UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the fiscal year ended December 31 , 2020
or
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the transition period from to
Commission File Number 001-35410
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | ||||||||||||||||
| (Address of principal executive offices) | (Zip Code) | ||||||||||||||||
(972 ) 371-5200
(Registrant’s telephone number, including area code)
_________________________________________________________
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading symbol(s) | Name of each exchange on which registered | ||||||||||||
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| ☒ | Accelerated filer | ☐ | ||||||||||||||||||
| Non-accelerated filer | ☐ | Smaller reporting company | ||||||||||||||||||
| Emerging growth company | ||||||||||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ☐ No ☒
The aggregate market value of the voting and non-voting common equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $930,575,164 .
As of February 23, 2021, there were 116,764,838 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE | ||
MATADOR RESOURCES COMPANY
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2020
TABLE OF CONTENTS
| Page | ||||||||
| PART I | ||||||||
ITEM 1. | ||||||||
ITEM 1A. | ||||||||
ITEM 1B. | ||||||||
ITEM 2. | ||||||||
ITEM 3. | ||||||||
ITEM 4. | ||||||||
| PART II | ||||||||
ITEM 5. | ||||||||
ITEM 6. | ||||||||
ITEM 7. | ||||||||
ITEM 7A. | ||||||||
ITEM 8. | ||||||||
ITEM 9. | ||||||||
ITEM 9A. | ||||||||
ITEM 9B. | ||||||||
| PART III | ||||||||
ITEM 10. | ||||||||
ITEM 11. | ||||||||
ITEM 12. | ||||||||
ITEM 13. | ||||||||
ITEM 14. | ||||||||
| PART IV | ||||||||
ITEM 15. | ||||||||
| ITEM 16. | ||||||||
i
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this Annual Report on Form 10-K (this “Annual Report”) constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecasted,” “hypothetical,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “project,” “should,” “would” or other similar words, although not all forward-looking statements contain such identifying words.
By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: general economic conditions; our ability to execute our business plan, including whether our drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; our ability to replace reserves and efficiently develop current reserves; costs of operations; delays and other difficulties related to producing oil, natural gas and natural gas liquids; delays and other difficulties related to regulatory and governmental approvals and restrictions; availability of sufficient capital to execute our business plan, including from future cash flows, available borrowing capacity under our revolving credit facilities and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate acquisitions; weather and environmental conditions; the impact of the worldwide spread of the novel coronavirus (“COVID-19”) on oil and natural gas demand, oil and natural gas prices and our business; the operating results of our midstream joint venture’s Black River cryogenic natural gas processing plant; the timing and operating results of the buildout by our midstream joint venture of oil, natural gas and water gathering and transportation systems and the drilling of any additional salt water disposal wells; and the other factors discussed below and elsewhere in this Annual Report and in other documents that we file with or furnish to the United States Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking statements may include statements about:
•our business strategy;
•our estimated future reserves and the present value thereof, including whether or not a full-cost ceiling impairment could be realized;
•our cash flows and liquidity;
•the amount, timing and payment of dividends, if any;
•our financial strategy, budget, projections and operating results;
•the supply and demand of oil, natural gas and natural gas liquids;
•oil, natural gas and natural gas liquids prices, including our realized prices thereof;
•the timing and amount of future production of oil and natural gas;
•the availability of drilling and production equipment;
•the availability of oil storage capacity;
•the availability of oil field labor;
•the amount, nature and timing of capital expenditures, including future exploration and development costs;
•the availability and terms of capital;
•our drilling of wells;
•our ability to negotiate and consummate acquisition and divestiture opportunities;
•government regulation and taxation of the oil and natural gas industry;
•our marketing of oil and natural gas;
•our exploitation projects or property acquisitions;
•the integration of acquisitions with our business;
•our ability and the ability of our midstream joint venture to construct and operate midstream facilities, including the operation of its Black River cryogenic natural gas processing plant and the drilling of additional salt water disposal wells;
•the ability of our midstream joint venture to attract third-party volumes;
•our costs of exploiting and developing our properties and conducting other operations;
•general economic conditions;
•competition in the oil and natural gas industry, including in both the exploration and production and midstream segments;
•the effectiveness of our risk management and hedging activities;
•our technology;
•environmental liabilities;
•counterparty credit risk;
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•developments in oil-producing and natural gas-producing countries;
•the impact of COVID-19 on the oil and natural gas industry and our business;
•our future operating results; and
•our plans, objectives, expectations and intentions contained in this Annual Report or in our other filings with the SEC that are not historical.
Although we believe that the expectations conveyed by the forward-looking statements in this Annual Report are reasonable based on information available to us on the date hereof, no assurances can be given as to future results, levels of activity, achievements or financial condition.
You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We undertake no obligation to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.
PART I
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 and (iii) references to “San Mateo” refer to San Mateo Midstream, LLC (collectively with its subsidiaries, “San Mateo I”) together with San Mateo Midstream II, LLC (collectively with its subsidiaries, “San Mateo II”). Effective October 1, 2020, San Mateo II merged with and into San Mateo I. 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, primarily through our midstream joint venture, San Mateo, 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 CEO. 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;
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•maintain our financial discipline; and
•pursue opportunistic acquisitions, divestitures and joint ventures.
Despite the precipitous decline in global oil demand resulting from the worldwide spread of COVID-19 in 2020, which led to a very challenging oil and natural gas price environment, the successful execution of our business strategies led to increases in our oil and natural gas production and proved oil and natural gas reserves in 2020. We achieved these results despite reducing our operated drilling rig count from six at the beginning of the year to three by the end of the second quarter. 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” and “—Midstream Segment”). In addition, we concluded several important financing transactions in 2020, including an increase in the elected commitment under our Credit Agreement (as defined below), the affirmation of the borrowing base and the restructuring of our oil hedging portfolio. San Mateo also achieved several important milestones in 2020, including the expansion of its cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) and associated pipelines and the merger of San Mateo II with and into San Mateo I. These achievements and transactions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position.
2020 Highlights
Increased Oil, Natural Gas and Oil Equivalent Production
For the year ended December 31, 2020, we achieved record oil, natural gas and average daily oil equivalent production. In 2020, we produced 15.9 million Bbl of oil, an increase of 14%, as compared to 14.0 million Bbl of oil produced in 2019. We also produced 69.5 Bcf of natural gas, an increase of 14% from 61.1 Bcf of natural gas produced in 2019. Our average daily oil equivalent production for the year ended December 31, 2020 was 75,175 BOE per day, including 43,526 Bbl of oil per day and 189.9 MMcf of natural gas per day, an increase of 14%, as compared to 66,203 BOE per day, including 38,312 Bbl of oil per day and 167.4 MMcf of natural gas per day, for the year ended December 31, 2019. The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin throughout 2020, which offset declining production in the Eagle Ford and Haynesville shales. Oil production comprised 58% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for both the years ended December 31, 2020 and December 31, 2019.
Increased Oil, Natural Gas and Oil Equivalent Reserves
At December 31, 2020, our estimated total proved oil and natural gas reserves were 270.3 million BOE, including 159.9 million Bbl of oil and 662.3 Bcf of natural gas, an increase of 7% from 252.5 million BOE, including 148.0 million Bbl of oil and 627.2 Bcf of natural gas, at December 31, 2019. The Standardized Measure of our total proved oil and natural gas reserves decreased 22% from $2.03 billion at December 31, 2019 to $1.58 billion at December 31, 2020. The PV-10 of our total proved oil and natural gas reserves decreased 26% from $2.25 billion at December 31, 2019 to $1.66 billion at December 31, 2020. The decreases in our Standardized Measure and PV-10 were primarily a result of the significantly lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2020, as compared to December 31, 2019. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.”
Our proved oil reserves grew 8% to 159.9 million Bbl at December 31, 2020 from 148.0 million Bbl at December 31, 2019. Our proved natural gas reserves increased 6% to 662.3 Bcf at December 31, 2020 from 627.2 Bcf at December 31, 2019. This growth in oil and natural gas reserves was attributable to our ongoing delineation and development drilling activities in the Delaware Basin during 2020.
At December 31, 2020, proved developed reserves included 69.6 million Bbl of oil and 323.2 Bcf of natural gas, and proved undeveloped reserves included 90.3 million Bbl of oil and 339.1 Bcf of natural gas. Proved developed reserves and proved oil reserves comprised 46% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2020. Proved developed reserves and proved oil reserves comprised 42% and 59%, respectively, of our total proved oil and natural gas reserves at December 31, 2019.
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,
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completing and producing Delaware Basin wells. We expect the Delaware Basin will continue to be our primary area of focus in 2021.
We completed and began producing oil and natural gas from 89 gross (47.8 net) wells in the Delaware Basin in 2020, including 53 gross (45.6 net) operated and 36 gross (2.2 net) non-operated wells. At December 31, 2020, our total acreage position in the Delaware Basin was approximately 230,600 gross (124,700 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. We have focused our Delaware Basin operations thus far on the following asset areas: the Wolf and Jackson Trust asset areas in Loving County, Texas, the Stateline, Rustler Breaks and Arrowhead asset areas in Eddy County, New Mexico and the Antelope Ridge, Ranger and Twin Lakes asset areas in Lea County, New Mexico. Our Delaware Basin properties have become the most significant component of our asset portfolio. Our average daily oil equivalent production from the Delaware Basin increased approximately 21% to 67,522 BOE per day (90% of total oil equivalent production), including 41,678 Bbl of oil per day (96% of total oil production) and 155.1 MMcf of natural gas per day (82% of total natural gas production), in 2020, as compared to 55,599 BOE per day (84% of total oil equivalent production), including 35,184 Bbl of oil per day (92% of total oil production) and 122.5 MMcf of natural gas per day (73% of total natural gas production), in 2019. We expect our Delaware Basin production to increase in 2021 as we continue the delineation and development of these asset areas.
During 2020, 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” and “—Midstream Segment”) were:
•we completed and turned to sales the first six Rodney Robinson wells, all of which were two-mile laterals, in the western portion of our Antelope Ridge asset area, in late March 2020; these six Rodney Robinson wells have produced in aggregate approximately 2.7 million BOE in approximately 10 months of production;
•we completed and turned to sales the first five Ray State wells, all of which were two-mile laterals, in the eastern portion of our Rustler Breaks asset area in late May and early June 2020; these five Ray State wells have produced in aggregate approximately 1.6 million BOE in just over seven months of production;
•we completed and turned to sales five Leatherneck wells in the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) in late July and early August 2020; these five Leatherneck wells have produced in aggregate approximately 1.0 million BOE in just over six months of production;
•we completed and turned to sales the first 13 Boros wells, all of which were two-mile laterals, in the eastern portion of the Stateline asset area in a staggered fashion during September 2020; these 13 Boros wells have produced in aggregate approximately 2.7 million BOE in just over four months of production, despite a number of these wells being produced on restricted chokes early in their production; and
•San Mateo completed the expansion of the Black River Processing Plant and associated pipelines and facilities in conjunction with the Boros and Leatherneck wells coming online.
In addition to achieving these five key operational milestones, further operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin”) in 2020 included:
•the ongoing transition to drilling longer laterals, whereby 83% of the operated horizontal wells we completed and turned to sales in 2020 had lateral lengths greater than one mile, as compared to 29% in 2019 and 9% in 2018;
•the continuing improvement in capital efficiency as demonstrated by (i) our average drilling and completion costs for all operated horizontal wells completed and turned to sales of approximately $850 per lateral foot in 2020, a decrease of 27% as compared to average drilling and completion costs of $1,165 per lateral foot in 2019 and a decrease of 44% as compared to average drilling and completion costs of $1,528 per lateral foot in 2018, and (ii) the sequential quarterly decrease in our drilling and completion costs per lateral foot on operated wells turned to sales throughout 2020, from $1,009 in the first quarter to $881 in the second quarter to $790 in the third quarter and, finally, to $625 in the fourth quarter;
•record-low unit operating costs for lease operating expenses of $3.81 per BOE and general and administrative expenses of $2.27 per BOE;
•in our Wolf asset area, the results from our first Third Bone Spring Carbonate test in the Delaware Basin, demonstrating the prospectivity of this formation throughout the basin; and
•in our Rustler Breaks asset area, the results from our first Third Bone Spring Sand test, demonstrating the prospectivity of this formation in that asset area.
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Financing Highlights
We concluded several important financing transactions in 2020 that increased our operational flexibility and opportunities, while preserving the strength of our balance sheet and improving our liquidity position. These transactions included:
•the amendment of our third amended and restated credit agreement (the “Credit Agreement”) in February 2020 to reaffirm the borrowing base at $900.0 million, increase our elected borrowing commitment from $500.0 million to $700.0 million and add two new banks to our lending group;
•the reaffirmation of the borrowing base under the Credit Agreement in October 2020; and
•the restructuring of a portion of our then-existing 2020 NYMEX West Texas Intermediate (“WTI”) oil derivative financial instruments in April 2020 to provide additional revenue assurance had oil prices declined further and help us remain in compliance with our Credit Agreement leverage covenant in 2020.
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
Effective October 1, 2020, together with our joint venture partner, a subsidiary of Five Point Energy LLC (“Five Point”), we completed the successful merger of San Mateo II with and into San Mateo I. San Mateo is owned 51% by us and 49% by Five Point.
San Mateo achieved strong operating results in 2020, highlighted by (i) increased midstream services revenues, (ii) increased produced water handling volumes and (iii) increased oil gathering and transportation volumes, all as compared to 2019. San Mateo’s natural gas gathering and processing volumes declined slightly in 2020 as compared to 2019 due to reduced volumes from a significant third-party customer, but, on a quarterly sequential basis, San Mateo’s natural gas gathering and processing volumes, water handling volumes and oil gathering and transportation volumes all increased significantly in the fourth quarter of 2020, as compared to the third quarter, as we realized the first full quarter of production from the Boros wells in the Stateline asset area and the Leatherneck wells in the Greater Stebbins Area.
During the third quarter of 2020, San Mateo completed the construction and successful start-up of the expansion of the Black River Processing Plant, which added an incremental designed inlet capacity of 200 MMcf of natural gas per day to the previously designed inlet capacity of 260 MMcf per day for a total designed inlet capacity of 460 MMcf per day. The expanded Black River Processing Plant supports our exploration and development activities in the Delaware Basin and, at December 31, 2020, 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.
In September 2020, San Mateo also completed and placed in service 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). In addition, San Mateo completed and placed in service approximately 19 miles of various diameter crude oil pipelines from certain points of origin in the Greater Stebbins Area to the existing San Mateo interconnect with a subsidiary of Plains All American Pipeline, L.P. (“Plains”) in Eddy County, New Mexico. At December 31, 2020, San Mateo was gathering or transporting our oil and natural gas production via pipeline in both the Stateline asset area and the Greater Stebbins Area, as well as in the Wolf and Rustler Breaks asset areas. San Mateo was handling our produced water via pipeline in each of these areas as well.
At December 31, 2020, San Mateo’s midstream system included:
•Natural Gas Assets: 460 MMcf per day of designed natural gas cryogenic processing capacity and approximately 140 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 central delivery points (“CDP”) with over 100,000 Bbl of designed oil throughput capacity and approximately 90 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: 13 commercial salt water disposal wells and associated facilities with designed produced water disposal capacity of 335,000 Bbl per day and approximately 120 miles of produced water gathering pipelines in Eddy County, New Mexico and Loving County, Texas.
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Environmental, Social and Governance (“ESG”) Initiatives
We maintain an active ESG program and continued working in 2020 to improve upon our various ESG efforts. For instance, we significantly increased the percentage of new production facilities operating on electrical grid power, lowering emissions by removing on-site generators. We also increased the percentage of recycled water used in our completions and increased the percentage of both produced water and oil we transported via pipeline.
Using batch drilling and longer laterals, we significantly increased our lateral footage drilled per new pad built, helping to reduce our surface footprint. Finally, we continued our commitment to a proactive safety culture, with approximately 2.1 million employee man-hours and no lost time accidents experienced from 2017 to 2020.
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 2020, we devoted most of our efforts and most of our capital expenditures to our drilling and completion operations in the Wolfcamp and Bone Spring plays in the Delaware Basin, as well as our midstream operations there. 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, 2020.
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| 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) | 230,600 | 124,700 | 831 | 398.5 | 4,359 | 1,502 | 261,888 | 43.9 | 67,522 | ||||||||||||||||||||||||||||||||||||||||||||
| South Texas: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Eagle Ford(5) | 29,300 | 26,300 | 126 | 105.0 | 229 | 182 | 4,909 | 100.0 | 2,412 | ||||||||||||||||||||||||||||||||||||||||||||
| Northwest Louisiana | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Haynesville | 16,700 | 9,100 | 237 | 18.8 | 163 | 16 | 3,486 | 100.0 | 5,015 | ||||||||||||||||||||||||||||||||||||||||||||
Cotton Valley(6) | 16,100 | 14,900 | 64 | 39.7 | 154 | 35 | 49 | 100.0 | 226 | ||||||||||||||||||||||||||||||||||||||||||||
Area Total(7) | 19,100 | 17,700 | 301 | 58.5 | 317 | 51 | 3,535 | 100.0 | 5,241 | ||||||||||||||||||||||||||||||||||||||||||||
| Total | 279,000 | 168,700 | 1,258 | 562.0 | 4,905 | 1,735 | 270,332 | 45.7 | 75,175 | ||||||||||||||||||||||||||||||||||||||||||||
(1)Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2020. 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, 2020, approximately two-thirds of these identified drilling locations were expected to be horizontal laterals with lateral lengths of two miles or greater, and approximately 80% are expected to have lateral lengths of 1.5 miles or greater. At December 31, 2020, these engineered drilling locations included only 358 gross (145 net) locations to which we have assigned proved undeveloped reserves, primarily in the Wolfcamp or Bone Spring plays, but also in the Brushy Canyon, Avalon and Delaware formations, in the Delaware Basin. At December 31, 2020, we had assigned no proved undeveloped reserves to our leasehold in the Eagle Ford shale or the Haynesville shale, primarily as a result of the significantly lower oil and natural gas prices used to estimate proved reserves at December 31, 2020, which were $36.04 per Bbl and $1.99 per MMBtu, respectively, as compared to prior periods.
(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, 2020.
(5)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.
(6)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
(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.
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We are active both as an operator and as a non-operating co-working interest owner with various industry participants. At December 31, 2020, 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, 2020, we also were the operator for approximately 93% of our Eagle Ford acreage and approximately 52% of our Haynesville acreage, including approximately 8% of our acreage in what we believe is the core area of the Haynesville play.
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 any 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 has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing 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, Avalon and Delaware formations.
In the western part of the Permian Basin, also known as the Delaware Basin, the Lower Permian age Bone Spring (also called the Leonardian) and Wolfcamp formations are several thousand feet thick and contain stacked layers of shales, sandstones, limestones and dolomites. These intervals represent a complex and dynamic submarine depositional system that also includes organic rich shales that are the source rocks for oil and natural gas produced in the basin. Historically, production has come from conventional reservoirs; however, we and other industry players have realized that the source rocks also have sufficient porosity and permeability to be commercial reservoirs. In addition, the source rocks are interbedded with reservoir layers that have filled with hydrocarbons, both of which can produce significant volumes of oil and natural gas when connected by horizontal wellbores with multi-stage hydraulic fracture treatments. Particularly in 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, 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, 2020, our total acreage position in Southeast New Mexico and West Texas was approximately 230,600 gross (124,700 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 34,600 gross (18,400 net) acres in our Ranger asset area in Lea County, 66,000 gross (26,800 net) acres in our Arrowhead asset area in Eddy County, 47,900 gross (26,200 net) acres in our Rustler Breaks asset area in Eddy County, 23,200 gross (16,000 net) acres in our Antelope Ridge asset area in Lea County, 15,100 gross (10,800 net) acres in our Wolf and Jackson Trust asset areas in Loving County, 2,800 gross (2,800 net) acres in our Stateline asset area in Eddy County and 40,500 gross (23,200 net) acres in our Twin Lakes asset area in Lea County at December 31, 2020. 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 Avalon and Delaware formations, as well as the Abo, Strawn, Devonian, Penn Shale, Atoka and Morrow formations. At December 31, 2020, our acreage position in the Delaware Basin was approximately 67% held by existing production. Excluding the Twin Lakes asset area, where we have drilled only three vertical operated wells and two horizontal operated wells, and 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, our acreage position in the Delaware Basin was approximately 79% held by existing production at December 31, 2020.
During the year ended December 31, 2020, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 89 gross (47.8 net) wells in the Delaware Basin, including 53 gross (45.6 net) operated horizontal wells and 36 gross (2.2 net) non-operated horizontal wells, throughout our various asset areas. At December 31, 2020, we had tested a number of different producing horizons at various locations across our acreage position, including the Brushy Canyon, the Avalon, the First Bone Spring, two benches of the Second Bone Spring, two benches of the Third Bone Spring, three benches of the Wolfcamp A, including the X and Y sands and the more organic, lower section of the Wolfcamp A, three benches of the Wolfcamp B, the Wolfcamp D, the Morrow and the Strawn. Most of our delineation and development efforts have been focused on multiple completion targets between the First Bone Spring and the Wolfcamp B.
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As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2020. Our average daily oil equivalent production from the Delaware Basin increased approximately 21% to 67,522 BOE per day (90% of total oil equivalent production), including 41,678 Bbl of oil per day (96% of total oil production) and 155.1 MMcf of natural gas per day (82% of total natural gas production), in 2020, as compared to 55,599 BOE per day (84% of total oil equivalent production), including 35,184 Bbl of oil per day (92% of total oil production) and 122.5 MMcf of natural gas per day (73% of total natural gas production), in 2019. Our average daily oil equivalent production from the Delaware Basin also grew approximately 26% from 61,493 BOE per day in the fourth quarter of 2019 to 77,367 BOE per day in the fourth quarter of 2020.
At December 31, 2020, approximately 97% of our estimated total proved oil and natural gas reserves, or 261.9 million BOE, was attributable to the Delaware Basin, including approximately 156.3 million Bbl of oil and 633.5 Bcf of natural gas, a 12% increase, as compared to 232.8 million BOE for the year ended December 31, 2019. Our Delaware Basin proved reserves at December 31, 2020 comprised approximately 98% of our proved oil reserves and 96% of our proved natural gas reserves, as compared to approximately 94% of our proved oil reserves and 89% of our proved natural gas reserves at December 31, 2019.
At December 31, 2020, we had identified 4,359 gross (1,502 net) engineered locations for potential future drilling on our Delaware Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including the shallower Brushy Canyon and Avalon formations. These locations include 2,091 gross (1,298 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 that location given our current acreage position. At December 31, 2020, approximately two-thirds of these identified drilling locations are expected to have horizontal lateral lengths of two miles or greater and approximately 80% are expected to have horizontal lateral lengths greater than 1.5 miles. At and prior to December 31, 2019, all of our identified horizontal drilling locations were based on the assumptions of a one-mile lateral being drilled at each location. 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, 2020 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, 2020, 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, 2020, these potential future drilling locations included 358 gross (145 net) locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Avalon and Delaware formations, to which we have assigned proved undeveloped reserves.
At December 31, 2020, we were operating three drilling rigs in the Delaware Basin, and we expect to operate three rigs in the Delaware Basin during most of the first quarter of 2021. We expect to add a fourth rig in March 2021 and to operate four rigs in the Delaware Basin throughout the remainder of 2021. Two of these operated rigs are expected to operate full-time in the Stateline asset area. The other two rigs are expected to operate in certain of our other asset areas, including the Greater Stebbins Area, the Wolf asset area, the Ranger asset area and the Rodney Robinson leasehold in the western portion of the Antelope Ridge asset area. We have built significant optionality into our drilling program, which allowed us to decrease the number of rigs in 2020 from six to three within a few months and should generally allow us to increase or decrease the number of rigs we operate as necessary based on changing commodity prices and other factors. We are also planning to participate in non-operated wells in the Delaware Basin as these opportunities arise in 2021.
Antelope Ridge Asset Area - Lea County, New Mexico
At the end of the first quarter of 2020, we achieved the first of the five operational milestones we set for Matador in 2020 when we completed and turned to sales our first six gross (6.0 net) wells on the Rodney Robinson leasehold. These wells also were the first wells drilled on acreage acquired in the BLM Acquisition. Including the Rodney Robinson wells, we completed and turned to sales 12 gross (11.4 net) operated and 15 gross (0.3 net) non-operated wells in the Antelope Ridge asset area during 2020.
The 1,200 gross and net acre Rodney Robinson leasehold is one of the key tracts we acquired as part of the of 8,400 gross and net leasehold acres in Lea and Eddy Counties, New Mexico for approximately $387 million in the BLM Acquisition. The federal leases provide an 87.5% net revenue interest (“NRI”) as compared to approximately 75% NRI on most fee leases today. The six Rodney Robinson wells, which included two Wolfcamp A-XY completions, two Second Bone Spring completions, one Upper Avalon completion and one Lower Avalon completion, were turned to sales late in the first quarter of 2020 and were all two-mile laterals. The 24-hour initial potential (“IP”) test results from all six Rodney Robinson wells totaled 19,236 BOE per day (79% oil). Notably, these IP test results included, at the time, the best IP test results we had achieved for wells completed and turned to sales in the Avalon, Second Bone Spring and Wolfcamp A-XY formations throughout the Delaware Basin. These
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six Rodney Robinson wells have produced in aggregate approximately 2.7 million BOE in approximately 10 months of production. We drilled four additional Rodney Robinson wells in the fall of 2020, and these four wells are expected to be completed and turned to sales late in the first quarter of 2021.
Rustler Breaks Asset Area - Eddy County, New Mexico
In the Rustler Breaks asset area, we completed and turned to sales 13 gross (7.8 net) operated wells and 21 gross (1.9 net) non-operated wells during 2020.
During the second quarter of 2020, we achieved the second of the five operational milestones we set for Matador in 2020 when we completed and turned to sales five wells on our Ray State leasehold in the eastern portion of the Rustler Breaks asset area in late May and early June. These five wells, which were all-two mile laterals, included two Wolfcamp A-XY completions, one Wolfcamp A-Lower completion and two Wolfcamp B-Blair completions. The 24-hour IP aggregate test results for the five Ray State wells were 12,507 BOE per day (61% oil). These five Ray State wells have produced in aggregate approximately 1.6 million BOE in just over seven months of production.
During the fourth quarter of 2020, we completed and turned to sales three wells on our Ace Stern Vegas leasehold in northeast Rustler Breaks, including two Wolfcamp A-XY completions and one Third Bone Spring completion. The 24-hour IP aggregate test results for these three wells, which were all two-mile laterals, were 7,415 BOE per day (74% oil). We believe these three wells demonstrate the prospectivity of the northeastern portion of our Rustler Breaks acreage.
Arrowhead, Ranger and Twin Lakes Asset Areas - Eddy and Lea Counties, New Mexico
During the third quarter of 2020, we achieved the third of the five operational milestones we set for Matador in 2020 when we completed and turned to sales five gross (4.3 net) operated wells, all of which were two-mile laterals, on the Leatherneck tract in the Greater Stebbins Area. These five Leatherneck wells have produced in aggregate approximately 1.0 million BOE in just over six months of production. We did not complete or turn to sales any other operated or non-operated wells in other portions of the Arrowhead asset area or in the Ranger or Twin Lakes asset areas during 2020.
We were pleased with the performance from the five Leatherneck wells, which included two Third Bone Spring completions, two Wolfcamp A-XY completions and one Wolfcamp B completion. The Wolfcamp B completion was particularly noteworthy, being our first test of the Wolfcamp B formation this far north in the Delaware Basin. This Wolfcamp B completion tested 2,101 BOE per day (71% oil) during its 24-hour IP test. We believe these results provide evidence of Wolfcamp B prospectivity moving north in the Delaware Basin.
Stateline Asset Area - Eddy County, New Mexico
We operated two drilling rigs in our Stateline asset area for the majority of 2020 and expect to do so again in 2021. In early September 2018, we acquired the Stateline asset area in southern Eddy County, New Mexico as part of the BLM Acquisition. The Stateline asset area includes approximately 2,800 gross and net leasehold acres prospective for multiple geologic targets. The federal leases provide an 87.5% NRI. The large majority of the Stateline asset area acreage is believed to be conducive to drilling longer laterals of up to two miles or more, utilizing central facilities and multi-well pad development. We plan to develop this acreage block drilling two-mile laterals on the eastern side of the leasehold and approximately 2.5-mile laterals on the western side of the leasehold. We began drilling operations in the Stateline asset area just before the end of 2019 and, at the end of the third quarter of 2020, we achieved the last two of the five operational milestones we set for Matador in 2020 when we completed and turned to sales our first 13 gross (13.0 net) wells on the Boros tract in the eastern portion of the Stateline asset area and connected these wells to the expanded Black River Processing Plant and associated pipeline and facilities discussed below.
The 13 Boros wells, all of which were two-mile laterals, tested six different intervals and included one Avalon completion, two Second Bone Spring completions, four Wolfcamp A-XY completions, four Wolfcamp A-Lower completions, one Wolfcamp B-Upper completion and one Wolfcamp B-Lower completion. In aggregate, these 13 Boros wells tested 45,225 BOE per day (56% oil), and the IP test results from the two Second Bone Spring completions were the top two IP test results that we had reported to date for wells completed and turned to sales in that formation throughout the Delaware Basin. Similarly, the IP test results for three of the Wolfcamp A-Lower completions were three of the top four IP test results that we had achieved to date for wells completed and turned to sales in the Wolfcamp A-Lower formation. In addition, most of these 24-hour IP test results were recorded at high flowing casing pressures of between 3,000 and 4,200 pounds per square inch (“psi”) in the Wolfcamp A-XY, Wolfcamp A-Lower and Wolfcamp B formations, further indicating the potential of these wells. These 13 Boros wells have produced in aggregate approximately 2.7 million BOE in just over four months of production, despite a number of these wells being produced on restricted chokes early in their production.
In addition, during 2020, we drilled 13 wells on the Voni tract on the western portion of the Stateline leasehold. These 13 Voni wells are expected to have completed lateral lengths of approximately 12,000 feet and should be completed in the first quarter of 2021 and turned to sales early in the second quarter of 2021.
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Wolf and Jackson Trust Asset Areas - Loving County, Texas
In the Wolf and Jackson Trust asset areas, we completed and turned to sales 10 gross (9.1 net) operated wells during 2020. The Larson 04-TTT-B02 WF #136H (Larson #136H) well in the Wolf asset area was particularly significant, being our first test of the Third Bone Spring Carbonate formation in the Delaware Basin. The Larson #136H well tested 1,668 BOE per day (68% oil) from a completed lateral length of 7,443 feet. We believe this test result indicates the prospectivity of the Third Bone Spring Carbonate, not only in the Wolf asset area, but also in our other asset areas throughout the Delaware Basin.
South Texas — Eagle Ford Shale and Other Formations
The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate.
At December 31, 2020, our properties included approximately 29,300 gross (26,300 net) acres in the Eagle Ford shale play in South Texas. We believe that approximately 87% 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. Approximately 99% of our Eagle Ford acreage was held by production at December 31, 2020.
We did not conduct any operated or non-operated drilling and completion activities on our leasehold properties in South Texas during the year ended December 31, 2020. In fact, as of December 31, 2020, we had not completed any wells in the Eagle Ford shale in over 18 months. As a result, our average daily oil equivalent production from the Eagle Ford shale decreased 40% to 2,412 BOE per day, including 1,840 Bbl of oil per day and 3.4 MMcf of natural gas per day, during 2020, as compared to 4,009 BOE per day, including 3,113 Bbl of oil per day and 5.4 MMcf of natural gas per day, during 2019. For the year ended December 31, 2020, 3% of our total daily oil equivalent production was attributable to the Eagle Ford shale, as compared to 6% for the year ended December 31, 2019.
At December 31, 2020, approximately 2% of our estimated total proved oil and natural gas reserves, or 4.9 million BOE, was attributable to the Eagle Ford shale, including approximately 3.6 million Bbl of oil and 7.8 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 2% of our proved oil reserves and 1% of our proved natural gas reserves at December 31, 2020, as compared to approximately 6% of our proved oil reserves and 3% of our proved natural gas reserves at December 31, 2019.
At December 31, 2020, we had identified 229 gross (182 net) engineered locations for potential future drilling on our Eagle Ford acreage. Each drilling location represents a horizontal lateral, and individual locations have estimated lateral lengths ranging from one mile to almost two miles. These 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 producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other factors.
These engineered drilling locations include only a single interval in the lower portion of the Eagle Ford shale. We believe portions of our Eagle Ford acreage may be prospective for an additional target in the lower portion of the Eagle Ford shale and for other intervals in the upper portion of the Eagle Ford shale, from which we would expect to produce predominantly oil and liquids. In addition, we believe portions of our South Texas acreage may also be prospective for the Austin Chalk, Buda and other formations, from which we would expect to produce predominantly oil and liquids. At December 31, 2020, we had not included any future drilling locations in the upper portion of the Eagle Ford shale, in any additional intervals of the lower portion of the Eagle Ford shale or in the Austin Chalk or Buda formations, even though activity from other operators in these formations around our South Texas acreage position has demonstrated the prospectivity of these intervals.
Northwest Louisiana — Haynesville Shale, Cotton Valley and Other Formations
The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%.
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We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2020, although we did participate in the drilling and completion of four gross (less than 0.1 net) non-operated Haynesville shale wells that were turned to sales in 2020. In the first quarter of 2020, we leased 2,800 net acres of our minerals in the southern portion of our Pine Island asset area to a third party and retained royalty interests ranging from 18% to 20%. This lessee drilled four wells in the second half of 2020. We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2021.
At December 31, 2020, we held approximately 19,100 gross (17,700 net) acres in Northwest Louisiana, including 16,700 gross (9,100 net) acres in the Haynesville shale play and 16,100 gross (14,900 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 (4,800 net) acres that we consider to be in the core area of the Haynesville shale play.
For the year ended December 31, 2020, approximately 7% of our average daily oil equivalent production, or 5,241 BOE per day, including eight Bbl of oil per day and 31.4 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2019, approximately 10% of our average daily oil equivalent production, or 6,595 BOE per day, including 15 Bbl of oil per day and 39.5 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana. For the year ended December 31, 2020, approximately 17% of our daily natural gas production, or 31.4 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana, while for the year ended December 31, 2019, approximately 24% of our daily natural gas production, or 39.5 MMcf of natural gas per day, was attributable to these properties. At December 31, 2020, just over 1% of our estimated total proved reserves, or 3.5 million BOE, was attributable to our properties in Northwest Louisiana.
At December 31, 2020, we had identified 163 gross (16 net) engineered locations for potential future drilling in the Haynesville shale play and 154 gross (35 net) engineered locations for potential future drilling in the Cotton Valley formation. Each drilling location represents a horizontal lateral, and individual locations have estimated lateral lengths ranging from one mile to two miles, with most being two miles. These 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 producing Haynesville and Cotton Valley wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other factors.
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 I, a strategic joint venture with Five Point. The midstream assets that were contributed to San Mateo I included (i) 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 Wolf asset area and (iv) substantially all related oil, natural gas and produced water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). We received $171.5 million in connection with the formation of San Mateo I 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. At February 23, 2021, we had earned $58.8 million of the potential $73.5 million in performance incentives. Through February 23, 2021, Five Point had paid $14.7 million in performance incentives in each of the first quarters of 2018, 2019 and 2020, and we expect Five Point to pay us an additional $14.7 million in performance incentives in the first quarter of 2021. We may earn up to the remaining $14.7 million in San Mateo I performance incentives over the next two years. In connection with the formation of San Mateo I, we dedicated to San Mateo I current and certain future leasehold interests in the Rustler Breaks and Wolf asset areas 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 I pursuant to a 15-year, fixed fee natural gas processing agreement.
On February 25, 2019, we announced the formation of 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
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company’s proportionate interest in San Mateo. In addition, we have the ability to earn up to $150.0 million in deferred performance incentives over the next several years, plus additional performance incentives for securing volumes from third-party customers. During the fourth quarter of 2020, we met the threshold requirements to begin earning the additional $150.0 million in performance incentives from Five Point. At February 23, 2021, we had received $0.7 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, 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 I. 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, Wolf 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 facilities that have been developed in the Greater Stebbins Area and the Stateline asset area.
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.
During the third quarter of 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, 2020, 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.
In September 2020, San Mateo completed and placed in service 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, 2020, San Mateo was gathering or transporting 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 asset area.
In addition, in early 2018, San Mateo completed a natural gas liquids (“NGL”) pipeline connection at the Black River Processing Plant to the NGL pipeline owned by EPIC Y-Grade Pipeline LP. This NGL connection provides several significant benefits to us and other San Mateo customers compared to transporting the 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 our Wolf 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 Wolf asset area, including a cryogenic natural gas processing plant (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline.
At December 31, 2020, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2020, San Mateo gathered approximately 73.9 Bcf of natural gas, a decrease of 4%, as compared to 77.2 Bcf of natural gas gathered during the year ended December 31, 2019. In addition, during the year ended December 31, 2020, San Mateo processed approximately 60.8 Bcf of natural gas at the Black River Processing Plant, a decrease of 6%, as compared to 64.7 Bcf of natural gas processed during the year ended December 31, 2019. San Mateo’s natural gas gathering and processing volumes declined slightly in 2020 as compared to 2019 due to reduced volumes from a significant third-party customer, but San Mateo’s sequential natural gas gathering and processing volumes increased significantly in the fourth quarter of 2020, as compared to the third quarter of 2020, as we realized the first full quarter of production from the Boros wells in the Stateline asset area and the Leatherneck wells in the Greater Stebbins Area.
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
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producers located within the Joint Development Area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets.
In 2020, San Mateo completed and placed into service (i) a crude oil gathering and transportation system in the Greater Stebbins Area, which was connected to the existing interconnect in the Rustler Breaks asset area via approximately 19 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 Wolf asset area, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2020, we estimated we had on pipe almost all of our oil production from the Stateline, Wolf and Rustler Breaks asset areas and the Greater Stebbins Area.
At December 31, 2020, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from points of origin in Loving County, Texas and Eddy County, New Mexico to interconnects with Plains and two trucking facilities. During the year ended December 31, 2020, the San Mateo Oil Pipeline Systems had throughput of approximately 11.6 million Bbl of oil, an increase of 32%, as compared to throughput of approximately 8.9 million Bbl of oil during the year ended December 31, 2019.
Produced Water Gathering and Disposal Assets
During 2020, San Mateo placed into service one commercial salt water disposal well in the Rustler Breaks asset area, bringing San Mateo’s commercial salt water disposal well count in the Rustler Breaks asset area to eight. In addition to its eight commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area, at February 23, 2021, San Mateo had three commercial salt water disposal wells and associated facilities in the Wolf asset area, two commercial salt water disposal wells and associated facilities in the Greater Stebbins Area and produced water gathering systems in the Stateline, Rustler Breaks and Wolf asset areas and the Greater Stebbins Area. At February 23, 2021, San Mateo had designed disposal capacity of approximately 335,000 Bbl of produced water per day.
During the year ended December 31, 2020, San Mateo handled approximately 84.8 million Bbl of produced water, an increase of 15%, as compared to approximately 73.9 million Bbl of produced water handled during the year ended December 31, 2019.
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 and from third parties. Our midstream assets in South Texas and Northwest Louisiana are not part of San Mateo.
Operating Summary
The following table sets forth certain unaudited production and operating data for the years ended December 31, 2020, 2019 and 2018.
__________________
| Year Ended December 31, | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
| Unaudited Production Data: | ||||||||||||||||||||
| Net Production Volumes: | ||||||||||||||||||||
| Oil (MBbl) | 15,931 | 13,984 | 11,141 | |||||||||||||||||
| Natural gas (Bcf) | 69.5 | 61.1 | 47.3 | |||||||||||||||||
Total oil equivalent (MBOE)(1) | 27,514 | 24,164 | 19,026 | |||||||||||||||||
Average daily production (BOE/d)(1) | 75,175 | 66,203 | 52,128 | |||||||||||||||||
| Average Sales Prices: | ||||||||||||||||||||
| Oil, without realized derivatives (per Bbl) | $ | 37.38 | $ | 54.34 | $ | 57.04 | ||||||||||||||
| Oil, with realized derivatives (per Bbl) | $ | 39.83 | $ | 54.98 | $ | 57.38 | ||||||||||||||
| Natural gas, without realized derivatives (per Mcf) | $ | 2.14 | $ | 2.17 | $ | 3.49 | ||||||||||||||
| Natural gas, with realized derivatives (per Mcf) | $ | 2.14 | $ | 2.18 | $ | 3.46 | ||||||||||||||
| Operating Expenses (per BOE): | ||||||||||||||||||||
| Production taxes, transportation and processing | $ | 3.39 | $ | 3.82 | $ | 4.00 | ||||||||||||||
| Lease operating | $ | 3.81 | $ | 4.85 | $ | 4.89 | ||||||||||||||
| Plant and other midstream services operating | $ | 1.51 | $ | 1.52 | $ | 1.29 | ||||||||||||||
| Depletion, depreciation and amortization | $ | 13.15 | $ | 14.51 | $ | 13.94 | ||||||||||||||
| General and administrative | $ | 2.27 | $ | 3.31 | $ | 3.64 | ||||||||||||||
(1)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
13
The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2020 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.
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| 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) | 15,254 | 674 | — | 3 | 15,931 | |||||||||||||||||||||||||||
| Natural gas (Bcf) | 56.8 | 1.2 | 11.0 | 0.5 | 69.5 | |||||||||||||||||||||||||||
Total oil equivalent (MBOE)(3) | 24,713 | 883 | 1,835 | 83 | 27,514 | |||||||||||||||||||||||||||
| Percentage of total annual net production | 89.8 | % | 3.2 | % | 6.7 | % | 0.3 | % | 100.0 | % | ||||||||||||||||||||||
| Average Net Daily Production Volumes | ||||||||||||||||||||||||||||||||
| Oil (Bbl/d) | 41,678 | 1,840 | — | 8 | 43,526 | |||||||||||||||||||||||||||
| Natural gas (MMcf/d) | 155.1 | 3.4 | 30.1 | 1.3 | 189.9 | |||||||||||||||||||||||||||
| Total oil equivalent (BOE/d) | 67,522 | 2,412 | 5,015 | 226 | 75,175 | |||||||||||||||||||||||||||
Average Sales Prices(4) | ||||||||||||||||||||||||||||||||
| Oil (per Bbl) | $ | 37.38 | $ | 37.42 | $ | 28.77 | $ | 38.31 | $ | 37.38 | ||||||||||||||||||||||
| Natural gas (per Mcf) | $ | 2.23 | $ | 2.82 | $ | 1.66 | $ | 1.69 | $ | 2.14 | ||||||||||||||||||||||
| Total oil equivalent (per BOE) | $ | 28.19 | $ | 32.56 | $ | 9.94 | $ | 11.09 | $ | 27.06 | ||||||||||||||||||||||
Production Costs(5) | ||||||||||||||||||||||||||||||||
| Lease operating, transportation and processing (per BOE) | $ | 4.52 | $ | 20.52 | $ | 4.71 | $ | 19.39 | $ | 5.09 | ||||||||||||||||||||||
(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.
(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.
14
The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2019 from our operating areas, which we consider to be distinct fields for purposes of accounting for production.
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| 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) | 12,843 | 1,136 | — | 5 | 13,984 | |||||||||||||||||||||||||||
| Natural gas (Bcf) | 44.7 | 2.0 | 13.9 | 0.5 | 61.1 | |||||||||||||||||||||||||||
Total oil equivalent (MBOE)(3) | 20,294 | 1,463 | 2,316 | 91 | 24,164 | |||||||||||||||||||||||||||
| Percentage of total annual net production | 84.0 | % | 6.0 | % | 9.6 | % | 0.4 | % | 100.0 | % | ||||||||||||||||||||||
| Average Net Daily Production Volumes | ||||||||||||||||||||||||||||||||
| Oil (Bbl/d) | 35,184 | 3,113 | — | 15 | 38,312 | |||||||||||||||||||||||||||
| Natural gas (MMcf/d) | 122.5 | 5.4 | 38.1 | 1.4 | 167.4 | |||||||||||||||||||||||||||
| Total oil equivalent (BOE/d) | 55,599 | 4,009 | 6,345 | 250 | 66,203 | |||||||||||||||||||||||||||
Average Sales Prices(4) | ||||||||||||||||||||||||||||||||
| Oil (per Bbl) | $ | 53.95 | $ | 58.71 | $ | — | $ | 52.89 | $ | 54.34 | ||||||||||||||||||||||
| Natural gas (per Mcf) | $ | 2.11 | $ | 3.45 | $ | 2.16 | $ | 2.17 | $ | 2.17 | ||||||||||||||||||||||
| Total oil equivalent (per BOE) | $ | 38.80 | $ | 50.22 | $ | 12.99 | $ | 15.22 | $ | 36.93 | ||||||||||||||||||||||
Production Costs(5) | ||||||||||||||||||||||||||||||||
| Lease operating, transportation and processing (per BOE) | $ | 5.22 | $ | 15.27 | $ | 4.36 | $ | 22.43 | $ | 5.81 | ||||||||||||||||||||||
(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.
(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.
15
The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2018 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) | 10,230 | 907 | — | 4 | 11,141 | |||||||||||||||||||||||||||
| Natural gas (Bcf) | 37.7 | 1.5 | 7.5 | 0.6 | 47.3 | |||||||||||||||||||||||||||
Total oil equivalent (MBOE)(3) | 16,512 | 1,152 | 1,247 | 115 | 19,026 | |||||||||||||||||||||||||||
| Percentage of total annual net production | 86.8 | % | 6.0 | % | 6.6 | % | 0.6 | % | 100.0 | % | ||||||||||||||||||||||
| Average Net Daily Production Volumes | ||||||||||||||||||||||||||||||||
| Oil (Bbl/d) | 28,026 | 2,485 | — | 13 | 30,524 | |||||||||||||||||||||||||||
| Natural gas (MMcf/d) | 103.3 | 4.0 | 20.5 | 1.8 | 129.6 | |||||||||||||||||||||||||||
| Total oil equivalent (BOE/d) | 45,237 | 3,158 | 3,417 | 316 | 52,128 | |||||||||||||||||||||||||||
Average Sales Prices(4) | ||||||||||||||||||||||||||||||||
| Oil (per Bbl) | $ | 56.12 | $ | 67.4 | $ | — | $ | 64.72 | $ | 57.04 | ||||||||||||||||||||||
| Natural gas (per Mcf) | $ | 3.55 | $ | 5.46 | $ | 2.85 | $ | 2.80 | $ | 3.49 | ||||||||||||||||||||||
| Total oil equivalent (per BOE) | $ | 42.88 | $ | 60.02 | $ | 17.09 | $ | 18.59 | $ | 42.08 | ||||||||||||||||||||||
Production Costs(5) | ||||||||||||||||||||||||||||||||
| Lease operating, transportation and processing (per BOE) | $ | 4.79 | $ | 17.25 | $ | 5.41 | $ | 19.11 | $ | 5.68 | ||||||||||||||||||||||
(1)Includes one well producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas.
(2)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
(3)Production volumes reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
(4)Excludes impact of derivative settlements.
(5)Excludes plant and other midstream services operating expenses, ad valorem taxes and oil and natural gas production taxes.
Our total oil equivalent production of approximately 27.5 million BOE for the year ended December 31, 2020 increased 14% from our total oil equivalent production of approximately 24.2 million BOE for the year ended December 31, 2019. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2020, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2020 was 75,175 BOE per day, as compared to 66,203 BOE per day for the year ended December 31, 2019. Our average daily oil production for the year ended December 31, 2020 was 43,526 Bbl of oil per day, an increase of 14% from 38,312 Bbl of oil per day for the year ended December 31, 2019. Our average daily natural gas production for the year ended December 31, 2020 was 189.9 MMcf of natural gas per day, an increase of 13% from 167.4 MMcf of natural gas per day for the year ended December 31, 2019.
Our total oil equivalent production of approximately 24.2 million BOE for the year ended December 31, 2019 increased 27% from our total oil equivalent production of approximately 19.0 million BOE for the year ended December 31, 2018. This increased production was primarily due to our delineation and development operations in the Delaware Basin throughout 2019 as well as from our nine-well program in South Texas concluded in the first half of 2019 and non-operated Haynesville shale wells completed and placed on production during the third quarter of 2019. Our average daily oil equivalent production for the year ended December 31, 2019 was 66,203 BOE per day, as compared to 52,128 BOE per day for the year ended December 31, 2018. Our average daily oil production for the year ended December 31, 2019 was 38,312 Bbl of oil per day, an increase of 26% from 30,524 Bbl of oil per day for the year ended December 31, 2018. Our average daily natural gas production for the year ended December 31, 2019 was 167.4 MMcf of natural gas per day, an increase of 29% from 129.6 MMcf of natural gas per day for the year ended December 31, 2018.
16
Producing Wells
The following table sets forth information relating to producing wells at December 31, 2020. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 79% in all wells that we operated at December 31, 2020. 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) | 673 | 322.1 | 158 | 76.4 | 831 | 398.5 | ||||||||||||||||||||||||||||||||
| South Texas: | ||||||||||||||||||||||||||||||||||||||
Eagle Ford(2) | 122 | 101.0 | 4 | 4.0 | 126 | 105.0 | ||||||||||||||||||||||||||||||||
| Northwest Louisiana: | ||||||||||||||||||||||||||||||||||||||
| Haynesville | — | — | 237 | 18.8 | 237 | 18.8 | ||||||||||||||||||||||||||||||||
Cotton Valley(3) | 1 | 1.0 | 63 | 38.7 | 64 | 39.7 | ||||||||||||||||||||||||||||||||
| Area Total | 1 | 1.0 | 300 | 57.5 | 301 | 58.5 | ||||||||||||||||||||||||||||||||
| Total | 796 | 424.1 | 462 | 137.9 | 1,258 | 562.0 | ||||||||||||||||||||||||||||||||
(1)Includes 219 gross (62.6 net) vertical wells that were acquired in multiple transactions.
(2)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.
(3)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
Estimated Proved Reserves
The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2020, 2019 and 2018. 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 the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
17
At December 31,(1) | ||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||
Estimated Proved Reserves Data:(2) | ||||||||||||||||||||
| Estimated proved reserves: | ||||||||||||||||||||
| Oil (MBbl) | 159,949 | 147,991 | 123,401 | |||||||||||||||||
| Natural Gas (Bcf) | 662.3 | 627.2 | 551.5 | |||||||||||||||||
Total (MBOE)(3) | 270,332 | 252,531 | 215,313 | |||||||||||||||||
| Estimated proved developed reserves: | ||||||||||||||||||||
| Oil (MBbl) | 69,647 | 59,667 | 53,223 | |||||||||||||||||
| Natural Gas (Bcf) | 323.2 | 276.3 | 246.2 | |||||||||||||||||
Total (MBOE)(3) | 123,507 | 105,710 | 94,261 | |||||||||||||||||
| Percent developed | 45.7 | % | 41.9 | % | 43.8 | % | ||||||||||||||
| Estimated proved undeveloped reserves: | ||||||||||||||||||||
| Oil (MBbl) | 90,301 | 88,324 | 70,178 | |||||||||||||||||
| Natural gas (Bcf) | 339.1 | 351.0 | 305.2 | |||||||||||||||||
Total (MBOE)(3) | 146,825 | 146,821 | 121,052 | |||||||||||||||||
Standardized Measure(4) (in millions) | $ | 1,584.4 | $ | 2,034.0 | $ | 2,250.6 | ||||||||||||||
PV-10(5) (in millions) | $ | 1,658.0 | $ | 2,248.2 | $ | 2,579.3 | ||||||||||||||
(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, 2020 were $36.04 per Bbl for oil and $1.99 per MMBtu for natural gas, for the 12 months ended December 31, 2019 were $52.19 per Bbl for oil and $2.58 per MMBtu for natural gas and for the 12 months ended December 31, 2018 were $62.04 per Bbl for oil and $3.10 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. We report our proved reserves in two streams, oil and natural gas, and 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.
(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% per annum 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, 2020, 2019 and 2018 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, 2020, 2019 and 2018 were, in millions, $73.6, $214.2 and $328.7, respectively.
Our estimated total proved oil and natural gas reserves increased 7% from 252.5 million BOE at December 31, 2019 to 270.3 million BOE at December 31, 2020. This increase in proved oil and natural gas reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2020. This increase in total proved reserves was achieved despite (i) the reduction in our operated rig count from six to three during 2020 and (ii) the 31% reduction in oil price and the 23% reduction in natural gas price used to estimate total proved reserves at December 31, 2020, as compared to December 31, 2019. We added 35.3 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2020, approximately 1.3 times our 2020 annual production of 27.5 million BOE. We also realized approximately 9.8 million BOE in net upward revisions to our proved reserves during 2020, primarily as a result of upward revisions resulting from better-than-projected well performance from certain wells, as compared to December 31, 2019, which more than offset the downward revisions resulting from the significantly lower commodity prices used to estimate proved reserves at December 31, 2020. Our proved oil reserves grew 8% from approximately 148.0 million Bbl at December 31, 2019 to approximately 159.9 million Bbl at December 31, 2020. Our proved natural gas reserves increased 6% from 627.2 Bcf at December 31, 2019 to 662.3 Bcf at December 31, 2020. Our proved reserves to production ratio at December 31, 2020 was 9.8, a decrease of 7% from 10.5 at December 31, 2019.
Over the past two years, our estimated total proved oil and natural gas reserves increased 26% from 215.3 million BOE at December 31, 2018 to 270.3 million Bbl at December 31, 2020. Our proved oil reserves grew 30% from 123.4 million Bbl at December 31, 2018 to 159.9 million Bbl at December 31, 2020. Our proved developed oil reserves increased 31% from 53.2 million Bbl at December 31, 2018 to 69.6 million Bbl at December 31, 2020.
18
The Standardized Measure of our total proved oil and natural gas reserves decreased 22% from $2.03 billion at December 31, 2019 to $1.58 billion at December 31, 2020. The PV-10 of our total proved oil and natural gas reserves decreased 26% from $2.25 billion at December 31, 2019 to $1.66 billion at December 31, 2020. The decreases in our Standardized Measure and PV-10 are primarily a result of the significantly lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2020, as compared to December 31, 2019. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2020 were $36.04 per Bbl and $1.99 per MMBtu, a decrease of 31% and 23%, respectively, as compared to average oil and natural gas prices of $52.19 per Bbl and $2.58 per MMBtu used to estimate proved reserves at December 31, 2019. Our total proved reserves were made up of 59% oil and 41% natural gas at both December 31, 2020 and December 31, 2019. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see the preceding table.
Our proved developed oil and natural gas reserves increased 17% from 105.7 million BOE at December 31, 2019 to 123.5 million BOE at December 31, 2020 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increased 17% from 59.7 million Bbl at December 31, 2019 to 69.6 million Bbl at December 31, 2020. Our proved developed natural gas reserves increased 17% from 276.3 Bcf at December 31, 2019 to 323.2 Bcf at December 31, 2020.
The following table summarizes changes in our estimated proved developed reserves at December 31, 2020.
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| Proved Developed Reserves | ||||||||
(MBOE)(1) | ||||||||
| As of December 31, 2019 | 105,710 | |||||||
| Extensions and discoveries | 15,217 | |||||||
| Net acquisitions of minerals-in-place | 190 | |||||||
| Revisions of prior estimates | 960 | |||||||
| Production | (27,514) | |||||||
| Conversion of proved undeveloped to proved developed | 28,944 | |||||||
| As of December 31, 2020 | 123,507 | |||||||
(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 were 146.8 million BOE at both December 31, 2019 and December 31, 2020, as the net additions to our proved undeveloped reserves of 28.9 million BOE offset the 28.9 million BOE we converted from proved undeveloped to proved developed reserves during 2020. Our proved undeveloped oil reserves increased 2% from 88.3 million Bbl at December 31, 2019 to 90.3 million Bbl at December 31, 2020. Our proved undeveloped natural gas reserves decreased 3% from 351.0 Bcf at December 31, 2019 to 339.1 Bcf at December 31, 2020. These changes in proved undeveloped oil and natural gas reserves were primarily the result of net increases in proved undeveloped reserves in the Delaware Basin resulting from our delineation and development operations there, which were offset by the conversion of proved undeveloped reserves to proved developed reserves and the removal of certain proved undeveloped reserves from total proved reserves at December 31, 2020, primarily as a result of the significantly lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2020, as compared to December 31, 2019.
At December 31, 2020, 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, 2020 within five years of booking these reserves.
19
The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2020.
__________________
| Proved Undeveloped Reserves | ||||||||
(MBOE)(1) | ||||||||
| As of December 31, 2019 | 146,821 | |||||||
| Extensions and discoveries | 20,080 | |||||||
| Revisions of prior estimates | 8,868 | |||||||
| Conversion of proved undeveloped to proved developed | (28,944) | |||||||
| As of December 31, 2020 | 146,825 | |||||||
(1)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
The following table sets forth, since 2017, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands).
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| 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) | ||||||||||||||||||||||||
| 2017 | 9,300 | 45.0 | 16,808 | $ | 211,860 | |||||||||||||||||||||
| 2018 | 16,009 | 61.7 | 26,283 | 356,830 | ||||||||||||||||||||||
| 2019 | 13,832 | 58.8 | 23,629 | 318,609 | ||||||||||||||||||||||
| 2020 | 16,256 | 76.1 | 28,944 | 257,590 | ||||||||||||||||||||||
| Total | 55,397 | 241.6 | 95,664 | $ | 1,144,889 | |||||||||||||||||||||
(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, 2020.
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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 | 156,309 | 633.5 | 261,888 | $ | 1,538.2 | $ | 1,609.7 | |||||||||||||||||||||||||
| South Texas: | ||||||||||||||||||||||||||||||||
Eagle Ford(5) | 3,610 | 7.8 | 4,909 | 37.4 | 39.1 | |||||||||||||||||||||||||||
| Northwest Louisiana | ||||||||||||||||||||||||||||||||
| Haynesville | — | 20.9 | 3,486 | 8.6 | 9.0 | |||||||||||||||||||||||||||
Cotton Valley(6) | 30 | 0.1 | 49 | 0.2 | 0.2 | |||||||||||||||||||||||||||
| Area Total | 30 | 21.0 | 3,535 | 8.8 | 9.2 | |||||||||||||||||||||||||||
| Total | 159,949 | 662.3 | 270,332 | $ | 1,584.4 | $ | 1,658.0 | |||||||||||||||||||||||||
(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% per annum 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, 2020 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, 2020 were approximately $73.6 million.
(4)Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas.
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(5)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.
(6)Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas.
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. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. 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 and material balance 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 volumetric and/or analogy 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. For 2020, our Executive Vice President of Reservoir Engineering and Chief Technology Officer was primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 43 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. The Operations and Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors 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, 2020.
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| Developed Acres | Undeveloped Acres | Total Acres | ||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||
| Southeast New Mexico/West Texas: | ||||||||||||||||||||||||||||||||||||||
| Delaware Basin | 165,800 | 83,300 | 64,800 | 41,400 | 230,600 | 124,700 | ||||||||||||||||||||||||||||||||
| South Texas: | ||||||||||||||||||||||||||||||||||||||
| Eagle Ford | 28,900 | 26,100 | 400 | 200 | 29,300 | 26,300 | ||||||||||||||||||||||||||||||||
| Northwest Louisiana: | ||||||||||||||||||||||||||||||||||||||
| Haynesville | 16,700 | 9,100 | — | — | 16,700 | 9,100 | ||||||||||||||||||||||||||||||||
| Cotton Valley | 16,100 | 14,900 | — | — | 16,100 | 14,900 | ||||||||||||||||||||||||||||||||
Area Total(1) | 19,100 | 17,700 | — | — | 19,100 | 17,700 | ||||||||||||||||||||||||||||||||
| Total | 213,800 | 127,100 | 65,200 | 41,600 | 279,000 | 168,700 | ||||||||||||||||||||||||||||||||
(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.
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Undeveloped Acreage Expiration
The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2020 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 2026 and beyond totals 6,800 net acres, all of which is in the Delaware Basin. All of our leasehold in the Haynesville and Cotton Valley plays in Northwest Louisiana was held by existing production at December 31, 2020.
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| Acres | Acres | Acres | Acres | Acres | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Expiring 2021 | Expiring 2022 | Expiring 2023 | Expiring 2024 | Expiring 2025 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Southeast New Mexico/West Texas: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Delaware Basin(1) | 29,300 | 15,800 | 19,600 | 10,200 | 5,600 | 5,200 | 1,300 | 1,100 | 2,300 | 2,300 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| South Texas: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Eagle Ford | 400 | 200 | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | 29,700 | 16,000 | 19,600 | 10,200 | 5,600 | 5,200 | 1,300 | 1,100 | 2,300 | 2,300 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
(1)Approximately 47% 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 2021 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, 2020, 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.
Drilling Results
The following table summarizes our drilling activity for the years ended December 31, 2020, 2019 and 2018.
| Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||
| Development Wells | ||||||||||||||||||||||||||||||||||||||
| Productive | 89 | 44.5 | 147 | 62.0 | 118 | 54.7 | ||||||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
| Exploration Wells | ||||||||||||||||||||||||||||||||||||||
| Productive | 4 | 3.3 | 25 | 13.3 | 35 | 20.8 | ||||||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
| Total Wells | ||||||||||||||||||||||||||||||||||||||
| Productive | 93 | 47.8 | 172 | 75.3 | 153 | 75.5 | ||||||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
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 deducted from the price received for crude oil and liquids.
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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 or third parties’ processing facilities to extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the sale of the liquids 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 and natural gas production fluctuate widely. Factors that, directly or indirectly, cause price fluctuations include the level of demand for oil and natural gas, the actions of the Organization of Petroleum Exporting Countries, Russia and certain other oil-exporting countries (“OPEC+”), weather conditions, including hurricanes in the Gulf Coast region and severe cold weather in the Delaware Basin, oil and natural gas storage levels, transportation and refinery capacity constraints, domestic and foreign governmental regulations, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, domestic or global health concerns such as COVID-19, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall 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 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 and natural gas. Low oil and natural gas 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 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—An increase 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, 2020, 2019 and 2018, we had two, two and four significant purchasers that accounted for approximately 65%, 67% and 60%, 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. As discussed below in “—Regulation,” in January 2021, the Biden administration issued certain orders limiting the issuance of federal drilling permits and other necessary federal approvals. The
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impact of these federal actions remains unclear, and if the restrictions do not lapse, or other limitations or prohibitions become effective, our oil and natural gas operations on federal lands could be adversely impacted.
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 in production and markets relating to 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 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 competes with other midstream companies that provide similar services in its 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, to acquire properties and to provide competitive midstream services will depend upon our ability to conduct operations, to evaluate and select suitable properties and to 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.”
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,
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the prohibition, restriction or limitation of venting or flaring natural gas, the sourcing and disposal of water used and produced in the drilling and completion process 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. In January 2021, the Biden administration issued: (i) an order signed by the acting Secretary of the Interior dated January 20, 2021 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 impact of the federal actions remains unclear, and if the restrictions do not lapse, or other limitations or prohibitions become effective, our oil and natural gas operations on federal lands could be adversely impacted. See “Risk Factors—Risks Related to Laws and Regulations—Approximately 28% 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 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 66 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
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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 (“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, 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. On January 13, 2017, PHMSA issued, but did not publish, a similar proposed rule for hazardous liquids (i.e., oil) pipelines and gathering lines. It is unclear when or if this rule will go into effect as, on January 20, 2017, the Trump administration requested that all regulations that had been sent to the Office of the Federal Register, but not yet published, be immediately withdrawn for further review. 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. In 2019, a bill was introduced in the New Mexico Senate to add a surtax on natural gas processors that would have started at $0.60 per MMBtu in 2020 and escalated to $3.00 per MMBtu by 2024. Although the bill did not pass, any such surtax would adversely affect the ability of San Mateo and other natural gas processors to operate in New Mexico and would 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, including proposals that would eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to 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” and “Risk Factors—Risks Related to Laws and Regulations—The Tax Cuts and Jobs Act may impact our ability to fully utilize our interest expense deductions and net operating loss carryovers to fully offset our taxable income in future periods.”
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Hydraulic Fracturing Policies and Procedures
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. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. 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 one-half to two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way as all other costs of drilling and completion of our wells and are included in and funded through our normal capital expenditure budget. 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 protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM, with respect to federal acreage).
Although rare, if the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs and temperature logs, and conducting pressure testing, followed by pumping remedial cement jobs and taking other appropriate remedial measures.
The vast majority of our hydraulic fracturing treatments are made up of water and sand or other kinds of man-made proppants. We use major hydraulic fracturing service companies that track and report chemical additives that are used in fracturing operations as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures and also work to develop more environmentally friendly fracturing fluids. We follow safety procedures and monitor all aspects of our fracturing operations in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures.
While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is either recycled or disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. Since mid-2015, we have been recycling a portion of our produced water in certain of our Delaware Basin asset areas. Recycling produced water mitigates the need for produced water disposal and also provides cost savings to us.
Environmental, Health and Safety Regulation
The exploration, development, production, gathering and processing of oil and natural gas, including the operation of produced water injection and disposal wells, 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”), the Safe Drinking Water Act (the “SDWA”) 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 below the rate 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
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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 Environmental Protection Agency (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, however, and promulgated the Navigable Waters Protection Rule (the “NWPR”) in 2020. The NWPR defined what waters qualify as navigable waters of the United States and are under CWA jurisdiction. This new rule has generally been viewed as narrowing the scope of WOTUS as compared to the 2015 rule, but there is currently litigation in multiple federal district courts challenging the rescission of the 2015 rule and the promulgation of the NWPR.
Separately, in April 2020, a Montana federal judge vacated the Corps’ Nationwide Permit (“NWP”) 12 and enjoined the Corps from authorizing any dredge or fill activities under NWP 12 until the agency completed formal consultation with the U.S. Fish and Wildlife Service (the “USFWS”) under the Endangered Species Act (the “ESA”) regarding NWP 12 generally. The court later revised its order to vacate NWP 12 only as it relates to the construction of new oil and natural gas pipelines, and that order is currently on appeal in the Ninth Circuit Court of Appeals. However, the Montana district court’s decision spawned other NWP 12-based challenges and may indicate that the rest of the NWPs, some of which are relied upon for oil and natural gas projects, are vulnerable to similar challenge. The Corps has proposed a new set of NWPs, which would replace the NWPs for dredge or fill discharges into WOTUS that the Corps last issued and made available in 2017, but has so far elected not to consult with the USFWS. If this status quo does not change, when the Corp re-issues the NWPs, the NWPs could be subject to the same legal challenges unless and until the ongoing litigation resolves the questions surrounding the need for a formal ESA consultation.
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. 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
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2016, requires countries to review and “represent a progression” in their intended nationally determined contributions, which set greenhouse gas emission reduction goals, every five years beginning in 2020. While the United States exited the Paris Agreement in November 2020, effective February 19, 2021, President Biden caused the United States to rejoin the Paris Agreement. 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. Following that executive order, the New Mexico Oil Conservation Division (the “NMOCD”), New Mexico Environment Department (the “NMED”) and New Mexico legislature have proposed various rules, regulations and bills regarding the reduction of natural gas waste and the control of emissions that would, 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.
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, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. Based on these 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. 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 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.”
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 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 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 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 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. 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.
Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “—Hydraulic Fracturing Policies and Procedures.” Hydraulic fracturing is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. The process of hydraulic fracturing is typically regulated by state oil and natural gas commissions. Various policy makers, regulatory agencies and
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political candidates at the federal, state and local levels have proposed restrictions on hydraulic fracturing, including its outright prohibition. In January 2021, the Biden administration issued the Biden Administration Federal Lease Orders. The impact of these federal actions remains unclear, and if the restrictions do not lapse, or other limitations or prohibitions become effective, they could have an adverse impact on our business, financial condition, results of operations and cash flows. Restrictions on hydraulic fracturing could also 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. 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 significant 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 28% 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.”
Oil and natural gas exploration and production operations and other activities have been conducted on some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties against some of the liability for environmental claims associated with the properties we purchase. 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.
Additionally, 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. 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.
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 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. 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. 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.” Our ability to maximize production from our leases may be adversely impacted by these restrictions.
As of December 31, 2020, approximately 28% of our Delaware Basin acreage position, including all of the BLM Acquisition, consists of federal leasehold administered by 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. Delays in obtaining necessary permits can disrupt our operations and have an adverse effect on our business. These BLM leases contain
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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, 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 an 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 January 2021, the Biden administration issued the Biden Administration Federal Lease Orders. The impact of these federal actions remains unclear, and if the restrictions do not lapse, or other limitations or prohibitions become effective, our oil and natural gas operations on federal lands could be adversely impacted.
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, has the potential to delay or even halt development of future oil and natural gas projects with NEPA applicability.
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. 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.”
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.
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, 2020, we had 288 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 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.
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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 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 2020, for example, our employees completed approximately 15,000 hours of continuing education and study. 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. Between 2017 and 2020, we estimate our employees have worked approximately 2.1 million combined hours without experiencing a single lost time accident. We attribute much of that to the efforts of our Health, Safety and Environmental (“HSE”) group, which is devoted to proactively minimizing safety risks and addressing 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 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.
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 and results of operations. 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 and natural gas, the volatility of which may adversely affect our financial condition.
•We face numerous risks related to the COVID-19 global pandemic, including its impact on global oil demand.
•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 may not reflect the actual volumes we will recover, and we may be required to write down the carrying value of our proved properties under accounting rules.
•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.
•Hedging transactions, or the lack thereof, may limit our potential gains and could result in financial losses.
•An increase 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 financial condition.
•A component of our growth may come through acquisitions, which we may be unable to complete or which may require us to incur certain liabilities, risks or title deficiencies.
•Our ability to complete dispositions of 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 San Mateo’s revolving credit facility (the “San Mateo Credit Facility”).
•The terms of the agreements governing our indebtedness impose significant operating and financial restrictions.
•Our credit rating may be downgraded, which could reduce our financial flexibility and increase interest expense.
•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.
Risks Related to our Operations
•Drilling for and producing oil and natural gas are highly speculative and involve a high degree of operational, geological and financial risk, and insurance against all such risks is not available to us.
•Because our reserves and production are concentrated in a few core areas, problems in production and markets relating to a particular area could have a material impact on our business.
•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, and multi-well pad drilling may result in volatility in our operating results.
•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.
•The unavailability or high cost of 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 unable to dispose of the water we use at a reasonable cost and pursuant to applicable environmental rules.
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•Regulatory changes could prevent our ability to continue to pool wells in the manner we have been.
•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 our plans.
Risks Related to Third Parties
•We depend upon several significant purchasers for the sale of most of our production, and financial difficulties encountered by such purchasers, other operators or third parties could decrease our cash flows from operations.
•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.
•Because of the natural decline in production in the regions of San Mateo’s midstream operations, San Mateo’s long-term success depends on its ability to obtain new sources of products.
•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.
•Competition in our industry is intense, making it more difficult for us to acquire properties, market production, provide midstream services and secure trained personnel, and our competitors may use superior technology and data resources.
•We have limited control over activities on properties we do not operate.
Risks Related to Laws and Regulations
•As of December 31, 2020, approximately 28% 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 environmental laws, which could require significant expenditures.
•We are subject to tax laws, and changes thereto could eliminate or reduced certain federal income tax deductions or net operating loss carryforwards currently available.
•Legislative and regulatory initiatives relating to hydraulic fracturing, induced seismicity, emissions and climate change could result in increased costs, operating restrictions or delays.
•We may incur significant costs and liabilities resulting from compliance with pipeline safety regulations, and the rates of our regulated assets are subject to oversight by regulators, which could adversely affect our revenues.
•Derivatives legislation adopted by Congress could limit our ability to hedge commodity price risks.
Risks Relating to Our Common Stock
•The price of our common stock is volatile and may fluctuate substantially in the future.
•Conservation measures and a negative shift in market perception towards the oil and natural gas industry could adversely affect our stock price.
•Our directors and executive officers own a significant percentage of our equity, which could give them influence in transactions and other matters, and their interests could differ from other shareholders.
•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.
General Risk Factors
•We may have difficulty managing growth in our business.
•Our success depends on our ability to retain our key personnel.
•If we fail to maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.
•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 that could have an adverse effect on our results of operations and financial condition.
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Risks Related to our Financial Condition
Our success is dependent on the prices of oil and natural gas. Low oil and natural gas 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 and natural gas 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 and natural gas 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 and natural gas have been volatile and will likely continue to be volatile in the future. For the year ended December 31, 2020, oil prices averaged $39.34 per Bbl, ranging from a high of $63.27 per Bbl in early January to a low of ($37.63) per Bbl in mid-April, based upon the WTI oil futures contract price for the earliest delivery date. For the year ended December 31, 2020, natural gas prices averaged $2.13 per MMBtu, as compared to $2.53 per MMbtu for the year ended December 31, 2019, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. During 2020, natural gas prices began the year at $2.12 per MMBtu and fell to a low of $1.48 per MMBtu at the end of June, before increasing to a high of $3.35 per MMBtu in late October and finishing the year at $2.54 per MMBtu.
Because we use the full-cost method of accounting, we perform a ceiling test quarterly that may be impacted by declining prices of oil and natural gas. The significant decline in oil and natural gas prices during 2020 caused us to recognize full-cost ceiling impairments in each of the second, third and fourth quarters of 2020, and we may recognize further full-cost ceiling impairments in future periods. Such full-cost ceiling impairments reduce the book value of our net tangible assets, retained earnings and shareholders’ equity but do not impact our cash flows from operations, liquidity or capital resources. See “—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.”
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 and natural gas;
•the actions of OPEC+ and state-controlled oil companies relating to oil price and production controls;
•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;
•political conditions in or affecting oil and natural gas producing regions or countries, including the United States, the Middle East, South America and Russia;
•domestic or global health concerns, including the outbreak of contagious or pandemic diseases, such as COVID-19;
•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.
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These factors make it difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas 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 and natural gas prices do not necessarily fluctuate in direct relation to each other.
During the first quarter and through April 2020, the oil and natural gas industry witnessed an abrupt and significant
decline in oil prices from $63 per Bbl in early January to as low as ($38) per Bbl in late April. This sudden decline in oil prices
was attributable to two primary factors: (i) the precipitous decline in global oil demand resulting from the worldwide spread of
COVID-19 and (ii) a sudden, unexpected increase in global oil supply resulting from actions initiated by Saudi Arabia to
increase its oil production to world markets following the failure of efforts by OPEC+ to agree on coordinated production cuts at their March 6, 2020 meetings in Vienna, Austria. Primarily as a result of these unexpected events and the resulting declines in oil prices, we significantly modified our 2020 operational plan.
Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically and could reduce the amount we may borrow under our Credit Agreement. Should oil or natural gas 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.
We face numerous risks related to the COVID-19 global pandemic, which has had and is likely to continue to have a material adverse effect on our business, financial condition, results of operations and cash flows.
Since the beginning of 2020, the COVID-19 pandemic has spread across the globe and disrupted economies and industries around the world, including the exploration and production and midstream businesses. The rapid spread of COVID-19 has led to the implementation of various responses, including federal, state and local government-imposed quarantines, shelter-in-place mandates, sweeping restrictions on travel and other public health and safety measures, nearly all of which have materially reduced global demand for crude oil. The extent to which COVID-19 will continue to affect our business, financial condition, results of operations and cash flows and the demand for our production will depend on future developments, which are highly uncertain and cannot be predicted, including the duration or any recurrence of the outbreak and responsive measures, additional or modified government actions, new information that may emerge concerning the severity of COVID-19 and the effectiveness of vaccines and other actions taken to contain COVID-19 or treat its impact now or in the future, among others.
Some impacts of the COVID-19 pandemic that could have an adverse effect on our business, financial condition, results of operations and cash flows include:
•significantly reduced prices for our oil production, resulting from a world-wide decrease in demand for hydrocarbons and a resulting oversupply of existing production;
•further decreases in the demand for our oil production, resulting from significantly decreased levels of global, regional and local travel as a result, in part, of federal, state and local government-imposed quarantines, including shelter-in-place mandates, enacted to slow the spread of COVID-19;
•increased likelihood that we may, either voluntarily or as a result of third-party and regulatory mandates, curtail or shut in production, resulting from depressed oil prices, lack of storage and other market or political forces;
•significant decreases in the volumes of oil, natural gas and produced water that are transported, gathered, processed or disposed of by San Mateo due to curtailed or shut-in production by Matador or other of San Mateo’s customers;
•increased costs associated with, or actual unavailability of, facilities for the storage of oil, natural gas and NGL production in the markets in which we operate;
•increased operational difficulties associated with the delivery of oil, natural gas and NGLs to end-markets, resulting from pipeline and storage constraints;
•the potential for the operations of the Black River Processing Plant and other critical midstream infrastructure to be adversely impacted by outbreaks of COVID-19 among the relevant workforce;
•the potential for forced curtailment of oil and natural gas production by state governmental agencies, resulting in a need to significantly curtail or shut in our production;
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•the potential for loss of leasehold interests due to the failure to produce oil and natural gas in paying quantities as a result of significantly lower commodity prices, voluntary or forced curtailments or other factors related to the misalignment of supply and demand, and the potential to incur significant costs associated with litigation related to the foregoing;
•increased third-party credit risk, including the risk that counterparties may not accept the delivery of our oil, natural gas and NGL production, resulting from adverse market conditions, a lack of access to capital and storage or the failure of certain of our counterparties to continue as going concerns;
•increased likelihood that counterparties to our existing agreements may seek to invoke force majeure provisions to avoid the performance of contractual obligations, resulting from significantly adverse market conditions;
•the potential impact for delays in construction or increased costs related to midstream construction projects;
•increased costs, staffing requirements and difficulties sourcing oilfield services related to social distancing measures implemented in connection with federal, state or local government and voluntarily imposed quarantines; and
•increased legal and operational costs related to compliance with significant changes in federal, state and local laws and regulations.
The COVID-19 outbreak continues to evolve, and the extent to which the outbreak may impact our business, financial condition, results of operations and cash flows will depend highly on future developments, which are very uncertain and cannot be predicted. Additionally, the extent and duration of the impact of the COVID-19 pandemic on our stock price and that of our peer companies is uncertain and may make us look less attractive to investors. As a result, there may be a less active trading market for our common stock, our stock price may be more volatile and our ability to raise capital could be impaired.
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 acquisitions or future capital expenditures. 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 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, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large 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 fund
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acquisitions, increase our rate of growth, expand our midstream operations, develop our properties or pay for higher service costs, 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 many 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 U.S. generally accepted accounting principles (“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.
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Approximately 54% of our total proved reserves at December 31, 2020 consisted of undeveloped and developed non-producing reserves, and those reserves may not ultimately be developed or produced.
At December 31, 2020, approximately 54% of our total proved reserves were undeveloped and less than 1% 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 increasing our production and reserves from 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, 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
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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, 2020.
An increase 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 ad