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, 2019
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 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 $2,187,634,344 .
As of February 28, 2020, there were 116,569,389 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE |
MATADOR RESOURCES COMPANY
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2019
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, increases in our borrowing base and otherwise; our ability to make acquisitions on economically acceptable terms; our ability to integrate acquisitions; weather and environmental conditions; the operating results of our midstream joint venture’s expansion of the Black River cryogenic natural gas processing plant, including the timing of the further expansion of such 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, including in conjunction with the expansion of our midstream joint venture’s services and assets into new areas in Eddy County, New Mexico; 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; |
• | our cash flows and liquidity; |
• | our financial strategy, budget, projections and operating results; |
• | our oil and natural gas realized prices; |
• | the timing and amount of future production of oil and natural gas; |
• | the availability of drilling and production equipment; |
• | 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 and expansion of our 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; |
• | developments in oil-producing and natural gas-producing countries; |
• | 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. |
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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 (“San Mateo I”) together with San Mateo Midstream II, LLC (“San Mateo II”). 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 salt water gathering services and salt 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; |
• | maintain our financial discipline; and |
• | pursue opportunistic acquisitions, divestitures and joint ventures. |
Despite a challenging commodity price environment since 2014, the successful execution of our business strategies in 2019 led to significant increases in our oil and natural gas production and proved oil and natural gas reserves. We also improved the capital efficiency of our drilling and completion operations and continued to improve our leasehold and minerals position in the Delaware Basin. In addition, we concluded several important financing transactions in 2019, including an
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increase in the borrowing base under our Credit Agreement (as defined below), two increases in the lender commitments under the San Mateo Credit Facility (as defined below) and the conversion of approximately $21.9 million of non-core assets to cash. San Mateo also achieved several important milestones in 2019, including the formation of San Mateo II, an increased natural gas gathering and processing commitment from an existing natural gas customer, significant additional acreage dedications from existing salt water disposal customers, an acreage dedication from a new oil customer and an increase in designed salt water disposal capacity. These achievements and transactions increased our operational flexibility and opportunities while preserving the strength of our balance sheet and our liquidity position.
2019 Highlights
Increased Oil, Natural Gas and Oil Equivalent Production
For the year ended December 31, 2019, we achieved record oil, natural gas and average daily oil equivalent production. In 2019, we produced 14.0 million Bbl of oil, an increase of 26%, as compared to 11.1 million Bbl of oil produced in 2018. We also produced 61.1 Bcf of natural gas, an increase of 29% from 47.3 Bcf of natural gas produced in 2018. Our average daily oil equivalent production for the year ended December 31, 2019 was 66,203 BOE per day, including 38,312 Bbl of oil per day and 167.4 MMcf of natural gas per day, an increase of 27%, as compared to 52,128 BOE per day, including 30,524 Bbl of oil per day and 129.6 MMcf of natural gas per day, for the year ended December 31, 2018. The increase in oil and natural gas production was primarily attributable to our ongoing delineation and development drilling activities 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. Oil production comprised 58% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2019, as compared to 59% for the year ended December 31, 2018.
Increased Oil, Natural Gas and Oil Equivalent Reserves
At December 31, 2019, our estimated total proved oil and natural gas reserves were 252.5 million BOE, including 148.0 million Bbl of oil and 627.2 Bcf of natural gas, an increase of 17% from 215.3 million BOE, including 123.4 million Bbl of oil and 551.5 Bcf of natural gas, at December 31, 2018. The Standardized Measure of our total proved oil and natural gas reserves decreased 10% from $2.25 billion at December 31, 2018 to $2.03 billion at December 31, 2019. The PV-10 of our total proved oil and natural gas reserves decreased 13% from $2.58 billion at December 31, 2018 to $2.25 billion at December 31, 2019. The decreases in our Standardized Measure and PV-10 were primarily a result of lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2019, as compared to December 31, 2018. 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 20% to 148.0 million Bbl at December 31, 2019 from 123.4 million Bbl at December 31, 2018. Our proved natural gas reserves increased 14% to 627.2 Bcf at December 31, 2019 from 551.5 Bcf at December 31, 2018. This growth in oil and natural gas reserves was primarily attributable to our ongoing delineation and development drilling activities in the Delaware Basin during 2019.
At December 31, 2019, proved developed reserves included 59.7 million Bbl of oil and 276.3 Bcf of natural gas, and proved undeveloped reserves included 88.3 million Bbl of oil and 351.0 Bcf of natural gas. 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. Proved developed reserves and proved oil reserves comprised 44% and 57%, respectively, of our total proved oil and natural gas reserves at December 31, 2018.
Operational Highlights
We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to better manage operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Delaware Basin wells, particularly over the past six years. We expect the Delaware Basin will continue to be our primary area of focus in 2020.
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We completed and began producing oil and natural gas from 138 gross (65.7 net) wells in the Delaware Basin in 2019, including 76 gross (61.4 net) operated and 62 gross (4.3 net) non-operated wells. At December 31, 2019, our total acreage position in the Delaware Basin was approximately 231,300 gross (128,200 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 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 23% 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, as compared to 45,237 BOE per day (87% of total oil equivalent production), including 28,026 Bbl of oil per day (92% of total oil production) and 103.3 MMcf of natural gas per day (80% of total natural gas production), in 2018. We expect our Delaware Basin production to increase in 2020 as we continue the delineation and development of these asset areas, as well as our new Stateline asset area in Eddy County, New Mexico, where we expect to begin production late in the third quarter of 2020.
Operational highlights in the Delaware Basin (as further described below in “—Exploration and Production Segment—Southeast New Mexico and West Texas—Delaware Basin” and “—Midstream Segment”) in 2019 included:
• | in our Rustler Breaks asset area, the results from our first two operated First Bone Spring tests, including the Garrett State Com 32-24S-29E RB #111H (Garrett #111H) well and the Paul 25-24S-28E RB #111H (Paul #111H) well, demonstrating the prospectivity of this formation and the continued delineation and development of previously tested horizons; |
• | in our Wolf asset area, the continuing success from several wells with longer laterals (greater than one mile) drilled and completed in the Wolfcamp A-XY interval; |
• | in our Jackson Trust asset area, the continued development of the Wolfcamp A-Lower interval; |
• | in our Arrowhead and Ranger asset areas, the results from our Wolfcamp A-XY completions, particularly in the Stebbins acreage block in the Arrowhead asset area, whose 24-hour initial potential (“IP”) test results and subsequent well performance demonstrate the prospectivity of the Wolfcamp formation moving north in the Delaware Basin; |
• | in our Antelope Ridge asset area, the results from the Jeff Hart State Com #124H and #134H (Jeff Hart #124H and #134H) wells, our first two operated two-mile horizontal wells in the asset area, and the initiation of drilling operations on six wells in the western region of the asset area (the “Rodney Robinson” wells); |
• | in our Stateline asset area, the successful approval and receipt of 14 drilling permits from the Bureau of Land Management (“BLM”) and the initiation of drilling operations there in late December 2019; |
• | the transition to drilling longer laterals, whereby 29% of the operated horizontal wells we completed and turned to sales in 2019 had lateral lengths greater than one mile, as compared to 9% in 2018; |
• | the continuing improvement in capital efficiency as demonstrated by our average drilling and completion costs for all operated horizontal wells completed and turned to sales of approximately $1,165 per lateral foot in 2019, a decrease of 24% as compared to average drilling and completion costs of $1,528 per lateral foot in 2018; |
• | the initial transportation of much of our Delaware Basin residue natural gas production to the Texas Gulf Coast on the newly commissioned Gulf Coast Express Pipeline Project (the “GCX Pipeline”) beginning in late September 2019; and |
• | the significant progress made in our midstream operations, including (i) strong operating results in 2019, (ii) the initiation of an expansion of San Mateo’s cryogenic natural gas processing plant in Eddy County, New Mexico (the “Black River Processing Plant”) by an additional 200 MMcf per day of designed natural gas processing inlet capacity, which is anticipated to be placed in service during the summer of 2020, (iii) the initiation of San Mateo’s plans to construct large diameter natural gas gathering lines southward from the Stebbins area and surrounding leaseholds in the southern portion of the Arrowhead asset area (the “Greater Stebbins Area”) and northward from the Stateline asset area to connect these areas with the Black River Processing Plant, (iv) the addition of significant salt water disposal capacity in the Rustler Breaks asset area and the Greater Stebbins Area and (v) the progress made by San Mateo in increasing commitments, throughput volumes and acreage dedications from both new and existing customers. |
We also concluded operations on our nine-well program in South Texas (initiated in late 2018) during the second quarter of 2019, which included turning to sales seven gross (6.9 net) wells in the Eagle Ford formation and one gross (1.0 net) well in the Austin Chalk formation in 2019. We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2019, although we did participate in the drilling and completion of 26 gross (1.7 net) non-operated Haynesville shale wells that began producing in 2019, including two highly productive two-mile lateral wells completed and turned to sales by an affiliate of Chesapeake Energy Corporation (“Chesapeake”) during the third quarter of 2019.
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Financing Transactions
We concluded several important financing transactions in 2019 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”) to increase the borrowing base to $900.0 million, which was further amended in February 2020 to increase our elected borrowing commitment from $500.0 million to $700.0 million; |
• | the increase of the lender commitments under San Mateo I’s credit facility (the “San Mateo Credit Facility”) to $375.0 million, using the accordion feature; and |
• | the conversion of approximately $21.9 million of non-core assets to cash during 2019. These properties were primarily located in South Texas and Northwest Louisiana and East Texas but included a small portion of our leasehold in a non-operated area of the Delaware Basin. |
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
On February 25, 2019, we announced the formation of San Mateo II, a strategic joint venture with a subsidiary of Five Point Energy LLC (“Five Point”) designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. San Mateo II is owned 51% by us and 49% by Five Point. As part of this transaction, we dedicated to San Mateo II acreage in the Greater Stebbins Area and the Stateline asset area pursuant to 15-year, fixed-fee agreements for oil, natural gas and salt water gathering, natural gas processing and salt water disposal. In addition, Five Point has 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. Five Point has also provided us the opportunity to earn deferred performance incentives of up to $150.0 million over the next several years as we execute our operational plans in and around the Greater Stebbins Area and the Stateline asset area, plus additional performance incentives for securing volumes from third-party customers.
San Mateo achieved strong operating results in 2019, highlighted by (i) increased third-party midstream services revenues, (ii) increased natural gas gathering and processing volumes, (iii) increased water gathering and water disposal volumes and (iv) increased oil gathering volumes, all as compared to 2018. San Mateo initiated construction on an additional 200 MMcf per day of designed natural gas processing inlet capacity as part of the expansion of the Black River Processing Plant, which is anticipated to be placed in service during the summer of 2020 and would bring the total designed inlet capacity of the Black River Processing Plant to 460 MMcf of natural gas per day. San Mateo also initiated plans to construct large diameter natural gas gathering lines southward from the Greater Stebbins Area and northward from the Stateline asset area to connect these areas with the Black River Processing Plant. During 2019, San Mateo added four commercial salt water disposal wells, two in the Rustler Breaks asset area and two in the Greater Stebbins Area, and expects to place into service one additional commercial salt water disposal well in the Rustler Breaks asset area in the first quarter of 2020, bringing San Mateo’s designed salt water disposal capacity to approximately 335,000 Bbl per day.
During 2019, San Mateo received an increased natural gas gathering and processing commitment from an existing natural gas customer, plus other interruptible volumes, obtained significant additional acreage dedications from existing salt water customers and added an acreage dedication from a new oil customer. At certain times near the end of the third quarter and early in the fourth quarter of 2019, as a result of increased throughput from existing natural gas processing customers, San Mateo was operating the Black River Processing Plant at greater than 95% of the current designed inlet capacity of 260 MMcf per day.
Environmental, Social and Governance (“ESG”) Initiatives
We maintain an active ESG program and continued working in 2019 to improve upon our various ESG efforts. For instance, we significantly increased the number of our production facilities operating on electrical grid power, lowering emissions by removing on-site generators. We increased the volumes of produced water we recycled in the Delaware Basin as well as the volumes of both produced water and oil transported via pipeline, taking trucks off the roads. We also reduced the number of well pads built in 2019 through our use of batch drilling and longer laterals, reducing our surface footprint. Finally, we continued our commitment to a proactive safety culture, with over 1.4 million employee man-hours and no lost time accidents since 2017.
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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 2019, 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, 2019.
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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) | 231,300 | 128,200 | 757 | 354.0 | 5,287 | 2,332.4 | 232,793 | 39.0 | 55,599 | |||||||||||||||||
South Texas: | ||||||||||||||||||||||||||
Eagle Ford(5) | 31,200 | 28,400 | 143 | 121.4 | 234 | 196.3 | 11,219 | 65.5 | 4,009 | |||||||||||||||||
Northwest Louisiana | ||||||||||||||||||||||||||
Haynesville | 17,500 | 10,000 | 246 | 20.5 | 341 | 80.8 | 7,652 | 86.3 | 6,345 | |||||||||||||||||
Cotton Valley(6) | 16,100 | 14,900 | 66 | 40.7 | 70 | 48.3 | 866 | 100.0 | 250 | |||||||||||||||||
Area Total(7) | 19,700 | 18,300 | 312 | 61.2 | 411 | 129.1 | 8,518 | 87.7 | 6,595 | |||||||||||||||||
Total | 282,200 | 174,900 | 1,212 | 536.6 | 5,932 | 2,657.8 | 252,530 | 41.9 | 66,203 | |||||||||||||||||
(1) | Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2019. 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. Each horizontal drilling location generally represents a one-mile lateral, although we anticipate that many of our future wells will have lateral lengths longer than one mile. At December 31, 2019, these engineered drilling locations included only 372 gross (168.5 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, Delaware and Strawn formations, in the Delaware Basin, 14 gross (13.7 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford and five gross (0.5 net) locations to which we have assigned proved undeveloped reserves in the Haynesville shale. Certain of these locations to which we have assigned proved undeveloped reserves may contemplate lateral lengths longer than one mile. |
(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, Strawn and Avalon plays on our acreage in the Delaware Basin at December 31, 2019. |
(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. |
We are active both as an operator and as a co-working interest owner with various industry participants. At December 31, 2019, we operated the 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, 2019, we also were the operator for approximately 93% of our Eagle Ford acreage and approximately 59% of our Haynesville acreage, including approximately 26% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by Chesapeake.
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
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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 several intervals within the Wolfcamp shale, often identified as Wolfcamp A through D.
At December 31, 2019, our total acreage position in Southeast New Mexico and West Texas was approximately 231,300 gross (128,200 net) acres, primarily in Loving County, Texas and Lea and Eddy Counties, New Mexico. These acreage totals included approximately 36,400 gross (19,500 net) acres in our Ranger asset area in Lea County, 61,900 gross (26,300 net) acres in our Arrowhead asset area in Eddy County, 44,000 gross (25,000 net) acres in our Rustler Breaks asset area in Eddy County, 24,200 gross (16,500 net) acres in our Antelope Ridge asset area in Lea County, 15,000 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 46,400 gross (26,800 net) acres in our Twin Lakes asset area in Lea County at December 31, 2019. 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, 2019, our acreage position in the Delaware Basin was approximately 59% 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 BLM 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 73% held by existing production at December 31, 2019.
During the year ended December 31, 2019, we continued the delineation and development of our Delaware Basin acreage. We completed and began producing oil and natural gas from 138 gross (65.7 net) wells in the Delaware Basin, including 76 gross (61.4 net) operated wells and 62 gross (4.3 net) non-operated wells, throughout our various asset areas. At December 31, 2019, 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, 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.
As a result of our ongoing drilling and completion operations in these asset areas, our Delaware Basin production increased significantly in 2019. Our average daily oil equivalent production from the Delaware Basin increased approximately 23% 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, as compared to 45,237 BOE per day (87% of total oil equivalent production), including 28,026 Bbl of oil per day (92% of total oil production) and 103.3 MMcf of natural gas per day (80% of total natural gas production), in 2018. Our average daily oil equivalent production from the Delaware Basin also grew approximately 25% from 49,309 BOE per day in the fourth quarter of 2018 to 61,493 BOE per day in the fourth quarter of 2019.
At December 31, 2019, approximately 92% of our estimated total proved oil and natural gas reserves, or 232.8 million BOE, was attributable to the Delaware Basin, including approximately 139.6 million Bbl of oil and 559.2 Bcf of natural gas, a 22% increase, as compared to 191.5 million BOE for the year ended December 31, 2018. Our Delaware Basin proved reserves
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at December 31, 2019 comprised approximately 94% of our proved oil reserves and 89% of our proved natural gas reserves, as compared to approximately 93% of our proved oil reserves and 83% of our proved natural gas reserves at December 31, 2018.
At December 31, 2019, we had identified 5,287 gross (2,332.4 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 and the deeper Strawn formation. These locations include 3,290 gross (2,139.7 net) locations that we anticipate operating as we hold a working interest of at least 25% in each of these locations. Each horizontal drilling location generally represents a one-mile lateral, although we anticipate that many of our future wells will have lateral lengths longer than one mile. 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, 2019 do not yet include all portions of our acreage position and do not include any horizontal locations in our Twin Lakes asset area in Lea County, New Mexico. 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, 2019, 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, 2019, these potential future drilling locations included 372 gross (168.5 net) locations in the Delaware Basin, primarily in the Wolfcamp and Bone Spring plays, but also in the Brushy Canyon, Avalon, Delaware and Strawn formations, to which we have assigned proved undeveloped reserves, and certain of these locations to which we have assigned proved undeveloped reserves may contemplate lateral lengths longer than one mile.
At December 31, 2019, we were operating six drilling rigs in the Delaware Basin, and we expect to operate six rigs in the Delaware Basin throughout 2020, including two to four rigs (at times) in the Stateline asset area, one to two rigs (at times) in the Rustler Breaks asset area, one to two rigs (at times) in the Antelope Ridge asset area, one rig in the Wolf and Jackson Trust asset areas and one rig in the Greater Stebbins Area in the southern Arrowhead asset area. We have continued to build significant optionality into our drilling program. Three of our rigs operate on longer-term contracts with remaining average terms of approximately 19 months. The other three rigs are on short-term contracts with remaining obligations of less than twelve months. This affords us the ability to modify our drilling program as we may deem 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 2020.
Rustler Breaks Asset Area - Eddy County, New Mexico
We operated one to two drilling rigs in our Rustler Breaks asset area during most of 2019. We completed and turned to sales 48 gross (16.7 net) horizontal wells and one gross (1.0 net) vertical well in the Rustler Breaks asset area in 2019, including 19 gross (14.4 net) operated and 30 gross (3.3 net) non-operated wells.
The Garrett #111H well was particularly significant, being our first operated test of the First Bone Spring formation in the Rustler Breaks asset area. This well, a one-mile lateral, tested 2,042 BOE per day (75% oil) during a 24-hour IP test in the third quarter of 2019. A second operated test of the First Bone Spring in the fourth quarter of 2019, the Paul #111H, tested 1,793 BOE per day (81% oil) during a 24-hour IP test. We believe these two wells demonstrate the prospectivity of the First Bone Spring formation in the Rustler Breaks asset area.
We were also pleased with the results from our Wolfcamp wells turned to sales in 2019 in the Rustler Breaks asset area. In particular, the General Kehoe wells in the eastern portion of the asset area were drilled and completed as part of a five-well batch from a single pad and contributed significantly to our better-than-expected oil and natural gas production in the second half of 2019.
Wolf and Jackson Trust Asset Areas - Loving County, Texas
In the Wolf and Jackson Trust asset areas, we continued to focus primarily on the Wolfcamp A-XY and Wolfcamp A-Lower formations in 2019. We operated one drilling rig in our Wolf and Jackson Trust asset areas during 2019, and we completed and turned to sales 11 gross (7.8 net) horizontal wells in these asset areas, including ten gross (7.8 net) operated wells and one gross (less than 0.1 net) non-operated well. Most of these wells were completed in the Wolfcamp A-XY interval.
We continued to experience success with longer laterals (greater than one mile) we drilled in the Wolf asset area in 2019. For example, the Howard Posner 83-TTT-B33 WF #203H and #204H (Howard Posner #203H and #204H) wells, both Wolfcamp A-XY completions, tested 2,382 BOE per day (58% oil) and 1,813 BOE per day (60% oil), respectively, during 24-hour IP tests. Both the Howard Posner #203H and #204H wells had completed lateral lengths of approximately 7,500 feet.
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Arrowhead, Ranger and Twin Lakes Asset Areas - Eddy and Lea Counties, New Mexico
We operated one drilling rig in our Arrowhead, Ranger and Twin Lakes asset areas during 2019. We completed and turned to sales 20 gross (11.3 net) horizontal wells and two gross (2.0 net) vertical wells in the Arrowhead, Ranger and Twin Lakes asset areas in 2019, including 17 gross (13.0 net) operated and five gross (0.3 net) non-operated wells. Most of these wells were completed in the Second Bone Spring and Third Bone Spring intervals.
Following our initial test of the Wolfcamp A-XY in the third quarter of 2018, we were pleased with our continued delineation of the Wolfcamp A-XY in the Arrowhead asset area in 2019. In the third quarter of 2019, we completed and placed on production the Stebbins 19 Federal Com #203H and #204H wells. These wells tested 2,815 BOE per day (73% oil) and 2,262 BOE per day (75% oil), respectively, during 24-hour IP tests. We believe these results provided further evidence of Wolfcamp A-XY prospectivity moving north in the Delaware Basin.
Antelope Ridge Asset Area - Lea County, New Mexico
We operated one to two drilling rigs in our Antelope Ridge asset area during 2019. We completed and turned to sales 55 gross (25.9 net) horizontal wells and one gross (1.0 net) vertical well in this asset area in 2019, including 30 gross (26.2 net) operated and 26 gross (0.7 net) non-operated wells. As we continued to delineate the Antelope Ridge asset area during 2019, we tested six different intervals, completing wells in the Brushy Canyon, First, Second and Third Bone Spring, Wolfcamp A-XY and Wolfcamp A-Lower.
A key achievement in our Antelope Ridge asset area in 2019 was the drilling and completion of our first two operated two-mile horizontal wells in the asset area—the Jeff Hart #124H and #134H wells, Second Bone Spring and Third Bone Spring completions, respectively. The Jeff Hart #124H and #134H wells tested 2,332 BOE per day (81% oil) and 2,884 BOE per day (90% oil), respectively, during 24-hour IP tests in the third quarter of 2019. The Jeff Hart #134H well produced approximately 70,000 Bbl of oil in its first 30 days of production, which is the highest 30-day cumulative oil production for any well drilled and completed by us, including our prolific Mallon wells in the Ranger asset area, also Third Bone Spring completions. Further, drilling and completion costs on the Jeff Hart #134H well were just under $1,000 per lateral foot, about 20% to 25% below the drilling and completion costs per lateral foot associated with one-mile laterals we previously drilled in the Antelope Ridge asset area. In their first five months of production, the Jeff Hart #124H and #134H wells each produced more than 200,000 Bbl of oil in its first 150 days of production. The early production from these wells has more than doubled that of our nearby one-mile lateral completions over a similar timeframe, and these wells continued to exhibit a shallower initial production decline as compared to nearby one-mile laterals drilled by us.
In addition, we were particularly pleased with our delineation of the Wolfcamp A formation in the Antelope Ridge asset area. The Brad Lummis Com #212H well, a Wolfcamp A-XY completion, flowed at 3,236 BOE per day (83% oil) during its 24-hour IP test, or over 700 BOE per 1,000 feet of completed lateral. This well result complemented those from the four Charles Ling wells completed and turned to sales in the Wolfcamp A-Lower formation late in the first quarter of 2019, which flowed at an average of 2,932 BOE per day (75% oil) during their respective 24-hour IP tests.
Additionally, we began drilling operations on the 1,200 gross and net acre Rodney Robinson tract in our western Antelope Ridge asset area in the third quarter of 2019. The Rodney Robinson tract is one of the key tracts we acquired in the BLM Acquisition. The acquired leases are federal leases and provide an 87.5% net revenue interest (“NRI”) as compared to approximately 75% NRI on most fee leases today. We drilled six initial wells on this tract from two separate three-well pads. These six wells, which are all two-mile laterals, are currently scheduled to be completed and turned to sales in late March 2020.
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Stateline Asset Area - Eddy County, New Mexico
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 undeveloped leasehold acres prospective for multiple geologic targets. The acquired leases are federal leases and provide an 87.5% NRI. The large majority of the acquired 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 began drilling operations in the Stateline asset area just before the end of 2019 and, at February 25, 2020, had two of our drilling rigs operating there. 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 initially expect to drill 13 wells on the eastern portion of this leasehold, and these 13 wells are expected to be completed and turned to sales late in third quarter of 2020 in conjunction with the expected completion of the expansion of the Black River Processing Plant by San Mateo. We anticipate running at least two rigs full-time in the Stateline asset area for the foreseeable future.
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, 2019, our properties included approximately 31,200 gross (28,400 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% 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 93% of our Eagle Ford acreage was held by production at December 31, 2019.
In October 2018, we commenced a drilling program in South Texas to drill nine wells, primarily in the Eagle Ford shale, to take advantage of higher oil and natural gas prices in South Texas, to conduct at least one exploratory test of the Austin Chalk formation and to validate and hold by production almost all of our remaining undeveloped acreage in South Texas. One of the Eagle Ford shale wells was completed and turned to sales during the fourth quarter of 2018, and the remaining eight gross (7.9 net) wells, including one well drilled in the Austin Chalk formation, were completed and turned to sales in the first half of 2019.
Two of these wells, the Lloyd Hurt C #12H and D #13H wells, which targeted the Eagle Ford shale, flowed an average of 1,085 BOE per day (85% oil), including 923 Bbl of oil per day and 1.0 MMcf of natural gas per day, during 24-hour IP tests from completed lateral lengths of approximately 8,800 feet. These wells marked the two best 24-hour IP test results from any Eagle Ford wells we have completed to date in our far northwest La Salle County acreage. In addition, the Lloyd Hurt AC-C #26H well, an Austin Chalk completion, tested approximately 600 BOE per day (93% oil) during a 24-hour IP test conducted following the installation of an electric submersible pump (“ESP”) in the wellbore. We were encouraged by this initial test and the early results from the Austin Chalk formation in far northwest La Salle County, where almost no horizontal completions of the Austin Chalk formation using modern drilling and stimulation technology had been previously attempted.
Primarily as a result of the initial production from this nine-well program, our average daily oil equivalent production from the Eagle Ford shale increased 27% 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, as compared to 3,158 BOE per day, including 2,485 Bbl of oil per day and 4.0 MMcf of natural gas per day, during 2018. For the year ended December 31, 2019, 6% of our total daily oil equivalent production was attributable to the Eagle Ford shale, as compared to 6% for the year ended December 31, 2018.
At December 31, 2019, approximately 4% of our estimated total proved oil and natural gas reserves, or 11.2 million BOE, was attributable to the Eagle Ford shale, including approximately 8.4 million Bbl of oil and 17.2 Bcf of natural gas. Our Eagle Ford total proved reserves comprised approximately 6% of our proved oil reserves and 3% of our proved natural gas reserves at December 31, 2019, as compared to approximately 7% of our proved oil reserves and 4% of our proved natural gas reserves at December 31, 2018.
At December 31, 2019, we had identified 234 gross (196.3 net) engineered locations for potential future drilling on our Eagle Ford acreage. 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
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regulatory authorities and surface considerations, among other factors. The identified well locations presume that we will be able to develop our Eagle Ford properties on 40- to 80-acre spacing, depending on the specific property and the wells we have already drilled. We anticipate that any Eagle Ford wells drilled on our acreage in central and northern La Salle, northern Karnes and southern Wilson Counties can be developed on 40- to 50-acre spacing, while other properties, particularly the eastern portion of our acreage in DeWitt County, are more likely to be developed on 80-acre spacing. At December 31, 2019, these 234 gross (196.3 net) identified drilling locations included 14 gross (13.7 net) locations to which we have assigned proved undeveloped reserves.
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 Eagle Ford 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, 2019, 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 potential 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%.
We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana during 2019, although we did participate in the drilling and completion of 26 gross (1.7 net) non-operated Haynesville shale wells that were turned to sales in 2019, the most significant of which were two gross (1.0 net) two-mile lateral wells drilled and completed by Chesapeake in the third quarter of 2019. These two wells, the LDW&F 15&10-14-12 HC001-ALT and HC002-ALT wells, were located in the southern part of our Elm Grove asset area in the core of the Haynesville shale play and tested 38.4 and 42.4 MMcf of natural gas per day, respectively, during 24-hour IP tests, and these wells contributed to our natural gas production growth in the second half of 2019. We do not plan to drill any operated Haynesville shale or Cotton Valley wells in 2020.
At December 31, 2019, we held approximately 19,700 gross (18,300 net) acres in Northwest Louisiana, including 17,500 gross (10,000 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 26% of the 12,400 gross (5,600 net) acres that we consider to be in the core area of the Haynesville shale play.
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 leasehold interests in Northwest Louisiana. Natural gas production from these properties comprised approximately 24% of our daily natural gas production during 2019, as compared to approximately 17% of our daily natural gas production during 2018. During the year ended December 31, 2018, approximately 7% of our average daily oil equivalent production, or 3,733 BOE per day, including 13 Bbl of oil per day and 22.3 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas.
For the year ended December 31, 2019, approximately 23% of our daily natural gas production, or 38.1 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 1%, or 1.4 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2018, approximately 16% of our daily natural gas production, or 20.5 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 1%, or 1.8 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. At December 31, 2019, approximately 3% of our estimated total proved reserves, or 7.7 million BOE, was attributable to the Haynesville shale with another 0.3% of our proved reserves, or 0.9 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage.
At December 31, 2019, we had identified 341 gross (80.8 net) engineered locations for potential future drilling in the Haynesville shale play and 70 gross (48.3 net) engineered locations for potential future drilling in the Cotton Valley formation. Each horizontal drilling location generally assumes a one-mile lateral, although we anticipate that many of our future wells may have lateral lengths longer than one mile. These locations have been identified on a property-by-property basis and take into
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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 criteria. Of the 341 gross (80.8 net) locations identified for future drilling on our Haynesville acreage, 277 gross (37.8 net) locations have been identified within the 12,400 gross (5,600 net) acres that we believe are located in the core area of the Haynesville shale play. As we explore and develop our Northwest Louisiana acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2019, these potential future drilling locations included 5 gross (0.5 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves.
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 salt water gathering services and salt 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 a subsidiary of Five Point. The midstream assets that were contributed to San Mateo I included (i) the Black River Processing Plant; (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 salt 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. At February 28, 2020, we had received $44.1 million of the potential $73.5 million in performance incentives. We may earn up to the remaining $29.4 million in San Mateo I performance incentives over the next two years. We continue to operate the Delaware Midstream Assets and retain operational control of San Mateo I. The Company and Five Point own 51% and 49% of San Mateo I, respectively. San Mateo I continues to provide firm service to us, while also being a midstream service provider to other customers in and around our Wolf and Rustler Breaks asset areas.
On February 25, 2019, we announced the formation of San Mateo II, a strategic joint venture with a subsidiary of Five Point designed to expand our midstream operations in the Delaware Basin, specifically in Eddy County, New Mexico. San Mateo II is owned 51% by us and 49% by Five Point. In addition, Five Point has 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. 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.
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 agreements for oil, natural gas and salt water gathering, natural gas processing and salt water disposal. San Mateo II provides firm service to us 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 2019, as part of the San Mateo II expansion, San Mateo began expanding the Black River Processing Plant in our Rustler Breaks asset area in Eddy County, New Mexico 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. This expansion is anticipated to be placed in service during the summer of 2020. In addition, San Mateo initiated plans in 2019 to construct large diameter natural gas gathering lines southward from the Greater Stebbins Area and northward from the Stateline asset area to connect these areas with the Black River Processing Plant. The expanded Black River Processing Plant supports our exploration and production development activities in the Delaware Basin and offers processing opportunities for other producers’ development efforts.
During 2019, San Mateo received an increased natural gas gathering and processing commitment from an existing natural gas customer, plus other interruptible volumes. At certain times near the end of the third quarter and early in the fourth quarter
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of 2019, as a result of increased throughput from existing natural gas processing customers, San Mateo was operating the Black River Processing Plant at greater than 95% of the current designed inlet capacity of 260 MMcf per day.
In October 2018, a subsidiary of San Mateo entered into a long-term agreement with a significant producer in Eddy County, New Mexico relating to the gathering and processing of such producer’s natural gas production. As a result of this agreement, along with prior natural gas gathering and processing agreements entered into by San Mateo with its customers, including us, at December 31, 2019, San Mateo had entered into contracts to provide firm gathering and processing services for over 200 MMcf of natural gas per day, or over 80% of the designed inlet capacity of 260 MMcf of natural gas per day, at the Black River Processing Plant.
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 and (iv) increased optionality through San Mateo’s ability to operate the Black River Processing Plant in ethane recovery mode, if desired.
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 (the “Loving County Processing System”) to an affiliate of EnLink Midstream Partners, LP (“EnLink”) in October 2015. The Loving County Processing System included a cryogenic natural gas processing plant (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline that connected our gathering system to the Wolf Processing Plant. Substantially all of our remaining midstream assets in the Wolf asset area were contributed to San Mateo I in February 2017.
At December 31, 2019, San Mateo’s natural gas gathering systems included natural gas gathering pipelines and related compression and treating systems. During the year ended December 31, 2019, San Mateo gathered approximately 77.2 Bcf of natural gas, as compared to 46.1 Bcf of natural gas gathered during the year ended December 31, 2018. In addition, during the year ended December 31, 2019, San Mateo processed approximately 64.7 Bcf of natural gas at the Black River Processing Plant, as compared to 32.3 Bcf of natural gas processed during the year ended December 31, 2018.
Crude Oil Gathering and Transportation Assets
Subsidiaries of San Mateo and Plains All American Pipeline, L.P. (“Plains”) have entered into a strategic relationship to gather and transport crude oil for upstream producers in Eddy County, New Mexico and have agreed to work together through a joint tariff arrangement and related transactions to offer producers located within the Joint Development Area crude oil transportation services from the wellhead to Midland, Texas with access to other end markets.
San Mateo completed its expanded oil gathering system in the Wolf asset area in Loving County, Texas (the “Wolf Oil Pipeline System”) in May 2018 and 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”) in December 2018. With the Wolf Oil Pipeline System and the Rustler Breaks Oil Pipeline System (collectively, the “San Mateo Oil Pipeline Systems”) in service, at December 31, 2019, we estimated we had on pipe almost all of our oil production from the Wolf and Rustler Breaks asset areas, which comprised approximately 56% of our Delaware Basin oil production in 2019. With the San Mateo Oil Pipeline Systems in service, we improved our oil price realizations in the Wolf and Rustler Breaks asset areas through the elimination of higher priced trucking services.
At December 31, 2019, the San Mateo Oil Pipeline Systems included crude oil gathering and transportation pipelines from origin points in Loving County, Texas and Eddy County, New Mexico to interconnects with Plains Pipeline, L.P. and two trucking facilities. During the year ended December 31, 2019, the San Mateo Oil Pipeline Systems had throughput of approximately 8.9 million Bbl of oil, as compared to 2.0 million Bbl of oil throughput during the year ended December 31, 2018.
Produced Water Gathering and Disposal Assets
During 2019, San Mateo placed into service two commercial salt water disposal wells in the Rustler Breaks asset area and, at February 25, 2020, expected to place into service one additional salt water disposal well in the Rustler Breaks asset area late in the first quarter of 2020, bringing San Mateo’s commercial salt water disposal well count in the Rustler Breaks asset area to eight. In the Greater Stebbins Area, San Mateo also acquired an existing commercial salt water disposal well and facility and surface acreage and subsequently placed into service an additional commercial salt water disposal well. In addition to its eight commercial salt water disposal wells and associated facilities in the Rustler Breaks asset area and its two commercial salt water disposal wells and associated facilities in the Greater Stebbins Area, at February 25, 2020, San Mateo had three commercial salt water disposal wells and associated facilities in the Wolf asset area, and San Mateo’s salt water gathering systems included salt
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water gathering pipelines in the Rustler Breaks and Wolf asset areas and the Greater Stebbins Area. At February 25, 2020, San Mateo expected to have a designed disposal capacity of approximately 335,000 Bbl of salt water per day by the end of the first quarter of 2020.
In June 2018, a subsidiary of San Mateo entered into a long-term agreement with a significant producer in Eddy County, New Mexico to gather and dispose of the customer’s produced salt water. The agreement includes the dedication of certain of the third party’s wells, which are or will be located near San Mateo’s existing salt water gathering system in Eddy County, New Mexico. In the first half of 2019, San Mateo obtained a significant additional acreage dedication and a salt water disposal well permit from another existing salt water disposal customer.
During the year ended December 31, 2019, San Mateo gathered approximately 69.9 million Bbl of salt water, as compared to 44.0 million Bbl of salt water gathered during the year ended December 31, 2018. In addition, during the year ended December 31, 2019, San Mateo disposed of approximately 67.1 million Bbl of salt water, as compared to 47.5 million Bbl of salt water disposed of during the year ended December 31, 2018.
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 and treat natural gas from most of our operated leases and from third parties and four non-commercial salt water disposal wells that dispose of our salt water. 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, 2019, 2018 and 2017.
__________________
Year Ended December 31, | ||||||||||||
2019 | 2018 | 2017 | ||||||||||
Unaudited Production Data: | ||||||||||||
Net Production Volumes: | ||||||||||||
Oil (MBbl) | 13,984 | 11,141 | 7,851 | |||||||||
Natural gas (Bcf) | 61.1 | 47.3 | 38.2 | |||||||||
Total oil equivalent (MBOE)(1) | 24,164 | 19,026 | 14,212 | |||||||||
Average daily production (BOE/d)(1) | 66,203 | 52,128 | 38,936 | |||||||||
Average Sales Prices: | ||||||||||||
Oil, without realized derivatives (per Bbl) | $ | 54.34 | $ | 57.04 | $ | 49.28 | ||||||
Oil, with realized derivatives (per Bbl) | $ | 54.98 | $ | 57.38 | $ | 48.81 | ||||||
Natural gas, without realized derivatives (per Mcf) | $ | 2.17 | $ | 3.49 | $ | 3.72 | ||||||
Natural gas, with realized derivatives (per Mcf) | $ | 2.18 | $ | 3.46 | $ | 3.70 | ||||||
Operating Expenses (per BOE): | ||||||||||||
Production taxes, transportation and processing | $ | 3.82 | $ | 4.00 | $ | 4.10 | ||||||
Lease operating | $ | 4.85 | $ | 4.89 | $ | 4.74 | ||||||
Plant and other midstream services operating | $ | 1.52 | $ | 1.29 | $ | 0.92 | ||||||
Depletion, depreciation and amortization | $ | 14.51 | $ | 13.94 | $ | 12.49 | ||||||
General and administrative | $ | 3.31 | $ | 3.64 | $ | 4.65 | ||||||
(1) | Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. |
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The following table sets forth 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.
__________________
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. |
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The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 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. |
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The following table sets forth information regarding our production volumes, sales prices and production costs for the year ended December 31, 2017 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) | 6,579 | 1,268 | — | 4 | 7,851 | |||||||||||||||
Natural gas (Bcf) | 25.1 | 2.0 | 10.3 | 0.8 | 38.2 | |||||||||||||||
Total oil equivalent (MBOE)(3) | 10,754 | 1,611 | 1,714 | 133 | 14,212 | |||||||||||||||
Percentage of total annual net production | 75.7 | % | 11.3 | % | 12.1 | % | 0.9 | % | 100.0 | % | ||||||||||
Average Net Daily Production Volumes | ||||||||||||||||||||
Oil (Bbl/d) | 18,023 | 3,475 | — | 12 | 21,510 | |||||||||||||||
Natural gas (MMcf/d) | 68.6 | 5.6 | 28.3 | 2.1 | 104.6 | |||||||||||||||
Total oil equivalent (BOE/d) | 29,463 | 4,413 | 4,697 | 363 | 38,936 | |||||||||||||||
Average Sales Prices(4) | ||||||||||||||||||||
Oil (per Bbl) | $ | 49.08 | $ | 50.29 | $ | — | $ | 45.52 | $ | 49.28 | ||||||||||
Natural gas (per Mcf) | $ | 4.03 | $ | 4.69 | $ | 2.83 | $ | 2.79 | $ | 3.72 | ||||||||||
Total oil equivalent (per BOE) | $ | 39.41 | $ | 45.58 | $ | 16.96 | $ | 17.69 | $ | 37.20 | ||||||||||
Production Costs(5) | ||||||||||||||||||||
Lease operating, transportation and processing (per BOE) | $ | 5.80 | $ | 10.92 | $ | 4.21 | $ | 16.77 | $ | 6.29 | ||||||||||
(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 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.
Our total oil equivalent production of approximately 19.0 million BOE for the year ended December 31, 2018 increased 34% from our total oil equivalent production of approximately 14.2 million BOE for the year ended December 31, 2017. This increased production was primarily due to our delineation and development operations in the Delaware Basin, which offset declining production in the Eagle Ford and Haynesville shales. Our average daily oil equivalent production for the year ended December 31, 2018 was 52,128 BOE per day, as compared to 38,936 BOE per day for the year ended December 31, 2017. Our average daily oil production for the year ended December 31, 2018 was 30,524 Bbl of oil per day, an increase of 42% from 21,510 Bbl of oil per day for the year ended December 31, 2017. Our average daily natural gas production for the year ended December 31, 2018 was 129.6 MMcf of natural gas per day, an increase of 24% from 104.6 MMcf of natural gas per day for the year ended December 31, 2017.
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Producing Wells
The following table sets forth information relating to producing wells at December 31, 2019. Wells are classified as oil wells or natural gas wells according to their predominant production stream. We had an approximate average working interest of 78% in all wells that we operated at December 31, 2019. 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) | 634 | 298.6 | 123 | 55.4 | 757 | 354.0 | ||||||||||||
South Texas: | ||||||||||||||||||
Eagle Ford(2) | 139 | 117.4 | 4 | 4.0 | 143 | 121.4 | ||||||||||||
Northwest Louisiana: | ||||||||||||||||||
Haynesville | — | — | 246 | 20.5 | 246 | 20.5 | ||||||||||||
Cotton Valley(3) | 1 | 1.0 | 65 | 39.7 | 66 | 40.7 | ||||||||||||
Area Total | 1 | 1.0 | 311 | 60.2 | 312 | 61.2 | ||||||||||||
Total | 774 | 417.0 | 438 | 119.6 | 1,212 | 536.6 | ||||||||||||
(1) | Includes 218 gross (56.5 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, 2019, 2018 and 2017. 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.
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At December 31,(1) | ||||||||||||
2019 | 2018 | 2017 | ||||||||||
Estimated Proved Reserves Data:(2) | ||||||||||||
Estimated proved reserves: | ||||||||||||
Oil (MBbl) | 147,991 | 123,401 | 86,743 | |||||||||
Natural Gas (Bcf) | 627.2 | 551.5 | 396.2 | |||||||||
Total (MBOE)(3) | 252,531 | 215,313 | 152,771 | |||||||||
Estimated proved developed reserves: | ||||||||||||
Oil (MBbl) | 59,667 | 53,223 | 36,966 | |||||||||
Natural Gas (Bcf) | 276.3 | 246.2 | 190.1 | |||||||||
Total (MBOE)(3) | 105,710 | 94,261 | 68,651 | |||||||||
Percent developed | 41.9 | % | 43.8 | % | 44.9 | % | ||||||
Estimated proved undeveloped reserves: | ||||||||||||
Oil (MBbl) | 88,324 | 70,178 | 49,777 | |||||||||
Natural gas (Bcf) | 351.0 | 305.2 | 206.1 | |||||||||
Total (MBOE)(3) | 146,821 | 121,052 | 84,120 | |||||||||
Standardized Measure(4) (in millions) | $ | 2,034.0 | $ | 2,250.6 | $ | 1,258.6 | ||||||
PV-10(5) (in millions) | $ | 2,248.2 | $ | 2,579.3 | $ | 1,333.4 | ||||||
(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, 2019 were $52.19 per Bbl for oil and $2.58 per MMBtu for natural gas, for the 12 months ended December 31, 2018 were $62.04 per Bbl for oil and $3.10 per MMBtu for natural gas and for the 12 months ended December 31, 2017 were $47.79 per Bbl for oil and $2.98 per MMBtu for natural gas. These prices were adjusted by lease 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 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. |
(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, 2019, 2018 and 2017 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, 2019, 2018 and 2017 were, in millions, $214.2, $328.7 and $74.8, respectively. |
Our estimated total proved oil and natural gas reserves increased 17% from 215.3 million BOE at December 31, 2018 to 252.5 million BOE at December 31, 2019. We added 58.6 million BOE in proved oil and natural gas reserves through extensions and discoveries throughout 2019, approximately 2.4 times our 2019 annual production of 24.2 million BOE. Our proved oil reserves grew 20% from approximately 123.4 million Bbl at December 31, 2018 to approximately 148.0 million Bbl at December 31, 2019. Our proved natural gas reserves increased 14% from 551.5 Bcf at December 31, 2018 to 627.2 Bcf at December 31, 2019. This increase in proved oil and natural gas reserves was primarily a result of our delineation and development operations in the Delaware Basin during 2019. We realized approximately 5.1 million BOE in net upward revisions to our proved reserves during 2019 primarily as a result of upward technical revisions resulting from better-than-projected well performance from certain wells, as compared to December 31, 2018, and despite lower commodity prices used to estimate proved reserves at December 31, 2019. Our proved reserves to production ratio at December 31, 2019 was 10.5, a decrease of 7% from 11.3 at December 31, 2018.
Over the past two years, our estimated total proved oil and natural gas reserves increased 65% from 152.8 million BOE at December 31, 2017 to 252.5 million Bbl at December 31, 2019. Our proved oil reserves grew 71% from 86.7 million Bbl at December 31, 2017 to 148.0 million Bbl at December 31, 2019. Our proved developed oil reserves increased 61% from 37.0 million Bbl at December 31, 2017 to 59.7 million Bbl at December 31, 2019.
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The Standardized Measure of our total proved oil and natural gas reserves decreased 10% from $2.25 billion at December 31, 2018 to $2.03 billion at December 31, 2019. The PV-10 of our total proved oil and natural gas reserves decreased 13% from $2.58 billion at December 31, 2018 to $2.25 billion at December 31, 2019. The decreases in our Standardized Measure and PV-10 are primarily a result of lower weighted average oil and natural gas prices used to estimate proved reserves at December 31, 2019, as compared to December 31, 2018. The unweighted arithmetic averages of first-day-of-the-month oil and natural gas prices used to estimate proved reserves at December 31, 2019 were $52.19 per Bbl and $2.58 per MMBtu, a decrease of 16% and 17%, respectively, as compared to average oil and natural gas prices of $62.04 per Bbl and $3.10 per MMBtu used to estimate proved reserves at December 31, 2018. Our total proved reserves were made up of 59% oil and 41% natural gas at December 31, 2019, as compared to 57% oil and 43% natural gas at December 31, 2018. 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 12% from 94.3 million BOE at December 31, 2018 to 105.7 million BOE at December 31, 2019 due primarily to our delineation and development operations in the Delaware Basin. Our proved developed oil reserves increased 12% from 53.2 million Bbl at December 31, 2018 to 59.7 million Bbl at December 31, 2019. Our proved developed natural gas reserves increased 12% from 246.2 Bcf at December 31, 2018 to 276.3 Bcf at December 31, 2019.
The following table summarizes changes in our estimated proved developed reserves at December 31, 2019.
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Proved Developed Reserves | |||
(MBOE)(1) | |||
As of December 31, 2018 | 94,261 | ||
Extensions and discoveries | 14,206 | ||
Net divestitures of minerals-in-place | (736 | ) | |
Revisions of prior estimates | (1,486 | ) | |
Production | (24,164 | ) | |
Conversion of proved undeveloped to proved developed | 23,629 | ||
As of December 31, 2019 | 105,710 | ||
(1) | Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. |
Our proved undeveloped oil and natural gas reserves increased 21% from 121.1 million BOE at December 31, 2018 to 146.8 million BOE at December 31, 2019. Our proved undeveloped oil and natural gas reserves increased from 70.2 million Bbl and 305.2 Bcf, respectively, at December 31, 2018 to 88.3 million Bbl and 351.0 Bcf, respectively, at December 31, 2019, primarily as a result of our delineation and development operations in the Delaware Basin.
At December 31, 2019, 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, 2019 within five years of booking these reserves.
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The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2019.
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Proved Undeveloped Reserves | |||
(MBOE)(1) | |||
As of December 31, 2018 | 121,052 | ||
Extensions and discoveries | 44,410 | ||
Net divestitures of minerals-in-place | (1,571 | ) | |
Revisions of prior estimates | 6,559 | ||
Conversion of proved undeveloped to proved developed | (23,629 | ) | |
As of December 31, 2019 | 146,821 | ||
(1) | Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. |
The following table sets forth, since 2016, 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) | |||||||||||
2016 | 4,705 | 13.1 | 6,883 | $ | 94,579 | ||||||||
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 | |||||||||
Total | 43,846 | 178.6 | 73,603 | $ | 981,878 | ||||||||
(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, 2019.
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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 | 139,595 | 559.2 | 232,793 | $ | 1,877.1 | $ | 2,074.8 | ||||||||||
South Texas: | |||||||||||||||||
Eagle Ford(5) | 8,350 | 17.2 | 11,219 | 123.6 | 136.6 | ||||||||||||
Northwest Louisiana | |||||||||||||||||
Haynesville | — | 45.9 | 7,652 | 31.0 | 34.3 | ||||||||||||
Cotton Valley(6) | 46 | 4.9 | 867 | 2.3 | 2.5 | ||||||||||||
Area Total | 46 | 50.8 | 8,519 | 33.3 | 36.8 | ||||||||||||
Total | 147,991 | 627.2 | 252,531 | $ | 2,034.0 | $ | 2,248.2 | ||||||||||
(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, 2019 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by adding the discounted future income taxes |
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associated with such reserves to the Standardized Measure. The discounted future income taxes at December 31, 2019 were approximately $214.2 million.
(4) | Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. |
(5) | Includes one well producing oil from the Austin Chalk formation in La Salle County, Texas 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. Our Executive Vice President of Reservoir Engineering and Chief Technology Officer is 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 42 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, 2019.
Developed Acres | Undeveloped Acres | Total Acres | ||||||||||||||||
Gross | Net | Gross | Net | Gross | ||||||||||||||