Matador Resources Co
For the period ended Dec 31, 2024. Filed Feb 25, 2025.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2024 · Filed Feb 25, 2025
MTDR$50.41+1.1%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2023-12-31; filed 2024-02-27.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2024-12-31; filed 2025-02-25.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 137 previous paragraphs and 140 current paragraphs.
60 unchanged; 67 reworded; 11 added; 8 removed; 2 previous and 2 current paragraphs rearranged.
Tables are not compared: 8 previous and 6 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (11)
Current report
On December 18, 2024, we completed the Pronto Transaction, pursuant to which we contributed Pronto, a wholly-owned subsidiary of the Company, to San Mateo, and Five Point made a cash contribution to San Mateo of $171.5 million. In connection with the Pronto Transaction, the Company received a special distribution from San Mateo of approximately $219.8 million. In addition, the Company has the potential to earn up to $75.0 million in incentive payments from Five Point over a five-year period. San Mateo continues to be owned 51% by the Company and 49% by Five Point.
Current report
Pronto owns and operates the Marlan Processing Plant, which has a designed inlet capacity of 60 MMcf of natural gas per day. Pronto is expanding the Marlan Processing Plant to add an additional plant with a designed inlet capacity of 200 MMcf of natural gas per day, which would increase the total capacity of the Marlan Processing Plant to 260 MMcf of natural gas per day.
Current report
In connection with the Pronto Transaction, the Company dedicated to Pronto its current and certain future leasehold interests in the Ranger and Antelope Ridge asset areas pursuant to 15-year, fixed fee natural gas gathering, compression, treating and processing agreements whereby Pronto will gather, compress, treat and process natural gas produced from the Company’s operated wells in northern Lea County, New Mexico. In addition, Pronto entered into certain agreements with Northwind, an affiliate of Five Point, whereby Northwind will treat certain sour gas gathered and delivered by Pronto in northern Lea County, New Mexico. Under these agreements, Northwind will redeliver the treated sweet gas from Pronto and other third-party customers to Pronto for processing.
Current report
In March 2024, we completed our natural gas pipeline connections between Pronto and San Mateo and between Pronto and Matador’s acreage obtained in the Advance Acquisition. These connector pipelines provide further flow assurance and options for Matador and third-party customer natural gas, and resulted in Pronto and San Mateo’s plants operating at or above nameplate capacity at times during 2024.
Current report
General and administrative. Our general and administrative expenses increased $17.1 million, or 15%, to $127.5 million for the year ended December 31, 2024, as compared to $110.4 million for the year ended December 31, 2023, primarily due to
Current report
increased compensation expenses for our existing employees as well as the addition of new employees to support the continued
Current report
On March 28, 2024, we completed the 2024 Equity Offering and used the net proceeds for general corporate purposes, including the funding of acquisitions and the repayment of borrowings outstanding under the Credit Agreement.
Current report
On April 2, 2024, we completed the 2032 Notes Offering and used the net proceeds to fund the 2026 Notes Repurchase and for general corporate purposes, including the funding of acquisitions and the repayment of borrowings outstanding under the Credit Agreement.
Current report
On September 25, 2024, we completed the 2033 Notes Offering and used the net proceeds to partially repay borrowings outstanding under the Credit Agreement including all of the $250.0 million in outstanding borrowings under the term loan.
Current report
On October 28, 2024, Piñon was acquired by an affiliate of Enterprise Products Partners L.P. During the fourth quarter of 2024, we received $113.6 million from the sale of Piñon resulting from our approximate 19% interest in the parent company of Piñon that we acquired as part of the Ameredev Acquisition and used these proceeds to reduce borrowings under our Credit Agreement. We currently expect to receive an additional $4.8 million from the sale of Piñon in the first half of 2025.
Current report
On November 21, 2024, we received notice from PNC Bank, National Association, as administrative agent under the Credit Agreement, that the lenders under the Credit Agreement completed their scheduled semi-annual review of our proved oil and natural gas reserves and unanimously determined to increase the borrowing base from $2.50 billion to $3.25 billion. We chose to maintain the elected borrowing commitments at $2.25 billion.
Removed paragraphs (8)
Previous report
Our proved oil and natural gas reserves in the Delaware Basin increased 31% to 452.6 million BOE at December 31, 2023, as compared to 346.8 million BOE at December 31, 2022, primarily as a result of the Advance Acquisition and our ongoing delineation and development operations there. At December 31, 2023, approximately 98% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin increased 40% to 270.1 million Bbl at December 31, 2023, as compared to 193.5 million Bbl at December 31, 2022, and our proved natural gas reserves in the Delaware Basin increased 19% to 1.09 Tcf, as compared to 919.7 Bcf at December 31, 2022. Proved oil reserves comprised 60% of our Delaware Basin total proved reserves at December 31, 2023, as compared to 56% at December 31, 2022.
Previous report
During 2023, Pronto closed new natural gas gathering and processing transactions with counterparties in Eddy and Lea Counties, New Mexico, which are expected to generate additional natural gas gathering and processing volumes in future periods. At December 31, 2023, Pronto’s midstream system included the Marlan Processing Plant, three compressor stations and approximately 70 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico, spanning from the northeastern portion of the Arrowhead asset area into the Ranger asset area. Pronto has also contracted to construct an additional natural gas processing plant with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities to be located near the Marlan Processing Plant.
Previous report
Cash Flows Provided by Operating Activities
Previous report
Guarantor Financial Information
Previous report
As of December 31, 2023, Matador’s outstanding senior notes registered under the Securities Act consisted of the 2026 Notes. The 2026 Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At December 31, 2023, the Guarantor Subsidiaries were each 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. Neither San Mateo nor Pronto is a Guarantor Subsidiary of the 2026 Notes.
Previous report
The following tables present summarized financial information of Matador (as issuer of the 2026 Notes) and the Guarantor Subsidiaries on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the Guarantor Subsidiaries and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. This financial information is presented in accordance with the amended requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations or financial position had the Guarantor Subsidiaries operated as independent entities.
Previous report
In January 2021, President Biden signed an executive order instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices, which has lapsed. In 2019, 2020 and 2021, an environmental group filed multiple lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico. In 2021, ten states, led by the State of Louisiana, filed a lawsuit in federal district court in Louisiana against President Biden and various other federal government officials and agencies challenging an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making. The BLM indicated that the Lease Sale Litigation or the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits. The impact of federal actions and lawsuits related to the oil and natural gas industry remains unclear, and should other limitations or prohibitions be imposed or continue to be applied, our operations on federal lands could be adversely impacted. Such limitations or prohibitions would almost certainly impact our future drilling and completion plans and could materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”
Previous report
We and San Mateo dispose of large volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for produced water disposal and the increased occurrence of seismic activity, also known as “induced seismicity.” This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regarding waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. The adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, and could result in increased costs and additional operating restrictions or delays, that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. The adoption of such legislation and regulations could also decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions for San Mateo as well.
Reworded paragraphs (67)
Previous wording
We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.
Current wording
We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also have operations in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of, and to provide flow assurance for, our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.
Previous wording
We began 2023 operating seven drilling rigs in the Delaware Basin. Following the closing of the Initial Advance Acquisition on April 12, 2023, we continued operating the drilling rig that Advance had been operating. Near the end of June 2023, we released this eighth operated drilling rig and continued operating seven drilling rigs in the Delaware Basin for the remainder of 2023. We added back an eighth operated drilling rig in the first quarter of 2024. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. We were able to achieve D/C/E capital expenditures for 2023 of $1.16 billion, which was below our estimated range for 2023 D/C/E capital expenditures of $1.18 to $1.32 billion as provided on February 21, 2023, and was in the middle of the revised estimated range of $1.10 to $1.22 billion, as provided on July 25, 2023.
Current wording
We began 2024 operating seven drilling rigs in the Delaware Basin. We added an eighth operated drilling rig in the first quarter of 2024 and a ninth operated drilling rig late in the second quarter of 2024. Upon the consummation of the Ameredev Acquisition, we continued operating a total of nine drilling rigs for the combined Matador and Ameredev properties. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. We were able to achieve D/C/E capital expenditures for 2024 of $1.32 billion, which was within our estimated range for 2024 D/C/E capital expenditures of $1.15 to $1.35 billion, as provided on October 22, 2024.
Previous wording
During the year ended December 31, 2023, we completed and began producing oil and natural gas from 119 gross (94.0 net) operated and 103 gross (5.6 net) horizontal non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2023, although we did participate in the drilling and completion of 22 gross (0.4 net) non-operated Haynesville shale wells and one gross (0.4 net) non-operated South Texas well that began producing in 2023.
Current wording
During the year ended December 31, 2024, we completed and began producing oil and natural gas from 124 gross (101.9 net) operated and 127 gross (8.3 net) horizontal non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2024, although we did participate in the drilling and completion of eight gross (0.1 net) non-operated Haynesville shale wells that began producing in 2024.
Previous wording
Substantially all of our 2023 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, including properties acquired in the Advance Acquisition, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells drilled and completed in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions, including certain non-operated well opportunities, and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin.
Current wording
Substantially all of our 2024 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, including properties acquired in the Ameredev Acquisition, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin, including the Ameredev Acquisition.
Previous wording
Our average daily oil equivalent production for the year ended December 31, 2023 was 131,813 BOE per day, including 75,457 Bbl of oil per day and 338.1 MMcf of natural gas per day, an increase of 25%, as compared to 105,465 BOE per day, including 60,119 Bbl of oil per day and 272.1 MMcf of natural gas per day, for the year ended December 31, 2022. Our average daily oil production in 2023 was 75,457 Bbl of oil per day, an increase of 26%, as compared to 60,119 Bbl of oil per day in 2022. This increase in oil production was primarily a result of the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining oil production in the Eagle Ford shale where we have not turned to sales any new operated wells since the second quarter of 2019. Our average daily natural gas production for the year ended December 31, 2023 was 338.1 MMcf per day, an increase of 24%, as compared to 272.1 MMcf per day in 2022. This increase in natural gas production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised 57% of our total production for each of the years ended December 31, 2023 and 2022.
Current wording
Our average daily oil equivalent production for the year ended December 31, 2024 was 170,751 BOE per day, including 99,808 Bbl of oil per day and 425.7 MMcf of natural gas per day, an increase of 30%, as compared to 131,813 BOE per day, including 75,457 Bbl of oil per day and 338.1 MMcf of natural gas per day, for the year ended December 31, 2023. Our average daily oil production in 2024 was 99,808 Bbl of oil per day, an increase of 32%, as compared to 75,457 Bbl of oil per day in 2023. This increase in oil production was primarily a result of the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Our average daily natural gas production for the year ended December 31, 2024 was 425.7 MMcf per day, an increase of 26%, as compared to 338.1 MMcf per day in 2023. This increase in natural gas production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised 58% and 57% of our total production for the years ended December 31, 2024 and 2023, respectively.
Previous wording
For the year ended December 31, 2023, our oil and natural gas revenues were $2.55 billion, a decrease of 12% from oil and natural gas revenues of $2.91 billion for the year ended December 31, 2022. Our oil revenues increased 1% to $2.14 billion, as compared to $2.11 billion for the year ended December 31, 2022. The increase in oil revenues resulted from the 26% increase in our oil production noted above, which was partially offset by a 19% decrease in the weighted average oil price realized for the year ended December 31, 2023 to $77.88 per Bbl, as compared to $96.32 per Bbl realized for the year ended December 31, 2022. Our natural gas revenues decreased 49% to $400.7 million, as compared to $792.1 million for the year ended December 31, 2022. The decrease in natural gas revenues resulted from a decrease in our weighted average realized natural gas price of $3.25 per Mcf in 2023, as compared to $7.98 per Mcf in 2022, which was partially offset by the 24% increase in natural gas production for the year ended December 31, 2023 noted above.
Current wording
For the year ended December 31, 2024, our oil and natural gas revenues were $3.14 billion, an increase of 24% from oil and natural gas revenues of $2.55 billion for the year ended December 31, 2023. Our oil revenues increased 29% to 2.77 billion, as compared to $2.14 billion for the year ended December 31, 2023. The increase in oil revenues resulted from the 33% increase in our oil production noted above, which was partially offset by a 3% decrease in the weighted average oil price realized for the year ended December 31, 2024 to $75.89 per Bbl, as compared to $77.88 per Bbl realized for the year ended December 31, 2023. Our natural gas revenues decreased 7% to $371.5 million, as compared to $400.7 million for the year ended December 31, 2023. The decrease in natural gas revenues resulted from a decrease in our weighted average realized natural gas price of $2.38 per Mcf in 2024, as compared to $3.25 per Mcf in 2023, which was partially offset by the 26% increase in natural gas production for the year ended December 31, 2024 noted above.
Previous wording
We reported net income attributable to Matador shareholders of approximately $846.1 million, or $7.05 per diluted common share, on a GAAP basis for the year ended December 31, 2023, as compared to a net income of $1.21 billion, or $10.11 per diluted common share, for the year ended December 31, 2022. Adjusted EBITDA for the year ended December 31, 2023 was $1.85 billion, as compared to Adjusted EBITDA of $2.13 billion for the year ended December 31, 2022. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.”
Current wording
We reported net income attributable to Matador shareholders of approximately $885.3 million, or $7.14 per diluted common share, on a GAAP basis for the year ended December 31, 2024, as compared to a net income of $846.1 million, or $7.05 per diluted common share, for the year ended December 31, 2023. Adjusted EBITDA for the year ended December 31, 2024 was $2.30 billion, as compared to Adjusted EBITDA of $1.85 billion for the year ended December 31, 2023. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.”
Previous wording
At December 31, 2023, our estimated total proved oil and natural gas reserves were 460.1 million BOE, including 272.3 million Bbl of oil and 1.13 Tcf of natural gas, with a Standardized Measure of $6.11 billion and a PV-10 of $7.70 billion. At December 31, 2022, our estimated total proved oil and natural gas reserves were 356.7 million BOE, including 196.3 million Bbl of oil and 962.6 Bcf of natural gas, with a Standardized Measure of $6.98 billion and a PV-10 of $9.13 billion. Our estimated total proved reserves of 460.1 million BOE at December 31, 2023 represented a 29% year-over-year increase, as compared to 356.7 million BOE at December 31, 2022. Our estimated proved oil reserves were 272.3 million Bbl at December 31, 2023, an increase of 39%, as compared to 196.3 million Bbl at December 31, 2022, and our estimated proved natural gas reserves were 1.13 Tcf at December 31, 2023, an increase of 17%, as compared to 962.6 Bcf at December 31, 2022. Proved oil reserves comprised 59% of our total proved reserves at December 31, 2023, as compared to 55% at December 31, 2022. At December 31, 2023, 63% of our total proved reserves were proved developed reserves, as compared to 62% at December 31, 2022.
Current wording
At December 31, 2024, our estimated total proved oil and natural gas reserves were 611.5 million BOE, including 361.8 million Bbl of oil and 1.50 Tcf of natural gas, with a Standardized Measure of $7.38 billion and a PV-10 of $9.23 billion. At December 31, 2023, our estimated total proved oil and natural gas reserves were 460.1 million BOE, including 272.3 million Bbl of oil and 1.13 Tcf of natural gas, with a Standardized Measure of $6.11 billion and a PV-10 of $7.70 billion. Our estimated total proved reserves of 611.5 million BOE at December 31, 2024 represented a 33% year-over-year increase, as compared to 460.1 million BOE at December 31, 2023. Our estimated proved oil reserves were 361.8 million Bbl at December 31, 2024, an increase of 33%, as compared to 272.3 million Bbl at December 31, 2023, and our estimated proved natural gas reserves were 1.50 Tcf at December 31, 2024, an increase of 33%, as compared to 1.13 Tcf at December 31, 2023. Proved oil reserves comprised 59% of our total proved reserves at each of December 31, 2024 and 2023. At December 31, 2024, 60% of our total proved reserves were proved developed reserves, as compared to 63% at December 31, 2023. At December 31, 2024, approximately 99% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin.
Previous wording
San Mateo achieved strong operating results in 2023, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes. Volumes for the years ended December 31, 2023 and 2022 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues during the years ended December 31, 2023 and 2022. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point.
Current wording
San Mateo achieved strong operating results in 2024, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point.
Previous wording
During 2023, San Mateo closed new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin.
Current wording
During 2024, San Mateo and Pronto also closed new midstream transactions with oil and natural gas producers and other counterparties in Eddy and Lea Counties, New Mexico, which are expected to generate additional natural gas gathering and processing and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo and Pronto by existing customers, which we believe is indicative of the quality of service San Mateo and Pronto provides to all of its customers in the Delaware Basin.
Previous wording
At December 31, 2023, San Mateo’s midstream system included:
Current wording
At December 31, 2024, following the Pronto Transaction, San Mateo’s midstream system included:
Previous wording
•Natural Gas Assets: 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 160 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico;
Current wording
•Natural Gas Assets: 520 MMcf per day of designed natural gas cryogenic processing capacity and approximately 295 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico;
Previous wording
•Oil Assets: three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 100 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and
Current wording
•Oil Assets: three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 110 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and
Previous wording
•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.
Current wording
•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.
Previous wording
We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2024. We began 2024 operating seven contracted drilling rigs in the Delaware Basin and added an eighth operated drilling rig in the first quarter of 2024. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2024 estimated capital expenditure budget consists of $1.10 to $1.30 billion for D/C/E capital expenditures and $200.0 to $250.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2024 capital expenditures as well as the estimated 2024 capital expenditures for other wholly-owned midstream projects, including projects completed by Pronto. The midstream capital expenditure budget includes 100% of the costs associated with the Marlan Processing Plant expansion noted above, although, at February 20, 2024, we were continuing to evaluate potential partners in Pronto that would share in these capital expenditures and strategic opportunities. Substantially all of these 2024 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, South Texas and the Haynesville shale. Our 2024 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware
Current wording
We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2025 and currently operate nine drilling rigs in the Delaware Basin. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2025 estimated capital expenditure budget consists of $1.28 to $1.47 billion for D/C/E capital expenditures and $120.0 to $180.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2025 capital expenditures as well as the estimated 2025 capital expenditures for other wholly-owned midstream projects. Substantially all of these 2025 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities. Our 2025 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells.
Previous wording
At December 31, 2023, we had $52.7 million in cash (excluding restricted cash) and $772.6 million in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $1.325 billion). We expect to fund our 2024 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2024, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all.
Current wording
At December 31, 2024, we had $23.0 million in cash (excluding restricted cash) and $1.60 billion in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $2.25 billion). We expect to fund our 2025 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2025, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all.
Previous wording
Oil and natural gas revenues. Our oil and natural gas revenues decreased $360.1 million, or 12%, to $2.55 billion for the year ended December 31, 2023, as compared to $2.91 billion for the year ended December 31, 2022. Our oil revenues increased $31.3 million, or 1%, to $2.14 billion for the year ended December 31, 2023, as compared to $2.11 billion for the year ended December 31, 2022. This increase in oil revenues resulted from a 26% increase in our oil production to 27.5 million Bbl of oil for the year ended December 31, 2023, as compared to 21.9 million Bbl of oil for the year ended December 31, 2022, which was partially offset by a 19% decrease in the weighted average oil price realized for the year ended December 31, 2023 to $77.88 per Bbl, as compared to $96.32 per Bbl realized for the year ended December 31, 2022. The increase in oil production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues decreased by $391.4 million, or 49%, to $400.7 million for the year ended December 31, 2023, as compared to $792.1 million for the year ended December 31, 2022. The decrease in natural gas revenues was primarily attributable to the 59% decrease in the weighted average natural gas price realized for the year ended December 31, 2023 to $3.25 per Mcf, as compared to $7.98 per Mcf realized for the year ended December 31, 2022, which was partially offset by a 24% increase in our natural gas production to 123.4 Bcf for the year ended December 31, 2023, as compared to 99.3 Bcf for the year ended December 31, 2022. The increase in natural gas production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin.
Current wording
Oil and natural gas revenues. Our oil and natural gas revenues increased $598.2 million, or 24%, to $3.14 billion for the year ended December 31, 2024, as compared to $2.55 billion for the year ended December 31, 2023. Our oil revenues increased $627.5 million, or 29%, to $2.77 billion for the year ended December 31, 2024, as compared to $2.14 billion for the year ended December 31, 2023. This increase in oil revenues resulted from a 33% increase in our oil production to 36.5 million Bbl of oil for the year ended December 31, 2024, as compared to 27.5 million Bbl of oil for the year ended December 31, 2023, which was partially offset by a 3% decrease in the weighted average oil price realized for the year ended December 31, 2024 to $75.89 per Bbl, as compared to $77.88 per Bbl realized for the year ended December 31, 2023. The increase in oil production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues decreased by $29.2 million, or 7%, to $371.5 million for the year ended December 31, 2024, as compared to $400.7 million for the year ended December 31, 2023. The decrease in natural gas revenues was primarily attributable to the 27% decrease in the weighted average natural gas price realized for the year ended December 31, 2024 to $2.38 per Mcf, as compared to $3.25 per Mcf realized for the year ended December 31, 2023, which was partially offset by a 26% increase in our natural gas production to 155.8 Bcf for the year ended December 31, 2024, as compared to 123.4 Bcf for the year ended December 31, 2023. The increase in natural gas production was primarily attributable to the Ameredev Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin.
Previous wording
Third-party midstream services revenues. Our third-party midstream services revenues increased $31.5 million, or 35%, to $122.2 million for the year ended December 31, 2023, as compared to $90.6 million for the year ended December 31, 2022. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in our third-party natural gas gathering, transportation and processing revenues to $65.9 million for the year ended December 31, 2023, as compared to $45.1 million for the year ended December 31, 2022, which includes $15.9 million associated with operating our Pronto midstream assets for the year ended December 31, 2023, as compared to $4.4 million for the year ended December 31, 2022, and (ii) an increase in third-party produced water disposal revenues to $45.3 million for the year ended December 31, 2023, as compared to $35.6 million for the year ended December 31, 2022.
Current wording
Third-party midstream services revenues. Our third-party midstream services revenues increased $18.9 million, or 15%, to $141.0 million for the year ended December 31, 2024, as compared to $122.2 million for the year ended December 31, 2023. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in third-party produced water disposal revenues to $56.3 million for the year ended December 31, 2024, as compared to $45.3 million for the year ended December 31, 2023 and (ii) an increase in our oil transportation revenues to $17.3 million for the year ended December 31, 2024, as compared to $11.0 million for the year ended December 31, 2023.
Previous wording
Sales of purchased natural gas. Our sales of purchased natural gas decreased $50.5 million, or 25%, to $149.9 million for the year ended December 31, 2023, as compared to $200.4 million for the year ended December 31, 2022. This decrease was primarily the result of the 65% decrease in realized natural gas prices, which was partially offset by a 117% increase in natural gas volumes sold during the year ended December 31, 2023. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at Pronto’s Marlan Processing Plant or San Mateo’s Black River Processing Plant and subsequently sell the residue gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statements of income.
Current wording
Sales of purchased natural gas. Our sales of purchased natural gas increased $44.2 million, or 30%, to $194.1 million for the year ended December 31, 2024, as compared to $149.9 million for the year ended December 31, 2023. This increase was primarily the result of a 45% increase in natural gas volumes sold, which was partially offset by an 11% decrease in natural gas prices realized. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at San Mateo’s cryogenic natural gas processing plants and subsequently sell the residue natural gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statements of income.
Previous wording
Realized loss on derivatives. Our realized net loss on derivatives was $9.6 million for the year ended December 31, 2023, as compared to a realized net loss of approximately $157.5 million for the year ended December 31, 2022. We realized a net loss of approximately $9.6 million related to our natural gas costless collar and natural gas basis differential swap contracts for the year ended December 31, 2023, resulting primarily from natural gas basis differentials that were above the strike price of our natural gas basis differential swap contracts, offset by natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. We realized a net loss of approximately $81.7 million related to our natural gas costless collar contracts for the year ended December 31, 2022, resulting primarily from natural gas prices that were above the ceiling prices of certain of our natural gas costless collar contracts. We realized a net loss of $73.9 million related to our oil costless collar contracts for the year ended December 31, 2022, resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts. We realized a net loss of $1.9 million from our oil basis differential swap contracts for the year ended December 31, 2022, resulting from oil basis differentials that were above the fixed prices of certain of our oil basis differential swap contracts. We realized an average loss on our natural gas derivatives of approximately $0.08 per Mcf of natural gas produced during the year ended December 31, 2023, as compared to an average loss on our natural gas derivatives of approximately $0.83 per Mcf of natural gas produced during the year ended December 31, 2022. Our total natural gas volumes hedged represented 2% and 61% of our total natural gas production for the years ended December 31, 2023 and 2022, respectively.
Current wording
Realized gain (loss) on derivatives. Our realized net gain on derivatives was $12.7 million for the year ended December 31, 2024, as compared to a realized net loss of approximately $9.6 million for the year ended December 31, 2023. We realized a net gain of approximately $12.7 million related to our natural gas basis differential swap contracts for the year ended December 31, 2024, resulting primarily from natural gas basis differentials that were below the fixed prices of our natural gas basis differential swap contracts. We realized a net loss of approximately $9.6 million related to our natural gas costless collar and natural gas basis differential swap contracts for the year ended December 31, 2023, resulting primarily from natural gas basis differentials that were above the strike price of our natural gas basis differential swap contracts, offset by natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. We realized an average gain on our natural gas derivatives of approximately $0.09 per Mcf of natural gas produced during the year ended December 31, 2024, as compared to an average loss on our natural gas derivatives of approximately $0.08 per Mcf of natural gas produced during the year ended December 31, 2023.
Previous wording
Unrealized (loss) gain on derivatives. Our unrealized loss on derivatives was approximately $1.3 million for the year ended December 31, 2023, as compared to an unrealized gain of $18.8 million for the year ended December 31, 2022. During the year ended December 31, 2023, the aggregate net fair value of our open natural gas derivative contracts changed from a net asset of approximately $3.9 million to a net asset of approximately $2.7 million, resulting in an unrealized loss on derivatives of approximately $1.3 million for the year ended December 31, 2023. During the year ended December 31, 2022, the aggregate net fair value of our open oil and natural gas derivatives and oil basis differential swap contracts changed from a net liability of approximately $14.9 million to a net asset of approximately $3.9 million, resulting in an unrealized gain on derivatives of approximately $18.8 million for the year ended December 31, 2022.
Current wording
Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $13.3 million for the year ended December 31, 2024, as compared to an unrealized loss of $1.3 million for the year ended December 31, 2023. During the year ended December 31, 2024, the aggregate net fair value of our open oil costless collar and natural gas basis differential swap contracts changed from a net asset of approximately $2.7 million to a net asset of approximately $16.0 million, resulting in an unrealized gain on derivatives of approximately $13.3 million for the year ended December 31, 2024. During the year ended December 31, 2023, the aggregate net fair value of our open natural gas derivative contracts changed from a net asset of approximately $3.9 million to a net asset of approximately $2.7 million, resulting in an unrealized loss on derivatives of approximately $1.3 million for the year ended December 31, 2023.
Previous wording
Production taxes, transportation and processing. Our production taxes and transportation and processing expenses decreased $17.7 million, or 6%, to $264.5 million for the year ended December 31, 2023, as compared to $282.2 million for the year ended December 31, 2022. On a unit-of-production basis, our production taxes and transportation and processing expenses decreased 25% to $5.50 per BOE for the year ended December 31, 2023, as compared to $7.33 per BOE for the year ended December 31, 2022. These decreases were primarily attributable to the $22.7 million decrease in our production taxes to $200.2 million for the year ended December 31, 2023, as compared to $222.9 million for the year ended December 31, 2022, resulting from the $360.1 million decrease in oil and natural gas revenues for the year ended December 31, 2023, as compared to the year ended December 31, 2022, which was partially offset by the $5.0 million increase in transportation and processing expenses to $64.3 million for the year ended December 31, 2023, as compared to $59.3 million for the year ended December 31, 2022, primarily resulting from the 25% increase in total oil equivalent production between the respective periods.
Current wording
Production taxes, transportation and processing. Our production taxes and transportation and processing expenses increased $42.3 million, or 16%, to $306.8 million for the year ended December 31, 2024, as compared to $264.5 million for the year ended December 31, 2023. This increase was primarily attributable to the $43.4 million increase in our production taxes to $243.6 million for the year ended December 31, 2024, as compared to $200.2 million for the year ended December 31, 2023, primarily due to the $598.2 million increase in oil and natural gas revenues for the year ended December 31, 2024, as compared to the year ended December 31, 2023. On a unit-of-production basis, our production taxes and transportation and processing expenses decreased 11% to $4.91 per BOE for the year ended December 31, 2024, as compared to $5.50 per BOE for the year ended December 31, 2023. This decrease was primarily attributable to a decrease in transportation and processing expense per BOE that resulted from a mix of revenue contracts, including from San Mateo, between the two periods.
Previous wording
Lease operating expenses. Our lease operating expenses increased $86.6 million, or 55%, to $243.7 million for the year ended December 31, 2023, as compared to $157.1 million for the year ended December 31, 2022. On a unit-of-production basis, our lease operating expenses increased 24% to $5.06 per BOE for the year ended December 31, 2023, as compared to $4.08 per BOE for the year ended December 31, 2022. These increases for the year ended December 31, 2023 were primarily attributable to the increased number of wells being operated by us, including 127 wells from the Advance Acquisition, and other operators (where we own a working interest) and to operating cost inflation during the year-ended December 31, 2023, as compared to the year ended December 31, 2022.
Current wording
Lease operating expenses. Our lease operating expenses increased $97.9 million, or 40%, to $341.5 million for the year ended December 31, 2024, as compared to $243.7 million for the year ended December 31, 2023. On a unit-of-production basis, our lease operating expenses increased 8% to $5.47 per BOE for the year ended December 31, 2024, as compared to $5.06 per BOE for the year ended December 31, 2023. These increases for the year ended December 31, 2024 were primarily attributable to the increased number of wells being operated by us, including 204 wells from the Ameredev Acquisition, and other operators (where we own a working interest) and to operating cost inflation during the year ended December 31, 2024, as compared to the year ended December 31, 2023.
Previous wording
Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $33.4 million, or 35%, to $128.9 million for the year ended December 31, 2023, as compared to $95.5 million for the year ended December 31, 2022. This increase was primarily attributable to increased throughput volumes at San Mateo and Pronto from Matador and other customers, which resulted in (i) increased expenses associated with our expanded pipeline operations of $36.7 million for the year ended December 31, 2023, as compared to $24.9 million for the year ended December 31, 2022, (ii) increased expenses associated with our commercial produced water disposal operations of $53.6 million for the year ended December 31, 2023, as compared to $46.5 million for the year ended December 31, 2022, and (iii) increased expenses in connection with operating our Pronto midstream assets of $18.3 million for the year ended December 31, 2023, which assets were purchased on June 30, 2022, as compared to $8.3 million for the year ended December 31, 2022.
Current wording
Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $42.6 million, or 33%, to $171.5 million for the year ended December 31, 2024, as compared to $128.9 million for the year ended December 31, 2023. This increase was primarily attributable to increased throughput volumes at San Mateo from Matador and other customers, which resulted in (i) increased expenses associated with our expanded pipeline operations, including assets acquired in the Ameredev Acquisition, of $73.9 million for the year ended December 31, 2024, as compared to $41.4 million for the year ended December 31, 2023 and (ii) increased expenses associated with our commercial produced water disposal operations of $63.0 million for the year ended December 31, 2024, as compared to $53.6 million for the year ended December 31, 2023.
Previous wording
Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $250.3 million, or 54%, to $716.7 million for the year ended December 31, 2023, as compared to $466.3 million for the year ended December 31, 2022, primarily as a result of the Advance Acquisition and a 25% increase in our total oil equivalent production between the respective periods. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 23% to $14.90 per BOE for the year ended December 31, 2023, as compared to $12.11 per BOE for the year ended December 31, 2022, primarily as a result of the Advance Acquisition and an increase in actual costs and estimated future costs to drill, complete and equip our wells between the two periods.
Current wording
Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $257.6 million, or 36%, to $974.3 million for the year ended December 31, 2024, as compared to $716.7 million for the year ended December 31, 2023, primarily as a result of the Ameredev Acquisition and a 30% increase in our total oil equivalent production between the respective periods. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 5% to $15.59 per BOE for the year ended December 31, 2024, as compared to $14.90 per BOE for the year ended December 31, 2023, primarily as a result of the Ameredev Acquisition.
Previous wording
General and administrative. Our general and administrative expenses decreased $5.9 million, or 5%, to $110.4 million for the year ended December 31, 2023, as compared to $116.2 million for the year ended December 31, 2022. Our general and administrative expenses on a unit-of-production basis decreased 24% to $2.29 per BOE for the year ended December 31, 2023, as compared to $3.02 per BOE for the year ended December 31, 2022, primarily as a result of the 25% increase in our total oil equivalent production between the two periods.
Current wording
growth in our land, geoscience, drilling, completion, production, midstream and administration functions. Our general and administrative expenses on a unit-of-production basis decreased 11% to $2.04 per BOE for the year ended December 31, 2024, as compared to $2.29 per BOE for the year ended December 31, 2023, primarily as a result of the 30% increase in our total oil equivalent production between the two periods.
Previous wording
Interest expense. For the year ended December 31, 2023, we incurred total interest expense of approximately $143.7 million. We capitalized approximately $22.2 million of our interest expense on certain qualifying projects for the year ended December 31, 2023 and expensed the remaining $121.5 million to operations. For the year ended December 31, 2022, we incurred total interest expense of approximately $77.2 million. We capitalized approximately $10.1 million of our interest expense on certain qualifying projects for the year ended December 31, 2022 and expensed the remaining $67.2 million to operations. The increase in interest expense for the year ended December 31, 2023 is a result of borrowings under the Credit Agreement that were used in connection with the Advance Acquisition, borrowings under the San Mateo Credit Facility, the issuance of the 2028 Notes in April 2023 and the significant increase in interest rates between the two periods.
Current wording
Interest expense. For the year ended December 31, 2024, we incurred total interest expense of approximately $201.5 million. We capitalized approximately $29.8 million of our interest expense on certain qualifying projects for the year ended December 31, 2024 and expensed the remaining $171.7 million to operations. For the year ended December 31, 2023, we incurred total interest expense of approximately $143.7 million. We capitalized approximately $22.2 million of our interest expense on certain qualifying projects for the year ended December 31, 2023 and expensed the remaining $121.5 million to operations. The increase in interest expense for the year ended December 31, 2024 was primarily attributable to an increase in our average debt outstanding between the two periods. In April 2024, we completed the 2026 Notes Repurchase and the 2032 Notes Offering and in September 2024 we completed the 2033 Notes Offering, resulting in a net increase in our total senior notes outstanding to $2.15 billion at December 31, 2024 as compared to $1.20 billion at December 31, 2023. In connection with the 2026 Notes Repurchase, the amendment of our Credit Agreement in March 2024 and the amendment of the San Mateo Credit Facility in November 2024, we also incurred a loss of approximately $6.2 million included in interest expense for the year ended December 31, 2024.
Previous wording
Total income tax provision. We recorded a current income tax provision of $13.9 million and a deferred income tax provision of $172.1 million for the year ended December 31, 2023. Our effective income tax rate of 18% for the year ended December 31, 2023 differed from the U.S. federal statutory rate due primarily to recognizing research and experimental expenditure tax credits of $74.0 million, which were partially offset by permanent differences between book and taxable income and state taxes, primarily in New Mexico. We recorded a current income tax provision of $54.9 million and a deferred income tax provision of $344.5 million for the year ended December 31, 2022. Our effective income tax rate of 25% for the year ended December 31, 2022 differed from the U.S. federal statutory rate due primarily to permanent differences between book and taxable income and state taxes, primarily in New Mexico.
Current wording
Total income tax provision. We recorded a current income tax provision of $27.1 million and a deferred income tax provision of $265.3 million for the year ended December 31, 2024. Our effective income tax rate of 25% for the year ended December 31, 2024 differed from the U.S. federal statutory rate due primarily to state taxes, primarily in New Mexico. We recorded a current income tax provision of $13.9 million and a deferred income tax provision of $172.1 million for the year ended December 31, 2023. Our effective income tax rate of 18% for the year ended December 31, 2023 differed from the U.S. federal statutory rate due primarily to recognizing research and experimental expenditure tax credits of $74.0 million, which were partially offset by permanent differences between book and taxable income and state taxes, primarily in New Mexico.
Previous wording
Our primary use of capital has been, and we expect will continue during 2024 and for the foreseeable future to be, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. In April 2023, we closed the Initial Advance Acquisition that was funded through a combination of cash on hand and borrowings under our Credit Agreement. In addition, on April 11, 2023, we issued and sold $500.0 million in aggregate principal amount of 2028 Notes. We used the net proceeds from the sale of the 2028 Notes of approximately $487.6 million, after deducting the initial purchasers’ discounts and estimated offering expenses, to partially repay borrowings under our Credit Agreement. We expect to fund our 2024 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2024, we expect to fund any excess capital expenditures, including for significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital.
Current wording
Our primary use of capital has been, and we expect will continue during 2025 and for the foreseeable future to be, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. We expect to fund our 2025 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2025, we expect to fund any excess capital expenditures, including for significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital.
Previous wording
At December 31, 2023, we had cash totaling $52.7 million and restricted cash totaling $53.6 million, which was primarily associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.
Current wording
At December 31, 2024, we had cash totaling $23.0 million and restricted cash totaling $71.7 million, which was primarily associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.
Previous wording
At December 31, 2023, we had (i) $699.2 million of outstanding 5.875% senior notes due September 2026 (the “2026 Notes”), (ii) $500.0 million of outstanding 2028 Notes, (iii) $500.0 million of borrowings outstanding under the Credit Agreement and (iv) approximately $52.3 million in outstanding letters of credit issued pursuant to the Credit Agreement.
Current wording
At December 31, 2024, we had (i) $500.0 million of outstanding 6.875% senior notes due 2028 (the “2028 Notes”), (ii) $900.0 million of outstanding 2032 Notes, (iii) $750.0 million of outstanding 2033 Notes, (iv) $595.5 million of borrowings outstanding under the Credit Agreement and (v) approximately $52.9 million in outstanding letters of credit issued pursuant to the Credit Agreement.
Previous wording
In March 2023, the lenders under our Credit Agreement completed their review of our proved oil and natural gas reserves, and, as a result, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) reaffirm the borrowing base at $2.25 billion, (ii) increase the elected borrowing commitment from $775.0 million to $1.25 billion and (iii) maintain the maximum facility amount at $1.50 billion. This March 2023 redetermination constituted the regularly scheduled May 1 redetermination.
Current wording
On March 22, 2024, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) reaffirm the borrowing base at $2.50 billion, (ii) increase the elected borrowing commitment from $1.325 billion to $1.50 billion, (iii) increase the maximum facility amount from $2.00 billion to $3.50 billion, (iv) extend the maturity date from October 31, 2026 to March 22, 2029, (v) appoint PNC Bank, National Association as administrative agent thereunder and (vi) add five new banks to the lending group. This March 2024 redetermination constituted the regularly scheduled May 1 redetermination.
Previous wording
In October 2023, the lenders under our Credit Agreement completed their review of the our proved oil and natural gas reserves, and, as a result, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) increase the borrowing base from $2.25 billion to $2.50 billion, (ii) increase the elected borrowing commitment from $1.25 billion to $1.325 billion and (iii) increase the maximum facility amount from $1.50 billion to $2.00 billion. This October 2023 redetermination constituted the regularly scheduled November 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment (subject to compliance with the covenants noted below). The Credit Agreement matures October 31, 2026.
Current wording
On September 18, 2024, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) provide for a term loan of $250.0 million, the full amount of which was borrowed to fund the Ameredev Acquisition, and (ii) increase the elected borrowing commitment from $1.50 billion to $2.25 billion.
Previous wording
The Credit Agreement requires us to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75 million of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less at the end of each fiscal quarter. We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2023.
Current wording
The Credit Agreement requires us to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities of debt, of not less than 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to the greater of $150 million or 10% of the elected borrowing commitments of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 or less at the end of each fiscal quarter. We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2024.
Previous wording
At December 31, 2023, San Mateo had $522.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. In October 2023, the lenders under the San Mateo Credit Facility increased the lender commitments from $485.0 million to $535.0 million. The San Mateo Credit Facility matures December 9, 2026.
Current wording
At December 31, 2024, San Mateo had $615.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. On November 26, 2024, San Mateo and its lenders entered into an amendment to the San Mateo Credit Facility to, among other things: (i) extend the maturity date of the facility from December 9, 2026 to November 26, 2029, (ii) increase the lender commitments from $535.0 million to $800.0 million and (iii) add six new banks to San Mateo’s lending group. The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in the commitments of the lenders to up to $1.05 billion.
Previous wording
The San Mateo Credit Facility is non-recourse with respect to Matador and its other subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2023.
Current wording
The San Mateo Credit Facility is non-recourse with respect to Matador and its other subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s debt to EBITDA ratio is greater than 4.50 or San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2024.
Previous wording
In February 2023, April 2023 and July 2023, our Board declared quarterly cash dividends of $0.15 per share of common stock. In October 2023, the Board amended our dividend policy to increase the quarterly dividend to $0.20 per share of common stock and also declared a quarterly cash dividend of $0.20 per share of common stock. On February 13, 2024, the Board declared a quarterly cash dividend of $0.20 per share of common stock payable on March 13, 2024 to shareholders of record as of February 23, 2024.
Current wording
In February 2024, April 2024 and July 2024, our Board declared quarterly cash dividends of $0.20 per share of common stock. In October 2024, the Board amended our dividend policy to increase the quarterly dividend to $0.25 per share of common stock and also declared a quarterly cash dividend of $0.25 per share of common stock. In February 2025, the Board amended our dividend policy to increase the quarterly dividend to $0.3125 per share of common stock and also declared a 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.
Previous wording
We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2024. We began 2023 operating seven drilling rigs in the Delaware Basin. Following the closing of the Initial Advance Acquisition on April 12, 2023, we continued operating the drilling rig that Advance had been operating. Near the end of June 2023, we released this eighth operated drilling rig and continued operating seven drilling rigs in the Delaware Basin for the remainder of 2023. We added back an eighth operated drilling rig in the first quarter of 2024. We have built significant optionality into our 2024 drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2024 estimated capital expenditure budget consists of $1.10 to $1.30 billion for D/C/E capital expenditures and $200.0 to $250.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2024 capital expenditures as well as the estimated 2024 capital expenditures for other wholly-owned midstream projects, including projects completed by Pronto. The midstream capital expenditure budget includes 100% of the costs associated with the Marlan Processing Plant expansion noted above, although, at February 20, 2024, we were continuing to evaluate potential partners in Pronto that would share in these capital expenditures and strategic opportunities. Substantially all of these 2024 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, South Texas and Haynesville shale. Our 2024 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells in 2024, including 99% with anticipated completed lateral lengths of one mile or greater.
Current wording
We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2025. We currently operate nine drilling rigs in the Delaware Basin. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2025 estimated capital expenditure budget consists of $1.28 to $1.47 billion for D/C/E capital expenditures and $120.0 to $180.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2025 capital expenditures as well as the estimated 2025 capital expenditures for other wholly-owned midstream projects. Substantially all of these 2025 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities. Our 2025 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells.
Previous wording
Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for 2024 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2024 and the hedges we currently have in place. For a discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below. At times, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2023. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”
Current wording
Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for 2025 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin. Our existing operated and non-operated wells may not produce at the levels we are forecasting or may be temporarily shut in or restricted due to low commodity prices, and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2025 and the hedges we currently have in place. For a discussion of our expectations of such commodity prices, see “—General Outlook and Trends” below. At times, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2024. See “Risk Factors—Risks Related to our Financial Condition—Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors—Risks Related to our Operations—Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors—Risks Related to our Operations—Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors—Risks Related to Laws and Regulations—Approximately 33% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”
Previous wording
Net cash provided by operating activities decreased by $110.9 million to $1.87 billion for the year ended December 31, 2023, as compared to net cash provided by operating activities of $1.98 billion for the year ended December 31, 2022. Excluding changes in operating assets and liabilities, net cash provided by operating activities decreased to $1.82 billion for the year ended December 31, 2023 from $2.10 billion for the year ended December 31, 2022. This decrease was primarily attributable to lower realized oil and natural gas prices for the year ended December 31, 2023, as compared to the year ended December 31, 2022, which was partially offset by the 25% increase in total oil equivalent production during 2023, as compared to 2022. Changes in our operating assets and liabilities between December 31, 2022 and December 31, 2023 resulted in a net increase of approximately $168.0 million in net cash provided by operating activities for the year ended December 31, 2023, as compared to the year ended December 31, 2022.
Current wording
Net cash provided by operating activities increased by $379.1 million to $2.25 billion for the year ended December 31, 2024, as compared to net cash provided by operating activities of $1.87 billion for the year ended December 31, 2023. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased to $2.23 billion for the year ended December 31, 2024 from $1.82 billion for the year ended December 31, 2023. This increase was primarily attributable to the 30% increase in total oil equivalent production during 2024, as compared to 2023, which was partially offset by lower realized oil and natural gas prices for the year ended December 31, 2024, as compared to the year ended December 31, 2023. Changes in our operating assets and liabilities between December 31, 2023 and December 31, 2024 resulted in a net decrease of approximately $36.9 million in net cash provided by operating activities for the year ended December 31, 2024, as compared to the year ended December 31, 2023.
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Rearranged current paragraphs (2)
Current report — wording carried from elsewhere
Net Cash Provided by Operating Activities
Current report — wording carried from elsewhere
Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years. In recent years, concerns about natural gas pipeline takeaway capacity out of the Delaware Basin began to increase and a result, the Waha-Henry Hub basis differential began to widen. The Waha-Henry Hub basis differential averaged ($2.20) per MMBtu for the year ended December 31, 2024. Between December 31, 2024 and February 18, 2025, this natural gas price differential widened to approximately ($2.70) per MMBtu. A significant portion of our
Rearranged previous paragraphs (2)
Previous report — wording carried elsewhere
Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells, including 99% with anticipated completed lateral lengths of greater than one mile.
Previous report — wording carried elsewhere
Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “—Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference.