Item 2. Properties
Item 2: Properties
General Background
Ring is engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas.
Management’s Business Strategy Related to Properties
Our goal is to increase stockholder value by investing in oil and natural gas projects with attractive rates of return on capital employed. We plan to achieve this goal by developing our existing oil and natural gas properties and pursuing strategic acquisitions of additional properties.
Developing Existing Properties
We believe that there is significant value to be created by drilling the undeveloped opportunities on our properties. As of December 31, 2022, we owned interests in a total of 101,773 gross (87,326 net) developed acres and operate the vast majority of our acreage position. In addition, as of December 31, 2022, we owned interests in approximately 22,444 gross (14,849 net) undeveloped acres. While our near-term plans are focused on drilling wells on our existing acreage to develop the potential contained therein, our long-term plans also include continuing to evaluate acquisition and leasing opportunities that can earn attractive rates of return on capital employed. Within the Northwest Shelf, we have a total of 73 proved undeveloped locations (85% horizontal and 15% vertical) and 19 PDNP opportunities based on the reserve report as of December 31, 2022. Our reserve estimates account for the capital costs required to develop these wells. We believe the Northwest Shelf leases contain additional potential drilling locations. Within the Central Basin Platform, we have a total of 141 proved undeveloped locations (21% horizontal and 79% vertical) and 205 PDNP opportunities based on the reserve report as of December 31, 2022. Our reserve estimates account for the capital costs required to develop these wells. We believe the Central Basin Platform leases contain additional potential drilling locations.
Pursuing Profitable Acquisitions
We have historically pursued acquisitions of properties that we believe to have exploitation and development potential comparable to our existing inventory of drilling locations. We have an experienced team of management, engineering, geoscience, and land professionals who identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties.
Summary of Oil and Natural Gas Properties and Projects
Significant Operations
The Company's significant operations are in two core areas which it has actively drilled over the last several years located in the Northwest Shelf and the Central Basin Platform of the Permian Basin.
Northwest Shelf –Yoakum, Runnels and Coke County, Texas and Lea County, New Mexico – In 2019, we acquired properties consisting of 49,754 gross (38,230 net) acres with an average working interest of 77% and an average net revenue interest of 58%. As of December 31, 2022, we owned interests in a total of 18,270 gross (13,930 net) developed acres and 18,539 gross (12,512 net) undeveloped acres. As of December 31, 2022, the Company had interests in approximately 27 gross vertical and 139 horizontal producing wells, of which we operate 27 vertical and 108 horizontal wells. The horizontal wells predominately produce from the San Andres conventional reservoir and the verticals produce from Wolfcamp and Devonian reservoirs.
33
Table of Contents
Central Basin Platform - Andrews, Gaines, Crane, Winkler, and Ward Counties, Texas leases – In 2011, we acquired a 100% working interest and a 75% net revenue interest in our initial leases in Andrews and Gaines counties. Since that time, we have acquired working and net revenue interests in additional producing leases and acquired additional undeveloped acreage in and around our Andrews County and Gaines County leases. In 2022, we acquired properties consisting of approximately 37,000 net acres, with an average working interest of 99% and an average net revenue interest of 88% for oil and 96% for natural gas in our initial leases in Crane, Winkler, and Ward counties. As of December 31, 2022, we owned interests in a total of 64,774 gross (54,959 net) developed acres and 3,905 gross (2,337 net) undeveloped acres. As of December 31, 2022, the Company had interests in approximately 625 gross vertical and 195 horizontal producing wells, of which we operate 518 vertical and 193 horizontal wells. The horizontal wells predominately produce from the San Andres conventional reservoir and the verticals produce from a variety of conventional pay sands including Holt, Glorieta, Clear Fork, Wichita Albany, Tubb, Wolfcamp and Devonian reservoirs .
Title to Properties
We generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests. Prior to commencement of operations on such acreage, a thorough title examination is usually conducted and any significant defects are remedied before proceeding with operations. We believe the title to our leasehold properties is good, defensible and customary with practices in the oil and natural gas industry, subject to such exceptions that we believe do not materially detract from the use of such properties. With respect to our properties of which we are not the record owner, we rely on contracts with the owner or operator of the property or assignment of leases, pursuant to which, among other things, we generally have the right to have our interest placed on record.
Our properties are generally subject to royalty, overriding royalty and other interests customary in the industry, liens incident to lending agreements, current taxes and other customary burdens, minor encumbrances, easements and restrictions. We do not believe any of these burdens will materially interfere with our use of these properties.
Summary of Oil and Natural Gas Reserves
As of December 31, 2022, our estimated proved reserves had a pre-tax PV-10 value (present value discounted at 10%) of approximately $2,773.7 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $2,272.1 million, 100% of which relates to our properties in the Permian Basin in Texas and New Mexico. We spent approximately $360.1 million on acquisitions and capital projects during 2022 and 2021. We expect to further develop these properties through additional drilling.
The following table summarizes our total net proved reserves, pre-tax PV-10 value and Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2022. All of our reserves are in the Permian Basin in Texas and New Mexico.
Oil
(Bbl) Natural
Gas (Mcf) Natural
Gas Liquids (Bbl) Total
(Boe) (1)
Pre-Tax PV-10
Value (2)
Standardized
Measure of
Discounted Future
Net Cash Flows
88,704,743 157,870,449 23,105,658 138,122,143 $ 2,773,656,500 $ 2,272,113,518
_____________________________
(1) Six Mcf is deemed the equivalent of one Boe.
(2) PV-10 is a non-GAAP financial measure. See below for a reconciliation.
We present the pre-tax PV-10 value, which is a non-GAAP financial measure, because it is a widely used industry standard which we believe is useful to those who may review this Report when comparing our asset base and performance to other comparable oil and natural gas exploration and production companies. PV-10 is a non-GAAP measure that differs from a measure under accounting principles generally accepted in the United States ("GAAP") known as “standardized measure of discounted future net cash flows” in that PV-10 is calculated without including future income taxes. PV-10 does not necessarily represent the fair market value of oil and natural gas properties. PV-10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
34
Table of Contents
The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows ( in thousands ):
Present value of estimated future net revenues (PV-10) $ 2,773,657
Future income taxes, discounted at 10% $ 501,543
Standardized measure of discounted future net cash flows $ 2,272,114
Reserve Quantity Information
Our estimates of proved reserves and related valuations are based on reports independently determined and prepared by Cawley, Gillespie & Associates, Inc. ("CGA"), independent petroleum engineers. These reserves are attributable solely to properties within the United States. A summary of the changes in quantities of proved (developed and undeveloped) oil, natural gas and natural gas liquid reserves is shown below.
Oil (Bbl) Gas (Mcf) Natural Gas Liquids (Bbl) (2)
Boe (1)
Balance, December 31, 2020 66,264,286 61,305,027 — 76,481,791
Purchase of minerals in place 2,180,497 824,512 — 2,317,916
Extensions, discoveries and improved recovery 3,975,675 5,172,392 — 4,837,740
Sales of minerals in place (462,970) (555,879) — (555,617)
Production (2,686,940) (2,535,188) — (3,109,471)
Revisions of previous quantity estimates (3,431,939) 7,562,925 — (2,171,452)
Balance, December 31, 2021 65,838,609 71,773,789 — 77,800,907
Purchase of minerals in place 28,086,920 108,456,107 16,715,626 62,878,564
Extensions, discoveries and improved recovery 628,978 522,178 52,810 768,818
Production (3,459,477) (4,088,642) (371,337) (4,512,254)
Revisions of previous quantity estimates (2,390,287) (18,792,983) 6,708,559 1,186,108
Balance, December 31, 2022 88,704,743 157,870,449 23,105,658 138,122,143
_____________________________
(1) Six Mcf is deemed the equivalent of one Boe.
(2) At year-end 2022, we began reporting reserves on a three-stream basis, including natural gas liquids separately from natural gas.
Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.
During the year ended December 31, 2022, our extensions and discoveries of 769 MBoe (one thousand Boe) resulted primarily from the 2022 operated drilling program in the Northwest Shelf and Central Basin Platform as well as non-operated activity in the Northwest Shelf. Revisions of 1,186 MBoe were predominately the result of converting from two-stream to three-stream reserves, the removal of proved undeveloped reserves in our Delaware asset, well performance, increased cost from 2022 industry activity, and increased commodity pricing.
35
Table of Contents
Our proved oil, natural gas and natural gas liquid reserves are shown below.
For the years ended December 31,
2022 2021
Oil (Bbl)
Developed 57,012,137 36,820,824
Undeveloped 31,692,606 29,017,785
Total 88,704,743 65,838,609
Natural Gas (Mcf)
Developed 106,399,050 39,748,880
Undeveloped 51,471,399 32,024,909
Total 157,870,449 71,773,789
Natural Gas Liquids (Bbl)
Developed 15,332,804 —
Undeveloped 7,772,854 —
Total 23,105,658 —
Total (Boe) 1
Developed 90,078,116 43,445,637
Undeveloped 48,044,027 34,355,270
Total 138,122,143 77,800,907
Standardized Measure of Discounted Future Net Cash Flows
Our standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and changes in the standardized measure as described below were prepared in accordance with GAAP.
Future income tax expenses are calculated by applying appropriate year-end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value of our oil and natural gas properties.
Our estimates of reserves and future cash flow as of December 31, 2022 and 2021 were prepared using an average price equal to the unweighted arithmetic average of the first day of the month price for each month within the 12-month periods ended December 31, 2022 and 2021, respectively, in accordance with SEC guidelines. As of December 31, 2022, our reserves are based on an SEC average price of $90.15 per Bbl of WTI oil posted and $6.358 per MMBtu of Henry Hub natural gas. As of December 31, 2021, our reserves are based on an SEC average price of $63.04 per Bbl of WTI oil posted and $3.598 per MMBtu Henry Hub natural gas. Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines.
1 Six Mcf is deemed the equivalent of one Boe.
36
Table of Contents
The standardized measure of discounted future net cash flows relating to the proved oil, natural gas and natural gas liquids reserves are shown below.
Standardized Measure of Discounted Future Net Cash Flows
December 31, 2022 2021 2020
Future cash inflows $ 9,871,961,000 $ 4,853,709,000 $ 2,682,488,655
Future production costs (2,751,896,250) (1,395,437,250) (821,515,126)
Future development costs (647,196,750) (347,757,000) (244,323,270)
Future income taxes (1,142,147,641) (501,586,949) (208,645,934)
Future net cash flows 5,330,720,359 2,608,927,801 1,408,004,325
10% annual discount for estimated timing of cash flows (3,058,606,841) (1,471,562,953) (852,133,072)
Standardized Measure of Discounted Future Net Cash Flows $ 2,272,113,518 $ 1,137,364,848 $ 555,871,253
The changes in the standardized measure of discounted future net cash flows relating to the proved oil, natural gas and natural gas liquid reserves are shown below.
Changes in Standardized Measure of Discounted Future Net Cash Flows
2022 2021 2020
Beginning of the year $ 1,137,364,848 $ 555,871,253 $ 923,175,051
Purchase of minerals in place 996,313,882 33,688,718 —
Extensions, discoveries and improved recovery 20,447,842 79,003,885 61,303,074
Development costs incurred during the year 67,454,522 17,513,180 29,916,746
Sales of oil and gas produced, net of production costs (283,588,498) (154,615,685) (70,634,853)
Sales of minerals in place — (2,523,746) —
Accretion of discount 133,209,763 63,810,764 92,838,323
Net changes in price and production costs 646,819,172 636,884,944 (368,974,767)
Net change in estimated future development costs (53,253,626) (44,357,751) (3,883,985)
Revisions of previous quantity estimates 33,583,837 (22,259,508) (66,213,586)
Changes in estimated timing of cash flows (119,428,019) 86,845,188 (139,039,115)
Net change in income taxes (306,810,205) (112,496,394) 97,384,365
End of the Year $ 2,272,113,518 $ 1,137,364,848 $ 555,871,253
37
Table of Contents
Our proved reserves by state as of December 31, 2022 are summarized in the table below.
Oil (Bbl) Gas (Mcf) Natural Gas Liquids (NGL) (Bbl) Total (Boe) % of Total
Proved Pre-tax PV-10
(In thousands) Standardized
Measure of
Discounted Future
Net Cash Flows
(In thousands) Future Capital
Expenditures
(In thousands)
Texas
PD 54,825,249 105,172,422 15,175,702 87,529,688 63 % $ 1,863,175 $ 1,526,269 $ 182,668
PUD 30,741,939 50,999,854 7,733,492 46,975,407 34 % 853,607 699,254 447,930
Total Proved: 85,567,188 156,172,276 22,909,194 134,505,095 97 % $ 2,716,782 $ 2,225,523 $ 630,598
New Mexico
PD 2,186,888 1,226,628 157,102 2,548,428 2 % $ 43,506 $ 35,639 $ 1,985
PUD 950,667 471,545 39,362 1,068,620 1 % 13,369 10,952 14,614
Total Proved: 3,137,555 1,698,173 196,464 3,617,048 3 % $ 56,875 $ 46,591 $ 16,599
Total
PD 57,012,137 106,399,050 15,332,804 90,078,116 65 % $ 1,906,681 $ 1,561,908 $ 184,653
PUD 31,692,606 51,471,399 7,772,854 48,044,027 35 % 866,976 710,206 462,544
Total Proved: 88,704,743 157,870,449 23,105,658 138,122,143 100 % $ 2,773,657 $ 2,272,114 $ 647,197
Proved Reserves
As of December 31, 2022, we had approximately 138.1 MMBoe (one million Boe) of proved reserves, consisting of approximately 64% oil, 19% natural gas, and 17% natural gas liquids, as summarized in the table above. Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC).
As of December 31, 2022, approximately 65% of the proved reserves have been classified as proved developed, or “PD” and the remaining 35% are proved undeveloped, or “PUD”.
As of December 31, 2022, our total proved reserves had a net pre-tax PV-10 value of approximately $2,773.7 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $2,272.1 million. Approximately $1,906.7 million and $1,561.9 million, respectively, of total proved reserves are associated with the PD reserves, which is approximately 69% of the total proved reserves’ pre-tax PV-10 value. The remaining $867.0 million and $710.2 million, respectively, are associated with PUD reserves.
Proved Undeveloped Reserves
Our reserve estimates as of December 31, 2022 include approximately 48.0 MMBoe as proved undeveloped reserves (PUD). As of December 31, 2021, our reserve estimates included approximately 34.4 MMBoe as proved undeveloped reserves. Below is a description of the changes in our PUD reserves from December 31, 2021 to December 31, 2022.
During the year ended December 31, 2022, we incurred costs of approximately $87.7 million to convert 26 properties from PUD to PD through development. These 26 properties produced 709 MBoe during the year ended December 31, 2022, and have reserves of 8,018 MBoe as of December 31, 2022.
The increase in proved undeveloped reserves was primarily attributable to the Stronghold Acquisition.
The following table indicates projected reserves that we currently estimate will be converted from proved undeveloped to proved developed, as well as the estimated costs per year involved in such development.
38
Table of Contents
Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves
Year Estimated Oil
Reserves
Developed (Bbl) Estimated Gas
Reserves
Developed (Mcf) Estimated NGL
Reserves
Developed (Bbl) Total Boe Estimated
Development Costs
2023 7,243,318 9,494,859 1,685,188 10,510,983 $ 102,822,989
2024 9,037,309 15,468,017 2,370,819 13,986,131 130,214,495
2025 8,631,583 17,046,317 2,403,159 13,875,795 125,779,913
2026 5,998,345 9,156,375 1,283,290 8,807,698 89,548,288
2027 782,049 305,832 30,399 863,420 14,178,133
31,692,604 51,471,400 7,772,855 48,044,027 $ 462,543,818
Preparation and Internal Controls Over Reserves Estimates
All the proved oil and natural gas reserves disclosed in this Report are based on reserve estimates determined and prepared by independent reserve engineers Cawley, Gillespie & Associates, Inc. (“CGA”), a leader of petroleum property analysis for industry and financial institutions. CGA was founded in 1960 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated February 3, 2023, filed as an exhibit to this Annual Report on Form 10-K, was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 35 years of practical experience in petroleum engineering, with over 33 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.
The proved oil and natural gas reserves disclosed in this Report are based on reserve estimates determined and prepared by independent reserve engineers primarily using decline curve analysis to determine the reserves of individual producing wells. To establish reasonable certainty with respect to our estimated proved reserves, the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using volumetric estimates or performance from analogous wells in the surrounding area. These wells were considered to be analogous based on production performance from the same formation and completions using similar techniques. The technologies and economic data used to estimate our proved reserves include, but are not limited to, well logs, geological maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. This data was reviewed by various levels of management for accuracy before consultation with independent reserve engineers. This consultation included review of properties, assumptions and available data. Internal reserve estimates were compared to those prepared by independent reserve engineers to test the estimates and conclusions before the reserves were included in this Report. The accuracy of the reserve estimates is dependent on many factors, including the following:
• the quality and quantity of available data and the engineering and geological interpretation of that data;
• estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;
• the accuracy of economic assumptions; and
• the judgment of the personnel preparing the estimates.
Our Executive Vice President of Engineering and Corporate Strategy, Mr. Alex Dyes, is the technical professional primarily responsible for overseeing the preparation of our reserves estimates. He has a Bachelor of Science degree in Petroleum Engineering from the University of Texas with over 16 years of practical industry experience, including over 12 years of estimating and evaluating reserve information. He has been a member of the Society of Petroleum Engineers since 2013 and his qualifications meet or exceed the Society of Petroleum Engineers’ standard requirements to be a professionally qualified Reserve Estimator and Auditor.
39
Table of Contents
We encourage ongoing professional education for our engineers and reservoir analysts on new technologies and industry advancements as well as refresher training on basic skill sets. In order to ensure the reliability of reserves estimates, our Corporate Reserves department follows comprehensive SEC-compliant internal controls and policies to determine, estimate and report proved reserves including:
• confirming that we include reserves estimates for all properties owned and that they are based upon proper working and net revenue interests;
• ensuring the information provided by other departments within the Company, such as Accounting, is accurate;
• communicating, collaborating, and analyzing with technical personnel in our business units;
• comparing and reconciling the internally generated reserves estimates to those prepared by third parties; and
• utilizing experienced reservoir engineers or those under their direct supervision to prepare reserve estimates.
Each quarter, the Executive Vice President of Engineering and Corporate Strategy presents the status of the Company’s reserves to senior executives, and subsequently obtains approval of significant changes from key executives. Additionally, our five-year PUD development plan is reviewed and approved annually by the Company’s Chief Executive Officer, Chief Financial Officer, Executive Vice President of Operations, and the Executive Vice President of Land, Legal, Human Resources, and Marketing.
The Corporate Reserves department works closely with independent reserve engineers from CGA at each fiscal year end to ensure the integrity, accuracy and timeliness of annual independent reserves estimates. These independently developed reserves estimates are presented to the Audit Committee. In addition to reviewing the independently developed reserve reports, the Audit Committee also periodically meets with the independent reserve engineers that prepare estimates of proved reserves.
Summary of Oil and Natural Gas Properties and Projects
Acreage
The following table summarizes gross and net developed and undeveloped acreage as of December 31, 2022 by region (net acreage is our percentage ownership of gross acreage). Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.
Developed Acreage Undeveloped Acreage Total Acreage
Gross Net Gross Net Gross Net
Central Basin Platform 64,774 54,959 3,905 2,337 68,679 57,296
Delaware Basin 18,729 18,437 — — 18,729 18,437
Northwest Shelf 18,270 13,930 18,539 12,512 36,809 26,442
Total 101,773 87,326 22,444 14,849 124,217 102,175
Leases of undeveloped acreage will generally expire at the end of their respective primary terms unless production from such leasehold acreage has been established prior to expiration of such primary term. If production is established on such acreage, the lease will generally remain in effect until the cessation of production from such acreage and is referred to in the industry as “Held-By-Production” or “HBP.” Leases of undeveloped acreage may terminate or expire as a result of not meeting certain drilling commitments, if any, or otherwise by not complying with the terms of a lease depending on the specific terms that are negotiated between the lessor and the lessee.
40
Table of Contents
The following table sets forth gross and net undeveloped acreage, as of December 31, 2022, under lease which will expire over the next three years unless (i) production is established on the lease or within a spacing unit of which the lease is participating, or (ii) the lease is renewed or extended prior to the relevant expiration dates:
Undeveloped Acreage
2023 2024 2025
Gross Net Gross Net Gross Net
Central Basin Platform 480 234 1,420 1,221 860 49
Delaware Basin — — — — — —
Northwest Shelf 15,240 4,023 11,610 2,021 10,446 3,835
Total 15,720 4,257 13,030 3,242 11,306 3,884
41
Table of Contents
Production History
The following table presents the historical information regarding our produced oil, natural gas and natural gas liquid volumes for the years ended December 31, 2022, 2021, and 2020:
Years ended December 31,
2022 2021 2020
Oil (Bbls)
Central Basin Platform 1,409,211 867,835 958,691
Delaware Basin 81,936 104,129 159,635
Northwest Shelf 1,968,693 1,714,976 1,683,202
Total 3,459,840 2,686,940 2,801,528
Natural Gas (Mcf)
Central Basin Platform 1,563,808 171,690 268,495
Delaware Basin 96,516 288,918 468,177
Northwest Shelf 2,428,318 2,074,580 1,757,830
Total 4,088,642 2,535,188 2,494,502
Natural Gas Liquids (Bbls) (1)
Central Basin Platform 227,996 — —
Delaware Basin 3,718 — —
Northwest Shelf 139,615 — —
Total 371,329 — —
Total production (Boe)
Central Basin Platform 1,897,842 896,087 1,003,440
Delaware Basin 101,740 152,282 237,665
Northwest Shelf 2,513,028 2,060,739 1,976,173
Total 4,512,610 3,109,108 3,217,278
Daily production (Boe/d)
Central Basin Platform 5,200 2,455 2,742
Delaware Basin 279 417 649
Northwest Shelf 6,885 5,646 5,399
Total 12,364 8,518 8,790
(1) Due to our acquisition of Stronghold's assets, which reported its volumes and revenues on a three-stream basis, beginning July 1, 2022, we began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and natural gas liquid sales. For periods prior to July 1, 2022, sales and reserve volumes, prices, and revenues for natural gas liquids were presented with natural gas.
42
Table of Contents
Production Prices and Production Costs
The following tables provides historical pricing and costs statistics for the years ended December 31, 2022, 2021, and 2020.
Years ended December 31,
2022 2021 2020
Average sales price:
Oil (per Bbl)
Central Basin Platform $ 91.72 $ 67.66 $ 39.64
Delaware Basin 95.97 65.98 35.00
Northwest Shelf 93.44 67.61 38.93
Total $ 92.80 $ 67.56 $ 38.95
Natural gas (per Mcf)
Central Basin Platform $ 3.72 $ 4.63 $ 1.12
Delaware Basin 5.26 4.75 0.54
Northwest Shelf 5.09 6.08 1.91
Total $ 4.57 $ 5.83 $ 1.57
Natural gas liquids (per Bbl) (1)
Central Basin Platform $ 20.02 $ — $ —
Delaware Basin 27.16 — —
Northwest Shelf 20.25 — —
Total $ 20.18 $ — $ —
Total (per Boe)
Central Basin Platform $ 73.58 $ 66.42 $ 38.17
Delaware Basin 83.28 54.13 24.57
Northwest Shelf 79.24 62.38 34.86
Total $ 76.95 $ 63.14 $ 35.13
(1) Due to our acquisition of Stronghold's assets, which reported its volumes and revenues on a three-stream basis, beginning July 1, 2022, we began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and natural gas liquid sales. For periods prior to July 1, 2022, sales and reserve volumes, prices, and revenues for natural gas liquids were presented with natural gas.
43
Table of Contents
Years ended December 31,
2022 2021 2020
Average lease operating expenses (per Boe)
Central Basin Platform $ 13.81 $ 15.97 $ 15.44
Delaware Basin 44.86 32.75 19.13
Northwest Shelf 6.74 5.34 4.91
Total $ 10.57 $ 9.75 $ 9.25
Average gathering, transportation and
processing costs (per Boe)
Central Basin Platform $ — $ — $ —
Delaware Basin — — —
Northwest Shelf 0.73 2.10 2.07
Total $ 0.41 $ 1.39 $ 1.27
Average ad valorem taxes (per Boe)
Central Basin Platform $ 1.11 $ 1.17 $ 1.82
Delaware Basin 0.41 0.33 0.50
Northwest Shelf 1.00 0.57 0.60
Total $ 1.04 $ 0.73 $ 0.97
Average production taxes (per Boe)
Central Basin Platform $ 3.64 $ 2.85 $ 1.67
Delaware Basin 3.97 2.45 1.30
Northwest Shelf 3.91 3.01 1.64
Total $ 3.80 $ 2.93 $ 1.63
The average oil sales price amounts above are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels “Bbl.” The average natural gas sales price amounts above are calculated by dividing revenue from natural gas sales by the volume of natural gas sold, in thousand cubic feet “Mcf.” The average natural gas liquids sales price amounts above are calculated by dividing revenue from natural gas liquids sales by the volume of natural gas liquids sold, in barrels “Bbl.”The total average sales price amounts are calculated by dividing total revenues by total volume sold, in Boe. The average production costs above are calculated by dividing production costs by total production in Boe.
Productive Wells
The following table presents our ownership as of December 31, 2022 in productive oil and natural gas wells (a net well is our percentage ownership of a gross well). All of such wells are in the Permian Basin in Texas and New Mexico.
Oil Wells Gas wells Total Wells
Gross Net Gross Net Gross Net
1,033 869 23 19 1,056 888
Drilling Activity
During 2022, we drilled 18.00 gross (17.35 net) horizontal San Andres wells in the Northwest Shelf (16.00 1.0-mile laterals and two 1.5-mile laterals.) In addition, we drilled 14.00 gross (14.00 net) wells in the Central Basin Platform, of which nine were horizontal San Andres wells in Andrews County, Texas (four 1.0-mile laterals and five 1.5-mile laterals) and five were vertical wells in Crane County, Texas. In addition, we also participated in three gross (0.33 net) non-operated wells in the Northwest shelf. These wells were successful and there were no dry wells.
44
Table of Contents
The table below contains information regarding the number of operated wells drilled and participated in during the periods indicated.
For the year ended December 31,
2022 2021 2020
Gross Net Gross Net Gross Net
Exploratory
Productive — — — — — —
Dry — — — — — —
Development
Productive 32.00 31.35 11.00 9.91 6.00 5.61
Dry — — — — — —
Total
Productive 32.00 31.35 11.00 9.91 6.00 5.61
Dry — — — — — —
The table below contains information regarding the number of non-operated wells drilled and participated in during the periods indicated.
For the year ended December 31,
2022 2021 2020
Gross Net Gross Net Gross Net
Exploratory
Productive — — — — — —
Dry — — — — — —
Development
Productive 3.00 0.33 2.00 0.23 1.00 0.11
Dry — — — — — —
Total
Productive 3.00 0.33 2.00 0.23 1.00 0.11
Dry — — — — — —
Present Activities
We had no operated wells in the process of being drilled or completed as of December 31, 2022.
Cost Information
We conduct our oil and natural gas activities entirely in the United States. As noted in the table under “Production Prices and Production Costs”, our average production costs including lease operating expenses, gathering, processing and transportation ("GPT") and ad valorem, per Boe, were $12.02 and $11.88 for the years ended December 31, 2022 and 2021, respectively, and our average production taxes, per Boe, were $3.80 and $2.93 for the years ended December 31, 2022 and 2021, respectively. These amounts are calculated by dividing our total production costs or total production taxes by our total volume sold, in Boe.
45
Table of Contents
Costs incurred for property acquisition, exploration and development activities for the years ended December 31, 2022, 2021 and 2020 are shown below:
2022 2021 2020
Stronghold Acquisition $ 177,823,787 $ — $ —
Acquisition of proved properties 1,563,703 1,368,437 1,317,313
Divestiture of proved properties (23,700) (2,000,000) —
Development costs 129,332,155 51,302,131 42,457,745
Total costs incurred $ 308,695,945 $ 50,670,568 $ 43,775,058
Other Properties and Commitments
Effective January 1, 2021, the Company moved its corporate headquarters to The Woodlands, Texas. Prior to this, our principal offices were in Midland, Texas. Those offices now serve as an operations office. Our office space lease in Tulsa, Oklahoma was terminated as of March 31, 2021.