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What changed in Matador Resources Co's 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of Matador Resources Co's 2023 and 2024 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2024 report.

+741 added−768 removedSource: 10-K (2025-02-25) vs 10-K (2024-02-27)

Top changes in Matador Resources Co's 2024 10-K

741 paragraphs added · 768 removed · 627 edited across 7 sections

Item 1. Business

Business — how the company describes what it does

239 edited+46 added−37 removed219 unchanged
Biggest changeIn this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company, (iii) references to “Advance” refer to Advance Energy Partners Holdings, LLC, (iv) references to the “Initial Advance Acquisition” refer to the acquisition of Advance from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties, undeveloped acreage and midstream assets located primarily in Lea County, New Mexico and Ward County, Texas, that was completed by a subsidiary of the Company on April 12, 2023, (v) references to the “Advance Royalty Acquisition” refer to the acquisition of 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, (vi) references to the “Advance Acquisition” refer, collectively, to the Initial Advance Acquisition and the Advance Royalty Acquisition, (vii) references to “San Mateo” refer to San Mateo Midstream, LLC, collectively with its subsidiaries, (viii) references to “Pronto” refer to Pronto Midstream, LLC, together with its subsidiary, and (ix) references to the “Pronto Acquisition” refer to the acquisition of Pronto by a subsidiary of the Company on June 30, 2022.
Biggest changeIn this Annual Report, (i) references to “we,” “our” or the “Company” refer to Matador Resources Company and its subsidiaries as a whole (unless the context indicates otherwise), (ii) references to “Matador” refer solely to Matador Resources Company, (iii) references to “Ameredev” refer to Ameredev Stateline II, LLC, (iv) references to “Piñon” refer to Piñon Midstream, LLC, (v) references to the “Ameredev Acquisition” refer to the acquisition of Ameredev from affiliates of EnCap Investments L.P., including (a) certain oil and natural gas producing properties and undeveloped acreage located in Lea County, New Mexico and Loving and Winkler Counties, Texas, and (b) an approximate 19% stake in the parent company of Piñon, which was completed by a subsidiary of the Company on September 18, 2024, (vi) references to “Advance” refer to Advance Energy Partners Holdings, LLC, (vii) references to the “Advance Acquisition” refer to the acquisition of Advance from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties, undeveloped acreage and midstream assets located primarily in Lea County, New Mexico and Ward County, Texas, that was completed by a subsidiary of the Company on April 12, 2023, and the acquisition of 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 on December 1, 2023, (viii) references to “San Mateo” refer to San Mateo Midstream, LLC, collectively with its subsidiaries (including, as of December 18, 2024, Pronto), and (ix) references to “Pronto” refer to Pronto Midstream, LLC, together with its subsidiary.
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.
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.
Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases.
Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect in most cases until the cessation of production in commercial quantities.
Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of emissions, venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process, the seismicity that may be related to salt water disposal wells and the plugging and abandonment of wells.
Many states also have laws, rules and regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing and setbacks, the surface use and restoration of properties upon which wells are drilled, the prohibition, restriction or limitation of emissions, venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process, the seismicity that may be related to salt water disposal wells and the plugging and abandonment of wells.
Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable to pass on such increased compliance costs to our customers.
Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly permitting, emissions control, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial condition. We may be unable or unwilling to pass on such increased compliance costs to our customers.
We plan to achieve our goal by, among other items, executing the following business strategies: • focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; • identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; • continue to improve operational and cost efficiencies; • identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo and Pronto; • maintain our financial discipline; • return capital to shareholders through our dividend policy; • pursue opportunistic acquisitions, divestitures and joint ventures; and • provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the oil and natural gas industry’s best practices.
We plan to achieve our goal by, among other items, executing the following business strategies: • focus our exploration and development activities primarily on unconventional plays, including the Wolfcamp and Bone Spring plays in the Delaware Basin; • identify, evaluate and develop additional oil and natural gas plays as necessary to maintain a balanced portfolio of oil and natural gas properties; • continue to improve operational and cost efficiencies; • identify and develop midstream opportunities that support and enhance our exploration and development activities and that generate value for San Mateo and Matador; • maintain our financial discipline; • return capital to shareholders through our dividend policy; • pursue opportunistic acquisitions, divestitures and joint ventures; and • provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the oil and natural gas industry’s best practices.
Proactive Safety Culture We are proud to have a company culture that emphasizes safety throughout our operations. Our Health, Safety and Environmental (“HSE”) group and of the experienced field and office staff involved in our drilling, completion, production and midstream operations proactively work to minimize safety risks and address any potential areas of concern.
Proactive Safety Culture We are proud to have a company culture that emphasizes safety throughout our operations. Our Health, Safety and Environmental (“HSE”) group and our experienced field and office staff involved in our drilling, completion, production and midstream operations proactively work to minimize safety risks and address any potential areas of concern.
The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s, Pronto’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas.
The prices we receive are calculated based on various pipeline indices. When there is an opportunity to do so, we may have our natural gas processed at San Mateo’s or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas.
We have focused our Delaware Basin operations on the following asset areas: the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico, the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico and the West Texas asset area in Loving and Ward Counties, Texas.
We have focused our Delaware Basin operations on the following asset areas: the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico, the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico and the West Texas asset area in Loving, Ward and Winkler Counties, Texas.
While we rely upon the judgment of oil and natural gas lease brokers and/or landmen in ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well.
While we rely upon the judgment of oil and natural gas lease brokers and landmen in ascertaining title for certain leasehold and mineral interest acquisitions, we typically obtain detailed title opinions prior to drilling an oil and natural gas well.
See “Risk Factors—Risks Related to Laws and Regulations—Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” Pipeline Regulation Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation.
See “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” Pipeline Regulation Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation.
The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement.
The potential adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities and our midstream operations, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement.
Undeveloped Acreage Expiration The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2023 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 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.
This total includes acreage that we are producing from or that we believe to be prospective for these formations. We are active both as an operator and as a non-operating, co-working interest owner with various industry participants. At December 31, 2023, we operated a significant majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas.
This total includes acreage that we are producing from or that we believe to be prospective for these formations. We are active both as an operator and as a non-operating, co-working interest owner with various industry participants. At December 31, 2024, we operated a significant majority of our acreage in the Delaware Basin in Southeast New Mexico and West Texas.
At December 31, 2023, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, two benches of the Avalon, two benches of the First Bone Spring, the Second Bone Spring Carbonate, three benches of the Second Bone Spring Sand, three benches of the Third Bone Spring Carbonate, two benches of the Third Bone Spring Sand, four benches of the Wolfcamp A, including the X, Y and Z sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Strawn and the Morrow.
At December 31, 2024, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, two benches of the Avalon, two benches of the First Bone Spring, the Second Bone Spring Carbonate, three benches of the Second Bone Spring Sand, three benches of the Third Bone Spring Carbonate, two benches of the Third Bone Spring Sand, four benches of the Wolfcamp A, including the X, Y and Z sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Strawn and the Morrow.
(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. 14 Table of Contents The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2021 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.
(5) Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes. 14 Table of Contents 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.
See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.” 23 Table of Contents Competition The oil and natural gas industry is highly competitive.
See “Risk Factors—Risks Related to our Operations—Because our reserves and production are concentrated in a few core areas, problems with production in and markets for a particular area could have a material impact on our business.” 24 Table of Contents Competition The oil and natural gas industry is highly competitive.
Water Management Using improving technologies, we are able to take produced water from our existing wells and from third-party systems, treat the water and then reuse that water in our completions operations on new wells. Use of recycled water saves significant amounts of fresh water that would otherwise have been used for hydraulic fracturing operations.
Water Management Using improving technologies, where feasible, we are able to take produced water from our existing wells and from third-party systems, treat the water and then reuse that water in our completions operations on new wells. Use of recycled water saves significant amounts of fresh water that would otherwise have been used for hydraulic fracturing operations.
Exploration and Production Segment Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana.
Exploration and Production Segment Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana.
We operate approximately 8% of the 11,600 gross (4,700 net) acres that we consider to be in the core area of the Haynesville shale play. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2023.
We operate approximately 8% of the 11,600 gross (4,700 net) acres that we consider to be in the core area of the Haynesville shale play. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2024.
We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of the leases.
We also have options to extend some of our leases through additional lease bonus payments prior to the expiration of the primary term of such lease.
(“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and • Produced Water Assets : 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 175 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.
(“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and • Produced Water Assets : 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 180 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.
At December 31, 2023, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2023 within five years of booking these reserves.
At December 31, 2024, we had no proved undeveloped reserves in our estimates that remained undeveloped for five years or more following their initial booking, and we currently have plans to use anticipated capital resources to develop the proved undeveloped reserves remaining as of December 31, 2024 within five years of booking these reserves.
Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana.
Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana.
At December 31, 2023, San Mateo had (i) a crude oil gathering and transportation system in the Greater Stebbins Area that was connected to the existing interconnect in the Rustler Breaks asset area totaling approximately 80 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline asset area.
At December 31, 2024, San Mateo had (i) a crude oil gathering and transportation system in the Greater Stebbins Area that was connected to the existing interconnect in the Rustler Breaks asset area totaling approximately 80 miles of various diameter crude oil pipelines and (ii) a crude oil gathering system in the Stateline 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 2023.
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.
These locations have been identified for potential future drilling and were not producing at December 31, 2023. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations.
These locations have been identified for potential future drilling and were not producing at December 31, 2024. The total net engineered drilling locations are calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations.
At December 31, 2023, approximately 3% of our proved oil and natural gas reserves would be impacted by the expirations of this undeveloped acreage. Drilling Results The following table summarizes our drilling activity for the years ended December 31, 2023, 2022 and 2021 .
At December 31, 2024, approximately 3% of our proved oil and natural gas reserves would be impacted by the expirations of this undeveloped acreage. Drilling Results The following table summarizes our drilling activity for the years ended December 31, 2024, 2023 and 2022 .
Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2024.
Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2025.
At December 31, 2023, we held approximately 18,500 gross (17,300 net) acres in Northwest Louisiana, including 16,200 gross (8,900 net) acres in the Haynesville shale play and 15,700 gross (14,800 net) acres in the Cotton Valley play.
At December 31, 2024, we held approximately 18,500 gross (17,300 net) acres in Northwest Louisiana, including 16,200 gross (8,900 net) acres in the Haynesville shale play and 15,700 gross (14,800 net) acres in the Cotton Valley play.
That effort is designed to infuse climate policy in all aspects of federal decision-making, including specific directives that touch on foreign policy, national security, financial regulation, federal procurement, infrastructure, and environmental justice among other things.
That effort was designed to infuse climate policy in all aspects of federal decision-making, including specific directives that touch on foreign policy, national security, financial regulation, federal procurement, infrastructure, and environmental justice among other things.
San Mateo achieved strong operating results in 2023, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes.
San Mateo achieved strong operating results in 2024, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes.
Our PV-10 at December 31, 2023, 2022 and 2021 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure.
Our PV-10 at December 31, 2024, 2023 and 2022 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure.
At December 31, 2023, San Mateo had approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles).
At December 31, 2024, San Mateo had approximately 43 miles of large diameter natural gas gathering pipelines between the Black River Processing Plant and the Stateline asset area (approximately 24 miles) and the Greater Stebbins Area (approximately 19 miles).
The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. 34 Table of Contents
The contents of our website are not intended to be incorporated by reference into this Annual Report or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. 35 Table of Contents
See “Risk Factors—Risks Related to our Financial Condition—A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” For the years ended December 31, 2023, 2022 and 2021, we had three significant purchasers that accounted for approximately 76%, 70% and 72%, respectively, of our total oil, natural gas and NGL revenues.
See “Risk Factors—Risks Related to our Financial Condition—A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” For the years ended December 31, 2024, 2023 and 2022, we had three significant purchasers that accounted for approximately 79%, 76% and 70%, respectively, of our total oil, natural gas and NGL revenues.
The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum 27 Table of Contents distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder.
The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder.
Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations.
Our activities are subject to a variety of environmental laws and regulations, including: the Oil Pollution Act of 1990 (the “OPA 90”), the Clean Water Act (the “CWA”), the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), the Clean Air Act (the “CAA”) and the Occupational Safety and Health Act (“OSHA”), as well as comparable state statutes and regulations.
Our engineered well locations, at December 31, 2023, do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location.
Our engineered well locations, at December 31, 2024, do not yet include all portions of our acreage position. Our identified well locations presume that multiple intervals may be prospective at any one surface location.
In addition to the financial benefits to us and our stakeholders of connecting oil, natural gas and produced water to pipelines, these pipeline connections have many other benefits, including the reduction in the number of trucks needed to transport the oil and produced water.
In addition to the financial benefits to us and our stakeholders of connecting oil and produced water to pipelines, these pipeline connections have many other benefits, including the reduction in the number of trucks needed to transport the oil and produced water.
See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to 29 Table of Contents administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” Environmental, Health and Safety Regulation The exploration, development, production, gathering and processing of oil and natural gas are subject to various federal, state and local environmental laws and regulations.
See “Risk Factors—Risks Related to Laws and Regulations—Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” Environmental, Health and Safety Regulation The exploration, development, production, gathering and processing of oil and natural gas are subject to various federal, state and local environmental laws and regulations.
This increased production was primarily attributable 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.
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.
San Mateo and Pronto compete with other midstream companies that provide similar services in their areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. Many of our competitors have substantially greater financial resources, staffs, facilities and other resources.
San Mateo competes with other midstream companies that provide similar services in their areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. Many of our competitors have substantially greater financial resources, staffs, facilities and other resources.
See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.” Office Location Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. Human Capital At December 31, 2023, we had 395 full-time employees. We believe that our relationships with our employees are satisfactory.
See “Risk Factors—Risks Related to our Operations—Insurance against all operational risks is not available to us.” Office Location Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. Human Capital At December 31, 2024, we had 452 full-time employees. We believe that our relationships with our employees are satisfactory.
The following table sets forth, since 2020, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands).
The following table sets forth, since 2021, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands).
The Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System is subject to PHMSA oversight.
The Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) imposes pipeline safety requirements on regulated pipelines and gathering lines pursuant to its authority under the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, each as amended. The Rustler Breaks Oil Pipeline System and the Trophy Pipeline System are subject to PHMSA oversight.
Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 84% in all wells that we operated at December 31, 2023. For wells where we are not the operator, our working interests range from less than 1% to approximately 52% and average approximately 10%.
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 fact, as of December 31, 2023, we had not completed any new operated wells in the Eagle Ford shale since the second quarter of 2019.
In fact, as of December 31, 2024, we had not completed any new operated wells in the Eagle Ford shale since the second quarter of 2019.
The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System.
The Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System and the Trophy Pipeline System.
The scientific community and regulatory agencies at all levels are studying the possible linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity.
The scientific community and regulatory agencies at all levels are studying the possible 30 Table of Contents linkage between oil and natural gas activity and induced seismicity, and some state regulatory agencies have modified their regulations or guidance to mitigate potential causes of induced seismicity.
Our HSE group’s experience allows us to understand the technical issues faced by our field employees and contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential safety issues and mitigation efforts. 33 Table of Contents Available Information Our Internet website address is www.matadorresources.com .
Our HSE group’s experience allows us to understand the technical issues faced by our field employees and contractors, as well as maintain an open dialogue with community leaders in the areas we operate about potential safety issues and mitigation efforts. Available Information Our Internet website address is www.matadorresources.com .
Acreage Summary The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2023.
Acreage Summary The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2024.
NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions 25 Table of Contents having the potential to significantly impact the environment.
NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions 26 Table of Contents having the potential to significantly impact the environment.
The Safe Drinking Water Act (the “SDWA”) establishes a regulatory framework for underground injection, the primary objective of which is to ensure 28 Table of Contents the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water.
The Safe Drinking Water Act (the “SDWA”) establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water.
Southeast New Mexico/West Texas South Texas Northwest 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 production 96.1 % 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. 13 Table of Contents (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.
Southeast New Mexico/West Texas South Texas Northwest 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 production 96.1 % 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.
Additionally, we realized approximately 14.1 million BOE in net downward revisions of prior estimates, most of which were attributable to the lower commodity prices used to estimate proved reserves at December 31, 2023, which resulted in shorter estimated economic lives for certain of our producing properties.
Additionally, we realized approximately 5.1 million BOE in net downward revisions of prior estimates in 2024, most of which were 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 our producing properties.
Factors that, directly or indirectly, cause price fluctuations include, but are not limited to: the domestic and foreign supply of, and demand for, oil, natural gas and NGLs; the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”) and state-controlled oil companies; the prices and availability of competitors’ supplies of oil and natural gas; the price and quantity of foreign imports; the impact of U.S. dollar exchange rates; domestic and foreign governmental regulations and taxes; speculative trading of oil and natural gas futures contracts; the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; the availability of refining capacity; the prices and availability of alternative fuel sources; weather conditions and natural disasters, including hurricanes and tropical storms in the Gulf Coast region and severe cold weather in the Delaware Basin; political conditions or conflicts in or affecting oil and natural gas producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; the ongoing military conflicts between Russia and Ukraine and Israel and Hamas, as well as the related actions of U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps; domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases such as COVID-19 and its variants; the continued threat of terrorism and the impact of military action and civil unrest; public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil and natural gas operations, including hydraulic fracturing activities; the level of global oil and natural gas inventories and exploration and 22 Table of Contents production activity; the impact of energy conservation efforts; technological advances affecting energy consumption; and overall worldwide economic conditions.
Factors that, directly or indirectly, cause price fluctuations include: the domestic and foreign supply of, and demand for, oil, natural gas and NGLs; the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”) and state-controlled oil companies; the prices and availability of competitors’ supplies of oil and natural gas; the price and quantity of foreign imports; the impact of U.S. dollar exchange rates; domestic and foreign governmental regulations and taxes; speculative trading of oil and natural gas futures contracts; the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; the availability of refining capacity; the prices and availability of alternative fuel and energy sources; weather conditions and natural disasters, including hurricanes and tropical storms in the Gulf Coast region and severe cold weather in the Delaware Basin; political conditions or conflicts in or affecting oil and natural gas producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; the ongoing military conflicts between Russia and Ukraine and in the Middle East, as well as the related actions of U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps; domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases; the threat of terrorism and the impact of military action and civil unrest; public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil and natural gas operations, including hydraulic fracturing activities; the level of global oil and natural gas inventories and exploration and production activity; the impact of energy conservation efforts; technological advances affecting energy consumption; tariffs and trade restrictions; and overall worldwide economic 23 Table of Contents conditions.
Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr.
Foran, Chairman and Chief Executive Officer. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr.
The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with FERC and posted publicly.
The ICA also requires tariffs that set forth the rates an interstate crude oil pipeline company charges for providing transportation services on its FERC-jurisdictional pipelines, as well as the rules and regulations governing these services, to be maintained on file with 28 Table of Contents FERC and posted publicly.
(6) Includes the Cotton Valley formation and shallower zones. (7) Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana.
(7) Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana.
Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States.
Such changes include (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States.
The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2023, was gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area.
The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2024, was also gathering and processing natural gas from the Stateline asset area and from the Greater Stebbins Area.
In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026.
In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, prohibit flaring in certain circumstances and require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026.
While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated 32 Table of Contents properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability.
While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability.
Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources.
Persons who are responsible for releases of 31 Table of Contents hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources.
Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030 and cooperating toward the advancement of the development of alternative sources of energy.
Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which included a range of measures designed to address climate change, including the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030 and cooperating toward the advancement of the development of alternative sources of energy.
Our PV-10 at December 31, 2023 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, 2023 were approximately $1.59 billion.
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.
In addition, we completed several important financing transactions in 2023 that increased our operational flexibility, while preserving the strength of our balance sheet and improving our liquidity position.
In addition, we completed several financing transactions in 2024 that increased our operational flexibility, while preserving the strength of our balance sheet and improving our liquidity position.
At December 31, 2023, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems.
At December 31, 2024, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems.
Our Eagle Ford total proved reserves comprised approximately 1% of our proved oil reserves and less than 1% of our proved natural gas reserves at December 31, 2023, essentially unchanged from December 31, 2022.
Our Eagle Ford total proved reserves comprised less than 1% of our proved oil reserves and less than 1% of our proved natural gas reserves at December 31, 2024, essentially unchanged from December 31, 2023.
Fish and Wildlife Service (the “USFWS”) and the Center of Excellence for Hazardous Materials Management to observe operational restrictions designed to protect certain wildlife, including the habitats of the lesser prairie-chicken, sand dune lizard and Texas hornshell mussel.
Fish and Wildlife Service (the “USFWS”) and the Center of Excellence for Hazardous Materials Management to observe operational restrictions designed to protect certain wildlife, including the habitats of the lesser prairie-chicken, dunes sagebrush lizard and Texas hornshell mussel.
The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2023.
The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2024.
The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, 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.
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.
In addition, at December 31, 2023, San Mateo had an NGL pipeline connection at the Black River Processing Plant to the NGL pipelines owned by EPIC Y-Grade Pipeline LP and Enterprise Products Partners LP. These NGL connections provide several significant benefits to us and other San Mateo customers compared to transporting NGLs by truck.
In addition, at December 31, 2024, San Mateo had NGL pipeline connections at the Black River Processing Plant to the NGL pipelines owned by EPIC Y-Grade Pipeline LP and Enterprise Products Partners L.P. These NGL connections provide several significant benefits to us and other San Mateo customers compared to transporting NGLs by truck.
At December 31, 2023, San Mateo was gathering or transporting almost all our operated natural gas 11 Table of Contents production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf portion of our West Texas asset area.
At December 31, 2024, San Mateo was gathering or transporting almost all our operated natural gas production via pipeline in the Stateline asset area, the Greater Stebbins Area, the Rustler Breaks asset area and the Wolf portion of our West Texas asset area.
In addition, we achieved several key capital resources objectives during the year, including generating free cash flow, paying down some of the borrowings that funded the Advance Acquisition, increasing our quarterly cash dividend and earning performance incentives from Five Point Energy, LLC (“Five Point”), our joint venture partner in San Mateo.
In addition, we achieved several key capital resources objectives during the year, including generating free cash flow, paying down a portion of the borrowings that funded the Advance Acquisition and Ameredev Acquisition, increasing our quarterly cash dividend and earning performance incentives from Five Point Energy, LLC or its affiliates (“Five Point”), our joint venture partner in San Mateo.
Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2023, although we did participate in the drilling and completion of 22 gross (0.4 net) non-operated Haynesville shale wells that were turned to sales in 2023.
Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2024, although we did participate in the drilling and completion of eight gross (0.1 net) non-operated Haynesville shale wells that were turned to sales in 2024.
Undeveloped acreage expiring in 2029 and beyond totals 2,600 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, 2023.
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.
Based on this Executive Order and other findings, the EPA has begun adopting and implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA.
Based on this Executive Order and other findings, the EPA began implementing a comprehensive suite of regulations to restrict emissions of greenhouse gases under existing provisions of the CAA.
In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells.
In response to these concerns, regulators in some states, including New Mexico and Texas, have imposed additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeOur cash flows from operations and access to capital are subject to a number of variables, including: • our estimated proved oil and natural gas reserves; • the amount of oil and natural gas we produce; • the prices at which we sell our production; • the costs of developing and producing our oil and natural gas reserves; • the costs of constructing, operating and maintaining our midstream facilities; • our ability to attract third-party customers for our midstream services; • our ability to acquire, locate and produce new reserves; • the ability and willingness of banks or other financial institutions to lend to us; and • our ability to access the equity and debt capital markets. 38 Table of Contents In addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, the outbreak or resurgence of contagious or pandemic diseases, financial market disruptions, failures of banks, general economic recessions, oil and natural gas industry recessions, oil and natural gas company bankruptcies, accounting scandals, overstated reserves estimates by public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and spending and earnings of public companies, including energy companies.
Biggest changeIn addition, the possible occurrence of future events, such as decreases in the prices of oil and natural gas, or extended periods of such decreased prices, terrorist attacks, wars or combat peace-keeping missions, the outbreak or resurgence of contagious or pandemic diseases, financial market disruptions, failures of banks, general economic recessions, oil and natural gas industry recessions, oil and natural gas company bankruptcies, accounting scandals, overstated reserves estimates by public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and spending and earnings of public companies, including energy companies.
Rather, in certain acquisitions we rely upon the judgment of oil and natural gas brokers and/or landmen who perform the field work by examining records in the appropriate governmental office before attempting to acquire a lease or mineral interest.
Rather, in certain acquisitions we rely upon the judgment of oil and natural gas brokers and landmen who perform the field work by examining records in the appropriate governmental office before attempting to acquire a lease or mineral interest.
A high level of indebtedness could affect our operations in several ways, including the following: • requiring a significant portion of our cash flows to be used for servicing our indebtedness; • increasing our vulnerability to general adverse economic and industry conditions; • placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing; • restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and • increasing the risk that we may default on our debt obligations.
A high level of indebtedness could affect our operations in several ways, including: • requiring a significant portion of our cash flows to be used for servicing our indebtedness; • increasing our vulnerability to general adverse economic and industry conditions; • placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing; • restricting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and • increasing the risk that we may default on our debt obligations.
If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) the Adjusted Term SOFR Rate (as defined in the San Mateo Credit Facility) for a one month tenor, plus 1.00% plus, in each case, an amount ranging from 1.25% to 2.25% depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility).
If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) the Adjusted Term SOFR Rate (as defined in the San Mateo Credit Facility) for a one month tenor, plus 1.00% plus, in each case, an amount ranging from 1.00% to 2.00% depending on San Mateo’s Consolidated Total Leverage Ratio (as defined in the San Mateo Credit Facility).
If San Mateo 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. Interest rates rose significantly during 2022 and remained elevated throughout 2023 as the Federal Reserve sought to control inflation.
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. Interest rates rose significantly during 2022 and remained elevated throughout 2023 and 2024 as the Federal Reserve sought to control inflation.
Furthermore, if we were unable to process such natural gas, we may be forced to flare natural gas from, or shut in, the affected wells for an indefinite period of time. In addition, San Mateo’s and Pronto’s gathering, processing and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties.
Furthermore, if we were unable to process such natural gas, we may be forced to flare natural gas from, or shut in, the affected wells for an indefinite period of time. In addition, San Mateo’s gathering, processing and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties.
If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport, process or dispose of product, or if the volumes San Mateo or Pronto gathers, processes or transports do not meet the product quality requirements of such pipelines or facilities, our and San Mateo’s revenues and cash flows could be adversely affected.
If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport, process or dispose of product, or if the volumes San Mateo gathers, processes or transports do not meet the product quality requirements of such pipelines or facilities, our and San Mateo’s revenues and cash flows could be adversely affected.
From time-to-time, we, through San Mateo, Pronto or otherwise, plan and construct midstream projects, some of which may take a number of months before commercial operation, such as construction of oil, natural gas and produced water gathering or transportation systems, construction of natural gas processing plants, drilling of commercial salt water disposal wells and construction of related facilities.
From time-to-time, we, through San Mateo or otherwise, plan and construct midstream projects, some of which may take a number of months before commercial operation, such as construction of oil, natural gas and produced water gathering or transportation systems, construction of natural gas processing plants, drilling of commercial salt water disposal wells and construction of related facilities.
Any such reductions may result in lower revenues and cash flows. In addition, FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received on the Rustler Breaks Oil Pipeline System and any other natural gas or crude oil pipeline that is determined to be under the jurisdiction of FERC.
Any such reductions may result in lower revenues and cash flows. In addition, FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received on the Rustler Breaks Oil Pipeline System, the Trophy Pipeline System and any other natural gas or crude oil pipeline that is determined to be under the jurisdiction of FERC.
San Mateo’s and Pronto’s midstream facilities are, or will be, connected to oil and natural gas wells operated by us or by third parties from which production will naturally decline over time, which means that the cash flows associated with these sources of oil, natural gas, NGLs and produced water will also decline over time.
San Mateo’s midstream facilities are, or will be, connected to oil and natural gas wells operated by us or by third parties from which production will naturally decline over time, which means that the cash flows associated with these sources of oil, natural gas, NGLs and produced water will also decline over time.
Because of our size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As and when we expand our activities, including our midstream business, through San Mateo, Pronto or otherwise, there will be additional demands on our financial, technical and management resources.
Because of our size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As and when we expand our activities, including our midstream business, through San Mateo or otherwise, there will be additional demands on our financial, technical and management resources.
Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters. From time to time, we may sell an interest in a strategic asset for the purpose of assisting or accelerating the asset’s development.
Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters. From time to time, we may sell a portion of an interest in a strategic asset for the purpose of assisting or accelerating the asset’s development.
Risks Related to Third Parties • Financial difficulties encountered by purchasers, operators or other third parties could decrease our cash flows from operations and adversely affect the exploration and development of our prospects and assets. • The marketability of our production is dependent upon gathering, processing and transportation facilities. • We conduct a portion of our operations through joint ventures, including San Mateo, which subjects us to certain risks. • San Mateo’s and Pronto’s long-term success depends on their ability to obtain new sources of products, which depends on certain factors beyond their control. • Certain of our long-term contracts require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput and may limit our ability to use other service providers. • We do not own all of the land on which our midstream assets are located, which could disrupt our operations. • Competition in our industry is intense, and our competitors may use superior technology and data resources. • Strategic relationships upon which we may rely are subject to change. • We have limited control over activities on properties we do not operate.
Risks Related to Third Parties • Financial difficulties encountered by purchasers, operators or other third parties could decrease our cash flows from operations and adversely affect the exploration and development of our prospects and assets. • The marketability of our production is dependent upon gathering, processing and transportation facilities. • We conduct a portion of our operations through joint ventures, including San Mateo, which subjects us to certain risks. • San Mateo’s long-term success depends on its ability to obtain new sources of products, which depends on certain factors beyond its control. • Certain of our long-term contracts require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput and may limit our ability to use other service providers. • We do not own all of the land on which our midstream assets are located, which could disrupt our operations. • Competition in our industry is intense, and our competitors may use superior technology and data resources. • Strategic relationships upon which we may rely are subject to change. • We have limited control over activities on properties we do not operate.
Risks Related to Third Parties Financial difficulties encountered by our oil, natural gas and NGL purchasers, third-party operators or other third parties could decrease our cash flows from operations and adversely affect the exploration and development of our prospects and assets.
Risks Related to Third Parties Financial difficulties encountered by our oil, natural gas and NGL purchasers, third-party operators, third-party customers or other third parties could decrease our cash flows from operations and adversely affect the exploration and development of our prospects and assets.
San Mateo’s and Pronto’s ability to obtain additional sources of oil, natural gas, NGLs and produced water depends, in part, on the level of successful drilling and production activity near its gathering and transportation systems and other midstream facilities.
San Mateo’s ability to obtain additional sources of oil, natural gas, NGLs and produced water depends, in part, on the level of successful drilling and production activity near its gathering and transportation systems and other midstream facilities.
Risks Relating to Our Common Stock • The price of our common stock has fluctuated substantially and may fluctuate substantially in the future. • Attention to ESG and conservation matters and a negative shift in market perception towards the oil and natural gas industry could adversely affect us. • Future sales and offerings of our common stock could depress the price of our common stock. • Our directors and executive officers own a significant percentage of our equity, which could give them influence in corporate transactions and other matters, and their interests could differ from other shareholders. • The issuance of preferred stock could diminish the rights of holders of our common stock.
Risks Related to Our Common Stock • The price of our common stock has fluctuated substantially and may fluctuate substantially in the future. • Attention to ESG and conservation matters and a negative shift in market perception towards the oil and natural gas industry could adversely affect us. • Future sales and offerings of our common stock could depress the price of our common stock. • Our directors and executive officers own a significant percentage of our equity, which could give them influence in corporate transactions and other matters, and their interests could differ from other shareholders. • The issuance of preferred stock could diminish the rights of holders of our common stock.
While we have entered into natural gas processing and transportation agreements covering the anticipated natural gas production from a significant portion of our Delaware Basin acreage in Southeast New Mexico and West Texas, no assurance can be given that these agreements will alleviate these issues completely, and we may be required to pay deficiency payments under such agreements if we do not meet the gathering or processing commitments, as applicable.
While we have entered into natural gas processing, treating, compression and transportation agreements covering the anticipated natural gas production from a significant portion of our Delaware Basin acreage in Southeast New Mexico and West Texas, no assurance can be given that these agreements will alleviate these issues completely, and we may be required to pay deficiency payments under such agreements if we do not meet the gathering or processing commitments, as applicable.
Similarly, our midstream business, and particularly the success of San Mateo and Pronto, depends in part on our ability to compete with other midstream service companies to attract third-party customers to our midstream facilities.
Similarly, our midstream business, and particularly the success of San Mateo, depends in part on our ability to compete with other midstream service companies to attract third-party customers to our midstream facilities.
Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a borrowing base that was less than our borrowings under the Credit Agreement, we 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 repay the deficit in equal installments over a period of six months.
Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a borrowing base that was less than our borrowings under the Credit Agreement, we could 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 repay the deficit in equal installments over a period of six months.
The potential adoption of federal, state and local legislation and regulations intended to address potential induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays.
The potential adoption of federal, state and local legislation and regulations intended to address potential induced seismicity in the areas in which we operate could restrict our drilling and production activities and our midstream operations, as well as our ability to dispose of produced water gathered from such activities, which could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays.
If our or our third-party providers’ systems for protecting against cyber incidents prove to be insufficient, we could be adversely affected by unauthorized access to proprietary information, which could lead to data corruption, communication interruption, exposure of our or third parties’ confidential or proprietary information, disruptions of our current or planned business operations or transactions, damage to our reputation or financial loss.
If our or our third-party providers’ systems for protecting against cyber incidents prove to be insufficient, we could be adversely affected by unauthorized access to proprietary or other sensitive information, which could lead to data corruption, communication interruption, exposure of our or third parties’ confidential or proprietary information, disruptions of our current or planned business operations or transactions, damage to our reputation or financial loss.
Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include: • our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates; • quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; • changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; • declaration of dividends or adjustments to our dividend policy; • speculation in the press or investment community; • announcement or consummation of acquisitions, dispositions or joint ventures by us; • public reaction to our operations or plans, press releases, announcements and filings with the SEC; • the publication of research or reports by industry analysts regarding the Company, its competitors or our industry; • the enactment of federal, state or local laws, rules or regulations that restrict our ability to conduct our operations, such as the Biden Administration Federal Lease Orders; 63 Table of Contents • sales of our common stock by the Company, directors, officers or other shareholders, or the perception that such sales may occur; • general financial market conditions and oil and natural gas industry market conditions, including fluctuations in the price of oil, natural gas and NGLs; • domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases, such as COVID-19 and its variants; • the realization of any of the risk factors presented in this Annual Report; • the recruitment or departure of key personnel; • commencement of, involvement in or unfavorable resolution of litigation; • the success of our exploration and development operations, our midstream business (including San Mateo) and the marketing of any oil, natural gas and NGLs we produce; • changes in market valuations of companies similar to ours; and • domestic and international economic, legal and regulatory factors unrelated to our performance.
Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include: • our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates; • quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; • changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; • declaration of dividends or adjustments to our dividend policy; 63 Table of Contents • speculation in the press or investment community; • announcement or consummation of acquisitions, dispositions or joint ventures by us; • public reaction to our operations or plans, press releases, announcements and filings with the SEC; • the publication of research or reports by industry analysts regarding the Company, its competitors or our industry; • the enactment of federal, state or local laws, rules or regulations that restrict our ability to conduct our operations; • sales of our common stock by the Company, directors, officers or other shareholders, or the perception that such sales may occur; • general financial market conditions and oil and natural gas industry market conditions, including fluctuations in the price of oil, natural gas and NGLs; • domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases; • the realization of any of the risk factors presented in this Annual Report; • the recruitment or departure of key personnel; • commencement of, involvement in or unfavorable resolution of litigation; • the success of our exploration and development operations, our midstream business (including San Mateo) and the marketing of any oil, natural gas and NGLs we produce; • changes in market valuations of companies similar to ours; and • domestic and international economic, legal and regulatory factors unrelated to our performance.
Our Credit Agreement, the San Mateo Credit Facility and the indentures governing our senior notes contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interest.
Our Credit Agreement, the San Mateo Credit Facility and the indentures governing our senior notes contain, and any future indebtedness we or San Mateo incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our and San Mateo’s ability to engage in acts that may be in our best long-term interest.
In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the U.S. federal level. Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies.
In addition, from time to time there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals at the U.S. federal level. Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies.
Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. At the federal level, various policy makers, regulatory agencies and political candidates, including President Biden, have also proposed restrictions on hydraulic fracturing, including its outright prohibition.
Should these or other limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. At the federal level, various policy makers, regulatory agencies and political candidates have also proposed restrictions on hydraulic fracturing, including its outright prohibition.
Risks Related to our Financial Condition • Our success is dependent on the prices of oil, natural gas and NGLs, the volatility of which may adversely affect our financial condition. • Our industry and the broader U.S. economy have experienced higher than expected inflationary pressures in recent years. • We cannot predict the impact of the ongoing military conflicts between Russia and Ukraine and Israel and Hamas. • Our business requires substantial capital expenditures that may exceed our cash flows from operations and potential borrowings. • Our oil and natural gas reserves are estimated, and significant inaccuracies in our oil and natural gas reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves. • The calculated present value of future net revenues from our proved oil and natural gas reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. • Approximately 39% of our total proved reserves at December 31, 2023 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced. • Unless we replace our oil and natural gas reserves, our reserves and production will decline. • We may be required to write down the carrying value of our proved properties under accounting rules. • Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses. • Changes in price differentials between benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect us. • Our failure to identify, complete or integrate future acquisitions successfully could reduce our earnings and hamper our growth. • We may purchase properties or midstream assets with liabilities or risks that we did not know about or assess correctly. • We may incur losses or costs as a result of title deficiencies in the properties in which we invest. • Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters.
Risks Related to our Financial Condition • Our success is dependent on the prices of oil, natural gas and NGLs, the volatility of which may adversely affect our financial condition. • Our industry and the broader U.S. economy have experienced higher than expected inflationary pressures in recent years. • We cannot predict the impact of the ongoing military conflicts between Russia and Ukraine and in the Middle East. • Our business requires substantial capital expenditures that may exceed our cash flows from operations and potential borrowings. • Our oil and natural gas reserves are estimated, and significant inaccuracies in our oil and natural gas reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves. • The calculated present value of future net revenues from our proved oil and natural gas reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. • Approximately 41% of our total proved reserves at December 31, 2024 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced. • Unless we replace our oil and natural gas reserves, our reserves and production will decline. • We may be required to write down the carrying value of our proved properties under accounting rules. • Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses. • Changes in price differentials between benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect us. • Our failure to identify, complete or integrate future acquisitions successfully could reduce our earnings and hamper our growth. • We may purchase properties or midstream assets with liabilities or risks that we did not know about or assess correctly. • We may incur losses or costs as a result of title deficiencies in the properties in which we invest. • Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters.
We cannot assure you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Any future downgrade could increase the cost of any indebtedness incurred in the future.
We cannot guarantee you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Any future downgrade could increase the cost of any indebtedness incurred in the future.
Should oil, natural gas or NGL prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities or cease or delay further expansion of our midstream projects, each of which could have a material adverse effect on our business, financial 37 Table of Contents condition, results of operations and reserves.
Should oil, natural gas or NGL prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities or cease or delay further expansion of our midstream projects, each of which could have a material adverse effect on our business, financial condition, results of operations and reserves.
If we borrow funds as a SOFR 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 1.75% to 2.75% depending on the level of borrowings under the Credit Agreement.
If we borrow funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate (as defined in the Credit Agreement) for the chosen interest period plus (y) an amount ranging from 1.75% to 2.75% depending on the level of borrowings under the Credit Agreement.
If San Mateo borrows funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate for the chosen interest period plus (y) an amount ranging from 2.25% to 3.25% depending on San Mateo’s Consolidated Total Leverage Ratio.
If San Mateo borrows funds as a SOFR loan, such borrowings will bear interest at a rate equal to (x) the Adjusted Term SOFR Rate for the chosen interest period plus (y) an amount ranging from 2.00% to 3.00% depending on San Mateo’s Consolidated Total Leverage Ratio.
We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems, processing facilities or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market.
We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems, treating, compression or processing facilities or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market.
Risks Related to Laws and Regulations Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.
Risks Related to Laws and Regulations Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.
Our federal and state income tax liabilities in 2024 and subsequent years will be dependent upon a variety of factors that will impact our taxable income, including oil and natural gas prices, allowable deductions and any legislative changes thereon, in addition to any tax credits generated that would offset tax liabilities in future periods.
Our federal and state income tax liabilities in 2025 and subsequent years will be dependent upon a variety of factors that will impact our taxable income, including oil and natural gas prices, allowable deductions and any legislative changes thereon, in addition to any tax credits generated that would offset tax liabilities in future periods.
The rates of our regulated assets are subject to review and reporting by federal regulators, which could adversely affect our revenues. The Rustler Breaks Oil Pipeline System transports crude oil in interstate commerce. FERC regulates the rates, terms and conditions of service on pipelines that transport crude oil in interstate commerce.
The rates of our regulated assets are subject to review and reporting by federal regulators, which could adversely affect our revenues. The Rustler Breaks Oil Pipeline System and the Trophy Pipeline System transport crude oil in interstate commerce. FERC regulates the rates, terms and conditions of service on pipelines that transport crude oil in interstate commerce.
Should we experience future periods of negative pricing for natural gas as we have experienced historically, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results.
Should we experience future periods of negative pricing for natural gas as we have experienced historically, including in 2024, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results.
Further, supply chain disruptions and other inflationary pressures being experienced throughout the United States and global economy may limit our ability to procure the necessary products and services for drilling and completing wells in a timely and cost effective manner, which could result in reduced margins and delays in our drilling and completion activities which, in turn, could adversely affect our business, financial condition, results of operations and cash flows.
Further, supply chain disruptions, tariffs and trade restrictions and other inflationary pressures being experienced throughout the United States and global economy may limit our ability to procure the necessary products and services for drilling and completing wells in a timely and cost effective manner, which could result in reduced margins and delays in our drilling and completion activities which, in turn, could adversely affect our business, financial condition, results of operations and cash flows.
As required by SEC rules and regulations, the estimated discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate.
As required by SEC rules and regulations, the estimated 40 Table of Contents discounted future net cash flows from proved oil and natural gas reserves are based on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate.
See “—Risks Related to our Financial Condition—A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner.
See “—Risks Related to our Financial Condition—A change in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition, results of operations and cash flows.” Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms, floods and inclement winter weather, resulting in delays in drilling and completions, damage to facilities and equipment and the 49 Table of Contents inability to receive equipment or access personnel and products at affected job sites in a timely manner.
We expect that substantially all of our capital expenditures in 2024 will continue to be in the Delaware Basin, with the exception of amounts allocated to limited operations and certain non-operated well opportunities in our South Texas and Haynesville shale positions.
We expect that substantially all of our capital expenditures in 2025 will continue to be in the Delaware Basin, with the exception of amounts allocated to limited operations and certain non-operated well opportunities in our South Texas and Haynesville shale positions.
Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could 50 Table of Contents increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, and all of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The process of estimating accumulations of oil and natural gas is complex and inexact due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary.
The process of estimating accumulations of oil and natural gas is complex and inexact due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of this technical data and the associated interpretations can vary.
These provisions include: 66 Table of Contents • authorization for our Board to issue preferred stock without shareholder approval; • a classified Board so that not all members of our Board are elected at one time; • the prohibition of cumulative voting in the election of directors; and • a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock.
These provisions include: • authorization for our Board to issue preferred stock without shareholder approval; • a classified Board so that not all members of our Board are elected at one time; • the prohibition of cumulative voting in the election of directors; and • a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock.
In addition, private parties, including the owners of properties upon which our wells are drilled or our facilities are located, the owners of properties adjacent to or in close proximity to those properties or non- 56 Table of Contents governmental organizations such as environmental groups, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations.
In addition, private parties, including the owners of properties upon which our wells are drilled or our facilities are located, the owners of properties adjacent to or in close proximity to those properties or non-governmental organizations such as environmental groups, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations.
Although our leasehold acreage is located primarily in the Delaware Basin, the broader consequences of the conflicts between Russia and Ukraine and Israel and Hamas, which may include further sanctions, embargoes, supply chain disruptions, regional instability and geopolitical shifts, may have adverse effects on global macroeconomic conditions, increase volatility in the price and demand for oil and natural gas, increase exposure to cyberattacks, cause disruptions in global supply chains, increase foreign currency fluctuations, cause constraints or disruption in the capital markets and limit sources of liquidity.
Although our leasehold acreage is located primarily in the Delaware Basin, the broader consequences of the conflicts between Russia and Ukraine and in the Middle East, which may include further sanctions, embargoes, supply chain disruptions, regional instability and geopolitical shifts, may have adverse effects on global macroeconomic conditions, increase volatility in the price and demand for oil and natural gas, increase exposure to cyberattacks, cause disruptions in global supply chains, increase foreign currency fluctuations, cause constraints or disruption in the capital markets and limit sources of liquidity.
A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity, and could lower the value of our common stock. Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses.
A write-down does not affect net cash flows from operating activities, liquidity or capital resources, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity, and could lower the value of our common stock. 41 Table of Contents Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses.
Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as (i) hydraulic fracturing, including, but not limited to, the use of fresh water in such operations, or (ii) disposal of waste, including, but not limited to, the disposal of produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas.
Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as (i) hydraulic fracturing, including the use of fresh water in such operations, or (ii) disposal of waste, including the disposal of produced water, drilling fluids and other wastes associated with the exploration, development and production of oil and natural gas.
Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. Certain of our unproved and unevaluated acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
Our actual drilling activities may be materially 51 Table of Contents different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. Certain of our unproved and unevaluated acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
This process, including any additional requirements that may be implemented or litigation regarding the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.
This process, including any additional requirements that may be implemented or litigation regarding the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability. See “Business—Regulation—Oil and Natural Gas Regulation.” We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.
We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, developing midstream assets, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may not be able to compete 54 Table of Contents successfully in the future in acquiring prospective reserves, developing reserves, developing midstream assets, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Unfavorable ESG ratings and recent activism directed at shifting funding away 64 Table of Contents from companies with energy-related assets could lead to increased negative investor sentiment toward us and to the diversion of investment to other industries, which could have an adverse effect on our stock price and our access to and costs of capital.
Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and to the diversion of investment to other industries, which could have an adverse effect on our stock price and our access to and costs of capital.
San Mateo and Pronto compete with other midstream companies that provide similar services in their areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. Also, there is substantial competition for capital available for investment in the oil and natural gas industry.
San Mateo competes with other midstream companies that provide similar services in their areas of operations, and such companies may have legacy relationships with producers in those areas and may have a longer history of efficiency and reliability. Also, there is substantial competition for capital available for investment in the oil and natural gas industry.
In addition, should oil and natural gas prices decline, third-party service providers may face financial difficulties and be unable to provide services. A reduction in the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us.
In addition, should oil and natural gas prices decline, third-party service providers may face financial difficulties and be unable to provide services. A reduction in 50 Table of Contents the number of service providers available to us may negatively impact our ability to retain qualified service providers, or obtain such services at costs acceptable to us.
These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil, natural gas and NGL sales are made in the spot market or pursuant to contracts based on spot market prices and are not pursuant to long-term fixed price contracts.
These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil, natural gas and NGL sales are made in the spot market or pursuant to contracts based on spot market prices and are not 38 Table of Contents pursuant to long-term fixed price contracts.
Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as: • actual prices we receive for oil and natural gas; 39 Table of Contents • actual costs and timing of development and production expenditures; • the amount and timing of actual production; and • changes in governmental regulations or taxation.
Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as: • actual prices we receive for oil and natural gas; • actual costs and timing of development and production expenditures; • the amount and timing of actual production; and • changes in governmental regulations or taxation.
As a result, interest expense on our existing floating rate debt rose during 2022 and 2023 and may remain high or increase during 2024. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly.
As a result, interest expense on our existing floating rate debt rose during 2022 and 2023, remained high during 2024 and may remain high during 2025. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly.
We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2024.
We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin in 2025.
Risks Related to our Operations • Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk. • Our operations are subject to operational hazards and risks, and insurance against all such risks is not available to us. • Our reserves and production are concentrated in a few core areas. • There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques. • Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions of other operators. • Multi-well pad drilling may result in volatility in our operating results. • The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis. • We may be unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules. • Regulatory changes could prevent our ability to continue to pool wells in accordance with our past practices. • Midstream projects are subject to risks of construction delays and cost over-runs. 35 Table of Contents • Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties and lease expirations that could materially alter the occurrence or timing of their drilling. • The seismic data and other technologies we use cannot eliminate exploration risk.
Risks Related to our Operations • Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk. • Our operations are subject to operational hazards and risks, and insurance against all such risks is not available to us. • Our reserves and production are concentrated in a few core areas. • There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques. • Certain of our properties are in areas that may have been partially depleted or drained by offset wells, and certain of our wells may be adversely affected by actions of other operators. • Multi-well pad drilling may result in volatility in our operating results. • The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis. • We may be unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules. • Midstream projects are subject to risks of construction delays and cost over-runs. 36 Table of Contents • Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties and lease expirations that could materially alter the occurrence or timing of their drilling. • The seismic data and other technologies we use cannot eliminate exploration risk.
Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well.
Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no 43 Table of Contents obvious deficiencies in title to the well.
See “Business—Regulation—Environmental, Health and Safety Regulation.” Increased seismicity in areas in which we operate could result in additional regulation and restrictions on the use of injection wells by us or by third parties whom we may contract with to dispose of produced water.
See “Business—Regulation—Environmental, Health and Safety Regulation.” 58 Table of Contents Increased seismicity in areas in which we operate could result in additional regulation and restrictions on the use of injection wells by us or by third parties whom we may contract with to dispose of produced water.
Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by us or other midstream companies, service companies or suppliers with whom we have a business relationship.
Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by us or other midstream 59 Table of Contents companies, service companies or suppliers with whom we have a business relationship.
New climate disclosure rules proposed by the SEC or states in which we have operations or do business could increase our costs of compliance and adversely impact our business.
New climate disclosure rules adopted by the SEC or states in which we have operations or do business could increase our costs of compliance and adversely impact our business.
These rules could result in increased compliance costs for our operations, which in turn 55 Table of Contents could have a material adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated.
These rules could result in increased compliance costs for our operations, which in turn could have a material adverse effect on our business and results of operations. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated.
Supply and demand fundamentals have been aggravated by disruptions in global energy supply caused by multiple geopolitical events, including the ongoing military conflicts between Russia and Ukraine and Israel and Hamas, as well as related actions of the U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps.
Supply and demand fundamentals have been aggravated by disruptions in global energy supply caused by multiple geopolitical events, including the ongoing military conflicts between Russia and Ukraine and in the Middle East, as well as related actions of the U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps.
Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” 40 Table of Contents to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option.
Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. Three-way costless collars also provide us with downside price protection through the purchase of a put option, but they also allow us to participate in price upside through the purchase of a call option.
Each of these risks is magnified in wells with longer laterals. In 2023, the average completed lateral length for operated wells turned to sales was approximately 9,800 feet. If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected.
Each of these risks is magnified in wells with longer laterals. In 2024, the average completed lateral length for operated wells turned to sales was approximately 9,300 feet. If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected.
If a seismic event were to occur in the area of our operations, the salt water disposal wells that we deliver to or operate may be shut in or curtailed, which may result in increased expenses or the curtailment of our oil and natural gas production.
If a seismic event were to occur in the area of our operations, the salt water disposal wells that we deliver to or operate may be shut in or curtailed, which may result in increased 48 Table of Contents expenses or the curtailment of our oil and natural gas production.
Furthermore, such facilities may become unavailable because of testing, turnarounds, line 52 Table of Contents repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues.
Furthermore, such facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues.
Risks that we face while drilling and completing horizontal wells include, but are not limited to, the following: • landing our wellbore in the desired drilling zone; • staying in the desired drilling zone while drilling horizontally through the formation; • running our casing the entire length of the wellbore; • fracture stimulating the planned number of stages; • drilling out the plugs between stages following hydraulic fracturing operations; and • being able to run tools and other equipment consistently through the horizontal wellbore.
Risks that we face while drilling and completing horizontal wells include: • landing our wellbore in the desired drilling zone; • staying in the desired drilling zone while drilling horizontally through the formation; • running our casing the entire length of the wellbore; • fracture stimulating the planned number of stages; • drilling out the plugs between stages following hydraulic fracturing operations; and • being able to run tools and other equipment consistently through the horizontal wellbore.
See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2023.
See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2024.
Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, maximum facility amount and elected borrowing commitment (subject to compliance with the covenants noted above).
Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment (subject to compliance with the covenants noted below).
In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable 48 Table of Contents or uninsured risks or in amounts in excess of existing insurance coverage.
In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage.
The oil and natural gas industry is dependent on digital technologies to conduct certain exploration, development, production, gathering, processing and financial activities, including technologies that are managed by third-party service providers or other providers to our industry on whom we directly or indirectly rely to help us collect, host or process information.
Our business, like the oil and natural gas industry in general, is dependent on digital technologies to conduct certain exploration, development, production, gathering, processing and financial activities, including technologies that are managed by third-party service providers or other providers to our industry on whom we directly or indirectly rely to help us collect, host or process information.
Lower revenues as a result of less volumes than anticipated, or 45 Table of Contents otherwise, or an increase in interest rates may adversely impact San Mateo’s EBITDA and interest expense, and therefore San Mateo’s ability to comply with these covenants.
Lower revenues as a result of less volumes than anticipated, or otherwise, or an increase in interest rates may adversely impact San Mateo’s EBITDA and interest expense, and therefore San Mateo’s ability to comply with these covenants.
These factors include, but are not limited to, the following: • the domestic and foreign supply of, and demand for, oil, natural gas and NGLs; • the actions of OPEC+ and state-controlled oil companies; • the prices and availability of competitors’ supplies of oil, natural gas and NGLs; • the price and quantity of foreign imports; • the impact of U.S. dollar exchange rates; • domestic and foreign governmental regulations and taxes; • speculative trading of oil and natural gas futures contracts; • the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; • the availability of refining capacity; • the prices and availability of alternative fuel sources; • weather conditions and natural disasters, including hurricanes and tropical storms in the Gulf Coast region and severe cold weather in the Delaware Basin; • political conditions or conflicts in or affecting oil, natural gas and NGL producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; • the ongoing military conflicts between Russia and Ukraine and Israel and Hamas, as well as the related actions of U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps; • domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases, such as COVID-19 and its variants; • the continued threat of terrorism and the impact of military action and civil unrest; • public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil, natural gas and NGL operations, including hydraulic fracturing activities; • the level of global oil, natural gas and NGL inventories and exploration and production activity; • the impact of energy conservation efforts; • technological advances affecting energy consumption; and • overall worldwide economic conditions.
These factors include the following: • the domestic and foreign supply of, and demand for, oil, natural gas and NGLs; • the actions of OPEC+ and state-controlled oil companies; • the prices and availability of competitors’ supplies of oil, natural gas and NGLs; • the price and quantity of foreign imports; • the impact of U.S. dollar exchange rates; • domestic and foreign governmental regulations and taxes; • speculative trading of oil and natural gas futures contracts; • the availability, proximity and capacity of gathering, processing and transportation systems for oil, natural gas and NGLs and gathering and disposal systems for produced water; • the availability of refining capacity; • the prices and availability of alternative fuel and energy sources; • weather conditions and natural disasters, including hurricanes and tropical storms in the Gulf Coast region and severe cold weather in the Delaware Basin; • political conditions or conflicts in or affecting oil, natural gas and NGL producing regions or countries, including the United States, the Middle East, South America, Russia, Ukraine and China; • the ongoing military conflicts between Russia and Ukraine and in the Middle East, as well as the related actions of U.S. and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps; • domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases; • the threat of terrorism and the impact of military action and civil unrest; • public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate oil, natural gas and NGL operations, including hydraulic fracturing activities; • the level of global oil, natural gas and NGL inventories and exploration and production activity; • the impact of energy conservation efforts; • technological advances affecting energy consumption; • tariffs and trade restrictions; and • overall worldwide economic conditions.
For each of the years ended December 31, 2023, 2022 and 2021, we had three significant purchasers that collectively accounted for approximately 76%, 70% and 72%, respectively, of our total oil, natural gas and NGL revenues. We cannot ensure that we will continue to have ready access to suitable markets for our future production.
For each of the years ended December 31, 2024, 2023 and 2022, we had three significant purchasers that collectively accounted for approximately 79%, 76% and 70%, respectively, of our total oil, natural gas and NGL revenues. We cannot ensure that we will continue to have ready access to suitable markets for our future production.
In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt 58 Table of Contents water disposal wells, including potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event.
In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event.
Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States.
Such changes include (i) the repeal of the percentage depletion allowance for certain oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States.
Our ability to explore, develop and produce oil and natural gas resources successfully, acquire oil and natural gas interests and acreage and conduct our midstream activities depends on our developing and maintaining close working 54 Table of Contents relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment.
Our ability to explore, develop and produce oil and natural gas resources successfully, acquire oil and natural gas interests and acreage and conduct our midstream activities depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment.
The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for, and supply of, oil, natural gas and NGLs and the proximity of reserves to pipelines and terminal facilities.
The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for, and supply of, oil, natural 52 Table of Contents gas and NGLs and the proximity of reserves to pipelines and terminal facilities.
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 our proved oil and natural gas reserves at December 31 and June 30 of each year, respectively.
The borrowing base under our Credit Agreement is subject to periodic redetermination. 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 our proved oil and natural gas reserves at December 31 and June 30 of each year, respectively.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeRisks from Cybersecurity Threats We have not been subject to cybersecurity challenges that have materially impaired our operations or financial standing. 67 Table of Contents Governance The Company is aware of the critical nature of managing risks associated with cybersecurity threats and has established oversight mechanisms at the Board and management levels to ensure effective governance in managing risks associated with cybersecurity threats.
Biggest changeFor further discussion regarding our cybersecurity risks, see “Risk Factors—General Risk Factors—A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss.” Governance The Company is aware of the critical nature of managing risks associated with cybersecurity threats and has established oversight mechanisms at the Board and management levels to ensure effective governance in managing risks associated with cybersecurity threats.
In addition to our scheduled meetings, the Board, Senior Vice President of Information Technology, CAO and COO maintain an ongoing dialogue regarding emerging or potential cybersecurity risks. Together, they receive updates on significant developments in the cybersecurity domain, ensuring the Board’s oversight is proactive and responsive.
In addition to our scheduled meetings, the Board, Senior Vice President of Information Technology, CAO and GC maintain an ongoing dialogue regarding emerging or potential cybersecurity risks. Together, they receive updates on significant developments in the cybersecurity domain, ensuring the Board’s oversight is proactive and responsive.
Oversee Third-Party Risk Because we are aware of the risks associated with third-party vendors, service providers and business partners, we have implemented processes to oversee and manage these risks. We conduct initial risk assessments of third-party providers before engagement.
Oversee Third-Party Risk 67 Table of Contents Because we are aware of the risks associated with third-party vendors, service providers and business partners, we have implemented processes to oversee and manage these risks. We conduct initial risk assessments of third-party providers before engagement.
Reporting to the Board The Senior Vice President of Information Technology regularly informs the Chief Executive Officer and COO of all aspects related to cybersecurity risks and incidents. This ensures that the highest levels of management are kept abreast of the cybersecurity posture and potential risks facing the Company.
Reporting to the Board The Senior Vice President of Information Technology regularly informs the Chief Executive Officer and GC of all aspects related to cybersecurity risks and incidents. This ensures that the highest levels of management are kept abreast of the 68 Table of Contents cybersecurity posture and potential risks facing the Company.
The Senior Vice President of Information Technology, the Executive Vice President and Chief Accounting Officer (“CAO”) and the Co-Chief Operating Officer (“COO”) play a pivotal role in informing the Board on cybersecurity risks. They provide comprehensive briefings to the Board on a regular basis, with a minimum frequency of once per year.
The Senior Vice President of Information Technology, the Executive Vice President and Chief Accounting Officer (“CAO”) and the Executive Vice President, General Counsel and Head of M&A (“GC”) play a pivotal role in informing the Board on cybersecurity risks. They provide comprehensive briefings to the Board on a regular basis, with a minimum frequency of once per year.
Added
Risks from Cybersecurity Threats As of February 18, 2025, we were not aware of any cybersecurity threats or incidents that have materially affected or are reasonably likely to materially affect the Company, including our business strategy, results of operations or financial standing.
Added
However, there can be no assurance that our cybersecurity processes will prevent or mitigate cybersecurity incidents or threats and that our efforts will always be successful.

Item 2. Properties

Properties — owned and leased real estate

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Biggest changeItem 2. Properties. 68 Table of Contents See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See Note 4 to the consolidated financial statements in this Annual Report for the future minimum rental payments. Such information is incorporated herein by reference.
Biggest changeItem 2. Properties. See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See Note 4 to the consolidated financial statements in this Annual Report for the future minimum rental payments. Such information is incorporated herein by reference.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeOn February 13, 2024, the Board declared a quarterly cash dividend of $0.20 per share of common stock payable on March 13, 2024 to shareholders of record as of February 23, 2024. We expect that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future.
Biggest changeIn February 2025, the Board amended our dividend policy to increase the quarterly dividend to $0.3125 per share of common stock and also declared a quarterly cash dividend of $0.3125 per share of common stock payable on March 14, 2025 to shareholders of record as of February 28, 2025.
Comparison of Cumulative Total Return Among Matador Resources Company, the Russell 2000 Index and the Russell 2000 Energy Index 71 Table of Contents Repurchase of Equity by the Company or Affiliates During the quarter ended December 31, 2023, the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock.
Comparison of Cumulative Total Return Among Matador Resources Company, the Russell 2000 Index and the Russell 2000 Energy Index 71 Table of Contents Repurchase of Equity by the Company or Affiliates During the quarter ended December 31, 2024, the Company re-acquired shares of common stock from certain employees in order to satisfy the employees’ tax liability in connection with the vesting of restricted stock.
For a description of our ESPP, see Note 9 to the consolidated financial statements in this Annual Report. 70 Table of Contents Share Performance Graph The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2018 through December 31, 2023, to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period.
For a description of our ESPP, see Note 9 to the consolidated financial statements in this Annual Report. 70 Table of Contents Share Performance Graph The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2019 through December 31, 2024, to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period.
Equity Compensation Plan Information Plan Category Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans Equity compensation plans approved by security holders (1)(2)(3) 830,377 $ 19.11 8,422,916 Equity compensation plans not approved by security holders — — — Total 830,377 $ 19.11 8,422,916 __________________ (1) Our Board has determined not to make any additional grants of awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”).
Equity Compensation Plan Information Plan Category Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans Equity compensation plans approved by security holders (1)(2)(3) 1,090,557 $ 14.80 7,850,907 Equity compensation plans not approved by security holders — — — Total 1,090,557 $ 14.80 7,850,907 __________________ (1) Our Board has determined not to make any additional grants of awards under the Matador Resources Company Amended and Restated 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”).
Prior to trading on the NYSE, there was no established public trading market for our common stock. On February 20, 2024, we had 119,519,883 shares of common stock outstanding held by approximately 350 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name.
Prior to trading on the NYSE, there was no established public trading market for our common stock. On February 18, 2025, we had 125,207,212 shares of common stock outstanding held by approximately 396 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name.
Dividends In February 2023, April 2023 and July 2023, our Board declared quarterly cash dividends of $0.15 per share of common stock. In October 2023, the Board amended our dividend policy to increase the quarterly dividend to $0.20 per share of common stock and also declared a quarterly cash dividend of $0.20 per share of common stock.
Dividends In each of the first, second and third quarters of 2024, our Board declared quarterly cash dividends of $0.20 per share of common stock. In October 2024, the Board amended our dividend policy to increase the quarterly dividend to $0.25 per share of common stock and also declared a quarterly cash dividend of $0.25 per share of common stock.
Period Total Number of Shares Purchased (1) Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs October 1, 2023 to October 31, 2023 373 $ 61.88 — — November 1, 2023 to November 30, 2023 — — — — December 1, 2023 to December 31, 2023 394 55.93 — — Total 767 $ 58.82 — — _________________ (1) The shares were not re-acquired pursuant to any repurchase plan or program.
Period Total Number of Shares Purchased (1) Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number of Shares that May Yet Be Purchased under the Plans or Programs October 1, 2024 to October 31, 2024 41,958 $ 54.68 — — November 1, 2024 to November 30, 2024 99 52.11 — — December 1, 2024 to December 31, 2024 638 57.03 — — Total 42,695 $ 54.71 — — _________________ (1) The shares were not re-acquired pursuant to any repurchase plan or program.
Equity Compensation Plan Information The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2023.
We expect that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future. Equity Compensation Plan Information The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2024.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

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Biggest changeSubstantially all of our 2023 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, including properties acquired in the Advance Acquisition, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells drilled and completed in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions, including certain non-operated well opportunities, and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin. 73 Table of Contents Our average daily oil equivalent production for the year ended December 31, 2023 was 131,813 BOE per day, including 75,457 Bbl of oil per day and 338.1 MMcf of natural gas per day, an increase of 25%, as compared to 105,465 BOE per day, including 60,119 Bbl of oil per day and 272.1 MMcf of natural gas per day, for the year ended December 31, 2022.
Biggest changeSubstantially all of our 2024 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, including properties acquired in the Ameredev Acquisition, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin, including the Ameredev Acquisition.
As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise.
As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise.
If capital expenditures were to exceed our operating cash flows in 2024, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all.
If capital expenditures were to exceed our operating cash flows in 2025, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all.
If capital expenditures were to exceed our operating cash flows in 2024, we expect to fund any excess capital expenditures, including for significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all.
If capital expenditures were to exceed our operating cash flows in 2025, we expect to fund any excess capital expenditures, including for significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all.
As of December 31, 2023, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures.
As of December 31, 2024, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures.
We have built significant optionality into our 2024 drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors.
We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors.
See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” 82 Table of Contents Our cash flows for the years ended December 31, 2023, 2022 and 2021 are presented below.
See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.” 82 Table of Contents Our cash flows for the years ended December 31, 2024, 2023 and 2022 are presented below.
These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statements of income. Realized loss on derivatives .
These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statements of income. Realized gain (loss) on derivatives .
As a result, it is difficult to estimate these 2024 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2024. 76 Table of Contents Revenues The following table summarizes our revenues and production data for the periods indicated.
As a result, it is difficult to estimate these 2025 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2025. 76 Table of Contents Revenues The following table summarizes our revenues and production data for the periods indicated.
In addition, during 2024, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect.
In addition, during 2025, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect.
In addition, during 2024, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect.
In addition, during 2025, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect.
During the year ended December 31, 2023, our net cash provided by financing activities was primarily attributable to (i) proceeds from the issuance of the 2028 Notes of $494.8 million, (ii) net borrowings under our Credit Agreement of $500.0 million and (iii) net borrowings under the San Mateo Credit Facility of $57.0 million, which were partially offset by (x) dividends paid of $77.2 million and (y) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $15.6 million.
During the year ended December 31, 2023, our net cash provided 83 Table of Contents by financing activities was primarily attributable to (i) proceeds from the issuance of the 2028 Notes of $494.8 million, (ii) net borrowings under our Credit Agreement of $500.0 million and (iii) net borrowings under the San Mateo Credit Facility of $57.0 million, which were partially offset by (x) dividends paid of $77.2 million and (y) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $15.6 million.
In addition, supply chain disruptions and other inflationary pressures experienced in recent periods throughout the United States and global economy and in the oil and natural gas industry may limit our ability to procure the necessary products and services we need for drilling, completing and producing wells in a timely and cost-effective manner, which could result in reduced margins and delays to our operations and could, in turn, adversely affect our business, financial condition, results of operations and cash flows.
In addition, supply chain disruptions, tariffs and trade restrictions and other inflationary pressures experienced in recent periods throughout the United States and global economy and in the oil and natural gas industry may limit our ability to procure the necessary products and services we need for drilling, completing and producing wells in a timely and cost-effective manner, which could result in reduced margins and delays to our operations and could, in turn, adversely affect our business, financial condition, results of operations and cash flows.
Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana.
Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana.
At December 31, 2023, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and a significant portion of our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the Waha hub in far West Texas.
At December 31, 2024, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and a significant portion of our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the Waha hub in far West Texas.
As a result, it is difficult to estimate these 2024 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2024.
As a result, it is difficult to estimate these 2025 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2025.
Should we experience future periods of negative pricing for natural gas as we have experienced historically, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results.
Should we experience future periods of negative pricing for natural gas as we have experienced historically, including in 2024, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results.
We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2023.
We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2024.
At both December 31, 2023 and December 31, 2022, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
At both December 31, 2024 and December 31, 2023, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
Revenues associated with NGLs are included with our natural gas revenues. (2) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. Year Ended December 31, 2023 as Compared to Year Ended December 31, 2022 Oil and natural gas revenues .
Revenues associated with NGLs are included with our natural gas revenues. (2) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. Year Ended December 31, 2024 as Compared to Year Ended December 31, 2023 Oil and natural gas revenues .
A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin.
A majority of these new opportunities reflect additional business awarded to San Mateo and Pronto by existing customers, which we believe is indicative of the quality of service San Mateo and Pronto provides to all of its customers in the Delaware Basin.
Liquidity and Capital Resources Our primary use of capital has been, and we expect will continue during 2024 and for the foreseeable future to be, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments.
Liquidity and Capital Resources Our primary use of capital has been, and we expect will continue during 2025 and for the foreseeable future to be, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments.
At December 31, 2023, we had derivative natural gas basis differential swap contracts in place to mitigate our exposure to the Waha-Henry Hub basis differential for approximately 11.0 Bcf of our anticipated natural gas production in each of 2024 and 2025. We have at times experienced pipeline-related interruptions to our oil, natural gas or NGL production or produced water disposal.
At December 31, 2024, we had derivative natural gas basis differential swap contracts in place to mitigate our exposure to the Waha-Henry Hub basis differential for approximately 11.0 Bcf of our anticipated natural gas production in 2025. We have at times experienced pipeline-related interruptions to our oil, natural gas or NGL production or produced water disposal.
We expect to fund our 2024 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo.
We expect to fund our 2025 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo.
We expect to fund our 2024 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo.
We expect to fund our 2025 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo.
Certain items excluded from Adjusted EBITDA are significant components of understanding and 84 Table of Contents assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.
Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.
The increase in natural gas production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Third-party midstream services revenues.
The increase in natural gas production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Third-party midstream services revenues.
See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2023.
See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2024.
Other than the off-balance sheet arrangements described above, the 85 Table of Contents Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources.
Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources.
Our 2024 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control.
Our 2025 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control.
The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. 90 Table of Contents Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates.
The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates.
At February 20, 2024, given our current projections, we expect to continue to pay federal income taxes and state income taxes in New Mexico of between 5% and 10% of 2024 pretax book income, but we do not expect to be subject to the Corporate Alternative Minimum Tax (the “CAMT”) in 2024.
At February 18, 2025, given our current projections, we expect to continue to pay federal income taxes and state income taxes in New Mexico of between 5% and 10% of 2025 pretax book income, but we do not expect to be subject to the Corporate Alternative Minimum Tax (the “CAMT”) in 2025.
Purchase Accounting Periodically we acquire assets and assume liabilities in transactions accounted for as business combinations, such as the Advance Acquisition in 2023. In estimating the fair value of assets acquired and liabilities assumed in these transactions, including the Advance Acquisition, we must make a number of estimates and assumptions and may engage third-party valuation experts.
Purchase Accounting Periodically we acquire assets and assume liabilities in transactions accounted for as business combinations, such as the Advance Acquisition in 2023 and the Ameredev Acquisition in 2024. 90 Table of Contents In estimating the fair value of assets acquired and liabilities assumed in these transactions, including the Advance Acquisition and the Ameredev Acquisition, we must make a number of estimates and assumptions and may engage third-party valuation experts.
The Credit Agreement requires us to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75 million of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less at the end of each fiscal quarter.
The Credit Agreement requires us to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities of debt, of not less than 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to the greater of $150 million or 10% of the elected borrowing commitments of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 or less at the end of each fiscal quarter.
During 2022 and 2023, we typically realized a narrower 87 Table of Contents differential to natural gas sold at the Waha hub despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our natural gas production into other markets to improve our realized natural gas pricing.
During 2023 and 2024, we typically realized a narrower differential to natural gas sold at the Waha hub despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our natural gas production into other markets to improve our realized natural gas pricing.
We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2023. At December 31, 2023, San Mateo had $522.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility.
We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2024. At December 31, 2024, San Mateo had $615.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility.
A significant portion of our Delaware Basin natural gas production, however, is sold at Houston Ship Channel pricing and is not exposed to Waha pricing.
A significant portion of our 87 Table of Contents Delaware Basin natural gas production, however, is sold at Houston Ship Channel pricing and is not exposed to Waha pricing.
Additionally, we conduct midstream operations in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. 2023 Operational Highlights We began 2023 operating seven drilling rigs in the Delaware Basin.
Additionally, we conduct midstream operations in support of, and to provide flow assurance for, our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties. 2024 Operational Highlights We began 2024 operating seven drilling rigs in the Delaware Basin.
Further, approximately 8% of our reported natural gas production for the year ended December 31, 2023 was attributable to the Haynesville and Eagle Ford shale plays, which are not exposed to Waha pricing.
Further, approximately 5% of our reported natural gas production for the year ended December 31, 2024 was attributable to the Haynesville and Eagle Ford shale plays, which are not exposed to Waha pricing.
(8) At December 31, 2023, we had outstanding commitments related to the construction and installation of Pronto’s additional natural gas processing plant with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities, in addition to commitments to purchase 11 compressors to be utilized in San Mateo and Pronto operations. 86 Table of Contents General Outlook and Trends Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy.
(8) At December 31, 2024, we had outstanding commitments related to the construction and installation of San Mateo’s Marlan Processing Plant expansion with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities, in addition to commitments to purchase compressors to be utilized in San Mateo operations. 86 Table of Contents General Outlook and Trends Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy.
This decrease was primarily attributable to lower realized oil and natural gas prices, partially offset by higher oil and natural gas production noted above for the year ended December 31, 2023, as compared to the year ended December 31, 2022.
This increase was primarily attributable to higher oil and natural gas production noted above, partially offset by lower realized oil and natural gas prices for the year ended December 31, 2024, as compared to the year ended December 31, 2023.
See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference. Obligations and Commitments We had the following material contractual obligations and commitments at December 31, 2023.
See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference. 85 Table of Contents Obligations and Commitments We had the following material contractual obligations and commitments at December 31, 2024.
(6) From time to time, we enter into agreements with third parties whereby we commit to deliver anticipated natural gas and oil production and produced water from certain portions of our acreage for transportation, gathering, processing, fractionation, sales and disposal. Certain of these agreements contain minimum volume commitments.
(6) From time to time, we enter into agreements with third parties whereby we commit to deliver anticipated natural gas and oil production and produced water from certain portions of our acreage for transportation, gathering, processing, fractionation, sales and disposal.
See “Cautionary Note Regarding Forward-Looking Statements.” For a comparison of our results of operations for the years ended December 31, 2022 and December 31, 2021, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on March 1, 2023.
See “Cautionary Note Regarding Forward-Looking Statements.” For a comparison of our results of operations for the years ended December 31, 2023 and December 31, 2022, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 27, 2024.
These increases for the year ended December 31, 2023 were primarily attributable to the increased number of wells being operated by us, including 127 wells from the Advance Acquisition, and other operators (where we own a working interest) and to operating cost inflation during the year-ended December 31, 2023, as compared to the year ended December 31, 2022.
These increases for the year ended December 31, 2024 were primarily attributable to the increased number of wells being operated by us, including 204 wells from the Ameredev Acquisition, and other operators (where we own a working interest) and to operating cost inflation during the year ended December 31, 2024, as compared to the year ended December 31, 2023.
Recent Accounting Pronouncements See Note 2 to the consolidated financial statements in this Annual Report for a description of recent accounting pronouncements. 91 Table of Contents
Recent Accounting Pronouncements See Note 2 to the consolidated financial statements in this Annual Report for a description of recent accounting pronouncements.
This decrease was primarily attributable to lower realized oil and natural gas prices for the year ended December 31, 2023, as compared to the year ended December 31, 2022, which was partially offset by the 25% increase in total oil equivalent production during 2023, as compared to 2022.
This increase was primarily attributable to the 30% increase in total oil equivalent production during 2024, as compared to 2023, which was partially offset by lower realized oil and natural gas prices for the year ended December 31, 2024, as compared to the year ended December 31, 2023.
Adjusted EBITDA for the year ended December 31, 2023 was $1.85 billion, as compared to Adjusted EBITDA of $2.13 billion for the year ended December 31, 2022. Adjusted EBITDA is a non-GAAP financial measure.
Adjusted EBITDA for the year ended December 31, 2024 was $2.30 billion, as compared to Adjusted EBITDA of $1.85 billion for the year ended December 31, 2023. Adjusted EBITDA is a non-GAAP financial measure.
For the year ended December 31, 2023, natural gas prices averaged $2.66 per MMBtu, as compared to $6.54 per MMBtu in 2022, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date.
For the year ended December 31, 2024, natural gas prices averaged $2.40 per MMBtu, as compared to $2.66 per MMBtu in 2023, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date.
The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years. At February 20, 2024, this oil price differential was approximately +$1.64 per Bbl. At February 20, 2024, we had no derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential for 2024.
The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years. At February 18, 2025, this oil price differential was approximately +$1.33 per Bbl. At February 18, 2025, we had no derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential for 2025.
At December 31, 2023, approximately 98% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin.
At December 31, 2024, approximately 99% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin.
Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at Pronto’s Marlan Processing Plant or San Mateo’s Black River Processing Plant and subsequently sell the residue gas and NGLs to other purchasers.
Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at San Mateo’s cryogenic natural gas processing plants and subsequently sell the residue natural gas and NGLs to other purchasers.
Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital. At December 31, 2023, we had cash totaling $52.7 million and restricted cash totaling $53.6 million, which was primarily associated with San Mateo.
Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital. At December 31, 2024, we had cash totaling $23.0 million and restricted cash totaling $71.7 million, which was primarily associated with San Mateo.
The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and taxes.
The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including assumptions related to oil and natural gas prices, development expenditures, operating expenses, capital expenditures, taxes and availability of funds.
The decrease in natural gas revenues resulted from a decrease in our weighted average realized natural gas price of $3.25 per Mcf in 2023, as compared to $7.98 per Mcf in 2022, which was partially offset by the 24% increase in natural gas production for the year ended December 31, 2023 noted above.
The decrease in natural gas revenues resulted from a decrease in our weighted average realized natural gas price of $2.38 per Mcf in 2024, as compared to $3.25 per Mcf in 2023, which was partially offset by the 26% increase in natural gas production for the year ended December 31, 2024 noted above.
Our unrealized loss on derivatives was approximately $1.3 million for the year ended December 31, 2023, as compared to an unrealized gain of $18.8 million for the year ended December 31, 2022.
Our unrealized gain on derivatives was approximately $13.3 million for the year ended December 31, 2024, as compared to an unrealized loss of $1.3 million for the year ended December 31, 2023.
We realized an average loss on our natural gas derivatives of approximately $0.08 per Mcf of natural gas produced during the year ended December 31, 2023, as compared to an average loss on our natural gas derivatives of approximately $0.83 per Mcf of natural gas produced during the year ended December 31, 2022.
We realized an average gain on our natural gas derivatives of approximately $0.09 per Mcf of natural gas produced during the year ended December 31, 2024, as compared to an average loss on our natural gas derivatives of approximately $0.08 per Mcf of natural gas produced during the year ended December 31, 2023. Unrealized gain (loss) on derivatives .
We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2023, although we did participate in the drilling and completion of 22 gross (0.4 net) non-operated Haynesville shale wells and one gross (0.4 net) non-operated South Texas well that began producing in 2023.
We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2024, although we did participate in the drilling and completion of eight gross (0.1 net) non-operated Haynesville shale wells that began producing in 2024.
Substantially all of these 2024 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, South Texas and Haynesville shale.
Substantially all of these 2025 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities.
Substantially all of these 2024 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, South Texas and the Haynesville shale.
Substantially all of these 2025 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities.
Our average daily natural gas production for the year ended December 31, 2023 was 338.1 MMcf per day, an increase of 24%, as compared to 272.1 MMcf per day in 2022. This increase in natural gas production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin.
Our average daily natural gas production for the year ended December 31, 2024 was 425.7 MMcf per day, an increase of 26%, as compared to 338.1 MMcf per day in 2023. This increase in natural gas production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin.
Our general and administrative expenses on a unit-of-production basis decreased 24% to $2.29 per BOE for the year ended December 31, 2023, as compared to $3.02 per BOE for the year ended December 31, 2022, primarily as a result of the 25% increase in our total oil equivalent production between the two periods. Interest expense.
Our general and administrative expenses on a unit-of-production basis decreased 11% to $2.04 per BOE for the year ended December 31, 2024, as compared to $2.29 per BOE for the year ended December 31, 2023, primarily as a result of the 30% increase in our total oil equivalent production between the two periods. Interest expense.
Excluding changes in operating assets and liabilities, net cash provided by operating activities decreased to $1.82 billion for the year ended December 31, 2023 from $2.10 billion for the year ended December 31, 2022.
Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $2.23 billion for the year ended December 31, 2024 from $1.82 billion for the year ended December 31, 2023.
Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” Cash Flows Used in Investing Activities Net cash used in investing activities increased by $2.17 billion to $3.21 billion for the year ended December 31, 2023 from $1.04 billion for the year ended December 31, 2022.
Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” Net Cash Used in Investing Activities Net cash used in investing activities increased by $460.9 million to $3.67 billion for the year ended December 31, 2024 from $3.21 billion for the year ended December 31, 2023.
Assuming the amounts outstanding and interest rates of 7.21% and 7.71%, respectively, for the Credit Agreement and the San Mateo Credit Facility at December 31, 2023, the interest expense for such facilities is expected to be approximately $36.6 million and $40.8 million, respectively, each year until maturity. (2) The amounts included in the table above represent principal maturities only.
Assuming the amounts outstanding and interest rates of 6.19% and 6.44%, respectively, for the Credit Agreement and the San Mateo Credit Facility at December 31, 2024, the interest expense for such facilities is expected to be approximately $37.4 million and $40.2 million, respectively, each year until maturity. (2) The amounts included in the table above represent principal maturities only.
We reported net income attributable to Matador shareholders of approximately $846.1 million, or $7.05 per diluted common share, on a GAAP basis for the year ended December 31, 2023, as compared to a net income of $1.21 billion, or $10.11 per diluted common share, for the year ended December 31, 2022.
We reported net income attributable to Matador shareholders of approximately $885.3 million, or $7.14 per diluted common share, on a GAAP basis for the year ended December 31, 2024, as compared to a net income of $846.1 million, or $7.05 per diluted common share, for the year ended December 31, 2023.
Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years. In 2022, concerns about natural gas pipeline takeaway capacity out of the Delaware Basin began to increase, particularly beginning in the latter half of 2022 and into 2023.
Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years. In recent years, concerns about natural gas pipeline takeaway capacity out of the Delaware Basin began to increase and a result, the Waha-Henry Hub basis differential began to widen.
On a unit-of-production basis, our lease operating expenses increased 24% to $5.06 per BOE for the year ended December 31, 2023, as compared to $4.08 per BOE for the year ended December 31, 2022.
On a unit-of-production basis, our lease operating expenses increased 8% to $5.47 per BOE for the year ended December 31, 2024, as compared to $5.06 per BOE for the year ended December 31, 2023.
The increase in oil revenues resulted from the 26% increase in our oil production noted above, which was partially offset by a 19% decrease in the weighted average oil price realized for the year ended December 31, 2023 to $77.88 per Bbl, as compared to $96.32 per Bbl realized for the year ended December 31, 2022.
The increase in oil revenues resulted from the 33% increase in our oil production noted above, which was partially offset by a 3% decrease in the weighted average oil price realized for the year ended December 31, 2024 to $75.89 per Bbl, as compared to $77.88 per Bbl realized for the year ended December 31, 2023.
Changes in our operating assets and liabilities between December 31, 2022 and December 31, 2023 resulted in a net increase of approximately $168.0 million in net cash provided by operating activities for the year ended December 31, 2023, as compared to the year ended December 31, 2022.
Changes in our operating assets and liabilities between December 31, 2023 and December 31, 2024 resulted in a net decrease of approximately $36.9 million in net cash provided by operating activities for the year ended December 31, 2024, as compared to the year ended December 31, 2023.
We realized a weighted average oil price of $77.88 per Bbl (with no realized gains or losses from oil derivatives) for our oil production for the year ended December 31, 2023, as compared to $96.32 per Bbl ($92.87 per Bbl including realized losses from oil derivatives) for the year ended December 31, 2022.
We realized a weighted average oil price of $75.89 per Bbl (with no realized gains or losses from oil derivatives) for our oil production for the year ended December 31, 2024, as compared to $77.88 per Bbl (with no realized gains or losses from oil derivatives) for the year ended December 31, 2023.
On a unit-of-production basis, our production taxes and transportation and processing expenses decreased 25% to $5.50 per BOE for the year ended December 31, 2023, as compared to $7.33 per BOE for the year ended December 31, 2022.
On a unit-of-production basis, our production taxes and transportation and processing expenses decreased 11% to $4.91 per BOE for the year ended December 31, 2024, as compared to $5.50 per BOE for the year ended December 31, 2023.
We realized a weighted average natural gas price of $3.25 per Mcf ($3.17 per Mcf including realized losses from natural gas derivatives) for our natural gas production for the year ended December 31, 2023, as compared to $7.98 per Mcf ($7.15 per Mcf including realized losses from natural gas derivatives) for the year ended December 31, 2022.
We realized a weighted average natural gas price of $2.38 per Mcf ($2.47 per Mcf including realized gains from natural gas derivatives) for our natural gas production for the year ended December 31, 2024, as compared to $3.25 per Mcf ($3.17 per Mcf including realized losses from natural gas derivatives) for the year ended December 31, 2023.
We added back an eighth operated drilling rig in the first quarter of 2024. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors.
We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors.
Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions.
By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production 88 Table of Contents declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions.
Our realized net loss on derivatives was $9.6 million for the year ended December 31, 2023, as compared to a realized net loss of approximately $157.5 million for the year ended December 31, 2022.
Our realized net gain on derivatives was $12.7 million for the year ended December 31, 2024, as compared to a realized net loss of approximately $9.6 million for the year ended December 31, 2023.
Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” For the year ended December 31, 2023, oil prices averaged $77.60 per Bbl, as compared to $94.33 per Bbl in 2022, ranging from a low of $66.74 per Bbl in mid-March to a high of $93.68 per Bbl in late September, based upon the WTI oil futures contract price for the earliest delivery date.
Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.” For the year ended December 31, 2024, oil prices averaged $75.76 per Bbl, as compared to $77.60 per Bbl in 2023, ranging from a high of $86.91 per Bbl in early April to a low of $65.75 per Bbl in mid-September, based upon the WTI oil futures contract price for the earliest delivery date.
A significant portion of our anticipated cash flows from operations for 2024 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana.
A significant portion of our anticipated cash flows from operations for 2025 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin.
Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $33.4 million, or 35%, to $128.9 million for the year ended December 31, 2023, as compared to $95.5 million for the year ended December 31, 2022.
Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $42.6 million, or 33%, to $171.5 million for the year ended December 31, 2024, as compared to $128.9 million for the year ended December 31, 2023.
For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.” At December 31, 2023, our estimated total proved oil and natural gas reserves were 460.1 million BOE, including 272.3 million Bbl of oil and 1.13 Tcf of natural gas, with a Standardized Measure of $6.11 billion and a PV-10 of $7.70 billion.
For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.” At December 31, 2024, our estimated total proved oil and natural gas reserves were 611.5 million BOE, including 361.8 million Bbl of oil and 1.50 Tcf of natural gas, with a Standardized Measure of $7.38 billion and a PV-10 of $9.23 billion.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeThe counterparty on our derivative financial instruments in place at February 20, 2024 was Bank of America, which is also a lender (or affiliate thereof) under our Credit Agreement. Impact of inflation . Inflation in the United States has become much more significant in recent years.
Biggest changeThe counterparties on our derivative financial instruments in place at February 18, 2025 were Bank of America, PNC Bank, Truist Bank, The Bank of Nova Scotia, Royal Bank of Canada, Comerica Bank and BOKF (or affiliates thereof), which are all lenders under our Credit Agreement. Impact of inflation .
See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2023. Such information is incorporated herein by reference. Effect of Derivatives Legislation. The Dodd-Frank Act, among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use.
See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2024. Such information is incorporated herein by reference. Effect of Derivatives Legislation. The Dodd-Frank Act, among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use.
In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future.
In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative 91 Table of Contents arrangements in the future.
We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers and San Mateo and Pronto are subject to the credit risk of their customers.
We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers and San Mateo is subject to the credit risk of their customers.
The inability or failure of our, San Mateo’s or Pronto’s significant customers to meet their obligations or their 92 Table of Contents insolvency or liquidation may adversely affect our financial condition, results of operations and cash flows. In addition, our derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties.
The inability or failure of our or San Mateo’s significant customers to meet their obligations or their insolvency or liquidation may adversely affect our financial condition, results of operations and cash flows. In addition, our derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties.
At December 31, 2023, we had natural gas basis differential swap contracts open and in place to mitigate our exposure to natural gas price volatility, with a specific term (calculation period), notional quantity (volume hedged) and fixed price.
At December 31, 2024, we had natural gas basis differential swap contracts open and in place to mitigate our exposure to natural gas price volatility, with a specific term (calculation period), notional quantity (volume hedged) and fixed price. We had no open contracts associated with NGL prices at December 31, 2024.
We do not know how long these inflationary pressures may persist or the impact they may have on our business moving forward.
Inflation in the United States has become much more significant in recent years. We do not know how long these inflationary pressures may persist or the impact they may have on our business moving forward.
At December 31, 2023, we had $500.0 million of outstanding borrowings under our Credit Agreement at an interest rate of 7.21%, $699.2 million of outstanding 2026 Notes at a coupon rate of 5.875%, $500.0 million of outstanding 2028 Notes at a coupon rate of 6.875% and $522.0 million of outstanding borrowings under the San Mateo Credit Facility at an interest rate of 7.71%.
At December 31, 2024, we had $595.5 million of outstanding borrowings under our Credit Agreement at an interest rate of 6.19%, $500.0 million of outstanding 2028 Notes at a coupon rate of 6.875%, $900.0 million of outstanding 2032 Notes at a coupon rate of 6.500%, $750.0 million of outstanding 2033 Notes at a coupon rate of 6.250% and $615.0 million of outstanding borrowings under the San Mateo Credit Facility at an interest rate of 6.44%.
At December 31, 2023, Bank of America was the counterparty for our derivative instruments. We have considered the credit standing of the counterparty in determining the fair value of our derivative financial instruments.
At December 31, 2024, Bank of America, PNC Bank, Truist Bank, The Bank of Nova Scotia, Royal Bank of Canada, Comerica Bank and BOKF (or affiliates thereof) were the counterparties for our derivative instruments. We have considered the credit standing of the counterparties in determining the fair value of our derivative financial instruments.
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At December 31, 2024, we had various costless collar contracts open and in place to mitigate our exposure to oil price volatility, each with an established price floor and ceiling.

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