimates of proved undeveloped reserves, including the removal of 15.3 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of the properties in the Delaware Basin and the removal of 2.1 million BOE for certain expense and pricing updates. These downward revisions were largely offset by positive forecast updates of 16.3 million BOE.
At December 31, 2024, the Company’s proved reserves were comprised of 59% oil and 41% natural gas and were approximately 60% proved developed and 40% proved undeveloped. The decrease in the Company’s proved developed reserves as a percentage of its total proved reserves at December 31, 2024, as compared to 63% and 62% proved developed reserves at December 31, 2023 and 2022, respectively, was primarily a result of extensions and discoveries of new proved undeveloped locations identified as a result of drilling activities on the Company’s existing acreage in the Delaware Basin and the Ameredev Acquisition.
The Company’s proved oil and natural gas reserves increased 29% from 356.7 million BOE at December 31, 2022 to 460.1 million BOE at December 31, 2023. The Company’s proved oil and natural gas reserves increased by 151.5 million BOE and the Company produced 48.1 million BOE during the year ended December 31, 2023, resulting in a net increase of 103.3 million BOE. This increase in proved oil and natural gas reserves was primarily attributable to the Advance Acquisition and the Company’s delineation and development operations in the Delaware Basin during 2023. The Company increased its total proved oil and natural gas reserves by 109.1 million BOE as a result of acquisitions and trades during 2023. The Company also added 88.3 million BOE in proved reserves through extensions and discoveries during 2023, of which 27.6 million BOE resulted from new well locations drilled during 2023 to establish proved developed reserves and 60.7 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on the Company’s existing acreage in the Delaware Basin during 2023. These increases were partially offset by the removal of 17.4 million BOE resulting from the 17% decrease in oil prices and the 58% decrease in natural gas prices used to estimate total proved reserves at December 31, 2023, as compared to December 31, 2022, and the removal of 31.5 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of the Company’s properties in the Delaware Basin.
The Company’s proved oil and natural gas reserves increased 10% from 323.4 million BOE at December 31, 2021 to 356.7 million BOE at December 31, 2022. The Company’s proved oil and natural gas reserves increased by 71.8 million BOE and the Company produced 38.5 million BOE during the year ended December 31, 2022, resulting in a net increase of 33.3

F-49
Table of Contents
Matador Resources Company and Subsidiaries
UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED
December 31, 2024, 2023 and 2022
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued
million BOE. The Company added 78.5 million BOE in proved reserves through extensions and discoveries during 2022, of which 24.7 million BOE resulted from new well locations drilled during 2022 to establish proved developed reserves and 53.8 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on the Company’s existing acreage in the Delaware Basin during 2022. The Company realized approximately 7.7 million BOE in net downward revisions of prior estimates in 2022, due primarily to proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking as a result of changes in development plans for certain of the properties in the Delaware Basin at December 31, 2022.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates.
As noted previously, for the period from January through December 2024, the unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices were $71.96 per Bbl and $2.13 per MMBtu, respectively. For the period from January through December 2023, the comparable 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, the comparable average oil and natural gas prices were $90.15 per Bbl and $6.36 per MMBtu, respectively.
Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and gathering costs, gravity and energy content and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production, development and plugging and abandonment costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations.
Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows.
The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2024, 2023 and 2022 (in thousands).
 Year Ended December 31,
 202420232022
Future cash inflows$29,033,021 $23,662,653 $24,952,118 
Future production costs(10,284,800)(7,717,106)(6,752,752)
Future development costs(2,705,340)(2,162,625)(1,776,029)
Future income tax expense(3,326,489)(2,939,514)(3,935,271)
Future net cash flows12,716,392 10,843,408 12,488,066 
10% annual discount for estimated timing of cash flows(5,339,842)(4,729,916)(5,504,863)
Standardized measure of discounted future net cash flows$7,376,550 $6,113,492 $6,983,203 

F-50
Table of Contents
Matador Resources Company and Subsidiaries
UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED
December 31, 2024, 2023 and 2022
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued
The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2024, 2023 and 2022 (in thousands).
 Year Ended December 31,
 202420232022
Balance, beginning of period$6,113,492 $6,983,203 $4,375,425 
Net change in sales and transfer prices and in production (lifting) costs related to future production(915,645)(3,074,085)4,046,504 
Changes in estimated future development costs(706,728)(504,323)(744,687)
Sales and transfers of oil and natural gas produced during the period(2,496,524)(2,037,451)(2,466,440)
Net purchases of reserves in place2,310,776 2,113,620 28,841 
Net change due to extensions and discoveries1,925,926 1,711,389 2,017,170 
Net change due to revisions in estimates of reserves quantities(102,776)(890,794)(8,576)
Previously estimated development costs incurred during the period685,163 441,671 434,336 
Accretion of discount770,407 807,896 475,474 
Other15,190 3,913 1,982 
Net change in income taxes(222,731)558,453 (1,176,826)
Standardized measure of discounted future net cash flows$7,376,550 $6,113,492 $6,983,203 

F-51

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