EDGAR 10-K Filing

Company CIK: 1520006
Filing Year: 2024
Filename: 1520006_10-K_2024_0001520006-24-000078.json

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ITEM 1. BUSINESS
Item 1. Business.
In 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. For certain oil and natural gas terms used in this Annual Report, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report.
General
We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. 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.
We are a Texas corporation founded in July 2003 by Joseph Wm. 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. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all-cash transaction for an enterprise value of approximately $388.5 million.
On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock.
Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows and providing midstream services at an attractive rate of return on invested capital. 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.
The successful execution of our business strategies, including the Advance Acquisition, led to increases in our oil and natural gas production and proved oil and natural gas reserves in 2023. We also improved the capital efficiency of our drilling and completion operations and achieved several key operational milestones throughout the year (as further described below in “-Exploration and Production Segment-Southeast New Mexico and West Texas-Delaware Basin”). 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. Further, we completed several important financing transactions in 2023, including the issuance of the 2028 Notes (as defined below), increasing the elected borrowing commitment and the borrowing base under our Credit Agreement (as defined below) and increasing the lender commitments under the San Mateo Credit Facility (as defined below). San Mateo also achieved important milestones in 2023, including the addition of produced water disposal capacity and being awarded new customer contracts. These actions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position.
2023 Highlights
Advance Acquisition
On April 12, 2023, we completed the Initial Advance Acquisition, pursuant to which our wholly-owned subsidiary acquired Advance from affiliates of EnCap Investments L.P., including certain oil and natural gas producing properties, undeveloped acreage and midstream assets located primarily in Lea County, New Mexico and Ward County, Texas. The Initial Advance Acquisition had an effective date of January 1, 2023 and an aggregate purchase price consisting of (i) an amount in cash equal to approximately $1.60 billion (which amount was subject to certain customary post-closing adjustments) (the “Cash Consideration”) and (ii) potential additional cash consideration of $7.5 million for each month of 2023 in which the average oil price (as defined in the securities purchase agreement) exceeded $85 per barrel (all such payments for the 12 months in 2023, the “Contingent Consideration”). The Cash Consideration was paid upon the closing of the Initial Advance Acquisition and was funded by a combination of cash on hand and borrowings under the Credit Agreement. We made no payments related to the Contingent Consideration during the first, second or third quarters of 2023. In the fourth quarter of 2023, we paid Contingent Consideration of $15.0 million, as the average oil price for the months of September and October 2023 exceeded $85 per barrel.
On December 1, 2023, we completed the Advance Royalty Acquisition, pursuant to which we acquired additional interests from affiliates of EnCap Investments L.P., including overriding royalty interests and royalty interests in certain oil and natural gas properties located primarily in Lea County, New Mexico, most of which were included in the Initial Advance Acquisition. The Advance Royalty Acquisition had an effective date of October 1, 2023 with an aggregate purchase price of approximately $81.0 million (which amount is subject to certain customary post-closing adjustments) and was funded by cash on hand.
The results of operations for the Initial Advance Acquisition and the Advance Royalty Acquisition since the respective closing dates have been included in our consolidated financial statements for the year ended December 31, 2023. The oil and natural gas production from the Advance Acquisition increased our revenues and net income for the period from April 12, 2023 through December 31, 2023 by $398.9 million and $166.9 million, respectively. See Note 5 to the consolidated financial
statements in this Annual Report for more information regarding the Advance Acquisition. Such information is incorporated herein by reference.
Increased Oil, Natural Gas and Oil Equivalent Production
For the year ended December 31, 2023, we achieved record oil, natural gas and average daily oil equivalent production. In 2023, we produced 27.5 million Bbl of oil, an increase of 26%, as compared to 21.9 million Bbl of oil produced in 2022. We also produced 123.4 Bcf of natural gas, an increase of 24% from 99.3 Bcf of natural gas produced in 2022. 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. The increase in oil and natural gas production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin throughout 2023, which offset declining production in the Eagle Ford shale. Oil production comprised 57% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for each of the years ended December 31, 2023 and 2022.
Increased Oil, Natural Gas and Oil Equivalent Reserves
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, an increase of 29% from 356.7 million BOE, including 196.3 million Bbl of oil and 962.6 Bcf of natural gas, at December 31, 2022. The Standardized Measure of our total proved oil and natural gas reserves decreased 12% from $6.98 billion at December 31, 2022 to $6.11 billion at December 31, 2023. The PV-10 of our total proved oil and natural gas reserves decreased 16% from $9.13 billion at December 31, 2022 to $7.70 billion at December 31, 2023. The decreases in our Standardized Measure and PV-10 were primarily a result of the lower unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2023, as compared to December 31, 2022, partially offset by a 29% increase in our total proved oil and natural gas reserves at December 31, 2023, as compared to December 31, 2022. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “-Estimated Proved Reserves.”
At December 31, 2023, estimated proved developed reserves included 161.6 million Bbl of oil and 782.7 Bcf of natural gas, and estimated proved undeveloped reserves included 110.6 million Bbl of oil and 344.0 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 63% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2023. Proved developed reserves and proved oil reserves comprised 62% and 55%, respectively, of our total proved oil and natural gas reserves at December 31, 2022.
Operational Highlights
We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. 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.
We completed and began producing oil and natural gas from 222 gross (99.6 net) horizontal wells in the Delaware Basin in 2023, including 119 gross (94.0 net) operated and 103 gross (5.6 net) non-operated wells. At December 31, 2023, our total acreage position in the Delaware Basin was approximately 265,600 gross (152,200 net) acres, primarily in Lea and Eddy Counties, New Mexico and 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 and Ward Counties, Texas. Our Delaware Basin properties are the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 27% to 126,720 BOE per day (96% of total oil equivalent production), including 74,697 Bbl of oil per day (99% of total oil production) and 312.1 MMcf of natural gas per day (92% of total natural gas production), in 2023, as compared to 100,135 BOE per day (95% of total oil equivalent production), including 59,139 Bbl of oil per day (98% of total oil production) and 246.0 MMcf of natural gas per day (90% of total natural gas production), in 2022. We expect our Delaware Basin production to increase in 2024 as we continue the delineation and development of these asset areas.
During 2023, we achieved all five significant and important operational milestones in the Delaware Basin we set at the beginning of the year. These five operational milestones (as further described below in “-Exploration and Production Segment-Southeast New Mexico and West Texas-Delaware Basin”) were each achieved when we turned to sales:
•eight Rodney Robinson wells in the first half of 2023;
•eight Stateline wells in the first half of 2023;
•21 Ranger wells on properties acquired in the Advance Acquisition in the second half of 2023, which was the largest single batch development project in our history;
•17 Stebbins wells in the second half of 2023; and
•13 Wolf wells in the second half of 2023, including our first two “U-Turn” two-mile lateral wells.
In addition to achieving these five key operational milestones, other operational highlights in the Delaware Basin (as further described below in “-Exploration and Production Segment-Southeast New Mexico and West Texas-Delaware Basin”) in 2023 included:
•continued drilling of longer laterals, with average completed lateral length for operated wells turned to sales in 2023 of approximately 9,800 feet; and
•capital expenditures for drilling, completing and equipping wells (“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.
Capital Resources and Financing Highlights
During 2023, we achieved several significant and important capital resources objectives, which included:
•the generation of free cash flow in all four quarters of 2023;
•the amendment of our dividend policy in the fourth quarter of 2023, pursuant to which we increased the quarterly cash dividend from $0.15 per share of common stock to $0.20 per share of common stock; and
•the receipt of $38.2 million in performance incentives directly from Five Point.
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. These transactions included:
•the issuance of $500.0 million in aggregate principal amount of 6.875% senior notes due 2028 (the “2028 Notes”);
•the spring and fall redetermination under our Fourth Amended and Restated Credit Agreement (the “Credit Agreement”) to collectively (i) increase the borrowing base to $2.50 billion, as compared to $2.25 billion at December 31, 2022, (ii) increase the elected borrowing commitment to $1.325 billion, as compared to $775.0 million at December 31, 2022, (iii) increase the maximum facility amount to $2.00 billion, as compared to $1.50 billion at December 31, 2022 and (iv) add two new banks to our lending group; and
•the amendment of San Mateo’s revolving credit facility (the “San Mateo Credit Facility”) in October 2023 to (i) increase the lender commitments from $485.0 million to $535.0 million and (ii) add a new bank to San Mateo’s lending group.
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources” for additional information regarding these financing transactions.
Midstream Highlights
Matador conducts its midstream operations primarily through San Mateo, which is owned 51% by us and 49% by our joint venture partner, Five Point, and through Pronto, which is our wholly-owned subsidiary.
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.
During 2023, San Mateo closed new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin.
At December 31, 2023, San Mateo’s midstream system included:
•Natural Gas Assets: 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 160 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”);
•Oil Assets: three oil central delivery points (“CDP”) 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 Marketing, L.P. (“Plains”) to gather our and other producers’ oil production in Eddy County, New Mexico; and
•Produced Water Assets: 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 175 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.
During 2023, Pronto closed new natural gas gathering and processing transactions with counterparties in Eddy and Lea Counties, New Mexico, which are expected to generate additional natural gas gathering and processing volumes in future periods. At December 31, 2023, Pronto’s midstream system included a cryogenic natural gas processing plant with a designed inlet processing capacity of 60 MMcf per day (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.
Environmental, Social and Governance (“ESG”) Initiatives
We are committed to creating long-term value in a responsible manner. Our aim is to reliably and profitably provide the energy that society needs in a manner that is safe, protects the environment and is consistent with the industry’s best practices and highest applicable regulatory and legal standards. More recently, we have begun formally reporting on our stewardship efforts in our annual Sustainability Report using quantitative metrics aligned with standards developed by an industry leader, the Sustainability Accounting Standards Board (SASB).
Highlights from our ESG initiatives, which generally relate to our operations in 2022 except as otherwise noted, include:
•decreased direct greenhouse gas emissions intensity by 44% in 2022, as compared to 2019;
•decreased methane emissions intensity by 61% in 2022, as compared to 2019;
•decreased flaring intensity by 84% in 2022, as compared to 2019;
•increased use of non-fresh water to 99% of total water consumption in 2022;
•increased number of wells utilizing recycled produced water to 72% of total wells completed in 2022, as compared to 16% in 2019;
•transported 98% of operated produced water and 94% of operated produced oil by pipeline in 2023; and
•provided approximately 22,000 hours of employee continuing education, equating to approximately 59 hours per employee in 2023.
These sustainability metrics have been calculated using the best information available to us. The data utilized in calculating such metrics is subject to certain reporting rules, regulatory reviews, definitions, calculation methodologies, estimates, adjustments and other factors. We expect to complete the review of fiscal year 2023 data from our ESG initiatives in the second half of 2024 in connection with the preparation of our 2023 Sustainability Report.
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. During 2023, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations and midstream operations in the Wolfcamp and Bone Spring plays in the Delaware Basin. Since our inception, our exploration and development efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions.
The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2023.
Producing Total Identified Estimated Net Proved
Wells Drilling Locations(1)
Reserves(2)
Avg. Daily
Gross Net Gross Net Gross Net % Production
Acreage Acreage MBOE(3)
Developed (BOE/d)(3)
Southeast New Mexico/West Texas:
Delaware Basin(4)
265,600 152,200 1,475 756.2 4,640 1,627 452,616 63.0 126,720
South Texas:
Eagle Ford(5)
14,400 12,100 89 72.1 114 88 3,048 100.0 1,068
Northwest Louisiana
Haynesville 16,200 8,900 256 18.1 138 13 3,847 100.0 3,761
Cotton Valley(6)
15,700 14,800 66 39.0 148 35 559 100.0 264
Area Total(7)
18,500 17,300 322 57.1 286 48 4,406 100.0 4,025
Total 298,500 181,600 1,886 885.4 5,040 1,762 460,070 63.5 131,813
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(1)Identified and engineered drilling locations. 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. Individual horizontal drilling locations generally represent a variety of lateral lengths, from one mile to greater than two miles, based upon our current assumptions for a well that could be drilled at that location given our current acreage position. At December 31, 2023, approximately two-thirds of these identified drilling locations in the Delaware Basin were expected to be horizontal laterals with lateral lengths of approximately two miles or greater, and approximately 83% are expected to have lateral lengths of approximately 1.5 miles or greater. At December 31, 2023, these engineered drilling locations included 470 gross (206 net) operated and non-operated locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Yeso and Avalon formations, in the Delaware Basin. At December 31, 2023, we had assigned no proved undeveloped reserves to our leasehold in the Eagle Ford shale or in Northwest Louisiana.
(2)These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. For additional information regarding our oil and natural gas reserves, see “-Estimated Proved Reserves” and Supplemental Oil and Natural Gas Disclosures included in the unaudited supplementary information in this Annual Report, which is incorporated herein by reference.
(3)Production volumes and proved reserves reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(4)Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring, Brushy Canyon and Avalon plays on our acreage in the Delaware Basin at December 31, 2023.
(5)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.
(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. 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. In those wells where we are not the operator, our working interests are often relatively small. At December 31, 2023, we also operated approximately 90% of our Eagle Ford acreage and approximately 51% of our Haynesville acreage.
While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves.
Southeast New Mexico and West Texas - Delaware Basin
The greater Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production region with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin had focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology has enhanced the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp formation and in the low permeability sand and carbonate reservoirs of the Bone Spring, Brushy Canyon and Avalon formations.
In the western part of the Permian Basin, also known as the Delaware Basin, there are multiple horizontal targets in a given area that exist within the several thousand feet of hydrocarbon bearing layers that make up the Bone Spring and Wolfcamp plays. Multiple horizontal drilling and completion targets are being identified and targeted by companies, including us, throughout the vertical section, including the Brushy Canyon, Avalon and Bone Spring (First, Second and Third Sand and Carbonate) and several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D.
At December 31, 2023, our total acreage position in Southeast New Mexico and West Texas was approximately 265,600 gross (152,200 net) acres, primarily in Lea and Eddy Counties, New Mexico and Loving and Ward Counties, Texas. These acreage totals included approximately 62,500 gross (36,200 net) acres in our Ranger asset area in Lea County, 58,000 gross (23,300 net) acres in our Arrowhead asset area in Eddy County, 45,700 gross (26,100 net) acres in our Rustler Breaks asset area in Eddy County, 31,900 gross (21,100 net) acres in our Antelope Ridge asset area in Lea County, 2,900 gross (2,900 net) acres in our Stateline asset area in Eddy County, 42,900 gross (27,100 net) acres in our Twin Lakes asset area in Lea County and 21,200 gross (15,000 net) acres in our Wolf, Jackson Trust and Quito asset areas in Loving and Ward County (collectively “West Texas”) at December 31, 2023. We consider the vast majority of our Delaware Basin acreage position to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Brushy Canyon and Avalon formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka, Yeso and Morrow formations. At December 31, 2023, our acreage position in the Delaware Basin was approximately 78% held by existing production. Excluding the undeveloped acreage acquired in the Bureau of Land Management New Mexico Oil and Gas Lease Sale on September 5 and 6, 2018 (the “BLM Acquisition”), which has 10-year leases with favorable lease-holding provisions, and the Twin Lakes asset area, our acreage position in the Delaware Basin was approximately 96% held by existing production at December 31, 2023.
During the year ended December 31, 2023, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 222 gross (99.6 net) horizontal wells in the Delaware Basin, including 119 gross (94.0 net) operated horizontal wells and 103 gross (5.6 net) non-operated horizontal wells, throughout our various asset areas. 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.
As a result of our ongoing drilling and completion operations in these asset areas and the Advance Acquisition, our Delaware Basin production increased significantly in 2023. Our average daily oil equivalent production from the Delaware Basin increased approximately 27% to 126,720 BOE per day (96% of total oil equivalent production), including 74,697 Bbl of oil per day (99% of total oil production) and 312.1 MMcf of natural gas per day (92% of total natural gas production), in 2023, as compared to 100,135 BOE per day (95% of total oil equivalent production), including 59,139 Bbl of oil per day (98% of total oil production) and 246.0 MMcf of natural gas per day (90% of total natural gas production), in 2022.
At December 31, 2023, approximately 98% of our estimated total proved oil and natural gas reserves, or 452.6 million BOE, was attributable to the Delaware Basin, including approximately 270.1 million Bbl of oil and 1.09 Tcf of natural gas, a 31% increase, as compared to 346.8 million BOE for the year ended December 31, 2022. Our Delaware Basin proved reserves at December 31, 2023 comprised approximately 99% of our proved oil reserves and 97% of our proved natural gas reserves, as compared to approximately 99% of our proved oil reserves and 96% of our proved natural gas reserves at December 31, 2022.
At December 31, 2023, we had identified 4,640 gross (1,627 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp and Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations. These locations include 2,287 gross (1,437 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Individual horizontal drilling locations represent a variety of lateral lengths, from one mile to greater than two miles based upon our current assumptions for a well that could be drilled at specified locations given our current acreage position. At December 31, 2023, approximately two-thirds of these identified drilling locations are expected to have horizontal lateral lengths of approximately two miles or greater and approximately 83% are expected to have horizontal lateral lengths of approximately 1.5 miles or greater. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Delaware Basin wells and other nearby wells based on available public data, drilling densities anticipated on our properties and properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. 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. Although we believe that denser well spacing may be possible in certain asset areas or in certain formations, at December 31, 2023, the majority of our estimated locations were based on the assumption of 160-acre well spacing. As we explore and develop our Delaware Basin acreage
further, we anticipate that we may identify additional locations for future drilling. At December 31, 2023, these potential future drilling locations included 470 gross (206 net) operated and non-operated locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Yeso and Avalon, to which we have assigned proved undeveloped reserves.
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.
Antelope Ridge Asset Area - Lea County, New Mexico
In the Antelope Ridge asset area, we turned to sales 20 gross (16.8 net) operated wells and 18 gross (0.9 net) non-operated wells during 2023.
The 1,300 gross and net acre Rodney Robinson leasehold is one of the key tracts we acquired in the BLM Acquisition. The federal leases provide an 87.5% net revenue interest (“NRI”) as compared to an approximately 75% NRI on most fee leases today. At the end of the first quarter of 2023, we achieved one of our five operational milestones we set for Matador in 2023 when we turned to sales eight gross (7.7 net) wells on the Rodney Robinson leasehold. These wells were the fourth group of wells drilled on the Rodney Robinson leasehold. The eight Rodney Robinson wells, which included four Second Bone Spring Carbonate, two Third Bone Spring Carbonate, and two Wolfcamp B completions, have produced in aggregate approximately 1.7 million BOE in approximately 10 months of production.
We turned to sales an additional 12 gross (9.1 net) operated wells in the Antelope Ridge asset area at various times during 2023. In total, these 12 Antelope Ridge wells, which included one First Bone Spring Sand, five Second Bone Spring Sand, two Third Bone Spring Sand, three Wolfcamp A and one Wolfcamp B completions, have produced in aggregate approximately 1.4 million BOE in an average of approximately six months of production.
Stateline Asset Area - Eddy County, New Mexico
During the second quarter of 2023, we achieved another of our five operational milestones when we turned to sales eight gross (8.0 net) wells in the Stateline asset area. These wells, which included four Wolfcamp B, two Upper Avalon and two Lower Avalon completions, have produced in aggregate approximately 1.8 million BOE in approximately six months of production. These eight wells had average completed lateral lengths of approximately 11,100 feet.
Ranger and Twin Lakes Asset Areas - Lea County, New Mexico
In the Ranger asset area, we turned to sales 40 gross (33.1 net) operated wells and 11 gross (0.7 net) non-operated wells during 2023. In the Twin Lakes asset area, we did not turn to sales or participate in any horizontal operated or non-operated wells during 2023.
In the third quarter of 2023, we achieved another of our five operational milestones when we turned to sales 21 gross (20.4 net) wells in the Ranger asset area that were acquired as part of the Advance Acquisition. Each of these wells had a lateral length of 2.25 miles, resulting in approximately 240,000 completed lateral feet, which was the largest single batch development project in Matador’s history. These wells included three Second Bone Spring Carbonate, six Second Bone Spring Sand, six Third Bone Spring Carbonate, three Third Bone Spring Sand and three Wolfcamp A completions, which averaged 24-hour initial production tests of 1,600 BOE per day with oil cuts averaging 84% and have in aggregate produced 2.4 million BOE in approximately four months of production.
We turned to sales an additional 19 gross (12.7 net) wells in the Ranger asset area at various times during 2023, which included three First Bone Spring Sand, seven Second Bone Spring Sand, one Third Bone Spring Carbonate, seven Third Bone Spring Sand and one Wolfcamp A completions. These wells have in aggregate produced 2.1 million BOE in an average of approximately six months of production.
Arrowhead Asset Area - Eddy County, New Mexico
During the fourth quarter of 2023, we achieved another of our five operational milestones when we turned to sales 17 gross (10.6 net) Stebbins wells in the Arrowhead asset area. These wells, which included eight Wolfcamp A, seven Second Bone Spring and two First Bone Spring completions, have produced in aggregate approximately 1.2 million BOE in approximately two months of production. These 17 wells had average completed lateral lengths of approximately 8,800 feet.
We also turned to sales 30 gross (1.8 net) non-operated wells in the Arrowhead asset area during 2023.
West Texas Asset Area - Loving and Ward Counties, Texas
During the fourth quarter of 2023, we achieved another of our five operational milestones when we turned to sales 13 gross (11.2 net) wells in the Wolf portion of the West Texas asset area. These wells, which included seven Wolfcamp B, five Wolfcamp A and one Third Bone Spring Carbonate completions, have produced in aggregate approximately 0.6 million BOE in approximately two months of production. These 13 wells had average completed lateral lengths of approximately 10,600 feet.
We also turned to sales 17 gross (0.2 net) non-operated wells in the West Texas asset area during 2023.
Rustler Breaks Asset Area - Eddy County, New Mexico
We turned to sales 21 gross (14.3 net) operated wells in the Rustler Breaks asset area at various times in the first, second and third quarters of 2023. In total, these 21 Rustler Breaks wells, which included two First Bone Spring Sand, eight Second Bone Spring Sand, six Wolfcamp A and five Wolfcamp B completions, have produced in aggregate approximately 3.9 million BOE in an average of approximately eight months of production.
We also turned to sales 23 gross (1.8 net) non-operated wells in the Rustler Breaks asset area during 2023.
South Texas - Eagle Ford Shale and Other Formations
At December 31, 2023, our properties included approximately 14,400 gross (12,100 net) acres in the Eagle Ford shale play in South Texas. We believe that approximately 76% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate, with the remainder being prospective for less liquids-rich natural gas. All of our Eagle Ford leasehold was held by existing production at December 31, 2023.
We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2023, although we did participate in one gross (0.4 net) non-operated well that turned to sales in 2023. 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. As a result of not completing any new operated wells since 2019 and our asset sales during the year, our average daily oil equivalent production from the Eagle Ford shale decreased 22% to 1,068 BOE per day, including 755 Bbl of oil per day and 1.9 MMcf of natural gas per day, during 2023, as compared to 1,373 BOE per day, including 971 Bbl of oil per day and 2.4 MMcf of natural gas per day, during 2022. For each of the years ended December 31, 2023 and 2022, 1% of our total daily oil equivalent production was attributable to the Eagle Ford shale.
At December 31, 2023, approximately 1% of our estimated total proved oil and natural gas reserves, or 3.0 million BOE, was attributable to the Eagle Ford shale, including approximately 2.1 million Bbl of oil and 5.5 Bcf of natural gas. 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.
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.
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. We operate substantially all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. 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.
For the year ended December 31, 2023, approximately 3% of our average daily oil equivalent production, or 4,025 BOE per day, including five Bbl of oil per day and 24.1 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2022, approximately 4% of our average daily oil equivalent production, or 3,957 BOE per day, including nine Bbl of oil per day and 23.7 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana. For the year ended December 31, 2023, approximately 7% of our daily natural gas production, or 24.1 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2022, approximately 9% of our daily natural gas production, or 23.7 MMcf of natural gas per day, was attributable to these properties. At December 31, 2023, approximately 1% of our estimated total proved reserves, or 4.4 million BOE, was attributable to our properties in Northwest Louisiana.
Midstream Segment
Our midstream segment conducts midstream operations in support of our exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.
Southeast New Mexico and West Texas - Delaware Basin
On February 17, 2017, we announced the formation of San Mateo, a strategic joint venture with Five Point. The midstream assets that were contributed to San Mateo included (i) San Mateo’s Black River cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) (before its expansions); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the West Texas asset area and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks asset area and in Loving County, Texas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo and had the potential to earn up to $73.5 million in performance incentives over a five-year period, which in October 2020 was extended by an additional year to January 31, 2023. Through January 31, 2023, we had earned all of the potential $73.5 million in performance incentives. In connection with the formation of San Mateo, we dedicated to San Mateo current and certain future leasehold interests in the Rustler Breaks asset area and the Wolf portion of the West Texas asset area pursuant to 15-year, fixed fee oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated current and certain future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15-year, fixed fee natural gas processing agreement.
On February 25, 2019, we announced the formation of San Mateo Midstream II, LLC (“San Mateo II”), a strategic joint venture with Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. In addition, Five Point committed to pay $125.0 million of the first $150.0 million of capital expenditures incurred by San Mateo II to develop facilities in the Greater Stebbins Area and the Stateline asset area. The $150.0 million threshold for capital expenditures was reached during 2020 and additional capital expenditures are the responsibility of the Company and Five Point based on each company’s proportionate interest in San Mateo. In addition, we have the ability to earn up to $150.0 million in performance incentives through mid-2024, plus additional performance incentives for securing volumes from third-party customers. Through February 20, 2024, we had received $85.7 million of the potential $150.0 million in performance incentives. In connection with the formation of San Mateo II, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering, natural gas processing and produced water disposal agreements.
Effective October 1, 2020, San Mateo II merged with and into San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. San Mateo provides firm service to us, while also being a midstream service provider to other customers in and around our Stateline, West Texas and Rustler Breaks asset areas and the Greater Stebbins Area. We retain operational control of San Mateo and continue to operate the Delaware Midstream Assets, the expanded Black River Processing Plant and the other midstream facilities that have been developed in the Greater Stebbins Area and the Stateline asset area.
On June 30, 2022, we acquired the Marlan Processing Plant, three compressor stations and approximately 45 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico as part of the Pronto Acquisition.
Natural Gas Gathering and Processing Assets
The Black River Processing Plant and associated gathering system were originally built to support our ongoing and future development efforts in the Rustler Breaks asset area and to provide us with firm takeaway and processing services for our Rustler Breaks natural gas production. We had previously completed the installation and testing of a 12-inch natural gas trunk line and associated gathering lines running throughout the length of our Rustler Breaks acreage position, and these natural gas gathering lines are being used to gather almost all of our operated natural gas production at Rustler Breaks.
In 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant to add an incremental designed inlet capacity of 200 MMcf of natural gas per day to the existing designed inlet capacity of 260 MMcf of natural gas per day, bringing the total designed inlet capacity to 460 MMcf of natural gas per day. 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 Black River Processing Plant also processes natural gas from our Rustler Breaks asset area and provides natural gas processing services for other San Mateo customers in the area.
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, 2023, 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, 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. San Mateo’s customers receive (i) firm NGL takeaway out of the Delaware Basin, (ii) increased NGL recoveries, (iii) improved pricing realizations through lower transportation and fractionation costs, (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired, and (v) a reliable alternative to pipe rather than to truck NGLs during severe weather events and otherwise.
In the Wolf portion of the West Texas asset area in Loving County, Texas, San Mateo gathers our natural gas production with the natural gas gathering system we retained following the sale of our wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the West Texas asset area, including a cryogenic natural gas processing plant and approximately six miles of high-pressure gathering pipelines.
At December 31, 2023, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2023, San Mateo gathered an average of approximately 358 MMcf of natural gas per day, an increase of 25% as compared to 287 MMcf of natural gas per day gathered during the year ended December 31, 2022. In addition, during the year ended December 31, 2023, San Mateo processed approximately 381 MMcf of natural gas per day at the Black River Processing Plant, an increase of 32%, as compared to 289 MMcf of natural gas per day processed during the year ended December 31, 2022. Natural gas gathering and processing 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.
At December 31, 2023, Pronto owned (i) the Marlan Processing Plant, (ii) three compressor stations and (iii) approximately 70 miles of natural gas gathering pipelines in Lea and Eddy Counties, New Mexico. During the year ended December 31, 2023, Pronto processed an average of approximately 41 MMcf of natural gas per day.
Crude Oil Gathering and Transportation Assets
San Mateo and Plains have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within a joint development area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets.
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. With these oil gathering and transportation systems (collectively with the crude oil gathering and transportation system in the Rustler Breaks asset area and the crude oil gathering system in the West Texas asset area, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2023, we estimated almost all of our oil production from the Stateline, West Texas and Rustler Breaks asset areas and the Greater Stebbins Area was transported by pipeline.
At December 31, 2023, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from points of origin in Eddy County, New Mexico and Loving County, Texas to interconnects with Plains and two trucking facilities. During the year ended December 31, 2023, the San Mateo Oil Pipeline Systems had throughput of approximately 43,600 Bbl of oil per day, a decrease of 10%, as compared to throughput of approximately 48,300 Bbl of oil per day during the year ended December 31, 2022.
Produced Water Gathering and Disposal Assets
During 2023, San Mateo placed into service one commercial salt water disposal well in the Greater Stebbins Area, bringing San Mateo’s commercial salt water disposal well count in the Greater Stebbins Area to four. In addition to its four commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, at February 20, 2024, San Mateo had nine commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, three commercial salt water disposal wells and associated facilities in the West Texas asset area and produced water gathering systems in the Stateline, Rustler Breaks and West Texas asset areas and the Greater Stebbins Area. At February 20, 2024, San Mateo had designed disposal capacity of approximately 475,000 Bbl of produced water per day.
During the year ended December 31, 2023, San Mateo handled approximately 376,000 Bbl of produced water per day, an increase of 4%, as compared to approximately 361,000 Bbl of produced water per day handled during the year ended December 31, 2022.
South Texas / Northwest Louisiana
In South Texas, we own a natural gas gathering system that gathers natural gas production from certain of our operated Eagle Ford leases. In Northwest Louisiana, we have midstream assets that gather natural gas from most of our operated leases. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo or Pronto.
Operating Summary
The following table sets forth certain unaudited production and operating data for the years ended December 31, 2023, 2022 and 2021.
Year Ended December 31,
2023 2022 2021
Unaudited Production Data:
Net Production Volumes:
Oil (MBbl) 27,542 21,943 17,840
Natural gas (Bcf) 123.4 99.3 81.7
Total oil equivalent (MBOE)(1)
48,112 38,495 31,454
Average daily production (BOE/d)(1)
131,813 105,465 86,176
Average Sales Prices:
Oil, without realized derivatives (per Bbl) $ 77.88 $ 96.32 $ 67.58
Oil, with realized derivatives (per Bbl) $ 77.88 $ 92.87 $ 56.70
Natural gas, without realized derivatives (per Mcf) $ 3.25 $ 7.98 $ 6.06
Natural gas, with realized derivatives (per Mcf) $ 3.17 $ 7.15 $ 5.74
Operating Expenses (per BOE):
Production taxes, transportation and processing $ 5.50 $ 7.33 $ 5.69
Lease operating $ 5.06 $ 4.08 $ 3.46
Plant and other midstream services operating $ 2.68 $ 2.48 $ 1.95
Depletion, depreciation and amortization $ 14.90 $ 12.11 $ 10.97
General and administrative $ 2.29 $ 3.02 $ 3.06
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(1)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2023 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.
Southeast
New Mexico/West Texas South 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
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(1)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.
(2)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas that was divested in September 2023.
(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(4)Excludes impact of derivative settlements.
(5)Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.
The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2022 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.
Southeast
New Mexico/West Texas South Texas Northwest Louisiana
Delaware Basin Eagle Ford(1)
Haynesville Cotton Valley(2)
Total
Annual Net Production Volumes
Oil (MBbl) 21,585 355 - 3 21,943
Natural gas (Bcf) 89.8 0.9 8.3 0.3 99.3
Total oil equivalent (MBOE)(3)
36,550 501 1,383 61 38,495
Percentage of total annual net production 94.9 % 1.3 % 3.6 % 0.2 % 100.0 %
Average Net Daily Production Volumes
Oil (Bbl/d) 59,139 971 - 9 60,119
Natural gas (MMcf/d) 246.0 2.4 22.7 1.0 272.1
Total oil equivalent (BOE/d) 100,135 1,373 3,789 168 105,465
Average Sales Prices(4)
Oil (per Bbl) $ 96.34 $ 95.23 $ - $ 91.53 $ 96.32
Natural gas (per Mcf) $ 8.18 $ 9.04 $ 5.81 $ 5.71 $ 7.98
Total oil equivalent (per BOE) $ 76.98 $ 83.24 $ 34.87 $ 37.23 $ 75.48
Production Costs(5)
Lease operating, transportation and processing (per BOE) $ 5.10 $ 27.41 $ 5.37 $ 22.69 $ 5.43
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(1)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.
(2)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(4)Excludes impact of derivative settlements.
(5)Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.
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.
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) 17,279 558 - 3 17,840
Natural gas (Bcf) 72.7 1.3 7.3 0.4 81.7
Total oil equivalent (MBOE)(3)
29,395 776 1,217 66 31,454
Percentage of total annual net production 93.4 % 2.5 % 3.9 % 0.2 % 100.0 %
Average Net Daily Production Volumes
Oil (Bbl/d) 47,339 1,528 - 9 48,876
Natural gas (MMcf/d) 199.2 3.6 20.0 1.0 223.8
Total oil equivalent (BOE/d) 80,534 2,126 3,334 182 86,176
Average Sales Prices(4)
Oil (per Bbl) $ 67.65 $ 65.41 $ - $ 64.40 $ 67.58
Natural gas (per Mcf) $ 6.33 $ 7.39 $ 3.19 $ 4.31 $ 6.06
Total oil equivalent (per BOE) $ 55.43 $ 59.49 $ 19.16 $ 27.81 $ 54.06
Production Costs(5)
Lease operating, transportation and processing (per BOE) $ 4.49 $ 19.51 $ 4.84 $ 25.69 $ 4.92
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(1)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. The two wells in Zavala County, Texas were divested in January 2022.
(2)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(4)Excludes impact of derivative settlements.
(5)Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.
Our total oil equivalent production of approximately 48.1 million BOE for the year ended December 31, 2023 increased 25% from our total oil equivalent production of approximately 38.5 million BOE for the year ended December 31, 2022. This increased production was primarily 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. Our average daily oil equivalent production for the year ended December 31, 2023 was 131,813 BOE per day, as compared to 105,465 BOE per day for the year ended December 31, 2022. Our average daily oil production for the year ended December 31, 2023 was 75,457 Bbl of oil per day, an increase of 26% from 60,119 Bbl of oil per day for the year ended December 31, 2022. Our average daily natural gas production for the year ended December 31, 2023 was 338.1 MMcf of natural gas per day, an increase of 24% from 272.1 MMcf of natural gas per day for the year ended December 31, 2022.
Our total oil equivalent production of approximately 38.5 million BOE for the year ended December 31, 2022 increased 22% from our total oil equivalent production of approximately 31.5 million BOE for the year ended December 31, 2021. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2022, which offset declining production in the Eagle Ford shale. Our average daily oil equivalent production for the year ended December 31, 2022 was 105,465 BOE per day, as compared to 86,176 BOE per day for the year ended December 31, 2021. Our average daily oil production for the year ended December 31, 2022 was 60,119 Bbl of oil per day, an increase of 23% from 48,876 Bbl of oil per day for the year ended December 31, 2021. Our average daily natural gas production for the year ended December 31, 2022 was 272.1 MMcf of natural gas per day, an increase of 22% from 223.8 MMcf of natural gas per day for the year ended December 31, 2021.
Producing Wells
The following table sets forth information relating to producing wells at December 31, 2023. 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%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells.
Oil Wells Natural Gas Wells Total Wells
Gross Net Gross Net Gross Net
Southeast New Mexico/West Texas:
Delaware Basin(1)
1,300 666.8 175 89.4 1,475 756.2
South Texas:
Eagle Ford(2)
89 72.1 - - 89 72.1
Northwest Louisiana:
Haynesville - - 256 18.1 256 18.1
Cotton Valley(3)
- - 66 39.0 66 39.0
Area Total - - 322 57.1 322 57.1
Total 1,389 738.9 497 146.5 1,886 885.4
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(1)Includes 223 gross (89.9 net) vertical wells that were primarily acquired in multiple transactions.
(2)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.
(3)Includes the Cotton Valley formation and shallower zones.
Estimated Proved Reserves
The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2023, 2022 and 2021. Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Delaware Basin and the Eagle Ford shale, the economic value of the NGLs associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the NGLs are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with SEC rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
At December 31,(1)
2023 2022 2021
Estimated Proved Reserves Data:(2)
Estimated proved reserves:
Oil (MBbl) 272,277 196,289 181,306
Natural Gas (Bcf) 1,126.8 962.6 852.5
Total (MBOE)(3)
460,070 356,722 323,397
Estimated proved developed reserves:
Oil (MBbl) 161,642 116,030 102,233
Natural Gas (Bcf) 782.7 632.9 546.2
Total (MBOE)(3)
292,097 221,507 193,262
Percent developed 63.5 % 62.1 % 59.8 %
Estimated proved undeveloped reserves:
Oil (MBbl) 110,635 80,259 79,073
Natural gas (Bcf) 344.0 329.7 306.4
Total (MBOE)(3)
167,973 135,215 130,135
Standardized Measure(4) (in millions)
$ 6,113.5 $ 6,983.2 $ 4,375.4
PV-10(5) (in millions)
$ 7,704.1 $ 9,132.2 $ 5,347.6
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(1)Numbers in table may not total due to rounding.
(2)Our estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2023 were $74.70 per Bbl for oil and $2.64 per MMBtu for natural gas, for the 12 months ended December 31, 2022 were $90.15 per Bbl for oil and $6.36 per MMBtu for natural gas and for the 12 months ended December 31, 2021 were $63.04 per Bbl for oil and $3.60 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead.
(3)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(4)Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.
(5)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 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. The discounted future income taxes at December 31, 2023, 2022 and 2021 were $1.59 billion, $2.15 billion and $972.2 million, respectively.
Our estimated total proved oil and natural gas reserves increased 29% from 356.7 million BOE at December 31, 2022 to 460.1 million BOE at December 31, 2023. This increase in proved oil and natural gas reserves was primarily attributable to the Advance Acquisition and our delineation and development operations in the Delaware Basin during 2023. We increased our total proved oil and natural gas reserves by 109.1 million BOE as a result of acquisitions and trades during 2023. We also added 88.3 million BOE in proved oil and natural gas reserves through extensions and discoveries during 2023, of which 27.6 million BOE resulted from new well locations turned to sales during 2023 to establish proved developed reserves and 60.7 million BOE resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2023. These increases were partially offset by the removal of 17.4 million BOE resulting from the 17% decrease in oil prices and the 58% decrease in natural gas prices used to estimate total proved reserves at December 31, 2023, as compared to December 31, 2022, and the removal of 31.5 million BOE in proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting primarily from changes in development plans for certain of our properties in the Delaware Basin. As we continue to develop our Delaware Basin assets, we may reclassify some or all of this 31.5 million BOE to proved reserves at a future date.
Our proved oil reserves grew 39% from approximately 196.3 million Bbl at December 31, 2022 to approximately 272.3 million Bbl at December 31, 2023. Our proved natural gas reserves increased 17% from 962.6 Bcf at December 31, 2022 to 1.13 Tcf at December 31, 2023. Our proved reserves to production ratio at December 31, 2023 was 9.6, an increase of 3% from 9.3 at December 31, 2022.
The Standardized Measure of our total proved oil and natural gas reserves decreased 12% from $6.98 billion at December 31, 2022 to $6.11 billion at December 31, 2023. The PV-10 of our total proved oil and natural gas reserves decreased 16% from $9.13 billion at December 31, 2022 to $7.70 billion at December 31, 2023. The decreases in our Standardized Measure and PV-10 are primarily a result of the lower unweighted arithmetic average oil and natural gas prices used to estimate proved reserves at December 31, 2023, as compared to December 31, 2022, partially offset by the 29% increase in our total proved oil and natural gas reserves at December 31, 2023, as compared to December 31, 2022. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2023 were $74.70 per Bbl and $2.64 per MMBtu, a decrease of 17% and 58%, respectively, as compared to average oil and natural gas prices of $90.15 per Bbl and $6.36 per MMBtu used to estimate proved reserves at December 31, 2022. Our total proved reserves were made up of 59% oil and 41% natural gas at December 31, 2023 and 55% oil and 45% natural gas at December 31, 2022. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table.
The following table summarizes changes in our estimated proved developed reserves at December 31, 2023.
Proved Developed Reserves
(MBOE)(1)
As of December 31, 2022 221,507
Extensions and discoveries 27,615
Net acquisitions of minerals-in-place 70,230
Revisions of prior estimates (14,071)
Production (48,112)
Conversion of proved undeveloped to proved developed 34,928
As of December 31, 2023 292,097
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(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
Our proved developed oil and natural gas reserves increased 32% from 221.5 million BOE at December 31, 2022 to 292.1 million BOE at December 31, 2023. We added 27.6 million BOE in proved developed reserves through extensions and discoveries during 2023, which resulted from new well locations drilled during 2023 to establish proved reserves. In addition, during 2023, we converted 34.9 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin. We also increased our proved developed reserves by 70.2 million BOE at December 31, 2023 as a result of property acquisitions, including the Advance Acquisition, and trades completed during 2023. 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. These cumulative net increases of 118.7 million BOE to our proved developed reserves exceeded by 2.5 times our total oil and natural gas production of 48.1 million BOE in 2023.
Our proved developed oil reserves increased 39% from 116.0 million Bbl at December 31, 2022 to 161.6 million Bbl at December 31, 2023. Our proved developed natural gas reserves increased 24% from 632.9 Bcf at December 31, 2022 to 782.7 Bcf at December 31, 2023. Proved developed reserves constituted 63% of our total proved oil and natural gas reserves at December 31, 2023, as compared to 62% at December 31, 2022.
The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2023.
Proved Undeveloped Reserves
(MBOE)(1)
As of December 31, 2022 135,215
Extensions and discoveries 60,724
Net acquisitions of minerals-in-place 38,872
Revisions of prior estimates (31,910)
Conversion of proved undeveloped to proved developed (34,928)
As of December 31, 2023 167,973
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(1)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
Our proved undeveloped oil and natural gas reserves increased 24% from 135.2 million BOE at December 31, 2022 to 168.0 million at December 31, 2023. We added 60.7 million BOE in proved undeveloped reserves through extensions and discoveries during 2023, which resulted primarily from new proved undeveloped locations identified as a result of drilling activities on our existing acreage in the Delaware Basin during 2023. In addition, we increased our proved undeveloped reserves by 38.9 million BOE at December 31, 2023 as a result of property acquisitions, including the Advance Acquisition, and trades completed during 2023. These increases were partially offset by approximately 31.9 million BOE in net downward revisions of prior estimates of proved undeveloped reserves, most of which were attributable to proved undeveloped reserves that were not developed or were no longer expected to be developed within five years of their initial booking resulting from changes in development plans for certain of the properties in the Delaware Basin. During 2023, we also converted 34.9 million BOE of our proved undeveloped reserves to proved developed reserves primarily through our development activities in the Delaware Basin.
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. 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).
Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves
Proved Undeveloped Reserves
Converted to
Proved Developed Reserves
Oil Natural Gas Total
(MBbl) (Bcf) (MBOE)(1)
2020 16,256 76.1 28,944 $ 257,590
2021 23,965 96.6 40,071 240,664
2022 22,515 95.3 38,403 434,336
2023 18,492 98.6 34,928 441,671
Total 81,228 366.6 142,346 $ 1,374,261
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(1) Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2023.
Net Proved Reserves(1)
Oil Natural Gas Oil Equivalent Standardized Measure(2)
PV-10(3)
(MBbl) (Bcf) (MBOE)(4)
(in millions) (in millions)
Southeast New Mexico/West Texas:
Delaware Basin 270,136 1,094.9 452,616 $ 6,070.5 $ 7,649.9
South Texas:
Eagle Ford(5)
2,135 5.5 3,048 35.9 45.3
Northwest Louisiana
Haynesville - 23.1 3,847 10.5 13.2
Cotton Valley(6)
6 3.3 559 (3.4) (4.3)
Area Total 6 26.4 4,406 7.1 8.9
Total 272,277 1,126.8 460,070 $ 6,113.5 $ 7,704.1
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(1)Numbers in table may not total due to rounding.
(2)Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.
(3)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 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.
(4)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(5)Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas.
(6)Includes the Cotton Valley formation and shallower zones.
Technology Used to Establish Reserves
Under current SEC rules, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible (from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations) prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The term “reasonable certainty” means a high degree of confidence that the quantities of oil and/or natural gas will be recovered. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, 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. Certain new producing properties with little production history were forecasted using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecasted using either analogy and/or volumetric methods.
Internal Control Over Reserves Estimation Process
We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Individual asset teams are responsible for the day-to-day management of the oil and natural gas activities for each team’s asset area. These asset teams are staffed with reservoir engineers who prepare reserves estimates at the end of each calendar quarter for the assets they manage. Our Vice President of Reservoir Engineering and the Reserves Team was primarily responsible for overseeing the preparation of our reserves estimates in 2023. He received Bachelor of Science degrees in both Petroleum Engineering and Mechanical Engineering from
Texas Tech University, is a licensed Professional Engineer in the state of Texas and has over ten years of industry experience. Our Vice President of Reservoir Engineering and the Reserves Team works under the direct supervision of our Executive Vice President of Reservoir Engineering and Senior Asset Manager, who received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and has over 15 years of industry experience. The Company has established internal controls over its reserves estimation processes and procedures to support the accurate and timely preparation and disclosure of reserves estimates in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation processes by our internal reserves group as well as accounting and finance personnel. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Members of our executive committee and members of the Operations and Engineering Committee of our Board of Directors (the “Board”) review the reserves report and our reserves estimation process, and the independent audit of our reserves is reviewed by other members of the Board as well.
Acreage Summary
The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2023.
Developed Acres Undeveloped Acres Total Acres
Gross Net Gross Net Gross Net
Southeast New Mexico/West Texas:
Delaware Basin 218,900 118,900 46,700 33,300 265,600 152,200
South Texas:
Eagle Ford 14,400 12,100 - - 14,400 12,100
Northwest Louisiana:
Haynesville 16,200 8,900 - - 16,200 8,900
Cotton Valley 15,700 14,800 - - 15,700 14,800
Area Total(1)
18,500 17,300 - - 18,500 17,300
Total 251,800 148,300 46,700 33,300 298,500 181,600
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(1)Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana.
Undeveloped Acreage Expiration
The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 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 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.
Acres Acres Acres Acres Acres
Expiring 2024 Expiring 2025 Expiring 2026 Expiring 2027 Expiring 2028
Gross Net Gross Net Gross Net Gross Net Gross Net
Southeast New Mexico/West Texas:
Delaware Basin(1)
5,100 2,800 10,100 5,200 10,200 4,500 11,700 11,400 6,700 6,700
Total 5,100 2,800 10,100 5,200 10,200 4,500 11,700 11,400 6,700 6,700
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(1)Approximately 66% of the acreage expiring in the Delaware Basin in the next five years is associated with our Twin Lakes asset area in northern Lea County, New Mexico. We expect to hold or extend portions of certain expiring acreage in the Delaware Basin through our future drilling activities or by paying an additional lease bonus, where applicable.
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. 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. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third-party leases, or top leases, that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. As of December 31, 2023,
our leases are primarily fee and state leases with primary terms of three to five years and federal leases with primary terms of 10 years. We believe that our lease terms are similar to our competitors’ lease terms as they relate to both primary term and royalty interests. 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.
Year Ended December 31,
2023 2022 2021
Gross Net Gross Net Gross Net
Development Wells
Productive 222 84.1 138 61.4 96 40.2
Dry - - - - - -
Exploration Wells
Productive(1)
24 16.9 20 11.0 8 8.0
Dry - - - - - -
Total Wells
Productive(2)
246 101.0 158 72.4 104 48.2
Dry - - - - - -
(1)All of these wells are extension wells.
(2)Includes one gross (0.5 net) vertical well in 2023 and three gross (1.6 net) vertical wells in 2022.
At December 31, 2023, we had a total of 46 gross (37.8 net) development wells and six gross (4.9 net) exploration wells that were in the process of being drilled, being completed or awaiting completion operations.
Marketing and Customers
Our crude oil is sold under both long-term and short-term oil purchase agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and our heavier liquid products move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of our lighter liquid products move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also generally deducted from the price received for crude oil and liquids.
Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points to both unaffiliated independent marketing companies and unaffiliated midstream companies. 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. We are then paid for the extracted NGLs based on either a negotiated percentage of the proceeds that are generated from the sale of NGLs or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees.
The prices we receive for our oil, natural gas and NGL production fluctuate widely. 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
production activity; the impact of energy conservation efforts; technological advances affecting energy consumption; and overall worldwide economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled or unscheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. See “Risk Factors-Risks Related to our Financial Condition-Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”
The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the NYMEX West Texas Intermediate (“WTI”) oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows. 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. If we lost one or more of these significant purchasers and were unable to sell our production to other purchasers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. For further details regarding these purchasers, see Note 2 to the consolidated financial statements in this Annual Report. Such information is incorporated herein by reference.
Title to Properties
We endeavor to ensure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. 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. Some of our acreage is subject to agreements that require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests may be contingent upon our satisfactory fulfillment of such obligations. Some of our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other similar burdens that we believe will not materially interfere with the use and operation of these properties or affect the value thereof. Generally, we intend to conduct operations, make lease rental payments or produce oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods in order to avoid lease termination. See “Risk Factors-Risks Related to our Financial Condition-We may incur losses or costs as a result of title deficiencies in the properties in which we invest.”
We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to customary encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially interfere with the use and operation of these properties in the conduct of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business.
Seasonality
Generally, but not always, the demand and price levels for natural gas increase during winter and decrease during summer. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are affected more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations where equipment may not be available during periods of peak demand or where weather conditions and events result in delayed operations. 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.”
Competition
The oil and natural gas industry is highly competitive. We compete with major and independent oil and natural gas companies for exploration and development opportunities and acreage acquisitions as well as drilling rigs and other equipment and labor required to drill, complete, operate and develop our properties. We also compete with public and private midstream companies for natural gas gathering and processing opportunities, as well as produced water gathering and disposal and oil gathering and transportation activities in the areas in which we operate. In addition, competition in the midstream industry is based on the geographic location of facilities, business reputation, reliability and pricing arrangements for the services offered. 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. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs, leasehold and mineral acreage, productive oil and natural gas properties or midstream facilities and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment.
Our ability to drill and explore for oil and natural gas, acquire properties and provide competitive midstream services will depend upon our ability to conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. In addition, many of our competitors may have a longer history of operations.
The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors-Risks Related to Third Parties-Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.”
Environmental
Emissions Mitigation
We work to maximize the percentage of natural gas we capture from the production of each of our wells. Newly drilled wells are connected to natural gas pipelines with expected sufficient reliability and capacity to support our production operations. We connect many of our wells to San Mateo’s and Pronto’s natural gas gathering systems. This greatly reduces the need to flare natural gas. We design our production facilities and use advanced natural gas capture and control equipment during production, including the use of vapor recovery units (“VRU”), to maximize natural gas capture. VRUs enable us to collect and compress natural gas from lower pressure sources that might otherwise be flared. This reduces emissions and increases the volumes of natural gas that we can sell. When possible, we use centralized tank batteries and commingle production from multiple wells to take advantage of economies of scale to use these VRUs and other specialized equipment in our production facilities.
Our field employees monitor our facilities and inspect for any necessary repairs or maintenance. In addition, we have implemented a leak detection and repair program that involves scheduled inspections for natural gas capture. These inspections are bolstered by our use of optical gas imaging cameras, which help to identify potential emissions that may not be visible to the naked eye. We have also implemented real-time remote monitoring of vapor control systems through Supervisory Control and Data Acquisition (“SCADA”) equipment at a number of our larger production facilities. These inspections are being conducted regularly, both by our staff and by third-party contractors, more frequently and at more locations than federal and state regulations require.
Additionally, we connect many of our production facilities to electric grid power. Connecting to grid power allows us to forego using internal combustion-powered generators on-site, which further reduces emissions.
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. As well as conserving fresh water, our use of recycled water in our completions operations reduces the amount of produced water that must be disposed. It also results in significant cost savings and efficiencies. In addition to using recycled water where feasible, we also use other sources of non-fresh water, which reduces the volume of fresh water used for our operations.
Land Stewardship
We attempt to reduce our surface footprint by batch drilling wells and drilling longer laterals, both of which result in fewer required drilling pads, and by working with the various regulatory agencies, including the New Mexico Oil Conservation Division (the “NMOCD”) and the U.S. Department of Interior Bureau of Land Management (“BLM”), to obtain approval to commingle production from different wells into centralized tank batteries. We also take steps to ensure we conduct our operations in locations that minimize any potential disturbance to the habitats around which we operate. As part of that effort, we have entered into voluntary agreements with the U.S. 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. Additionally, for our federal locations and as otherwise warranted, we conduct wildlife, biology and archeology surveys and undertake reviews for caves, karsts and potential hydrology considerations.
During 2023, 94% of our gross operated oil production and 98% of our gross operated water production were connected to pipelines. 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. This is significant because it both (i) reduces truck traffic and increases road safety and (ii) reduces emissions.
Regulation
Oil and Natural Gas Regulation
Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations.
Texas, New Mexico, Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. 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. While not presently the case in the states in which we operate, some states restrict production to the market demand for oil and natural gas or prescribe ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.
Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, ability to commingle production, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. 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. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. In addition, government disruptions, such as a shutdown of the U.S. federal government resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the granting and renewal of such permits or other licenses, approvals or certificates required to conduct our operations. Delays in obtaining necessary permits or other approvals can disrupt our operations and have a material adverse effect on our business.
Oil and natural gas exploration and production activities on federal lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions
having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process, including any additional requirements or procedures that may be included in the process or litigation over the sufficiency of the process, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability.
In January 2021, the Biden administration issued: (i) an order signed by the acting Secretary of the Interior providing for a 60-day pause limiting the authority of local offices of the BLM to issue new leases and grant federal drilling permits and certain extensions, sundries, rights-of-way and other necessary approvals for the development of federal oil and natural gas leases; and (ii) an executive order signed by President Biden 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 (together, the “Biden Administration Federal Lease Orders”). The U.S. District Court for the District of Louisiana enjoined the pause within 13 states, including Texas, in August 2022. The Department of the Interior has recently resumed lease sales in several states.
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 (the “Lease Sale Litigation”). The Lease Sale Litigation challenges the BLM’s decision to hold the lease sales based on alleged defects in the environmental reviews conducted under NEPA in conjunction with those sales. In 2020, the New Mexico federal district court dismissed the case pending there. That decision was appealed to the Tenth Circuit Court of Appeals, but the appeal was voluntarily dismissed in 2021. The lawsuits in the District of Columbia were also dismissed in 2022. In connection with these dismissals, in February 2022, the BLM announced an internal policy of delaying approval of drilling permits associated with the leases subject to the Lease Sale Litigation, including the dismissed New Mexico case, while the BLM conducted additional NEPA analyses. BLM later announced that drilling permit approvals could be considered for the subject leases, provided that the process included additional time for public comments and objections. In November 2022, the BLM published a supplemental environmental assessment of the greenhouse gas emissions related to the leases that evaluated a proposal to affirm its previous decisions to offer and approve the leases. Public comment on the supplemental environmental assessment closed on December 27, 2022. The outcome of the supplemental environmental assessment, including the BLM’s response to public comments and any future litigation regarding the leases at issue and any related drilling permits, is uncertain.
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 “Social Cost of Carbon Litigation”). Among the decisions impacted by the executive order were NEPA reviews conducted in connection with oil and natural gas leasing and permitting decisions by the BLM. After Louisiana and Missouri-led litigation in the federal district courts and the Fifth and Eighth Circuit Courts of Appeals, in May 2022, the U.S. Supreme Court let the challenged interim social cost of greenhouse gases go into effect. In November 2022, the Environmental Protection Agency (the “EPA”) suggested increasing the value of the social cost of greenhouse gases from $51 per metric ton to $190 per metric ton, and in December 2023, the EPA used $190 per metric ton as the social cost of greenhouse gases in its final rule revising New Source Performance Standards (“NSPS”) and Emission Guidelines for greenhouse gas and volatile organic compound emissions in the oil and gas sector. As part of this final rulemaking, the EPA published a peer-reviewed report on the updated social cost of greenhouse gases estimates. Future EPA rulemakings may also incorporate the methodology and social cost of greenhouse gases estimate developed in this report and result in more stringent rules and regulations affecting the oil and gas sector.
In 2022, environmental groups filed a lawsuit alleging that the BLM failed to conduct adequate NEPA reviews prior to issuing drilling permits in 2021 and 2022 for wells on federal acreage in New Mexico and Wyoming, including some drilling permits issued to the Company. In November 2023, the federal district court for the District of Columbia dismissed the case, holding that the environmental groups lacked standing. The environmental groups have appealed the district court’s ruling, and their appeal remains pending. In February 2023, in a separate lawsuit, the Tenth Circuit Court of Appeals ruled that certain BLM drilling permits for wells in the Chaco region of New Mexico were issued without adequate NEPA review (collectively with the 2022 lawsuit, the “Drilling Permit Litigation”). The outcome of the Drilling Permit Litigation, as well as any process changes that the BLM may implement in response to such lawsuits, is uncertain. The BLM indicated that the Lease Sale Litigation, the Social Cost of Carbon Litigation and the Drilling Permit Litigation could delay lease sales and the approval of drilling permits.
In November 2022, the BLM proposed a new rule designed to reduce natural gas waste through limitation of certain oil and natural gas production activities and the imposition of more stringent royalty obligations on natural gas that is “avoidably lost” during operations. The proposed rule has not yet been adopted.
Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions related to the oil and natural gas industry, including those in response to the Lease Sale Litigation, Social Cost of Carbon Litigation and Drilling Permit Litigation, remains unclear, and should limitations or prohibitions be imposed or continue to be applied, our oil and natural gas operations on federal lands could be adversely impacted. 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. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (the “NGA”), as well as under Section 311 of the Natural Gas Policy Act of 1978 (the “NGPA”). Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA, and intrastate crude oil pipeline facilities are not subject to FERC’s jurisdiction under the Interstate Commerce Act (the “ICA”). State regulation of natural gas gathering facilities and intrastate crude oil pipeline facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements or complaint-based rate regulation. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. In December 2018, San Mateo placed into service its crude oil gathering and transportation system in the Rustler Breaks asset area in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”) following an open season to gauge shipper interest in committed crude oil interstate transportation service on the Rustler Breaks Oil Pipeline System earlier in 2018. The Rustler Breaks Oil Pipeline System was expanded to the Greater Stebbins Area following another open season in the third quarter of 2020. The Rustler Breaks Oil Pipeline System, including the expansion to the Greater Stebbins Area, is subject to FERC jurisdiction and includes approximately 70 miles of various diameter crude oil pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains. We believe that the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC jurisdiction.
In 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation in connection with the purchase or sale of natural gas or the purchase or sale of natural gas transportation services subject to FERC jurisdiction by any entity and to direct FERC to facilitate transparency in the market for the sale or transportation of natural gas in interstate commerce. The Energy Policy Act also significantly increased the penalties for violations of, among other things, the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties and disgorgement, we may also be subject to third-party damage claims.
Intrastate natural gas transportation is subject to regulation by state regulatory agencies (and to a limited extent by FERC, as noted above). The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated.
As mentioned above, in December 2018, San Mateo placed into service the Rustler Breaks Oil Pipeline System. The Rustler Breaks Oil Pipeline System is subject to regulation by FERC under the ICA and the Energy Policy Act of 1992 (the “EP Act”). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate crude oil pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. 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 EP Act and its implementing regulations also generally allow interstate crude oil pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative.
The price we receive from the sale of oil and NGLs will be affected by the availability, terms and cost of transportation of such products to market. As noted above, under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulations promulgated by state regulatory commissions, which vary from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations.
In 2007, the Energy Independence & Security Act of 2007 (the “EISA”) went into effect. 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.
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 Department of Transportation, through PHMSA, has established rules regarding integrity management programs for interstate oil pipelines, including the Rustler Breaks Oil Pipeline System. In recent years, pursuant to these laws and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and PIPES Act of 2016, PHMSA has expanded its regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. Certain of our natural gas gathering lines are federally “regulated gathering lines” subject to PHMSA requirements. On April 8, 2016, PHMSA published a notice of proposed rulemaking that would amend existing integrity management requirements, expand assessment and repair requirements in areas with medium population densities and extend regulatory requirements to onshore natural gas gathering lines that are currently exempt. In October 2019, PHMSA submitted three major rules, including rules focused on: the safety of gas transmission pipelines (the first of three parts of the so-called gas Mega Rule), the safety of hazardous liquid pipelines and enhanced emergency order procedures. The final 2019 gas transmission rule requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the maximum allowable operating pressure. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA issued the second part of the Mega Rule in November 2021, extending the federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures. PHMSA issued the third part of the Mega Rule in August 2022, which is applicable to onshore gas transmission pipelines and clarifies integrity management regulations, expands corrosion control requirements, mandates inspections after extreme weather events and updates existing repair criteria for both High Consequence Areas (“HCA”) and non-HCA pipelines. In September 2023, PHMSA issued a proposed rule applicable to gas transmission and distribution and gathering pipelines, which would require updates to emergency response plans and other safety practices. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. See “Risk Factors-Risks Related to Laws and Regulations-We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.”
Additional expansion of pipeline safety requirements or our operations could subject us to more stringent or costly safety standards, which could result in increased operating costs or operational delays.
U.S. Federal and State Taxation
The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico.
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 federal level. 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. Any such changes in federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and natural gas exploration and development, and any such changes could negatively affect our financial condition, results of operations, and cash flows.
Changes to state or federal tax laws could adversely affect our business and our financial results. See “Risk Factors-Risks Related to Laws and Regulations-We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows.”
Underground Injection and Hydraulic Fracturing
We own and operate underground injection wells throughout our areas of operation. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. Underground injection allows us to safely and economically dispose of produced 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. In addition, the Railroad Commission of Texas (the “RRC”) and the NMOCD require injected fluids to be confined to a permitted injection interval to aid in the protection of potentially productive intervals. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. Failure to obtain, or abide by the requirements for the issuance of, necessary permits could subject us to civil and/or criminal enforcement actions and penalties. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. 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 regulating 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. In October 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and natural gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant for a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone, or if scientific data indicates such a disposal well is likely to be, or determined to be, contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that disposal well. The RRC has used this authority to deny permits for waste disposal wells and to restrict the volumes authorized to be injected by permitted wells. In addition, 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. The protocols also 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. For example, the salt water disposal well we acquired in the Advance Acquisition is restricted due to these protocols. 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.
We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately half of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. 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.”
The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce. Some states and localities have placed additional regulatory burdens upon hydraulic fracturing activities and, in some areas, severely restricted or prohibited those activities. In recent years, various bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In addition, separate and apart from the referenced potential connection between injection wells and seismicity, concerns have been raised that hydraulic fracturing activities may be correlated to induced seismicity. 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. Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level imposing any restrictions on the use of hydraulic fracturing, this could have a material adverse impact on our financial condition, results of operations and cash flows. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, would result in additional expense and delay in our operations. 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
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. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells, midstream facilities and produced water injection and disposal wells. 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. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (“NORM”) that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations, and violations and liability with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, may require notice to stakeholders of proposed and ongoing operations, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. These laws, rules and regulations may also restrict the production rate of oil and natural gas or limit the injection of produced water into disposal wells below the rates that would otherwise be possible. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and do not expect that these laws and regulations will have a material adverse impact on us.
The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal and remediation costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action.
The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In September 2015, a rule issued by the EPA and U.S. Army Corps of Engineers (the “Corps”) to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. The EPA rescinded this rule in 2019 and promulgated the Navigable Waters Protection Rule (the “NWPR”) in 2020. The NWPR was viewed as narrowing the scope of WOTUS as compared to the 2015 rule. In August 2021, the U.S. District Court for the District of Arizona vacated and remanded the NWPR. On January 18, 2023, the EPA and the Corps jointly issued a final rule revising the definition of WOTUS that largely returned to the pre-2015 regulatory regime. On September 8, 2023, the U.S. Supreme Court issued a decision limiting the scope of federal jurisdiction over wetlands only to those that have a continuous surface connection to water bodies. On August 29, 2023, the EPA and the Corps jointly issued a final rule, which took effect immediately, aligning the regulatory definition of WOTUS with the Supreme Court’s ruling.
CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. 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. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that are classified as hazardous substances under CERCLA. Each state also has environmental cleanup laws analogous to CERCLA.
RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration
and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than nonhazardous wastes.
The CAA, as amended, restricts the emission of air pollutants from many sources, including oil and natural gas production. In addition, certain states have comparable legislation, which may be more restrictive than the CAA. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. On August 16, 2022, the Inflation Reduction Act created the Methane Emissions Reduction Program to incentivize methane emission reductions and impose a fee on greenhouse gas emissions from certain facilities that exceed specified emissions levels. See “Risk Factors-Risks Related to Laws and Regulations-New regulations on all emissions from our operations could cause us to incur significant costs.”
Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended nationally determined contributions (“NDC”), which set greenhouse gas emission reduction goals, every five years beginning in 2020. The United States exited the Paris Agreement in November 2020, but rejoined the agreement effective February 19, 2021. In April 2021, the United States made its NDC submittal, setting an emissions reduction goal of a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. 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.
In January 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The New Mexico Environment Department (the “NMED”) adopted rules and regulations in April 2022 to address the formation of ground-level ozone, including from existing oil and natural gas operations. In August 2022, the NMED issued a final rule imposing additional controls on oil and natural gas operations to reduce ozone-precursor emissions. A challenge to the ozone precursor rule is currently pending in New Mexico state court.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial condition, as well as those of the oil and natural gas industry in general. For instance, in January 2021, President Biden issued Executive Order 14088, which directed a government-wide effort to address climate change by reducing greenhouse gas emissions and achieving net-zero global carbon emissions by 2050 or before. 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. 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. On December 2, 2023, the EPA issued a prepublication version of a final rule to regulate emissions from oil and natural gas sources that includes NSPS to limit greenhouse gas and volatile organic compound emissions for new, modified or reconstructed sources, as well as emissions guidelines for states to follow when establishing plans to limit methane emissions from existing sources. Additionally, on November 17, 2023, the EPA issued a final rule that enables states to implement more stringent methane emissions standards than the federal guidelines require. As another example, in January 2023, the EPA announced a proposed consent decree that, if finalized as proposed, would establish a December 10, 2024 deadline for the EPA to review and propose revisions to the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) for oil and natural gas production facilities and natural gas transmission and storage facilities, which may require us to make additional changes to our operations.
Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. See “Risk Factors-Risks Related to Laws and Regulations-Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects” and “Risk Factors-Risks Related to Laws and Regulations-New regulations on all emissions from our operations could cause us to incur significant costs.”
In the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil, produced water or other materials may occur, and we may incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, New Mexico and Louisiana, have enacted regulations governing the handling, treatment, storage and disposal of NORM.
We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards.
The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. On March 27, 2023, a final rule became effective that, among other things, lists the lesser prairie-chicken as endangered under the ESA in certain portions of Southeast New Mexico where we operate. On July 3, 2023, the USFWS issued a proposed rule to list the dunes sagebrush lizard as endangered. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and to bald and golden eagles under the Bald and Golden Eagle Protection Act. The USFWS must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. Our oil and natural gas operations in certain of our operating areas could also be adversely affected by seasonal or permanent restrictions on drilling activity designed to protect certain wildlife in the Delaware Basin and other areas in which we operate and our ability to maximize production from our leases may be adversely impacted by these restrictions. See “Risk Factors-Risks Related to Laws and Regulations-We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.”
We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. 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. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. See “Risk Factors-Risks Related to Laws and Regulations-We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.”
Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Operations by previous owners and operators may not have been conducted in compliance with applicable rules and regulations, and materials from these operations may remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers and buyers, respectively, of producing properties against some of the liability for environmental claims or violations associated with the properties we purchase or sell, respectively. Moreover, we will be able to control directly the operations of only those wells we operate. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. 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.
We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We generally do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. 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. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, including in the areas of geology and geophysics, land, production and midstream operations, construction, design, well site surveillance and supervision, permitting and environmental assessment, legal and income tax preparation and accounting services. Independent contractors, at our request, drill and complete all of our wells and usually perform field and on-site production operation services for us, including midstream services, facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities.
Employee Recruiting, Retention and Professional Development
We promote inclusion throughout our organization. We respect cultural diversity and do not tolerate harassment or discrimination of any kind, including, but not limited to, discrimination based on race, color, ethnicity, religion, gender, sexual orientation, gender identity, age, national origin, disability and veteran or marital status.
Our employees are our most important asset. We have invested the time, attention and resources necessary to recruit, retain and develop an extraordinary team. We offer a comprehensive compensation package with base pay, discretionary bonus and equity incentive opportunities, paid time off, 401(k) matching contributions, an employee stock purchase plan and an affordable and comprehensive health insurance program, among other benefits. We also provide employees the opportunity to have significant responsibility and daily interaction with our executive management and team leaders.
We encourage continuing education and study, requiring every employee to complete at least 40 hours of professional training annually. In 2023, for example, our employees completed approximately 22,000 hours of continuing education and study, equating to approximately 59 hours per employee. We also have a formal leadership program that fosters the development and growth of many of our staff with regular meetings and opportunities to enhance their leadership skills.
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.
We emphasize the importance of recruiting and maintaining a quality HSE group, and we believe it is important that our HSE group has actual hands-on experience in the field to understand the challenges and issues that can arise. 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. We make available, free of charge, through our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Environmental, Social and Corporate Governance Committee, Executive Committee, Nominating Committee and Strategic Planning and Compensation Committee, our Code of Ethics and Business Conduct for Officers, Directors and Employees and information regarding certain of our ESG initiatives, investor presentations, press releases and shareholder communications are available through our website, and we also intend to disclose any amendments to our Code of Ethics and Business Conduct, or waivers to such code on behalf of our Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer, on our website. All of these corporate governance materials are available free of charge and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. 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.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors.
Summary of Risk Factors
The following is a summary of some of the risks and uncertainties that could materially adversely affect our business, financial condition, results of operations and cash flows. You should read this summary together with the more detailed risk factors contained below.
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 Liquidity
•We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may incur additional indebtedness, which could reduce our financial flexibility.
•The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility.
•The terms of the agreements governing our outstanding indebtedness may restrict our current and future operations.
•Our credit rating may be downgraded, which could reduce our financial flexibility.
•Dividend payments are at the discretion of our Board of Directors and subject to numerous 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.
•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.
•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 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 Laws and Regulations
•Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to various requirements and regulations.
•We are subject to government regulation, including complex environmental laws, which could require significant expenditures.
•We are subject to tax laws and may become subject to new taxes, or tax deductions currently available to us may be eliminated or reduced.
•Legislation and regulatory initiatives relating to hydraulic fracturing, induced seismicity, emissions and climate change could result in increased costs and additional operating restrictions or delays, and the physical effects of climate change could disrupt our production and cause us to incur significant costs.
•New climate disclosure rules proposed by the SEC or states in which we have operations or do business could increase our costs of compliance.
•We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.
•A change in the jurisdictional characterization of some of our assets by FERC or a change in policy by FERC may result in increased regulation of our assets.
•The rates of our regulated assets are subject to review and reporting by federal regulators.
•Should we fail to comply with FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
•Derivatives legislation adopted by Congress could limit our ability to hedge risks associated with our business.
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.
General Risk Factors
•We may have difficulty managing growth in our business.
•The loss of any key personnel or Board member could disrupt our business operations.
•A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss.
•Our governing documents and Texas law may have anti-takeover effects that could prevent a change in control.
•We operate in a litigious environment and may be involved in legal proceedings.
Risks Related to our Financial Condition
Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.
The prices we receive for the oil, natural gas and NGLs we produce heavily influence our revenue, profitability, cash flow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil, natural gas and NGLs are commodities and,
therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile and will likely continue to be volatile in the future. 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 high of $93.68 per Bbl in late September to a low of $66.74 per Bbl in mid-March, based upon the WTI oil futures contract price for the earliest delivery date. For the year ended December 31, 2023, natural gas prices averaged $2.66 per MMBtu, as compared to $6.54 per MMbtu in 2022, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2023, natural gas prices ranged from a low of $1.99 per MMBtu in late March to a high of $4.17 per MMBtu in early January before finishing the year at $2.51 per MMBtu.
The prices we receive for our production, and the levels of our production, depend on numerous factors. 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 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. Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relation to each other.
Declines in oil, natural gas or NGL prices not only reduce our revenue, but could also reduce the amount of oil, natural gas and NGLs that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves and our ability to comply with the financial covenants under our Credit Agreement. 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. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, 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.
Our industry and the broader U.S. economy have experienced higher than expected inflationary pressures in recent years related to increases in oil and natural gas prices, continued supply chain disruptions, labor shortages and geopolitical instability, among other pressures. Should these conditions persist, it may impact our ability to procure services, materials and equipment on a cost-effective basis, or at all, and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.
Inflation in the U.S. has become much more significant in recent years. Throughout 2022 and 2023, we experienced significant increases in the costs of certain oilfield services, materials and equipment, including diesel, steel, labor, trucking, sand, personnel and completion costs, among others, as a result of the recent increases in oil and natural gas prices, as well as availability constraints, supply chain disruptions, increased demand, labor shortages and wage increases associated with a low U.S unemployment rate, inflation and other factors. 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. Should oil and natural gas prices remain at their current levels or increase, we expect to be subject to additional supply chain constraints and service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. In addition, supply chain disruptions and other inflationary pressures being experienced throughout the U.S. 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, have a material adverse effect on our business, financial condition, results of operations and cash flows.
We cannot predict the impact of the ongoing military conflicts between Russia and Ukraine and Israel and Hamas and the related humanitarian crises on the global economy, energy markets, geopolitical stability and our business.
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. We cannot predict the extent of either conflict’s effect on our business and results of operations as well as on the global economy and energy markets.
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.
Our exploration, development, exploitation and midstream activities are capital intensive. Our cash, operating cash flows, contributions from our joint venture partners and potential future borrowings under our Credit Agreement, the San Mateo Credit Facility or otherwise may not be sufficient to fund all of our future capital expenditures or future acquisitions. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable.
Our 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.
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. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future.
If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or the value thereof or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain opportunities. Alternatively, to develop our properties, pay for higher service costs, fund acquisitions, increase our rate of growth, or expand our midstream operations, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets, oil and natural gas producing assets or leasehold interests, the sale or joint venture of oil and natural gas mineral interests, the borrowing of funds or otherwise to meet any increase in capital spending. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds or make acquisitions, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and results of operations could be adversely affected.
Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
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. This process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of:
•the quality and quantity of available data;
•the interpretation of that data;
•the judgment of the persons preparing the estimate; and
•the accuracy of the assumptions used.
The accuracy of any estimates of proved oil and natural gas reserves generally increases with the length of production history. Due to the limited production history of certain of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance from our estimates could 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.
It should not be assumed that the present value of future net cash flows included in this Annual Report is the current market value of our estimated proved oil and natural gas reserves. 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. 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.
In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general.
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.
At December 31, 2023, approximately 37% of our total proved reserves were undeveloped and approximately 2% of our total proved reserves were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced, or such reserves may not be developed or produced within the time periods we have projected or at the costs we have estimated. SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they are related to wells scheduled to be drilled within five years after the date of booking. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing our total proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused by the reclassification of undeveloped or developed non-producing reserves could materially affect our business, financial condition, results of operations and cash flows.
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows.
The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing on developing our assets in the Delaware Basin, an area with intense competition and industry activity. As a result of this activity, we may have difficulty growing our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected.
We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition.
There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low or are declining, as occurred in 2020. In addition, non-cash write-downs may occur if we have:
•downward adjustments to our estimated proved reserves;
•increases in our estimates of development costs; or
•deterioration in our exploration and development results.
We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is calculated by determining the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. 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.
To manage our exposure to price risk, including price differential risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option, which is financed through the sale 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. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option and the call option or options have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or NGL prices rise above the maximum price established by the call option or swap, as applicable, and may offer protection if prices fall below the minimum price established by the put option or swap, as applicable, only to the extent of the volumes then hedged.
In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option or swap contracts fail to perform under the contracts. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions.
Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful. 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.
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.
The prices we receive for our oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition, results of operations and cash flows.
Over the past several years, these oil and natural gas basis differentials were volatile and widened at various times. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-General Outlook and Trends” for additional information regarding the differentials. These wider oil and natural gas basis differentials were largely attributable to industry concerns regarding the near-term sufficiency of pipeline takeaway capacity for oil, natural gas and NGL production in the Delaware Basin. If we do experience any interruptions with takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected.
Although the completion of additional oil and natural gas pipeline capacity from West Texas to the Texas Gulf Coast and other end markets improved these price differentials in 2020 and 2021, these price differentials for natural gas widened in 2022 and 2023 and could widen further in future periods. 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.
A component of our growth may come through acquisitions, and our failure to identify, complete or integrate future acquisitions successfully could reduce our earnings and hamper our growth.
We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The pursuit and completion of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees. In addition, if we are not successful in identifying and acquiring properties, our earnings could be reduced and our growth could be restricted.
In addition, the success of our acquisitions will depend, in part, on our ability to realize the anticipated benefits and cost savings from integrating the acquired assets and operations into our business, and there can be no assurance that we will be able to successfully integrate or otherwise realize the anticipated benefits of our acquisitions. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations and could negatively impact our results of operations and growth potential. Members of our management team may be required to devote
considerable amounts of time to the integration process, which will decrease the time they will have to manage our business. Difficulties in integrating our acquisitions into our company may result in us performing differently than expected, in operational challenges or in the delay or failure to realize anticipated expense-related efficiencies, and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Potential difficulties that may be encountered in the integration process include, among others:
•the inability to successfully integrate our acquisitions operationally, in a manner that permits us to achieve the full revenue, expected cash flows and cost savings anticipated from such acquisitions;
•not realizing anticipated operating synergies; and
•potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with such acquisitions.
Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our financial condition, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods.
We may engage in bidding and negotiation to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the borrowing of funds, the issuance of debt or equity securities, the sale of production payments, the sale or joint venture of midstream assets or oil and natural gas producing assets or acreage or otherwise. Our Credit Agreement, the San Mateo Credit Facility and the indentures governing our outstanding senior notes include covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests.
We may purchase oil and natural gas properties or midstream assets with liabilities or risks that we did not know about or that we did not assess correctly, and, as a result, we could be subject to liabilities that could adversely affect our results of operations.
Before acquiring oil and natural gas properties or midstream assets, we assess the potential reserves, future oil and natural gas prices, operating costs, potential environmental liabilities, condition of the assets, customer contracts and other factors relating to the properties or assets, as applicable. However, our review process is complex and involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties or assets we buy. We may not become sufficiently familiar with the properties or assets to assess fully their deficiencies and capabilities. We may not perform inspections on every well, property or asset, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. Even when problems with a property or asset are identified, the seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other risks and liabilities in connection with properties or assets we acquire. If we acquire properties or assets with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities.
We may incur losses or costs as a result of title deficiencies in the properties in which we invest.
If an examination of the title history of a property that we have purchased reveals oil and natural gas leases or mineral interests have been purchased in error from a person who is not the owner of such interests or if the property has other title deficiencies, our interest would likely be worth less than what we paid or may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease or mineral interest, as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect, would be lost.
It is not our practice in all acquisitions of oil and natural gas leases or mineral interests, or undivided interests in such interests, to undergo the expense of retaining lawyers to examine the title to the interest. 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.
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. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such title review and curative work entails expense, which may be significant and difficult to accurately predict. A failure to cure any title defects may delay or prevent us from utilizing the associated leasehold right or mineral interest, which may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has
greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights or mineral interests in properties in which we hold an interest, we will suffer a financial loss that could adversely affect our financial condition, results of operations and cash flows.
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. In addition, we regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect our ability to dispose of such interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of governmental agencies or third parties and the identification of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable to us.
Sellers typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of litigation, environmental contingencies, royalty obligations and income taxes. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
Risks Related to our Liquidity
We may not be able to generate sufficient cash to fund our capital expenditures, service all of our indebtedness and pay dividends to our shareholders, and we may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.
Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, cease the payment of any dividends to our shareholders, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our Credit Agreement, the San Mateo Credit Facility and the indentures governing our outstanding senior notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations, which could have a material adverse effect on our financial condition and results of operations.
We may incur additional indebtedness, which could reduce our financial flexibility, increase interest expense and adversely impact our operations and our unit costs.
As of February 20, 2024, the maximum facility amount under the Credit Agreement was $2.00 billion, the borrowing base was $2.50 billion and our elected borrowing commitment was $1.325 billion. 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). At February 20, 2024, we had available borrowing capacity of approximately $772.6 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by our interests in the majority of our oil and natural gas properties and contains covenants restricting our ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. 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. If we are required to do so, we may not have sufficient funds to fully make such
repayments. The Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75.0 million of unrestricted cash and cash equivalents), divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less and 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 equal to or greater than 1.0 to 1.0 at the end of each fiscal quarter.
As of February 20, 2024, the facility amount under the San Mateo Credit Facility was $535.0 million, and San Mateo had available borrowing capacity of approximately $36.0 million (after giving effect to outstanding letters of credit and subject to San Mateo’s compliance with the covenants noted below). The San Mateo Credit Facility includes an accordion feature, which provides for potential increases in the commitments of the lenders to up to $735.0 million. 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. In addition to these restrictions, the San Mateo Credit Facility also contains covenants restricting San Mateo’s ability to incur additional indebtedness, sell assets, pay dividends and make certain investments.
In the future, subject to the restrictions in the indentures governing our outstanding senior notes and in other instruments governing our other outstanding indebtedness (including our Credit Agreement and the San Mateo Credit Facility), we may incur significant amounts of additional indebtedness, including under our Credit Agreement and the San Mateo Credit Facility, through the issuance of additional notes or otherwise, in order to develop our properties, fund acquisitions or invest in certain opportunities. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly.
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.
The borrowing base under our Credit Agreement is subject to periodic redetermination, and we are subject to interest rate risk under our Credit Agreement and the San Mateo Credit Facility.
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. We and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. In addition, our lenders have the flexibility to reduce our borrowing base due to a variety of factors, some of which may be beyond our control. As of February 20, 2024, our borrowing base was $2.50 billion, our elected borrowing commitment was $1.325 billion, the maximum facility amount under the Credit Agreement was $2.00 billion and we had $500.0 million in outstanding borrowings under, and approximately $52.4 million in outstanding letters of credit issued pursuant to, the Credit Agreement. 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). We could be required to repay a portion of any outstanding debt under the Credit Agreement to the extent that, after a redetermination, our outstanding borrowings at such time exceeded the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the Credit Agreement and an acceleration of the loans thereunder, requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results.
Our earnings are exposed to interest rate risk associated with borrowings under our Credit Agreement and the San Mateo Credit Facility. Borrowings under the Credit Agreement may be in the form of a base rate loan or a loan based on the secured overnight financing rate administered by the Federal Reserve Bank of New York (“SOFR”). If we borrow 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 Credit Agreement) on such day, plus 0.50%, and (iii) the Adjusted Term SOFR Rate (as defined in the Credit Agreement) for a one month tenor, plus 1.00%, plus, in each case, an amount ranging from 0.75% to 1.75% 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 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 have outstanding borrowings under our Credit Agreement and interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.
Similarly, borrowings under the San Mateo Credit Facility may be in the form of a base rate loan or a SOFR loan. If San Mateo borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the greatest of (i) the prime rate for such day, (ii) the Federal Funds Effective Rate (as defined in the San Mateo Credit Facility) on such day, plus 0.50% and (iii) the Adjusted Term SOFR Rate (as defined in the San Mateo Credit Facility) for a one month tenor, plus 1.00% 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 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 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. Interest rates may remain high or increase during 2024. Our Credit Agreement and the San Mateo Credit Facility have floating rates tied to SOFR or other interest rate benchmarks that generally rise alongside the increase in the federal funds rates. 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.
The terms of the agreements governing our outstanding indebtedness may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions.
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. One or more of these agreements include covenants that, among other things, restrict our ability to:
•incur or guarantee additional debt or issue certain types of preferred stock;
•pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;
•transfer or sell assets;
•make certain investments;
•create certain liens;
•enter into agreements that restrict dividends or other payments from our Restricted Subsidiaries (as defined in the indentures governing our outstanding senior notes) to us;
•consolidate, merge or transfer all or substantially all of our assets;
•engage in transactions with affiliates; and
•create unrestricted subsidiaries.
A breach of any of these covenants could result in an event of default under our Credit Agreement, the San Mateo Credit Facility and the indentures governing our outstanding senior notes. For example, our Credit Agreement requires us to maintain a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75.0 million of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less and a current ratio, which is defined as current assets plus the unused availability under the Credit Agreement, divided by current liabilities, of equal to or greater than 1.0 to 1.0. Low oil and natural gas prices or a decline in our oil or natural gas production may adversely impact our EBITDA, cash flows and debt levels, and therefore our ability to comply with this covenant.
Similarly, the San Mateo Credit Facility requires San Mateo to meet 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. 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. 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.
Upon the occurrence of an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If indebtedness under our Credit Agreement, the San Mateo Credit Facility or the indentures governing our outstanding senior notes is accelerated, there can be no assurance that we will have sufficient assets to repay such indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements could materially adversely affect our ability to finance future operations or capital needs or to engage in other business activities.
Our credit rating may be downgraded, which could reduce our financial flexibility, increase interest expense and adversely impact our operations.
In March 2020, our corporate credit rating from S&P Global Ratings was downgraded from “B+” to “B-” and our corporate credit rating from Moody’s Investors Service was downgraded from “B1” to “B3.” The downgrades resulted in significant part due to the sudden decline in oil prices in early 2020. Moody’s Investor Services subsequently upgraded our corporate credit rating to “B2” in July 2020, to “B1” in September 2021 and to “Ba3” in September 2022. S&P Global Ratings upgraded our corporate credit rating to “B” in June 2021, “B+” in January 2022 and “BB-” in September 2022. In September 2021, Fitch Ratings assigned us a corporate credit rating of “B+” and subsequently upgraded our corporate credit rating to “BB-” in September 2022. As of February 20, 2024, our corporate credit ratings from S&P Global Ratings, Moody’s Investors Service and Fitch Ratings remained “BB-,” “Ba3” and “BB-,” respectively. 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.
Any increase in our financing costs resulting from a credit rating downgrade could adversely affect our ability to obtain additional financing in the future for working capital, capital expenditures, additional letters of credit or other credit support we may be required to provide to counterparties, acquisitions and general corporate or other purposes. If a credit rating downgrade were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations could be materially adversely affected.
The payment of dividends will be at the discretion of our Board of Directors and subject to numerous factors, and we do not presently intend to repurchase any shares of our common stock.
In February 2023, April 2023 and July 2023, our Board declared quarterly cash dividends of $0.15 per share of common stock. In October 2023, the Board amended our dividend policy to increase the quarterly dividend to $0.20 per share of common stock and also declared a quarterly cash dividend of $0.20 per share of common stock. On February 13, 2024, the Board declared a quarterly cash dividend of $0.20 per share of common stock payable on March 13, 2024 to shareholders of record as of February 23, 2024. We intend to continue to pay a quarterly dividend in the future pursuant to the dividend policy adopted by our Board. However, the payment and amount of future dividend payments, if any, are subject to declaration by our Board. Such payments will depend on, among other things, our available cash, earnings, financial condition, capital requirements, level of indebtedness, stock price, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board deems relevant. Cash dividend payments in the future may only be made out of legally available funds, and, if we experience substantial losses, such funds may not be available.
We do not presently intend to repurchase any shares of our common stock. Certain covenants in our Credit Agreement and the indentures governing our outstanding senior notes may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid. We are under no obligation to make dividend payments on our common stock and may cease such payments at any time in the future. Any elimination of or downward revision in our dividend payout could have a material adverse effect on our stock price.
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.
Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation and approvals before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells may be exceeded and such costs can increase significantly due to various complications that may arise during
drilling, completion and operation. Before a well is spud, we may incur significant geological, geophysical and land costs, including seismic acquisition costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells could bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly.
If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill or participate in wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to affirmatively determine in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and profitability of a well may be negatively affected by a number of additional factors, including the following:
•general economic and industry conditions, including the prices received for oil and natural gas;
•shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel;
•potential drainage of oil and natural gas from our properties by operations on adjacent properties;
•the existence or magnitude of faults or unanticipated geological features;
•loss of or damage to oilfield development and service tools;
•accidents, equipment failures or mechanical problems;
•title defects of the underlying properties;
•increases in severance taxes;
•adverse weather conditions that delay drilling activities or cause producing wells to be shut in;
•inflation in exploration, drilling, completion and production costs;
•domestic and foreign governmental regulations; and
•proximity to and capacity of gathering, processing, transportation and disposal facilities.
Furthermore, our exploration and production operations involve using some of the latest drilling and completion techniques developed by us, other operators and service providers. 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.
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.
Our operations are subject to operational hazards and risks, which could result in significant damages and the loss of revenue.
There are numerous operational hazards inherent in oil and natural gas exploration, development, production, gathering, transportation and processing, including:
•natural disasters;
•adverse weather conditions, including hurricanes and tropical storms in the Gulf Coast region and severe cold weather in the Delaware Basin;
•domestic or global health concerns, including the outbreak or resurgence of contagious or pandemic diseases, such as COVID-19 and its variants;
•loss of drilling fluid circulation;
•blowouts where oil or natural gas flows uncontrolled at a wellhead;
•cratering or collapse of the formation;
•pipe or cement leaks, failures or casing collapses;
•damage to pipelines, processing plants and disposal wells and associated facilities;
•fires or explosions;
•releases of hazardous substances or other waste materials that cause environmental damage;
•pressures or irregularities in formations; and
•equipment failures or accidents.
In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations and services, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.
Furthermore, our operations may be subject to curtailment due to seismic events. In 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. 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 to the seismic event. 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. In addition, if such a seismic event occurred in the area of the Company’s or San Mateo’s operations, the Company or San Mateo may be required to shut in or curtail the volumes disposed in its salt water disposal wells. For example, the salt water disposal well we acquired in the Advance Acquisition is restricted due to these protocols. Any such further events could adversely impact our and San Mateo’s revenues and cash flows.
There are also significant risks associated with the operation of cryogenic natural gas processing plants such as the Marlan Processing Plant and the Black River Processing Plant. Natural gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of the Black River Processing Plant or the Marlan Processing Plant could result in an explosion or the discharge of toxic gases, which could result in significant damage claims, interrupt a revenue source and prevent us from processing some or all of the natural gas produced from our wells or third-party wells located in nearby asset areas. 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. The continuing operation of, and our continuing access to, such third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants, salt water disposal wells and other midstream 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. In addition, if San Mateo’s or Pronto’s costs to access and transport on these third-party pipelines significantly increase, their profitability could be reduced. 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.
Insurance against all operational risks is not available to us.
Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. 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. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would have otherwise obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows.
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.
Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in the Delaware Basin in Southeast New Mexico and West Texas, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. In recent years, the Delaware Basin has become an area of increasing focus for us, and approximately 96% of our total oil and natural gas production for 2023 was attributable to our properties in the Delaware Basin. Since 2016, the vast majority of our capital expenditures have been allocated to the Delaware Basin. 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.
The industry focus on the Delaware Basin may adversely impact our ability to gather, transport and process our oil and natural gas production due to significant competition for access to gathering systems, pipelines, processing and refinery facilities and oil, condensate and produced water trucking operations. Due to the concentration of our operations, we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled or unscheduled maintenance. Due to our concentration of properties in the Delaware Basin, we are also particularly exposed to any differential between benchmark prices of oil and natural gas and the wellhead price we receive for our production. 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. For example, in recent years, the Delaware Basin has experienced periods of severe winter weather that impacted many operators. In particular, weather conditions and freezing temperatures have resulted in shut-ins of producing wells, power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. Certain areas of the Delaware Basin have also experienced periods of severe flooding that impacted our operations as well as many other operators in the area, resulting in delays in drilling, completing and initiating production on certain wells. As we continue to focus our operations on the Delaware Basin, we may increasingly face these and other challenges posed by severe weather.
Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. For example, our operations in the Delaware Basin are subject to particular restrictions on drilling activities based on environmental sensitivities and requirements and potash mining operations. Such delays, interruptions or restrictions could have a material adverse effect on our business, financial condition, results of operations and cash flows.
There is no guarantee that we will be successful in optimizing our spacing, drilling and completions techniques in order to maximize our rate of return, cash flow from operations and shareholder value.
As we accumulate and process geological and production data, we attempt to create a development plan, including well spacing and completion design, that maximizes our rate of return, cash flow from operations and shareholder value. Due to many factors, however, including some beyond our control, there is no guarantee that we will be able to find the optimal plan. Future drilling and completion efforts may impact production from existing wells, and parent-child well effects may impact future well productivity as a result of timing, spacing proximity or other factors. If we are unable to design and implement an effective spacing, drilling and completions strategy, it may have a material adverse effect on our financial condition, results of operations and cash flows.
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 other operators may take when drilling, completing or operating wells that they own.
Certain of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
Multi-well pad drilling may result in volatility in our operating results.
We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not produced until other wells being drilled on the pad at the same time are drilled and completed, multi-well pad drilling delays the commencement of production from wells drilled on a given pad, which may cause volatility in our operating results. In addition, problems affecting one well could adversely affect production from other wells on the same pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in ongoing production. Additionally, infrastructure expansion, including more complex facilities and takeaway capacity, could become challenging in project development areas. Managing capital expenditures for infrastructure expansion could cause economic constraints when considering design capacity.
The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Shortages or the high cost of drilling rigs, completion equipment and services, drill pipe, casing and other tubular goods, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States or a particular operating area increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, drill pipe, casing and other tubular goods, including sand and other proppants, and personnel and the services and products of other industry vendors. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling or completion activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. 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. 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.
In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs or delays in procuring these services could result, which could adversely affect our business, financial condition, results of operations and cash flows.
If we are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired.
We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. In recent years, Southeast New Mexico and West Texas have experienced severe drought. As a result, we may experience difficulty in securing the necessary volumes of water for our operations. 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. 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.
If regulatory changes prevent our ability to continue to pool wells in the manner we have been, it could have a material adverse impact on our future production results.
In Texas, allocation wells allow an operator to drill a horizontal well under two or more leaseholds that are not pooled or across multiple existing pooled units. In New Mexico, operators are able to pool multiple spacing units in order to drill a single horizontal well across several leaseholds. We are active in drilling and producing both allocation wells in Texas and pooled spacing unit wells in New Mexico. If there are regulatory changes with regard to such wells, the applicable state agency denies or significantly delays the permitting of such wells, legislation is enacted that negatively impacts the current process under which such wells are permitted or litigation challenges the regulatory schemes pursuant to which such wells are permitted, it could have an adverse impact on our ability to drill long horizontal lateral wells on some of our leases, which in turn could have a material adverse impact on our anticipated future production.
Construction of midstream projects subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our financial condition, results of operations, cash flows and liquidity.
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. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, government and regulatory approval, compliance with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our business, results of operations, liquidity, financial condition and the ability of San Mateo or Pronto to attract third-party customers. The construction of produced water disposal facilities, pipelines and gathering and processing facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and financial condition could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions.
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.
Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including oil and natural gas prices, assessment of risks, costs, drilling results, reservoir heterogeneities, the availability of equipment and capital, approval by regulators, lease terms, seasonal conditions and the actions of other operators. Additionally, as lateral lengths greater than one mile have become increasingly common in the Delaware Basin, we may have to cooperate with other operators to ensure that our acreage is included in drilling units or otherwise developed. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. The BLM indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions related to the natural gas industry remains unclear. Should these or other limitations or prohibitions be imposed or continue to be applied, our drilling locations on federal lands may not be drilled as scheduled. The final determination on whether to drill any of the identified locations will be dependent upon the factors described elsewhere in this Annual Report as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe, or at all, or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. 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.
At December 31, 2023, we had leasehold interests in approximately 30,600 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to 2029. Unless we establish and maintain production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases will expire. The cost to renew such leases may increase significantly, and we may not be
able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases, or top leases, may have been taken and could become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases, we will lose our right to develop the related properties. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows.
The 2-D and 3-D seismic data and other advanced technologies we use cannot eliminate exploration risk, which could limit our ability to replace and grow our reserves and materially and adversely affect our results of operations and cash flows.
We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Furthermore, the acquisition of seismic and geological data can be expensive and require the incurrence of various risks and liabilities, and we may not be able to license or obtain such data at an acceptable cost. Poor results from our exploration and development activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows.
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.
We derive most of our revenues from the sale of our oil, natural gas and NGLs to unaffiliated third-party purchasers, independent marketing companies and midstream companies. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. 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. If we lost one or more of these customers and were unable to sell our production to other customers on terms we consider acceptable, it could materially and adversely affect our business, financial condition, results of operations and cash flows. Furthermore, we cannot predict the extent to which counterparties’ businesses would be impacted if oil and natural gas prices decline, such prices remain depressed for a sustained period of time or other conditions in our industry were to deteriorate. Any delays in payments from our purchasers caused by financial problems encountered by them could have an immediate negative effect on our results of operations and cash flows.
In addition to credit risk related to purchasers of our production, we also face credit risk through receivables from joint interest owners on properties we operate and from San Mateo’s and Pronto’s customers. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We are generally unable to control which co-owners participate in our wells. Liquidity and cash flow problems encountered by our joint interest owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our joint interest owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. If we are not able to obtain the capital necessary to fund either of these contingencies or find a new farmout party, our results of operations and cash flows could be adversely affected.
The marketability of our production is dependent upon oil, natural gas and NGL gathering, processing and transportation facilities, and the unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements could have a material adverse effect on our revenue.
The unavailability of satisfactory oil, natural gas and NGL gathering, processing and transportation arrangements may hinder our access to oil, natural gas and NGL markets or delay production from our wells. 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. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations. Such systems and operations include those of San Mateo, as well as other systems and operations owned and operated by third parties. The continuing operation of, and our continuing access to, third-party systems and operations is outside our control. Regardless of who operates the midstream systems or operations upon which we rely, our failure to obtain these services on acceptable terms could materially harm our business. In addition, certain of these gathering systems, pipelines and processing facilities, particularly in the Delaware Basin, may be outdated or in need of repair and subject to higher rates of line loss, failure and breakdown. 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.
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. Furthermore, if we were required to shut in wells, we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases.
The disruption of our own or third-party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and NGLs. If our costs to access and transport on these pipelines significantly increase, our profitability could be reduced. Third parties control when or if their facilities are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production. 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. For example, in January 2024, we experienced temporary natural gas pipeline and processing interruptions due to maintenance and constraints that are estimated to have resulted in approximately 5,500 BOE per day of less production. 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. If we were required to shut in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We conduct a portion of our operations through joint ventures, which subjects us to additional risks that could have a material adverse effect on the success of these operations, our financial position, results of operations or cash flows.
We own and operate substantially all of our midstream assets in Eddy County, New Mexico and Loving County, Texas through San Mateo, and we have and may continue to enter into other joint venture arrangements in the future. The nature of a joint venture requires us to share a portion of control with unaffiliated third parties. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing us to fund operating and/or capital expenditures, the timing and amount of which we may not control. In addition, if our joint venture partners do not fulfill their contractual, financial and other obligations, the affected joint venture may be unable to operate according to its business plan, and we may be required to increase our level of financial commitment or seek third-party capital, which could dilute our ownership in the applicable joint venture. If we do not timely meet our financial commitments or otherwise comply with our joint venture agreements, our ownership of and rights with respect to the applicable joint venture may be reduced or otherwise adversely affected. Furthermore, there can be no assurance that any joint venture will be successful or generate cash flows at the level we have anticipated, or at all. Differences in views among joint venture participants could also result in delays in business decisions or otherwise, failures to agree on major issues, operational inefficiencies and impasses, litigation or other issues. We provide management functions for certain joint ventures and may provide such services for future joint venture arrangements, which may require additional time and attention of management or require us to hire or contract additional personnel. Third parties may also seek to hold us liable for a joint venture’s liabilities. These issues or any other difficulties that cause a joint venture to deviate from its original business plan could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Because of the natural decline in production in the regions of San Mateo’s and Pronto’s midstream operations, San Mateo’s and Pronto’s long-term success depend on their ability to obtain new sources of products, which depends on certain factors beyond San Mateo’s and Pronto’s control. Any decrease in supplies to their midstream facilities could adversely affect San Mateo’s and Pronto’s business and operating results.
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. Some of these third parties are not subject to minimum volume commitments. To maintain or increase throughput levels on San Mateo’s and Pronto’s gathering systems and the utilization rate at its other midstream facilities, San Mateo and Pronto must continually obtain new sources of products. 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 and Pronto have no control over the level of activity in the areas of their operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, San Mateo and Pronto have no control over producers or their drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital.
We have entered into certain long-term contracts that require us to pay fees to our service providers based on minimum volumes regardless of actual volume throughput and that may limit our ability to use other service providers.
From time to time, we have entered into and may in the future enter into certain oil, natural gas or produced water gathering or transportation agreements, natural gas processing agreements, NGL transportation agreements, produced water disposal agreements or similar commercial arrangements with midstream companies, including San Mateo. Certain of these agreements require us to meet minimum volume commitments, often regardless of actual throughput. Reductions in our drilling activity could result in insufficient production to fulfill our obligations under these agreements. As of December 31, 2023, our long-term contractual obligations under agreements with minimum volume commitments totaled approximately $764.2 million over the terms of the agreements. If we have insufficient production to meet the minimum volume commitments under any of these agreements, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations.
Pursuant to certain of our agreements with midstream companies, we have dedicated our current and future leasehold interests in certain of our asset areas to counterparties. As a result, we will be limited in our ability to use other gathering, processing, disposal and transportation service providers, even if such service providers are able to offer us more favorable pricing or more efficient service.
We do not own all of the land on which our midstream assets are located, which could disrupt our operations.
We do not own all of the land on which our midstream assets are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs or royalties to retain necessary land access if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land or find alternative locations for our operations at increased costs, each of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources that we may be unable to afford.
Competition is intense in virtually all facets of our business. Our ability to acquire additional prospects and to find and develop reserves in the future will depend in part on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, to market oil and natural gas and to secure trained personnel. 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. 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. Many of our competitors possess and employ financial, technical, technological and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial, technical, technological or personnel resources permit. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we use or that we may implement in the future may become obsolete, and our operations may be adversely affected.
In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to a competitive labor market, inflation and other factors, and may increase substantially in the future. 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.
Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.
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. These relationships are subject to change and, if they do, our ability to grow may be impaired.
To develop our business, we endeavor to use the business relationships of our management and Board to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies and service companies, including those that supply equipment and other resources that we expect to use in our business, as well as midstream companies and certain financial institutions. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur or undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.
We have limited control over activities on properties we do not operate.
We are not the operator on some of our properties in Northwest Louisiana, particularly in the Haynesville shale. We also have other non-operated acreage positions in Southeast New Mexico, West Texas and South Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including:
•the timing and amount of capital expenditures;
•the operator’s expertise and financial resources;
•the rate of production of reserves, if any;
•approval of other participants in drilling wells; and
•selection and implementation or execution of technology.
In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production.
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.
At December 31, 2023, Matador held approximately 152,200 net leasehold and mineral acres in the Delaware Basin, primarily in Eddy and Lea Counties, New Mexico and in Loving and Ward Counties, Texas, of which approximately 48,100 net acres, or about 32%, was on federal lands administered by the BLM. In addition to permits issued by state and local authorities, oil and natural gas activities on federal lands also require permits from the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the permitting process for oil and natural gas activities not located on federal lands. In addition, government disruptions, such as a shutdown of the U.S. federal government resulting from the failure to pass budget appropriations, adopt continuing funding resolutions or raise the debt ceiling, could delay or halt the granting and renewal of such permits or other licenses, approvals or certificates required to conduct our operations. Delays in obtaining necessary permits or other approvals can disrupt our operations and have a material adverse effect on our business. BLM leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change. For example, on August 16, 2022, H.R. 5376, commonly known as the Inflation Reduction Act of 2022 (the “IRA”), was enacted. Pursuant to the IRA, the royalty rate for federal leases issued on or after August 16, 2022 was increased to 16.67 percent. On July 24, 2023, the BLM issued a proposed rule that would revise the BLM’s oil and gas leasing regulations, including aligning royalty rates, rentals, and minimum bids with the IRA, and would update the bonding requirements for leasing, development and production. These operations are also subject to BLM rules regarding engineering and construction specifications for production facilities, ability to commingle production, safety procedures, the valuation of production, the payment of royalties, the removal of facilities, the posting of bonds, hydraulic fracturing, the control of air emissions and other areas of environmental protection. 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. In addition, litigation related to leasing and permitting of federal lands could also restrict, delay or limit our ability to conduct operations on our federal leasehold or acquire additional federal leasehold. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders limiting the issuance of federal drilling permits and other necessary federal approvals. The BLM indicated that the Lease Sale Litigation and the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions remains unclear. 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. It is possible that any such restrictions on hydraulic fracturing may particularly target activity on federal lands. Any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have a material adverse impact on our business, financial condition, results of operations and cash flows.
Oil and natural gas exploration and production activities on federal lands are also subject to NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses impacts that are “reasonably foreseeable” and have a “reasonably close causal relationship” to the agency action under review and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. 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.
The exploration, development, production, gathering, processing, transportation and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. A change in the presidential administration, as well as a closely divided Congress, may also increase the uncertainty with regard to potential changes in these laws, rules and regulations and the enforcement of any new legislation or directives by governmental authorities. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation, gathering and transportation of oil, natural gas and NGLs, gathering and disposal of produced water, environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. If existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations or those of our service providers, such changes may affect the costs that we pay for such services or the results of business. In addition to expenditures required in order for us to comply with such laws and regulations, expenditures required by such laws and regulations could also include payments and fines for:
•personal injuries;
•property damage;
•containment and clean-up of oil, produced water and other spills;
•venting, flaring or other emissions;
•management and disposal of hazardous materials;
•remediation, clean-up costs and natural resource damages; and
•other environmental damages.
We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. The costs of remedying noncompliance may be significant, and remediation obligations could adversely affect our financial condition, results of operations and leasehold acreage. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous and non-hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. 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. For example, 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 regulating waste disposal. Private parties may also pursue legal actions challenging permitting programs that authorize certain of our operations. For example, it is possible that courts could vacate relevant NWPs as such potential permit coverage relates to activities in the oil and natural gas sector, or the Biden administration could choose to suspend the availability of NWPs in the future, thereby forcing our relevant operations to seek coverage under individual permits under CWA Section 404 (which is a longer and more administratively complex process that is subject to NEPA).
Part of the regulatory environment in which we operate includes, in some cases, federal requirements for obtaining environmental assessments, environmental impact statements and/or plans of development before commencing exploration and production or midstream activities. Oil and natural gas operations in certain of our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. For example, on March 27, 2023, a final rule became effective that, among other things, lists the lesser prairie-chicken as endangered under the ESA in certain portions of southeastern New Mexico where we operate. On July 3, 2023, the USFWS issued a proposed rule to list the dunes sagebrush lizard as endangered. We participate in candidate conservation agreements for the lesser prairie-chicken, as well as the dunes sagebrush lizard and the Texas hornshell mussel, pursuant to which we are restricted from operating in certain sensitive locations or at certain times. The listing of the dunes sagebrush lizard as endangered, participation in such candidate conservation agreements or the designation of previously unprotected species as threatened or endangered species could prohibit drilling or other operations in certain of our operating areas, cause us to incur increased costs arising from species protection measures or result in limitations on our exploration and production and midstream activities, each of which could have a material adverse impact on our business, financial condition, results of operations and cash flows. See “Business-Regulation.”
We are subject to federal, state and local taxes and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition, results of operations and cash flows.
The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. For instance, in New Mexico, there have been proposals to impose a surtax on natural gas processors that, if enacted into law, could adversely affect the prices we receive for our natural gas processed in New Mexico.
Historically, we have generated and carried forward net operating losses (“NOL”) in amounts sufficient to offset substantially all of our taxable income and, thus, have not incurred material federal or state income tax liabilities. As of December 31, 2022, we had utilized all of our federal NOL carryovers. During 2023, we recognized research and experimental expenditure tax credits of $74.0 million, which had the effect of reducing our federal income tax liability for 2023. 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.
Additionally, the IRA contains a number of revisions to the Internal Revenue Code, including (i) a 15% corporate minimum income tax for certain corporations with more than $1 billion in average adjusted financial statement income for the three-year tax period ending before the corporation’s current tax year, (ii) a 1% excise tax on corporate stock repurchases in tax years beginning after December 31, 2022 and (iii) expanded business tax credits and incentives for the development of clean energy projects and the production of clean energy. The impact of the 15% corporate minimum tax will depend on our results of operations each year. While we do not expect such minimum tax (or any other tax provision contained in the IRA) to have any immediate material impact, we will continue to evaluate its future impact as further information becomes available.
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. 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. The passage of any such legislation or any other similar change in U.S. federal income or state tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing involves the injection of water, sand or other proppants and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to complete wells in order to produce oil, natural gas and NGLs from formations such as the Wolfcamp and Bone Spring plays, the Eagle Ford shale and the Haynesville shale, where we focus our operations. Hydraulic fracturing has been regulated at the state and local level through permitting and compliance requirements. Federal, state and local laws or regulations targeting various aspects of the hydraulic fracturing process are being considered, or have been proposed or implemented. In past sessions, Congress has considered, but has not passed, legislation to amend the SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Also at the federal level, in March 2015, the BLM issued final rules, including new requirements relating to public disclosure, wellbore integrity and handling of flowback water, to regulate hydraulic fracturing on federal and Indian lands, but these rules never became effective. These rules were rescinded by rule in December 2017. The rescission was challenged, and the challenge remains pending before the Ninth Circuit Court of Appeals. Separately, in 2016, BLM issued the 2016 Waste Prevention Rule to address flaring, venting and leaks from oil and natural gas operations on federal lands. Following litigation, the 2016 Waste Prevention Rule was vacated. However, the IRA contains a suite of provisions addressing onshore and offshore oil and natural gas development under federal leases. Under the authority of the IRA, on November 30, 2022, BLM proposed new regulations to reduce the waste of natural gas from venting, flaring, and leaks during oil and natural gas production activities on federal and Indian leases. In addition, in July 2023, the Louisiana Department of Natural Resources issued a proposed rule that would restrict routine venting and flaring of methane from oil and natural gas production facilities in the state.
Various policymakers, regulatory agencies and political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. Any such restrictions on hydraulic fracturing on federal lands could adversely impact our operations in the Delaware Basin, and an outright prohibition would adversely impact essentially all of our operations. In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, including bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example, Texas and New Mexico have adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. Bills have been introduced in the New Mexico legislature to place a moratorium on, ban or otherwise restrict hydraulic fracturing activities, including prohibiting the injection of fresh water in such operations. Although such bills have not passed, similar laws, rules, regulations or orders, if passed at the local, state or federal level could limit our operations.
The adoption of new laws or regulations imposing reporting or operational obligations on, or otherwise limiting or prohibiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or BLM, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations.
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.
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. When caused by human activity, such events are called “induced seismicity.” Regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity. 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 regulating 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.
While the scientific community and regulatory agencies at all levels are continuing to study the possible link between oil and natural gas activity and induced seismicity, some state regulatory agencies, including in Texas and New Mexico, have modified their regulations or guidance to mitigate potential causes of induced seismicity. 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 wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. 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. Additional regulation and attention given to induced seismicity could also lead to greater opposition, including litigation, to oil and natural gas activities. Any one or more of these developments may result in operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. 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. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our ability to dispose of produced water gathered from drilling and production activities could adversely impact our business, cash flows and results of operations and could decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions or delays.
Legislation or regulations restricting emissions of greenhouse gases or promoting the development of alternative sources of energy could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
We believe it is likely that scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations and litigation that could affect our operations. Our operations result in greenhouse gas emissions. The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Internationally, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement, which was signed by the United States in April 2016, requires countries to review and “represent a progression” in their intended NDCs, which set greenhouse gas emission reduction goals, every five years beginning in 2020. The United States exited the Paris Agreement in November 2020 but rejoined the agreement effective February 19, 2021. In April 2021, the United States made its NDC submittal, setting a goal to achieve a 50 to 52% reduction from 2005 levels in economy-wide net greenhouse gas pollution in 2030. 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. On August 16, 2022, the IRA created the Methane Emissions Reduction Program to incentivize methane emission reductions and, for the first time ever, impose a fee on GHG emissions from certain facilities that exceed specified emissions levels. Further, on November 11, 2022, the EPA issued a supplemental notice of proposed rulemaking on methane and greenhouse gas emissions from new and existing sources in the oil and natural gas industry. On December 2, 2023, the EPA issued a prepublication version of a final rule to reduce methane and volatile organic chemicals emissions from the oil and natural gas sector, which strengthens and expands the EPA’s November 1, 2021 proposed revisions to the New Source Performance Standards program established under Section 111 of the CAA and creates new emissions restrictions for existing sources as well. On November 17, 2023, the EPA issued a final rule that enables states to implement more stringent methane emissions standards than the federal guidelines require. In 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, prohibits flaring in certain circumstances and requires 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. The NMED adopted rules and regulations in April 2022 to address the formation of ground-level ozone, including from existing oil and natural gas operations. In August 2022, the NMED issued a final rule imposing additional controls on oil and natural gas operations to reduce ozone-precursor emissions. A challenge to the ozone precursor rule is currently pending in New Mexico state court. The EPA has begun adopting and implementing a comprehensive suite of regulations to restrict greenhouse gas emissions under existing provisions of the CAA and the recent authority of the IRA. Legislative and regulatory initiatives related to climate change and greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting
our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas.
In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes, droughts and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, there is the potential for our exploration and production operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production, less efficient or non-routine operating practices necessitated by climate effects and increased costs for insurance coverage in the aftermath of such effects. Any future exploration and development activities and equipment could also be adversely affected by severe weather conditions such as hurricanes or freezing temperatures, which may cause a loss of production from temporary cessation of activity from regional power outages or lost or damaged facilities and equipment. Such severe weather conditions could also impact access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of and our access to, necessary third-party services, such as gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations. 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. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. See “-Risks Related to our Operations-If we are unable to acquire adequate supplies of water for our drilling and hydraulic fracturing operations or are unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules, our ability to produce oil and natural gas commercially and in commercial quantities could be impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly.
The adoption of legislation or regulatory programs to reduce greenhouse gas emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have a material adverse effect on our business, financial condition and results of operations. Reduced demand for the oil and natural gas that we produce could also have the effect of lowering the value of our reserves. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors, investment fund managers and certain family foundations, universities, individual investors and sovereign wealth, pension and endowment funds, promoting divestment of, or limit investment in, fossil fuel equities and pressuring lenders to limit or stop funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Additionally, the threat of climate change has resulted in increasing political risk in the United States as various policy makers, regulatory agencies and political candidates at the federal, state and local levels have proposed bans of new leases for production of minerals on federal properties and various restrictions on hydraulic fracturing, including its outright prohibition. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders, limiting the issuance of federal drilling permits and other federal approvals. Also in 2021, President Biden issued 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 and the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits. Although some of the restrictions in the Biden Administration Federal Lease Orders have lapsed, the impact of these and similar federal actions remains unclear. 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.
President Biden and the Democratic Party, which now controls the U.S. Senate, have identified climate change as a priority, and new executive orders, regulatory action and/or legislation targeting greenhouse gas emissions, promoting energy efficiency or the development and consumption of alternative forms of energy, or prohibiting or restricting oil and natural gas development activities in certain areas, have been proposed and/or promulgated during the Biden administration and additional such measures are likely. The Biden administration has issued multiple executive orders pertaining to environmental regulations and climate change, including the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis and the Executive Order on Tackling the Climate Crisis at Home and Abroad. In the latter executive order, President Biden established climate change as a primary foreign policy and national security consideration, affirmed that achieving net-zero greenhouse gas emissions by or before 2050 is a critical priority, affirmed his administration’s desire to establish the United States as a leader in addressing climate change and generally further integrated climate change and environmental justice considerations into government agencies’ decision-making, among other measures. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public
and private entities against oil and natural gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors. The ultimate impact of greenhouse gas emissions-related agreements, legislation and measures on our financial performance is highly uncertain because we are unable to predict, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and trade-offs that inevitably occur in connection with such processes.
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.
On March 21, 2022, the SEC released proposed new rules that would require significantly expanded climate-related disclosures in SEC filings, including certain climate-related risks, climate-related metrics and greenhouse gas emissions, information about climate-related targets and goals, transition plans, if any, and extensive attestation requirements. The proposed rules include certain phase-in compliance dates for disclosure of Scope 1, 2 and 3 greenhouse gas emissions. As initially proposed, large accelerated filers such as us would be obligated to disclose Scope 1 and 2 greenhouse gas emissions beginning in the first filing year in which the rules apply and disclose Scope 3 greenhouse gas emissions beginning in the following filing year. While we are currently assessing the proposed rule, the final form and substance of the rule is not yet known, and at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. In addition, in the absence of federal action, states may propose and adopt climate disclosure requirements.
In the event the SEC finalizes its proposed climate disclosure rule or states in which we operate or do business adopt climate disclosure requirements, we could incur significant additional costs relating to the assessment and disclosure of climate-related risks, including costs relating to monitoring, collecting, analyzing and reporting the new metrics and implementing systems and procuring additional internal and external personnel with the requisite skills and expertise to serve those functions. These additional costs or changes in operations could have a material adverse effect on our business, financial condition, results of operations and cash flows. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, enhanced climate disclosure requirements could accelerate the trend of certain investors and lenders restricting or seeking more stringent conditions with respect to their investments in carbon-intensive sectors. Separately, the SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures to be misleading or deficient.
New regulations on all emissions from our operations could cause us to incur significant costs.
In recent years, the EPA issued final rules to subject oil and natural gas operations to regulation under the NSPS and NESHAP programs under the CAA and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. In January 2023, the EPA announced a proposed consent decree that, if finalized as proposed, would establish a December 10, 2024 deadline for the EPA to review and propose revisions to the NESHAP for oil and natural gas production facilities and natural gas transmission and storage facilities, which may require us to make additional changes to our operations. The EPA finalized a more stringent National Ambient Air Quality Standard for ozone in October 2015. The EPA finished promulgating final area designations under the new standard in 2018, which, to the extent areas in which we operate have been classified as “non-attainment” areas, may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. To the extent regions reclassified as non-attainment areas under the lower ozone standard have begun implementing new, more stringent regulations, those regulations could also apply to our or San Mateo’s customers’ operations. Generally, it takes states several years to develop compliance plans for their non-attainment areas. In November 2016, BLM issued final rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands. The rules were designed to limit routine flaring of natural gas, require the payment of royalties on avoidable natural gas losses and require plans or programs relating to natural gas capture and leak detection and repair. Following litigation, the 2016 Waste Prevention Rule was vacated. However, the IRA contains a suite of provisions addressing onshore and offshore oil and natural gas development under Federal leases. Under the authority of the IRA, on November 30, 2022, BLM proposed new regulations to reduce the waste of natural gas from venting, flaring, and leaks during oil and natural gas production activities on Federal and Indian leases. If not withdrawn or significantly revised, these proposed rules are expected to result in an increase to our operating costs and changes in our operations. In December 2023, the EPA issued final NSPS updates and emission guidelines to reduce methane and other pollutants from the oil and gas industry. In addition, several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. As a result of this continued regulatory focus, future federal and state regulations of the oil and natural gas industry remain a possibility and could result in increased compliance costs for our operations.
We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations.
Our pipelines are subject to stringent and complex regulation related to pipeline safety and integrity management. For instance, the Department of Transportation, through PHMSA, has established a series of rules that require pipeline operators to develop and implement integrity management programs for hazardous liquid (including oil) pipeline segments that, in the event of a leak or rupture, could affect high-consequence areas. The Rustler Breaks Oil Pipeline System is subject to such rules. PHMSA also recently finalized rulemaking to expand existing integrity management, reporting and records retention, and safety requirements to certain natural gas transmission lines. Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. At this time, we cannot predict the cost of such requirements, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties.
Several states have also passed legislation or promulgated rules to address pipeline safety. Compliance with pipeline integrity laws and other pipeline safety regulations issued by state agencies such as the RRC and the NMOCD could result in substantial expenditures for testing, repairs and replacement. Due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with PHMSA or state requirements will not have a material adverse effect on our results of operations or financial position.
A change in the jurisdictional characterization of some of our assets by FERC or a change in policy by FERC may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC regulation. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. Similarly, intrastate crude oil pipeline facilities are exempt from regulation by FERC under the ICA. San Mateo’s Rustler Breaks Oil Pipeline System, which includes crude oil gathering and transportation pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains, is subject to FERC jurisdiction. We believe the other crude oil pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as an intrastate facility not subject to FERC regulation. Whether a pipeline provides service in interstate commerce or intrastate commerce is highly fact dependent and determined on a case-by-case basis. A change in the jurisdictional characterization of our facilities by FERC, the courts or Congress, a change in policy by FERC or Congress or the expansion of our activities may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
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. If a party with an economic interest were to file either a complaint against our tariff rates or protest any proposed increases to our tariff rates, or FERC were to initiate an investigation of our rates, then our rates could be subject to detailed review. If any proposed rate increases were found by FERC to be in excess of just and reasonable levels, FERC could order us to reduce our rates and to refund the amount by which the rate increases were determined to be excessive, plus interest. If our existing rates were found by FERC to be in excess of just and reasonable levels, we could be ordered to refund the excess we collected for up to two years prior to the date of the filing of the complaint challenging the rates, and we could be ordered to reduce our rates prospectively. In addition, a state commission also could investigate our intrastate rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our rates exceeded levels justified by our cost of service, the state commission could order us to reduce our rates. 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.
Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to approximately $1.3 million per day for each violation and disgorgement of profits associated with any violation. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation. While the nature of our gathering facilities is such that these facilities have not yet been regulated by FERC, the Rustler Breaks Oil Pipeline System does transport crude oil in interstate commerce and, therefore, is subject to FERC regulation. Laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability.
Derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), among other things, established federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished.
In 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in 2012. However, in 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. In 2016, the CFTC decided to re-propose, rather than finalize, certain regulations, including limitations on speculative futures and swap positions. The CFTC has not acted on the re-proposed position limit regulations. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act could also result in 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.
If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our cash flows, which could adversely affect our ability to make capital expenditures.
Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices.
Any of these consequences could have a material adverse effect on our business, financial condition and results of operations.
Risks Relating to Our Common Stock
The price of our common stock has fluctuated substantially and may fluctuate substantially in the future.
Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2023, our stock price fluctuated between a high of $69.41 and a low of $42.04. In addition, the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.
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;
•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.
Attention to ESG and conservation matters and a negative shift in market perception towards the oil and natural gas industry could adversely affect demand for oil and natural gas and our stock price.
Attention from governmental and regulatory bodies, investors, consumers and other stakeholders on ESG practices, together with changes in consumer, industrial and commercial behavior, investor and societal expectations on companies to address climate change and to make voluntary disclosures related to climate change and sustainability, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons and the use of products manufactured with, or powered, by hydrocarbons, may result in the enactment of climate and ESG-related regulations, policies and initiatives at the government, regulator, corporate and/or investor community levels; technological advances with respect to the generation, transmission, storage and consumption of energy; and the development of, and increased demand from consumers for, lower-emission products and services. These developments may in the future result in increased costs (including increased costs associated with compliance, shareholder engagement, contracting and insurance) and reduced demand for products manufactured with, or powered by, petroleum products, as well as the demand for our products and services. Such developments could result in downward pressure on the stock prices of oil and natural gas companies, including ours.
In addition, negative perceptions regarding our industry and reputational risks, including perceptions related to the sufficiency of our ESG program (which may include policies, practices and extralegal objectives related to climate change, environmental stewardship, social responsibility and corporate governance), may in the future adversely affect our ability to successfully carry out our business strategy by adversely affecting our access to capital. In particular, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. In recent years prior to 2021, equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, sovereign wealth funds, university endowments, individual investors and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Other significant investors and asset managers, both domestically and internationally, have published ESG guidelines and disclosure standards that companies in which they invest are expected to adopt or follow.
Certain other stakeholders have pressured commercial and investment banks and other capital providers to stop or limit funding of oil and natural gas projects and have pressured insurance underwriters to limit coverages to companies engaged in the extraction of fossil fuel reserves. Institutional lenders that provide financing to energy companies have also become more attentive to sustainable lending practices, and some may elect not to provide traditional energy producers or companies that support such producers with funding. With the continued volatility in oil and natural gas prices, and the possibility that interest rates will rise in the near term, increasing the cost of borrowing, certain investors have emphasized capital efficiency and free cash flow from earnings as key drivers for energy companies, especially those primarily focused in the shale plays. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results. Furthermore, if we are unable to achieve the desired level of capital efficiency or free cash flow within the timeframe expected by the market, our stock price may be adversely affected.
In addition, shareholder activism has been recently increasing in the oil and gas industry, and shareholders may attempt to effect changes to our business or governance, whether by shareholder proposals, public campaigns, proxy solicitations or otherwise. Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters, and such ratings are used by some investors to inform their investment and voting decisions. 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.
Future sales of shares of our common stock by existing shareholders and future offerings of our common stock by us could depress the price of our common stock.
The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, including shares of equity or debt securities convertible into common stock, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders, including directors or officers, sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock.
We may also sell or issue additional shares of common stock or equity or debt securities convertible into common stock in public or private offerings or in connection with acquisitions. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market 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.
As of February 20, 2024, our directors and executive officers beneficially owned approximately 6.3% of our outstanding common stock. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, our directors and executive officers may be able to remain entrenched in their positions.
Our Board can authorize the issuance of preferred stock, which could diminish the rights of holders of our common stock and make a change of control of the Company more difficult even if it might benefit our shareholders.
Our Board is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock.
Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the Company, even if that change of control might benefit our shareholders.
General Risk Factors
We may have difficulty managing growth in our business, which could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion.
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. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers, landmen, midstream professionals, attorneys and financial and accounting professionals, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion.
Our success depends, to a large extent, on our ability to retain our key personnel, including our chairman and chief executive officer, management and technical team and the members of our Board, and the loss of any key personnel or Board member could disrupt our business operations.
Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment
agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.
We have an active Board that meets at least quarterly throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our Board work closely with management to identify potential prospects, acquisitions and areas for further development. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected.
It has also been widely reported in the press and elsewhere that businesses have faced a more challenging hiring environment since the onset of the COVID-19 pandemic and the subsequent recovery, which has resulted in increased costs to attract skilled labor, such as higher wages or costs for contractors. We may experience employee turnover or labor shortages if our business requirements, compensation, benefits and/or perquisites are inconsistent with the expectations of current or prospective employees, or if workers pursue employment in fields with less volatility than in the energy industry. If we are unsuccessful in our efforts to attract and retain sufficient qualified personnel on terms acceptable to us, or do so at rates necessary to maintain our competitive position, our business could be adversely affected.
A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss.
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. We depend on such digital technology to, among other things, estimate oil and natural gas reserves quantities, plan, execute and analyze drilling, completion, production, gathering, processing and disposal operations, process and record financial and operating data and communicate with employees, shareholders, royalty owners and other third-party industry participants. Industrial control systems, such as our SCADA systems, control important processes and facilities that are critical to our operations.
While we and our third-party service providers commit resources to the design, implementation and monitoring of our information systems, there is no guarantee that these security measures will provide absolute security. Despite these security measures, we may not be able to anticipate, detect or prevent cyberattacks, particularly because the methodologies used by attackers change frequently or may not be recognized until launch, and because attackers are increasingly using technologies designed to circumvent controls and avoid detection. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches, phishing schemes or attacks, possible consequences include financial losses, damage to our reputation and the inability to engage in any of the aforementioned activities. Any such consequence could have a material adverse effect on our business. In addition, any failure of our third-party providers’ computer systems, or those of our customers, suppliers or others with whom we do business, could materially disrupt our ability to operate our business.
While we have experienced certain phishing schemes and efforts to access our network, we have not experienced any material losses due to cyber incidents. However, we may suffer such losses in the future. 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. Additionally, costs for insurance may also increase as a result of cybersecurity threats, and insurance against losses relating to cyber incidents may become more difficult to obtain.
As cyber threats continue to evolve, we may be required to expend additional resources to continue to modify and further enhance our protective systems or to investigate and remediate any vulnerabilities. In addition, the continuing and evolving threat of cybersecurity attacks has resulted in evolving legal and compliance matters, including increased regulatory focus on prevention, which could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. Any failure by us to comply with any additional regulations could result in significant penalties and liability to us, and we cannot predict the potential impact to our business or the energy industry resulting from additional regulations. We may also be subject to regulatory investigations or litigation relating to cybersecurity issues.
Provisions of our certificate of formation, bylaws and Texas law may have anti-takeover effects that could prevent a change in control even if it might be beneficial to our shareholders.
Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition of the Company or other change in control transaction that our shareholders may consider favorable. 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.
Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or an affiliated shareholder, cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our Board before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder.
We operate in a litigious environment and may be involved in legal proceedings that could have a material adverse effect on our results of operations and financial condition.
Like many oil and natural gas companies, we are from time to time involved in various legal and other proceedings in the ordinary course of business, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have a material adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments.
Not applicable.

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ITEM 2. PROPERTIES
Item 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.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings.
We are party to several legal proceedings encountered in the ordinary course of business. While the ultimate outcome and impact on us cannot be predicted with certainty, in the opinion of management, it is remote that these legal proceedings will have a material adverse impact on our financial condition, results of operations or cash flows.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures.
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
General Market Information
Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since February 2, 2012. 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.
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. On February 13, 2024, the Board declared a quarterly cash dividend of $0.20 per share of common stock payable on March 13, 2024 to shareholders of record as of February 23, 2024. We expect that, 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, 2023.
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”).
(2)The Matador Resources Company 2019 Long-Term Incentive Plan (the “2019 Incentive Plan”) was adopted by our Board in April 2019 and approved by our shareholders on June 6, 2019. For a description of our 2019 Incentive Plan, see Note 9 to the consolidated financial statements in this Annual Report.
(3)The Matador Resources Company 2022 Employee Stock Purchase Plan (the “ESPP”) was adopted by our Board in April 2022 and approved by our shareholders on June 10, 2022. For a description of our ESPP, see Note 9 to the consolidated financial statements in this Annual Report.
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. In calculating the cumulative return, reinvestment of dividends, if any, is assumed.
This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before, on, or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance.
Comparison of Cumulative Total Return Among
Matador Resources Company, the Russell 2000 Index
and the Russell 2000 Energy Index
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.
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. 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.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Selected Financial Data.
Not applicable.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement and the San Mateo Credit Facility, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting our oil and natural gas and midstream operations, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering, processing and transportation facilities, availability and integration of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.”
For a comparison of our results of operations for the years ended December 31, 2022 and December 31, 2021, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on March 1, 2023.
Overview
We are an independent energy company founded in July 2003 engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. We also operate in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana. Additionally, we conduct midstream operations in support of our exploration, development and production operations and provide natural gas processing, oil transportation services, oil, natural gas and produced water gathering services and produced water disposal services to third parties.
2023 Operational Highlights
We began 2023 operating seven drilling rigs in the Delaware Basin. Following the closing of the Initial Advance Acquisition on April 12, 2023, we continued operating the drilling rig that Advance had been operating. Near the end of June 2023, we released this eighth operated drilling rig and continued operating seven drilling rigs in the Delaware Basin for the remainder of 2023. We added back an eighth operated drilling rig in the first quarter of 2024. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. We were able to achieve D/C/E capital expenditures for 2023 of $1.16 billion, which was below our estimated range for 2023 D/C/E capital expenditures of $1.18 to $1.32 billion as provided on February 21, 2023, and was in the middle of the revised estimated range of $1.10 to $1.22 billion, as provided on July 25, 2023.
During the year ended December 31, 2023, we completed and began producing oil and natural gas from 119 gross (94.0 net) operated and 103 gross (5.6 net) horizontal non-operated wells in the Delaware Basin. We did not conduct any operated drilling and completion activities on our leasehold properties in South Texas or Northwest Louisiana during 2023, although we did participate in the drilling and completion of 22 gross (0.4 net) non-operated Haynesville shale wells and one gross (0.4 net) non-operated South Texas well that began producing in 2023.
Substantially all of our 2023 capital expenditures were directed to (i) the further delineation and development of our leasehold position in the Delaware Basin, including properties acquired in the Advance Acquisition, (ii) the acquisition, construction, installation and maintenance of midstream assets, (iii) our participation in non-operated wells drilled and completed in the Delaware Basin, with the exception of amounts allocated to limited operations in our South Texas and Haynesville shale positions, including certain non-operated well opportunities, and (iv) the acquisition of additional producing properties, leasehold and mineral interests prospective for the Wolfcamp, Bone Spring and other liquids-rich plays in the Delaware Basin.
Our average daily oil equivalent production for the year ended December 31, 2023 was 131,813 BOE per day, including 75,457 Bbl of oil per day and 338.1 MMcf of natural gas per day, an increase of 25%, as compared to 105,465 BOE per day, including 60,119 Bbl of oil per day and 272.1 MMcf of natural gas per day, for the year ended December 31, 2022. Our average daily oil production in 2023 was 75,457 Bbl of oil per day, an increase of 26%, as compared to 60,119 Bbl of oil per day in 2022. This increase in oil production was primarily a result of the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin, which offset declining oil production in the Eagle Ford shale where we have not turned to sales any new operated wells since the second quarter of 2019. Our average daily natural gas production for the year ended December 31, 2023 was 338.1 MMcf per day, an increase of 24%, as compared to 272.1 MMcf per day in 2022. This increase in natural gas production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Oil production comprised 57% of our total production for each of the years ended December 31, 2023 and 2022.
For the year ended December 31, 2023, our oil and natural gas revenues were $2.55 billion, a decrease of 12% from oil and natural gas revenues of $2.91 billion for the year ended December 31, 2022. Our oil revenues increased 1% to $2.14 billion, as compared to $2.11 billion for the year ended December 31, 2022. The increase in oil revenues resulted from the 26% increase in our oil production noted above, which was partially offset by a 19% decrease in the weighted average oil price realized for the year ended December 31, 2023 to $77.88 per Bbl, as compared to $96.32 per Bbl realized for the year ended December 31, 2022. Our natural gas revenues decreased 49% to $400.7 million, as compared to $792.1 million for the year ended December 31, 2022. The decrease in natural gas revenues resulted from a decrease in our weighted average realized natural gas price of $3.25 per Mcf in 2023, as compared to $7.98 per Mcf in 2022, which was partially offset by the 24% increase in natural gas production for the year ended December 31, 2023 noted above.
We reported net income attributable to Matador shareholders of approximately $846.1 million, or $7.05 per diluted common share, on a GAAP basis for the year ended December 31, 2023, as compared to a net income of $1.21 billion, or $10.11 per diluted common share, for the year ended December 31, 2022. Adjusted EBITDA for the year ended December 31, 2023 was $1.85 billion, as compared to Adjusted EBITDA of $2.13 billion for the year ended December 31, 2022. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Non-GAAP Financial Measures.”
At December 31, 2023, our estimated total proved oil and natural gas reserves were 460.1 million BOE, including 272.3 million Bbl of oil and 1.13 Tcf of natural gas, with a Standardized Measure of $6.11 billion and a PV-10 of $7.70 billion. At December 31, 2022, our estimated total proved oil and natural gas reserves were 356.7 million BOE, including 196.3 million Bbl of oil and 962.6 Bcf of natural gas, with a Standardized Measure of $6.98 billion and a PV-10 of $9.13 billion. Our estimated total proved reserves of 460.1 million BOE at December 31, 2023 represented a 29% year-over-year increase, as compared to 356.7 million BOE at December 31, 2022. Our estimated proved oil reserves were 272.3 million Bbl at December 31, 2023, an increase of 39%, as compared to 196.3 million Bbl at December 31, 2022, and our estimated proved natural gas reserves were 1.13 Tcf at December 31, 2023, an increase of 17%, as compared to 962.6 Bcf at December 31, 2022. Proved oil reserves comprised 59% of our total proved reserves at December 31, 2023, as compared to 55% at December 31, 2022. At December 31, 2023, 63% of our total proved reserves were proved developed reserves, as compared to 62% at December 31, 2022.
Our proved oil and natural gas reserves in the Delaware Basin increased 31% to 452.6 million BOE at December 31, 2023, as compared to 346.8 million BOE at December 31, 2022, primarily as a result of the Advance Acquisition and our ongoing delineation and development operations there. At December 31, 2023, approximately 98% of our total proved oil and natural gas reserves were attributable to our properties in the Delaware Basin. Our proved oil reserves in the Delaware Basin increased 40% to 270.1 million Bbl at December 31, 2023, as compared to 193.5 million Bbl at December 31, 2022, and our proved natural gas reserves in the Delaware Basin increased 19% to 1.09 Tcf, as compared to 919.7 Bcf at December 31, 2022. Proved oil reserves comprised 60% of our Delaware Basin total proved reserves at December 31, 2023, as compared to 56% at December 31, 2022.
At both December 31, 2023 and December 31, 2022, these reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business-Estimated Proved Reserves.”
2023 Midstream Highlights
San Mateo achieved strong operating results in 2023, highlighted by (i) free cash flow generation, (ii) increased midstream services revenues and (iii) increased natural gas gathering and processing volumes, produced water handling volumes and oil gathering and transportation volumes. Volumes for the years ended December 31, 2023 and 2022 do not include the full quantity of volumes that would have otherwise been delivered by certain San Mateo customers subject to minimum volume commitments (although partial deliveries were made in both years), but for which San Mateo recognized revenues during the years ended December 31, 2023 and 2022. San Mateo is owned 51% by us and 49% by our joint venture partner, Five Point.
During 2023, San Mateo closed new midstream transactions with oil and natural gas producers and other counterparties in Eddy County, New Mexico, which are expected to generate additional natural gas gathering and processing and water handling volumes in future periods. A majority of these new opportunities reflect additional business awarded to San Mateo by existing customers, which we believe is indicative of the quality of service San Mateo provides to all of its customers in the Delaware Basin.
At December 31, 2023, San Mateo’s midstream system included:
•Natural Gas Assets: 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 160 miles of natural gas gathering pipelines in Eddy County, New Mexico and Loving County, Texas, including 43 miles of large diameter natural gas gathering lines spanning from the Stateline asset area to the Greater Stebbins Area in Eddy County, New Mexico;
•Oil Assets: three oil CDPs with over 100,000 Bbl of designed oil throughput capacity and approximately 100 miles of oil gathering and transportation pipelines in Eddy County, New Mexico and Loving County, Texas, as well as a 400,000-acre joint development area with Plains to gather our and other producers’ oil production in Eddy County, New Mexico; and
•Produced Water Assets: 16 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 475,000 Bbl per day and approximately 175 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.
During 2023, Pronto closed new natural gas gathering and processing transactions with counterparties in Eddy and Lea Counties, New Mexico, which are expected to generate additional natural gas gathering and processing volumes in future periods. At December 31, 2023, Pronto’s midstream system included the Marlan Processing Plant, three compressor stations and approximately 70 miles of natural gas gathering pipelines in Eddy and Lea Counties, New Mexico, spanning from the northeastern portion of the Arrowhead asset area into the Ranger asset area. Pronto has also contracted to construct an additional natural gas processing plant with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities to be located near the Marlan Processing Plant.
2024 Capital Expenditure Budget
We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2024. We began 2023 operating seven drilling rigs in the Delaware Basin. Following the closing of the Initial Advance Acquisition on April 12, 2023, we continued operating the drilling rig that Advance had been operating. Near the end of June 2023, we released this eighth operated drilling rig and continued operating seven drilling rigs in the Delaware Basin for the remainder of 2023. We added back an eighth operated drilling rig in the first quarter of 2024. We have built significant optionality into our 2024 drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2024 estimated capital expenditure budget consists of $1.10 to $1.30 billion for D/C/E capital expenditures and $200.0 to $250.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2024 capital expenditures as well as the estimated 2024 capital expenditures for other wholly-owned midstream projects, including projects completed by Pronto. The midstream capital expenditure budget includes 100% of the costs associated with the Marlan Processing Plant expansion noted above, although, at February 20, 2024, we were continuing to evaluate potential partners in Pronto that would share in these capital expenditures and strategic opportunities. Substantially all of these 2024 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, South Texas and Haynesville shale. Our 2024 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells in 2024, including 99% with anticipated completed lateral lengths of one mile or greater.
At December 31, 2023, we had $52.7 million in cash (excluding restricted cash) and $772.6 million in undrawn borrowing capacity under the Credit Agreement (after giving effect to outstanding letters of credit based upon our elected borrowing commitment of $1.325 billion). We expect to fund our 2024 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2024, we expect to fund any excess capital expenditures, including for other significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all.
As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, during 2024, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2024 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2024.
Revenues
The following table summarizes our revenues and production data for the periods indicated.
Year Ended December 31,
2023 2022 2021
Operating Data:
Revenues (in thousands):(1)
Oil $ 2,144,894 $ 2,113,606 $ 1,205,608
Natural gas 400,705 792,132 494,934
Total oil and natural gas revenues 2,545,599 2,905,738 1,700,542
Third-party midstream services revenues 122,153 90,606 75,499
Sales of purchased natural gas 149,869 200,355 86,034
Realized loss on derivatives (9,575) (157,483) (220,105)
Unrealized (loss) gain on derivatives (1,261) 18,809 21,011
Total revenues $ 2,806,785 $ 3,058,025 $ 1,662,981
Net Production Volumes:(1)
Oil (MBbl) 27,542 21,943 17,840
Natural gas (Bcf) 123.4 99.3 81.7
Total oil equivalent (MBOE)(2)
48,112 38,495 31,454
Average daily production (BOE/d)(2)
131,813 105,465 86,176
Average Sales Prices:
Oil, without realized derivatives (per Bbl) $ 77.88 $ 96.32 $ 67.58
Oil, with realized derivatives (per Bbl) $ 77.88 $ 92.87 $ 56.70
Natural gas, without realized derivatives (per Mcf) $ 3.25 $ 7.98 $ 6.06
Natural gas, with realized derivatives (per Mcf) $ 3.17 $ 7.15 $ 5.74
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(1)We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with NGLs are included with our natural gas revenues.
(2)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
Year Ended December 31, 2023 as Compared to Year Ended December 31, 2022
Oil and natural gas revenues. Our oil and natural gas revenues decreased $360.1 million, or 12%, to $2.55 billion for the year ended December 31, 2023, as compared to $2.91 billion for the year ended December 31, 2022. Our oil revenues increased $31.3 million, or 1%, to $2.14 billion for the year ended December 31, 2023, as compared to $2.11 billion for the year ended December 31, 2022. This increase in oil revenues resulted from a 26% increase in our oil production to 27.5 million Bbl of oil for the year ended December 31, 2023, as compared to 21.9 million Bbl of oil for the year ended December 31, 2022, which was partially offset by a 19% decrease in the weighted average oil price realized for the year ended December 31, 2023 to $77.88 per Bbl, as compared to $96.32 per Bbl realized for the year ended December 31, 2022. The increase in oil production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin. Our natural gas revenues decreased by $391.4 million, or 49%, to $400.7 million for the year ended December 31, 2023, as compared to $792.1 million for the year ended December 31, 2022. The decrease in natural gas revenues was primarily attributable to the 59% decrease in the weighted average natural gas price realized for the year ended December 31, 2023 to $3.25 per Mcf, as compared to $7.98 per Mcf realized for the year ended December 31, 2022, which was partially offset by a 24% increase in our natural gas production to 123.4 Bcf for the year ended December 31, 2023, as compared to 99.3 Bcf for the year ended December 31, 2022. The increase in natural gas production was primarily attributable to the Advance Acquisition and our ongoing delineation and development drilling activities in the Delaware Basin.
Third-party midstream services revenues. Our third-party midstream services revenues increased $31.5 million, or 35%, to $122.2 million for the year ended December 31, 2023, as compared to $90.6 million for the year ended December 31, 2022. Third-party midstream services revenues are those revenues from midstream operations related to third parties, including working interest owners in our operated wells. This increase was primarily attributable to (i) an increase in our third-party natural gas gathering, transportation and processing revenues to $65.9 million for the year ended December 31, 2023, as compared to $45.1 million for the year ended December 31, 2022, which includes $15.9 million associated with operating our Pronto midstream assets for the year ended December 31, 2023, as compared to $4.4 million for the year ended December 31, 2022, and (ii) an increase in third-party produced water disposal revenues to $45.3 million for the year ended December 31, 2023, as compared to $35.6 million for the year ended December 31, 2022.
Sales of purchased natural gas. Our sales of purchased natural gas decreased $50.5 million, or 25%, to $149.9 million for the year ended December 31, 2023, as compared to $200.4 million for the year ended December 31, 2022. This decrease was primarily the result of the 65% decrease in realized natural gas prices, which was partially offset by a 117% increase in natural gas volumes sold during the year ended December 31, 2023. Sales of purchased natural gas primarily reflect those natural gas purchase transactions that we periodically enter into with third parties whereby we purchase natural gas and (i) subsequently sell the natural gas to other purchasers or (ii) process the natural gas at Pronto’s Marlan Processing Plant or San Mateo’s Black River Processing Plant and subsequently sell the residue gas and NGLs to other purchasers. These revenues, and the expenses related to these transactions included in “Purchased natural gas,” are presented on a gross basis in our consolidated statements of income.
Realized loss on derivatives. Our realized net loss on derivatives was $9.6 million for the year ended December 31, 2023, as compared to a realized net loss of approximately $157.5 million for the year ended December 31, 2022. We realized a net loss of approximately $9.6 million related to our natural gas costless collar and natural gas basis differential swap contracts for the year ended December 31, 2023, resulting primarily from natural gas basis differentials that were above the strike price of our natural gas basis differential swap contracts, offset by natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. We realized a net loss of approximately $81.7 million related to our natural gas costless collar contracts for the year ended December 31, 2022, resulting primarily from natural gas prices that were above the ceiling prices of certain of our natural gas costless collar contracts. We realized a net loss of $73.9 million related to our oil costless collar contracts for the year ended December 31, 2022, resulting primarily from oil prices that were above the ceiling prices of certain of our oil costless collar contracts. We realized a net loss of $1.9 million from our oil basis differential swap contracts for the year ended December 31, 2022, resulting from oil basis differentials that were above the fixed prices of certain of our oil basis differential swap contracts. We realized an average loss on our natural gas derivatives of approximately $0.08 per Mcf of natural gas produced during the year ended December 31, 2023, as compared to an average loss on our natural gas derivatives of approximately $0.83 per Mcf of natural gas produced during the year ended December 31, 2022. Our total natural gas volumes hedged represented 2% and 61% of our total natural gas production for the years ended December 31, 2023 and 2022, respectively.
Unrealized (loss) gain on derivatives. Our unrealized loss on derivatives was approximately $1.3 million for the year ended December 31, 2023, as compared to an unrealized gain of $18.8 million for the year ended December 31, 2022. During the year ended December 31, 2023, the aggregate net fair value of our open natural gas derivative contracts changed from a net asset of approximately $3.9 million to a net asset of approximately $2.7 million, resulting in an unrealized loss on derivatives of approximately $1.3 million for the year ended December 31, 2023. During the year ended December 31, 2022, the aggregate net fair value of our open oil and natural gas derivatives and oil basis differential swap contracts changed from a net liability of approximately $14.9 million to a net asset of approximately $3.9 million, resulting in an unrealized gain on derivatives of approximately $18.8 million for the year ended December 31, 2022.
Expenses
The following table summarizes our operating expenses and other income (expense) for the periods indicated.
Year Ended December 31,
2023 2022 2021
(In thousands, except expenses per BOE)
Expenses:
Production taxes, transportation and processing $ 264,493 $ 282,193 $ 178,987
Lease operating 243,655 157,105 108,964
Plant and other midstream services operating 128,910 95,522 61,459
Purchased natural gas 129,401 178,937 77,126
Depletion, depreciation and amortization 716,688 466,348 344,905
Accretion of asset retirement obligations 3,943 2,421 2,068
General and administrative 110,373 116,229 96,396
Total expenses 1,597,463 1,298,755 869,905
Operating income 1,209,322 1,759,270 793,076
Other income (expense):
Net loss on asset sales and impairment (202) (1,311) (331)
Interest expense (121,520) (67,164) (74,687)
Other income (expense) 8,785 (5,121) (2,712)
Total other expense (112,937) (73,596) (77,730)
Income before income taxes 1,096,385 1,685,674 715,346
Income tax provision (benefit)
Current 13,922 54,877 -
Deferred 172,104 344,480 74,710
Total income tax provision 186,026 399,357 74,710
Net income attributable to non-controlling interest in subsidiaries (64,285) (72,111) (55,668)
Net income attributable to Matador Resources Company shareholders $ 846,074 $ 1,214,206 $ 584,968
Expenses per BOE:
Production taxes, transportation and processing $ 5.50 $ 7.33 $ 5.69
Lease operating $ 5.06 $ 4.08 $ 3.46
Plant and other midstream services operating $ 2.68 $ 2.48 $ 1.95
Depletion, depreciation and amortization $ 14.90 $ 12.11 $ 10.97
General and administrative $ 2.29 $ 3.02 $ 3.06
Year Ended December 31, 2023 as Compared to Year Ended December 31, 2022
Production taxes, transportation and processing. Our production taxes and transportation and processing expenses decreased $17.7 million, or 6%, to $264.5 million for the year ended December 31, 2023, as compared to $282.2 million for the year ended December 31, 2022. On a unit-of-production basis, our production taxes and transportation and processing expenses decreased 25% to $5.50 per BOE for the year ended December 31, 2023, as compared to $7.33 per BOE for the year ended December 31, 2022. These decreases were primarily attributable to the $22.7 million decrease in our production taxes to $200.2 million for the year ended December 31, 2023, as compared to $222.9 million for the year ended December 31, 2022, resulting from the $360.1 million decrease in oil and natural gas revenues for the year ended December 31, 2023, as compared to the year ended December 31, 2022, which was partially offset by the $5.0 million increase in transportation and processing expenses to $64.3 million for the year ended December 31, 2023, as compared to $59.3 million for the year ended December 31, 2022, primarily resulting from the 25% increase in total oil equivalent production between the respective periods.
Lease operating expenses. Our lease operating expenses increased $86.6 million, or 55%, to $243.7 million for the year ended December 31, 2023, as compared to $157.1 million for the year ended December 31, 2022. On a unit-of-production basis, our lease operating expenses increased 24% to $5.06 per BOE for the year ended December 31, 2023, as compared to $4.08 per BOE for the year ended December 31, 2022. These increases for the year ended December 31, 2023 were primarily attributable to the increased number of wells being operated by us, including 127 wells from the Advance Acquisition, and other operators (where we own a working interest) and to operating cost inflation during the year-ended December 31, 2023, as compared to the year ended December 31, 2022.
Plant and other midstream services operating. Our plant and other midstream services operating expenses increased $33.4 million, or 35%, to $128.9 million for the year ended December 31, 2023, as compared to $95.5 million for the year ended December 31, 2022. This increase was primarily attributable to increased throughput volumes at San Mateo and Pronto
from Matador and other customers, which resulted in (i) increased expenses associated with our expanded pipeline operations of $36.7 million for the year ended December 31, 2023, as compared to $24.9 million for the year ended December 31, 2022, (ii) increased expenses associated with our commercial produced water disposal operations of $53.6 million for the year ended December 31, 2023, as compared to $46.5 million for the year ended December 31, 2022, and (iii) increased expenses in connection with operating our Pronto midstream assets of $18.3 million for the year ended December 31, 2023, which assets were purchased on June 30, 2022, as compared to $8.3 million for the year ended December 31, 2022.
Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased $250.3 million, or 54%, to $716.7 million for the year ended December 31, 2023, as compared to $466.3 million for the year ended December 31, 2022, primarily as a result of the Advance Acquisition and a 25% increase in our total oil equivalent production between the respective periods. On a unit-of-production basis, our depletion, depreciation and amortization expenses increased 23% to $14.90 per BOE for the year ended December 31, 2023, as compared to $12.11 per BOE for the year ended December 31, 2022, primarily as a result of the Advance Acquisition and an increase in actual costs and estimated future costs to drill, complete and equip our wells between the two periods.
General and administrative. Our general and administrative expenses decreased $5.9 million, or 5%, to $110.4 million for the year ended December 31, 2023, as compared to $116.2 million for the year ended December 31, 2022. Our general and administrative expenses on a unit-of-production basis decreased 24% to $2.29 per BOE for the year ended December 31, 2023, as compared to $3.02 per BOE for the year ended December 31, 2022, primarily as a result of the 25% increase in our total oil equivalent production between the two periods.
Interest expense. For the year ended December 31, 2023, we incurred total interest expense of approximately $143.7 million. We capitalized approximately $22.2 million of our interest expense on certain qualifying projects for the year ended December 31, 2023 and expensed the remaining $121.5 million to operations. For the year ended December 31, 2022, we incurred total interest expense of approximately $77.2 million. We capitalized approximately $10.1 million of our interest expense on certain qualifying projects for the year ended December 31, 2022 and expensed the remaining $67.2 million to operations. The increase in interest expense for the year ended December 31, 2023 is a result of borrowings under the Credit Agreement that were used in connection with the Advance Acquisition, borrowings under the San Mateo Credit Facility, the issuance of the 2028 Notes in April 2023 and the significant increase in interest rates between the two periods.
Total income tax provision. We recorded a current income tax provision of $13.9 million and a deferred income tax provision of $172.1 million for the year ended December 31, 2023. Our effective income tax rate of 18% for the year ended December 31, 2023 differed from the U.S. federal statutory rate due primarily to recognizing research and experimental expenditure tax credits of $74.0 million, which were partially offset by permanent differences between book and taxable income and state taxes, primarily in New Mexico. We recorded a current income tax provision of $54.9 million and a deferred income tax provision of $344.5 million for the year ended December 31, 2022. Our effective income tax rate of 25% for the year ended December 31, 2022 differed from the U.S. federal statutory rate due primarily to permanent differences between book and taxable income and state taxes, primarily in New Mexico.
Liquidity and Capital Resources
Our primary use of capital has been, and we expect will continue during 2024 and for the foreseeable future to be, for the acquisition, exploration and development of oil and natural gas properties and for midstream investments. In April 2023, we closed the Initial Advance Acquisition that was funded through a combination of cash on hand and borrowings under our Credit Agreement. In addition, on April 11, 2023, we issued and sold $500.0 million in aggregate principal amount of 2028 Notes. We used the net proceeds from the sale of the 2028 Notes of approximately $487.6 million, after deducting the initial purchasers’ discounts and estimated offering expenses, to partially repay borrowings under our Credit Agreement. We expect to fund our 2024 capital expenditures through a combination of cash on hand, operating cash flows and performance incentives paid to us by Five Point in connection with San Mateo. If capital expenditures were to exceed our operating cash flows in 2024, we expect to fund any excess capital expenditures, including for significant acquisitions, through borrowings under the Credit Agreement or the San Mateo Credit Facility (assuming availability under such facilities) or through other capital sources, including borrowings under expanded or additional credit arrangements, the sale or joint venture of midstream assets, oil and natural gas producing assets, leasehold interests or mineral interests and potential issuances of equity, debt or convertible securities, none of which may be available on satisfactory terms or at all. Our future success in growing proved reserves and production will be highly dependent on our ability to generate operating cash flows and access outside sources of capital.
At December 31, 2023, we had cash totaling $52.7 million and restricted cash totaling $53.6 million, which was primarily associated with San Mateo. By contractual agreement, the cash in the accounts held by our less-than-wholly-owned subsidiaries is not to be commingled with our other cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries.
At December 31, 2023, we had (i) $699.2 million of outstanding 5.875% senior notes due September 2026 (the “2026 Notes”), (ii) $500.0 million of outstanding 2028 Notes, (iii) $500.0 million of borrowings outstanding under the Credit Agreement and (iv) approximately $52.3 million in outstanding letters of credit issued pursuant to the Credit Agreement.
In March 2023, the lenders under our Credit Agreement completed their review of our proved oil and natural gas reserves, and, as a result, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) reaffirm the borrowing base at $2.25 billion, (ii) increase the elected borrowing commitment from $775.0 million to $1.25 billion and (iii) maintain the maximum facility amount at $1.50 billion. This March 2023 redetermination constituted the regularly scheduled May 1 redetermination.
In October 2023, the lenders under our Credit Agreement completed their review of the our proved oil and natural gas reserves, and, as a result, we and our lenders entered into an amendment to the Fourth Amended and Restated Credit Agreement, which amended the Credit Agreement to, among other things: (i) increase the borrowing base from $2.25 billion to $2.50 billion, (ii) increase the elected borrowing commitment from $1.25 billion to $1.325 billion and (iii) increase the maximum facility amount from $1.50 billion to $2.00 billion. This October 2023 redetermination constituted the regularly scheduled November 1 redetermination. Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected borrowing commitment (subject to compliance with the covenants noted below). The Credit Agreement matures October 31, 2026.
The Credit Agreement requires us to maintain (i) a current ratio, which is defined as (x) total consolidated current assets plus the unused availability under the Credit Agreement divided by (y) total consolidated current liabilities less current maturities under the Credit Agreement, of not less than 1.0 to 1.0 at the end of each fiscal quarter and (ii) a debt to EBITDA ratio, which is defined as debt outstanding (net of up to $75 million of unrestricted cash and cash equivalents) divided by a rolling four quarter EBITDA calculation, of 3.50 to 1.0 or less at the end of each fiscal quarter. We believe that we were in compliance with the terms of the Credit Agreement at December 31, 2023.
At December 31, 2023, San Mateo had $522.0 million in borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. In October 2023, the lenders under the San Mateo Credit Facility increased the lender commitments from $485.0 million to $535.0 million. The San Mateo Credit Facility matures December 9, 2026.
The San Mateo Credit Facility is non-recourse with respect to Matador and its other subsidiaries, but is guaranteed by San Mateo’s subsidiaries and secured by substantially all of San Mateo’s assets, including real property. The San Mateo Credit Facility requires San Mateo to maintain a debt to EBITDA ratio, which is defined as total consolidated funded indebtedness outstanding (as defined in the San Mateo Credit Facility) divided by a rolling four quarter EBITDA calculation, of 5.00 or less, subject to certain exceptions. The San Mateo Credit Facility also requires San Mateo to maintain an interest coverage ratio, which is defined as a rolling four quarter EBITDA calculation divided by San Mateo’s consolidated interest expense for such period, of 2.50 or more. The San Mateo Credit Facility also restricts the ability of San Mateo to distribute cash to its members if San Mateo’s liquidity is less than 10% of the lender commitments under the San Mateo Credit Facility. We believe that San Mateo was in compliance with the terms of the San Mateo Credit Facility at December 31, 2023.
In February 2023, April 2023 and July 2023, our Board declared quarterly cash dividends of $0.15 per share of common stock. In October 2023, the Board amended our dividend policy to increase the quarterly dividend to $0.20 per share of common stock and also declared a quarterly cash dividend of $0.20 per share of common stock. On February 13, 2024, the Board declared a quarterly cash dividend of $0.20 per share of common stock payable on March 13, 2024 to shareholders of record as of February 23, 2024.
We expect that development of our Delaware Basin assets will be the primary focus of our operations and capital expenditures in 2024. We began 2024 operating seven contracted drilling rigs in the Delaware Basin and added an eighth operated drilling rig in the first quarter of 2024. We have built significant optionality into our drilling program, which should generally allow us to decrease or increase the number of rigs we operate as necessary based on changing commodity prices and other factors. Our 2024 estimated capital expenditure budget consists of $1.10 to $1.30 billion for D/C/E capital expenditures and $200.0 to $250.0 million for midstream capital expenditures, which reflects our proportionate share of San Mateo’s estimated 2024 capital expenditures as well as the estimated 2024 capital expenditures for other wholly-owned midstream projects, including projects completed by Pronto. The midstream capital expenditure budget includes 100% of the costs associated with the Marlan Processing Plant expansion noted above, although, at February 20, 2024, we were continuing to evaluate potential partners in Pronto that would share in these capital expenditures and strategic opportunities. Substantially all of these 2024 estimated capital expenditures are expected to be allocated to (i) the further delineation and development of our leasehold position, (ii) the construction, installation and maintenance of midstream assets and (iii) our participation in certain non-operated well opportunities in the Delaware Basin, South Texas and the Haynesville shale. Our 2024 Delaware Basin operated drilling program is expected to focus on the continued development of our various asset areas throughout the Delaware
Basin, with a continued emphasis on drilling and completing a high percentage of longer horizontal wells, including 99% with anticipated completed lateral lengths of greater than one mile.
As we have done in recent years, we may divest portions of our non-core assets, particularly in the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana, as well as consider monetizing other assets, such as certain midstream assets and mineral and royalty interests, as value-creating opportunities arise. In addition, during 2024, we intend to continue evaluating the opportunistic acquisition of producing properties, acreage and mineral interests and midstream assets, principally in the Delaware Basin. These monetizations, divestitures and expenditures are opportunity-specific, and purchase price multiples and per-acre prices can vary significantly based on the asset or prospect. As a result, it is difficult to estimate these 2024 monetizations, divestitures and capital expenditures with any degree of certainty; therefore, we have not provided estimated proceeds related to monetizations or divestitures or estimated capital expenditures related to acquiring producing properties, acreage and mineral interests and midstream assets for 2024.
Our 2024 capital expenditures may be adjusted as business conditions warrant and the amount, timing and allocation of such expenditures is largely discretionary and within our control. The aggregate amount of capital we will expend may fluctuate materially based on market conditions, the actual costs to drill, complete and place on production operated or non-operated wells, our drilling results, the actual costs and scope of our midstream activities, the ability of our joint venture partners to meet their capital obligations, other opportunities that may become available to us and our ability to obtain capital. When oil or natural gas prices decline, or costs increase significantly, we have the flexibility to defer a significant portion of our capital expenditures until later periods to conserve cash or to focus on projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control.
Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate. A significant portion of our anticipated cash flows from operations for 2024 is expected to come from producing wells and development activities on currently proved properties in the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale in South Texas and the Haynesville shale in Northwest Louisiana. Our existing wells may not produce at the levels we are forecasting and our exploration and development activities in these areas may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2024 and the hedges we currently have in place. For a discussion of our expectations of such commodity prices, see “-General Outlook and Trends” below. At times, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. See Note 12 to the consolidated financial statements in this Annual Report for a summary of our open derivative financial instruments at December 31, 2023. See “Risk Factors-Risks Related to our Financial Condition-Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth,” “Risk Factors-Risks Related to our Operations-Drilling for and producing oil, natural gas and NGLs is highly speculative and involves a high degree of operational and financial risk, with many uncertainties that could adversely affect our business,” “Risk Factors-Risks Related to our Operations-Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling” and “Risk Factors-Risks Related to Laws and Regulations-Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”
Our cash flows for the years ended December 31, 2023, 2022 and 2021 are presented below.
Year Ended December 31,
2023 2022 2021
(In thousands)
Net cash provided by operating activities $ 1,867,828 $ 1,978,739 $ 1,053,355
Net cash used in investing activities (3,211,192) (1,037,477) (729,265)
Net cash provided by (used in) financing activities 902,332 (480,852) (328,553)
Net change in cash $ (441,032) $ 460,410 $ (4,463)
Adjusted EBITDA attributable to Matador Resources Company shareholders(1)
$ 1,849,547 $ 2,127,156 $ 1,051,973
__________________
(1)Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income and net cash provided by operating activities, see “-Non-GAAP Financial Measures” below.
Cash Flows Provided by Operating Activities
Net cash provided by operating activities decreased by $110.9 million to $1.87 billion for the year ended December 31, 2023, as compared to net cash provided by operating activities of $1.98 billion for the year ended December 31, 2022. Excluding changes in operating assets and liabilities, net cash provided by operating activities decreased to $1.82 billion for the year ended December 31, 2023 from $2.10 billion for the year ended December 31, 2022. This decrease was primarily attributable to lower realized oil and natural gas prices for the year ended December 31, 2023, as compared to the year ended December 31, 2022, which was partially offset by the 25% increase in total oil equivalent production during 2023, as compared to 2022. Changes in our operating assets and liabilities between December 31, 2022 and December 31, 2023 resulted in a net increase of approximately $168.0 million in net cash provided by operating activities for the year ended December 31, 2023, as compared to the year ended December 31, 2022.
Our operating cash flows are sensitive to a number of variables, including changes in our production and the volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, the actions of OPEC+ and other large state-controlled oil producers, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. From time to time, we use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. For additional information on the impact of changing prices on our financial condition, see “Quantitative and Qualitative Disclosures About Market Risk.” See also “Risk Factors-Risks Related to Our Financial Condition-Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”
Cash Flows Used in Investing Activities
Net cash used in investing activities increased by $2.17 billion to $3.21 billion for the year ended December 31, 2023 from $1.04 billion for the year ended December 31, 2022. This increase in net cash used in investing activities was primarily due to (i) an increase between the periods of $1.68 billion in expenditures related to the Advance Acquisition, (ii) an increase between the periods of $421.0 million in D/C/E capital expenditures primarily attributable to our operated and non-operated drilling, completion and equipping activities in the Delaware Basin and (iii) an increase between the periods of $85.7 million in midstream capital expenditures. These increases were partially offset by a decrease of $75.8 million related to the Pronto Acquisition in 2022.
Cash Flows Provided by (Used in) Financing Activities
Net cash provided by financing activities increased $1.38 billion to $902.3 million for the year ended December 31, 2023, from net cash used in financing activities of $480.9 million for the year ended December 31, 2022. During the year ended December 31, 2023, our net cash provided by financing activities was primarily attributable to (i) proceeds from the issuance of the 2028 Notes of $494.8 million, (ii) net borrowings under our Credit Agreement of $500.0 million and (iii) net borrowings under the San Mateo Credit Facility of $57.0 million, which were partially offset by (x) dividends paid of $77.2 million and (y) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $15.6 million. During the year ended December 31, 2022, our net cash used in financing activities was primarily attributable to (i) the repurchase of an aggregate principal of $350.8 million of the 2026 Notes for $344.3 million, (ii) net repayments under our Credit Agreement of $100.0 million, (iii) net distributions related to non-controlling interest owners of less-than-wholly-owned subsidiaries of $57.7 million and (iv) dividends paid of $35.2 million, which were partially offset by net borrowings under the San Mateo Credit Facility of $80.0 million.
See Note 7 to the consolidated financial statements in this Annual Report for a summary of our debt, including the Credit Agreement, the San Mateo Credit Facility, the 2026 Notes and the 2028 Notes.
Guarantor Financial Information
As of December 31, 2023, Matador’s outstanding senior notes registered under the Securities Act consisted of the 2026 Notes. The 2026 Notes are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). At December 31, 2023, the Guarantor Subsidiaries were each 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. Neither San Mateo nor Pronto is a Guarantor Subsidiary of the 2026 Notes.
The following tables present summarized financial information of Matador (as issuer of the 2026 Notes) and the Guarantor Subsidiaries on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the Guarantor Subsidiaries and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. This financial information is presented in accordance with the amended requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations or financial position had the Guarantor Subsidiaries operated as independent entities.
(in thousands)
Summarized Balance Sheet December 31, 2023
Assets
Current assets $ 619,716
Net property and equipment $ 5,867,130
Other long-term assets $ 64,759
Liabilities
Current liabilities $ 684,159
Long-term debt $ 1,684,627
Other long-term liabilities $ 701,153
(in thousands) Year Ended
Summarized Statement of Income December 31, 2023
Revenues $ 2,550,755
Expenses 1,499,363
Operating income $ 1,051,392
Other expense (80,325)
Tax provision (186,026)
Net income $ 785,041
Non-GAAP Financial Measures
We define Adjusted EBITDA attributable to Matador shareholders (“Adjusted EBITDA”) as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, non-recurring transaction costs for certain acquisitions, certain other non-cash items and non-cash stock-based compensation expense and net gain or loss on asset sales and impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.
Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired.
Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with GAAP or as a primary indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and
assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.
The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities, respectively.
Year Ended December 31,
2023 2022 2021
(In thousands)
Unaudited Adjusted EBITDA Reconciliation to Net Income:
Net income attributable to Matador Resources Company shareholders $ 846,074 $ 1,214,206 $ 584,968
Net income attributable to non-controlling interest in subsidiaries 64,285 72,111 55,668
Net income 910,359 1,286,317 640,636
Interest expense 121,520 67,164 74,687
Total income tax provision 186,026 399,357 74,710
Depletion, depreciation and amortization 716,688 466,348 344,905
Accretion of asset retirement obligations 3,943 2,421 2,068
Unrealized loss (gain) on derivatives 1,261 (18,809) (21,011)
Non-cash stock-based compensation expense 13,661 15,123 9,039
Net loss on impairment 202 1,311 331
(Income) expense related to contingent consideration and other (6,038) 4,926 1,485
Consolidated Adjusted EBITDA 1,947,622 2,224,158 1,126,850
Adjusted EBITDA attributable to non-controlling interest in subsidiaries (98,075) (97,002) (74,877)
Adjusted EBITDA attributable to Matador Resources Company shareholders $ 1,849,547 $ 2,127,156 $ 1,051,973
Year Ended December 31,
2023 2022 2021
(In thousands)
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities:
Net cash provided by operating activities $ 1,867,828 $ 1,978,739 $ 1,053,355
Net change in operating assets and liabilities (50,027) 117,935 982
Interest expense, net of non-cash portion 114,473 63,064 71,028
Current income tax provision 13,922 54,877 -
Other non-cash and non-recurring expense 1,426 9,543 1,485
Adjusted EBITDA attributable to non-controlling interest in subsidiaries (98,075) (97,002) (74,877)
Adjusted EBITDA attributable to Matador Resources Company shareholders $ 1,849,547 $ 2,127,156 $ 1,051,973
For the year ended December 31, 2023, we reported net income attributable to Matador shareholders of $846.1 million, as compared to $1.21 billion for the year ended December 31, 2022. This decrease primarily resulted from lower realized oil and natural gas prices, partially offset by higher oil and natural gas production, for the year ended December 31, 2023, as compared to the year ended December 31, 2022. In addition, we had increased depletion, depreciation and amortization expenses of $716.7 million for the year ended December 31, 2023, as compared to $466.3 million for the year ended December 31, 2022, and increased interest expense of $121.5 million for the year ended December 31, 2023, as compared to $67.2 million for the year ended December 31, 2022. This was partially offset by an income tax provision of $186.0 million for the year ended December 31, 2023, as compared to an income tax provision of $399.4 million for the year ended December 31, 2022.
Adjusted EBITDA, a non-GAAP financial measure, decreased $277.6 million to $1.85 billion for the year ended December 31, 2023, as compared to $2.13 billion for the year ended December 31, 2022. This decrease was primarily attributable to lower realized oil and natural gas prices, partially offset by higher oil and natural gas production noted above for the year ended December 31, 2023, as compared to the year ended December 31, 2022.
Off-Balance Sheet Arrangements
From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2023, the material off-balance sheet arrangements and transactions that we have entered into include (i) non-operated drilling commitments, (ii) firm gathering, transportation, processing, fractionation, sales and disposal commitments and (iii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, treating, transportation and disposal commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the
Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See “-Obligations and Commitments” below and Note 14 to the consolidated financial statements in this Annual Report for more information regarding our off-balance sheet arrangements. Such information is incorporated herein by reference.
Obligations and Commitments
We had the following material contractual obligations and commitments at December 31, 2023.
Payments Due by Period
Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years
(In thousands)
Contractual Obligations:
Borrowings, including letters of credit(1)
$ 1,083,317 $ - $ 1,083,317 $ - $ -
Senior unsecured notes(2)
1,199,191 - 699,191 500,000 -
Office leases 10,229 4,385 5,844 - -
Non-operated drilling commitments(3)
27,946 27,946 - - -
Drilling rig contracts(4)
22,226 21,742 484 - -
Asset retirement obligations(5)
92,090 4,605 4,220 2,376 80,889
Transportation, gathering, processing and disposal agreements with non-affiliates(6)
546,023 78,563 164,709 132,073 170,678
Transportation, gathering, processing and disposal agreements with San Mateo(7)
218,185 - 110,719 107,466 -
Midstream contracts(8)
162,692 109,979 52,713 - -
Total contractual cash obligations $ 3,361,899 $ 247,220 $ 2,121,197 $ 741,915 $ 251,567
__________________
(1)The amounts included in the table above represent principal maturities only. At December 31, 2023, we had $500.0 million in borrowings outstanding under the Credit Agreement and approximately $52.3 million in outstanding letters of credit issued pursuant to the Credit Agreement. The Credit Agreement matures October 31, 2026. At December 31, 2023 San Mateo had $522.0 million of borrowings outstanding under the San Mateo Credit Facility and approximately $9.0 million in outstanding letters of credit issued pursuant to the San Mateo Credit Facility. The San Mateo Credit Facility matures December 9, 2026. Assuming the amounts outstanding and interest rates of 7.21% and 7.71%, respectively, for the Credit Agreement and the San Mateo Credit Facility at December 31, 2023, the interest expense for such facilities is expected to be approximately $36.6 million and $40.8 million, respectively, each year until maturity.
(2)The amounts included in the table above represent principal maturities only. Interest expense on the $699.2 million of outstanding 2026 Notes as of December 31, 2023 is expected to be approximately $41.1 million each year until maturity. Interest expense on the $500.0 million of outstanding 2028 Notes as of December 31, 2023 is expected to be approximately $34.4 million each year until maturity.
(3)At December 31, 2023, we had outstanding commitments to participate in the drilling and completion of various non-operated wells.
(4)We do not own or operate our own drilling rigs, but instead we enter into contracts with third parties for such drilling rigs. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments.
(5)The amounts included in the table above represent discounted cash flow estimates for future asset retirement obligations at December 31, 2023.
(6)From time to time, we enter into agreements with third parties whereby we commit to deliver anticipated natural gas and oil production and produced water from certain portions of our acreage for transportation, gathering, processing, fractionation, sales and disposal. Certain of these agreements contain minimum volume commitments. If we do not meet the minimum volume commitments under these agreements, we would be required to pay certain deficiency fees. See Note 14 to the consolidated financial statements in this Annual Report for more information about these contractual commitments.
(7)We dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and the Wolf portion of the West Texas asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee oil transportation, oil, natural gas and produced water gathering and produced water disposal agreements. In addition, we dedicated to San Mateo our current and certain future leasehold interests in the Rustler Breaks asset area and acreage in the Greater Stebbins Area and Stateline asset area pursuant to 15-year, fixed-fee natural gas processing agreements. See Note 14 to the consolidated financial statements in this Annual Report for more information regarding these contractual commitments.
(8)At December 31, 2023, we had outstanding commitments related to the construction and installation of Pronto’s additional natural gas processing plant with a designed inlet processing capacity of 200 MMcf per day, including a nitrogen rejection unit and additional related facilities, in addition to commitments to purchase 11 compressors to be utilized in San Mateo and Pronto operations.
General Outlook and Trends
Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk to our business, cash flows and results of operations. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, the ongoing military conflicts between Russia and Ukraine and Israel and Hamas, political instability in China, military conflict and political instability in the Middle East, the actions of OPEC+, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors.
The prices we receive for oil, natural gas and NGLs heavily influence our revenues, profitability, cash flow available for capital expenditures, the repayment of debt and the payment of cash dividends, if any, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil, natural gas and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or NGL prices not only reduce our revenues, but could also reduce the amount of oil, natural gas and NGLs we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves and our ability to comply with the financial covenants under our Credit Agreement. See “Risk Factors-Risks Related to our Financial Condition-Our success is dependent on the prices of oil, natural gas and NGLs. Low oil, natural gas and NGL prices and the continued volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.”
For the year ended December 31, 2023, oil prices averaged $77.60 per Bbl, as compared to $94.33 per Bbl in 2022, ranging from a low of $66.74 per Bbl in mid-March to a high of $93.68 per Bbl in late September, based upon the WTI oil futures contract price for the earliest delivery date. We realized a weighted average oil price of $77.88 per Bbl (with no realized gains or losses from oil derivatives) for our oil production for the year ended December 31, 2023, as compared to $96.32 per Bbl ($92.87 per Bbl including realized losses from oil derivatives) for the year ended December 31, 2022. At February 20, 2024, the WTI oil futures contract price for the earliest delivery date had increased from year-end 2023, closing at $78.18 per Bbl, and was also higher compared to $76.34 per Bbl on February 17, 2023.
Natural gas prices decreased significantly during 2023. For the year ended December 31, 2023, natural gas prices averaged $2.66 per MMBtu, as compared to $6.54 per MMBtu in 2022, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2023, natural gas prices ranged from a high of $4.17 per MMBtu in early January to a low of $1.99 per MMBtu in late March. As a result of milder-than-expected winter weather and high storage levels, natural gas prices declined over the course of the fourth quarter of 2023, finishing the year at $2.51 per MMBtu. We report production volumes in two streams, oil and natural gas (which includes both dry gas and NGLs). NGL prices were also lower in 2023 as compared to 2022, which contributed to lower realized weighted average natural gas prices for the year ended December 31, 2023. We realized a weighted average natural gas price of $3.25 per Mcf ($3.17 per Mcf including realized losses from natural gas derivatives) for our natural gas production for the year ended December 31, 2023, as compared to $7.98 per Mcf ($7.15 per Mcf including realized losses from natural gas derivatives) for the year ended December 31, 2022. At February 20, 2024, the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date had decreased further from year-end 2023, closing at $1.58 per MMBtu, and was also lower as compared to $2.28 per MMBtu at February 17, 2023.
The prices we receive for oil and natural gas production often reflect a discount to the relevant benchmark prices, such as the WTI oil price or the NYMEX Henry Hub natural gas price. The difference between the benchmark price and the price we receive is called a differential. At December 31, 2023, most of our oil production from the Delaware Basin was sold based on prices established in Midland, Texas, and a significant portion of our natural gas production from the Delaware Basin was sold based on Houston Ship Channel pricing, while the remainder of our Delaware Basin natural gas production was sold primarily based on prices established at the Waha hub in far West Texas.
The Midland-Cushing (Oklahoma) oil price differential has been highly volatile in recent years. At February 20, 2024, this oil price differential was approximately +$1.64 per Bbl. At February 20, 2024, we had no derivative contracts in place to mitigate our exposure to this Midland-Cushing (Oklahoma) oil price differential for 2024.
Certain volumes of our Delaware Basin natural gas production are exposed to the Waha-Henry Hub basis differential, which has also been highly volatile in recent years. In 2022, concerns about natural gas pipeline takeaway capacity out of the Delaware Basin began to increase, particularly beginning in the latter half of 2022 and into 2023. As a result, the Waha-Henry Hub basis differential began to widen. The Waha-Henry Hub basis differential averaged ($1.00) per MMBtu for the year ended December 31, 2023. Between December 31, 2023 and February 20, 2024, this natural gas price differential narrowed to approximately ($0.80) per MMBtu. A significant portion of our Delaware Basin natural gas production, however, is sold at Houston Ship Channel pricing and is not exposed to Waha pricing. During 2022 and 2023, we typically realized a narrower
differential to natural gas sold at the Waha hub despite higher transportation charges incurred to transport the natural gas to the Gulf Coast. At certain times, we may also sell a portion of our natural gas production into other markets to improve our realized natural gas pricing. Further, approximately 8% of our reported natural gas production for the year ended December 31, 2023 was attributable to the Haynesville and Eagle Ford shale plays, which are not exposed to Waha pricing. In addition, as a two-stream reporter, most of our natural gas volumes in the Delaware Basin are processed for NGLs, resulting in a further reduction in the reported natural gas volumes exposed to Waha pricing.
From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and NGL prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and NGL prices, and we may not always employ the optimal hedging strategy. This, in turn, may affect the liquidity that can be accessed through the borrowing base under the Credit Agreement and through the capital markets. During year ended December 31, 2023, we incurred realized losses on our natural gas basis differential derivative contracts of approximately $9.6 million resulting primarily from natural gas basis differentials that were above the strike price of our natural gas basis differential swap contracts, offset by natural gas prices that were below the floor prices of certain of our natural gas costless collar contracts. At December 31, 2023, we had derivative natural gas basis differential swap contracts in place to mitigate our exposure to the Waha-Henry Hub basis differential for approximately 11.0 Bcf of our anticipated natural gas production in each of 2024 and 2025.
We have at times experienced pipeline-related interruptions to our oil, natural gas or NGL production or produced water disposal. In certain recent periods, shortages of NGL fractionation capacity were experienced by certain operators in the Delaware Basin. Although we did not encounter such fractionation capacity problems, we can provide no assurances that such problems will not arise. If we do experience any material interruptions with produced water disposal, takeaway capacity or NGL fractionation, our oil and natural gas revenues, business, financial condition, results of operations and cash flows could be adversely affected. Should we experience future periods of negative pricing for natural gas as we have experienced historically, we may temporarily shut in certain high gas-oil ratio wells and take other actions to mitigate the impact on our realized natural gas prices and results.
As a result of the increases in oil prices during 2022 and 2023, we have at times experienced inflation in the costs of certain oilfield services, including diesel, steel, labor, trucking, sand, personnel and completion costs, among others. Should oil prices remain at their current levels or increase, we may be subject to additional service cost inflation in future periods, which may increase our costs to drill, complete, equip and operate wells. In addition, supply chain disruptions and other inflationary pressures experienced in recent periods throughout the United States and global economy and in the oil and natural gas industry may limit our ability to procure the necessary products and services we need for drilling, completing and producing wells in a timely and cost-effective manner, which could result in reduced margins and delays to our operations and could, in turn, adversely affect our business, financial condition, results of operations and cash flows.
We recorded a current income tax provision of $13.9 million and a deferred income tax provision of $172.1 million for the year ended December 31, 2023. Our effective income tax rate of 18% for the year ended December 31, 2023 differed from the U.S. federal statutory rate due primarily to recognizing research and experimental expenditure tax credits of $74.0 million, which were partially offset by permanent differences between book and taxable income and state taxes, primarily in New Mexico. At February 20, 2024, given our current projections, we expect to continue to pay federal income taxes and state income taxes in New Mexico of between 5% and 10% of 2024 pretax book income, but we do not expect to be subject to the Corporate Alternative Minimum Tax (the “CAMT”) in 2024. We could be subject to the CAMT in future years, which would require us to pay minimum cash tax payments of 15% of annual adjusted pretax book income.
Our oil and natural gas exploration, development, production, midstream and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are proposed or promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. For example, although such bills have not passed, in recent years, various bills have been introduced in the New Mexico legislature proposing to add a surtax on natural gas processors and proposing to place a moratorium on, ban or otherwise restrict hydraulic fracturing, including prohibiting the injection of fresh water in such operations. In 2019, New Mexico’s governor signed an executive order declaring that New Mexico would support the goals of the Paris Agreement by joining the U.S. Climate Alliance, a bipartisan coalition of governors committed to reducing greenhouse gas emissions consistent with the goals of the Paris Agreement. The stated objective of the executive order is to achieve a statewide reduction in greenhouse gas emissions of at least 45% by 2030 as compared to 2005 levels. The executive order also requires New Mexico regulatory agencies to create an “enforceable regulatory framework” to ensure methane emission reductions. In 2021, the NMOCD implemented rules regarding the reduction of natural gas waste and the control of emissions that, among other items, require upstream and midstream
operators to reduce natural gas waste by a fixed amount each year and achieve a 98% natural gas capture rate by the end of 2026. The NMED has implemented similar rules and regulations. These and other laws, rules and regulations, including any federal legislation, regulations or orders intended to limit or restrict oil and natural gas operations on federal lands, if enacted, could have a material adverse impact on our business, financial condition, results of operations and cash flows. See “Business-Regulation.”
In January 2021, President Biden signed an executive order instructing the Department of the Interior to pause new oil and natural gas leases on public lands pending completion of a comprehensive review and consideration of federal oil and natural gas permitting and leasing practices, which has lapsed. In 2019, 2020 and 2021, an environmental group filed multiple lawsuits in federal district courts in New Mexico and the District of Columbia challenging certain BLM lease sales, including lease sales in which we purchased leases in New Mexico. In 2021, ten states, led by the State of Louisiana, filed a lawsuit in federal district court in Louisiana against President Biden and various other federal government officials and agencies challenging an executive order directing the federal government to utilize certain calculations of the “social cost” of carbon and other greenhouse gases in its decision making. The BLM indicated that the Lease Sale Litigation or the Social Cost of Carbon Litigation could delay lease sales and the approval of drilling permits. The impact of federal actions and lawsuits related to the oil and natural gas industry remains unclear, and should other limitations or prohibitions be imposed or continue to be applied, our operations on federal lands could be adversely impacted. Such limitations or prohibitions would almost certainly impact our future drilling and completion plans and could materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. See “Risk Factors-Risks Related to Laws and Regulations-Approximately 32% of our leasehold and mineral acres in the Delaware Basin is located on federal lands, which are subject to administrative permitting requirements and potential federal legislation, regulation and orders that may limit or restrict oil and natural gas operations on federal lands.”
We and San Mateo dispose of large volumes of produced water gathered from our and third parties’ drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. State and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for produced water disposal and the increased occurrence of seismic activity, also known as “induced seismicity.” This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. In addition, a number of lawsuits have been filed in some states against others in our industry alleging that fluid injection or oil and natural gas extraction have caused damage to neighboring properties or otherwise violated state and federal rules regarding waste disposal. In response to these concerns, regulators in some states, including New Mexico and Texas, are seeking to impose additional requirements, including requirements regarding the permitting of salt water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. For example, in 2021, the NMOCD implemented new rules establishing protocols in response to seismic events in New Mexico. Under these protocols, applications for salt water disposal well permits in certain areas of New Mexico with recent seismic activity require enhanced review prior to approval. In addition, the protocols require enhanced reporting and varying levels of curtailment of injection rates for salt water disposal wells, including potentially shutting in such wells, in the area of seismic events based on the magnitude, timing and proximity of the seismic event. The adoption of federal, state and local legislation and regulations intended to address induced seismicity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, and could result in increased costs and additional operating restrictions or delays, that could, in turn, materially impact our production volumes, revenues, reserves, cash flows and availability under our Credit Agreement. The adoption of such legislation and regulations could also decrease our and San Mateo’s revenues and result in increased costs and additional operating restrictions for San Mateo as well.
Certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. In recent years prior to 2021, equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices and some investors, including certain pension funds, sovereign wealth funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations.
Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and NGL price declines, however, drilling additional oil or natural gas wells may not be economic, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A significant reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and the availability under our Credit Agreement. See “Risk Factors-Risks Related to our Financial Condition-Our exploration, development, exploitation and midstream projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth”.
We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable and that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See Note 2 to the consolidated financial statements in this Annual Report for further details on our accounting policies at December 31, 2023.
Oil and Natural Gas Properties
We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities.
Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive.
Ceiling Test
The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of:
(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus
(b) unproved and unevaluated property costs not being amortized, plus
(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less
(d) any income tax effects related to the properties involved.
Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. Our derivative instruments are not considered in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes.
Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue
Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report. The applicable rules define proved reserves as the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time.
Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated quarterly and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial condition, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. See “Risk Factors-Risks Related to our Financial Condition-Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will recover, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves” and “Risk Factors-Risks Related to our Financial Condition-We may be required to write down the carrying value of our proved properties under accounting rules, and these write-downs could adversely affect our financial condition.”
Estimates of proved oil and natural gas reserves are key inputs used for the calculations of depletion, the ceiling test and the fair value assigned to proved oil and natural gas reserves acquired in a business combination. The estimated present value of future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The associated commodity prices and the applicable discount rate used to determine the fair value assigned to proved oil and natural gas reserves acquired in a business combination are based upon a variety of factors on the date of acquisition. The associated commodity prices and the applicable discount rate used in estimates for depletion and the ceiling test are in accordance with guidelines established by the SEC. Under these guidelines, future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues.
Income Taxes
We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition.
We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.
Purchase Accounting
Periodically we acquire assets and assume liabilities in transactions accounted for as business combinations, such as the Advance Acquisition in 2023.
In estimating the fair value of assets acquired and liabilities assumed in these transactions, including the Advance Acquisition, we must make a number of estimates and assumptions and may engage third-party valuation experts. The most significant assumptions relate to the estimated fair values of oil and natural gas properties. Significant judgments and assumptions are inherent in these estimates and include, among other things, estimates of future production volumes, estimates of future commodity prices, expected development and operating costs, an estimate of a market-based weighted average cost of capital rate and recent market comparable transactions for unproved acreage.
Recent Accounting Pronouncements
See Note 2 to the consolidated financial statements in this Annual Report for a description of recent accounting pronouncements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative financial instruments, but we do not enter into derivative financial instruments for trading purposes.
Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and NGLs fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our anticipated future production.
We typically use costless (or zero-cost) collars, three-way collars and/or swap contracts to manage risks related to changes in oil, natural gas and NGL prices. Costless collars provide us with downside price protection through the purchase of a put option that is financed through the sale 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. The purchase of both the put option and call option are financed through the sale of a call option. Because the proceeds from the call option sale are used to offset the cost of the purchased put and call options, these arrangements are also initially “costless” to us. In the case of a costless collar, the put option or options and the call option or options have different fixed price components. When the settlement price is below the price floor established by the collar, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil, natural gas or NGL volume. When the settlement price is above the price ceiling established by the costless collar, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil, natural gas or NGL volume. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection.
We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. 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, 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.
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. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. 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. See “Risk Factors-Risks Related to Laws and Regulations-Derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business.”
Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense on existing debt. 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%. If we incur additional indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Counterparty and customer credit risk. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. 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. The inability or failure of our, San Mateo’s or Pronto’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.
While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation requires us to conduct the due diligence necessary to determine credit terms and credit limits, which may include (i) reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record and the financial ability of its parent company to make payment if the customer cannot and (ii) undertaking the due diligence necessary to determine credit terms and credit limits. The 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. We do not know how long these inflationary pressures may persist or the impact they may have on our business moving forward. We tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Wolfcamp and Bone Spring plays in the Delaware Basin, the Eagle Ford shale play and the Haynesville shale play. See “Risk Factors-Risks Related to our Financial Condition-Our industry and the broader U.S. economy have experienced higher than expected inflationary pressures in recent years related to increases in oil and natural gas prices, continued supply chain disruptions, labor shortages and geopolitical instability, among other pressures. Should these conditions persist, it may impact our ability to procure services, materials and equipment on a cost-effective basis, or at all, and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected” and “Risk Factors-Risks Related to our Operations-The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our financial condition, results of operations and cash flows.”

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data.
Our financial statements appear at the end of this Annual Report beginning on page.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Not applicable.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this Annual Report, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2023 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2023, there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report based on the framework in 2013 “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
KPMG, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2023 as included herein.
Important Considerations
The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management.
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
Matador Resources Company:
Opinion on Internal Control Over Financial Reporting
We have audited Matador Resources Company and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2023 and 2022, the related consolidated statements of income, changes in shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2023, and the related notes (collectively, the consolidated financial statements), and our report dated February 27, 2024 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Dallas, Texas
February 27, 2024

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information.
During the three months ended December 31, 2023, no director or officer (as defined in Rule 16a-1(f) under the Exchange Act) of the Company adopted, modified or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance.
The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement for our 2024 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report (our “Definitive Proxy Statement”). Such responsive information is expected to be included under the captions “Proposal 1-Election of Directors,” “Corporate Governance,” “Executive Compensation” and “Director Compensation.”

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation.
The information required in response to this Item 11 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Executive Compensation.”

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption “Equity Compensation Plan Information” in Part II, Item 5 of this Annual Report and is incorporated herein by reference. Other information required in response to this Item 12 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Security Ownership of Certain Beneficial Owners and Management.”

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required in response to this Item 13 is incorporated herein by reference to our Definitive Proxy Statement under the captions “Transactions with Related Persons” and “Corporate Governance-Independence of Directors.”

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services.
The information required in response to this Item 14 is incorporated herein by reference to our Definitive Proxy Statement under the caption “Proposal 4-Ratification of Appointment of KPMG LLP.”
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits and Financial Statement Schedules.
The following documents are filed as part of this Annual Report:
1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2023 and 2022, Consolidated Statements of Income for the Years Ended December 31, 2023, 2022 and 2021, Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2023, 2022 and 2021 and Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021.
2. Financial Statement Schedules: All other schedules for which provision is made in the applicable accounting regulations of the SEC are omitted because the required information is either not applicable, not required or is shown in the respective financial statements or in the notes thereto.
3. Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index included below.