Item 2. Properties
Item 2:
Properties
General Background
Ring is currently engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in Texas and New Mexico.
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 exploiting and developing our existing oil and natural gas properties and pursuing strategic acquisitions of additional properties.
Developing and Exploiting Existing Properties
We believe that there is significant value to be created by drilling the identified undeveloped opportunities on our properties. As of December 31, 2021, we owned interests in a total of 60,882 gross (50,981 net) developed acres and operate the vast majority of our acreage position. In addition, as of December 31, 2021, we owned interests in approximately 22,722 gross (13,399 net) undeveloped acres. While our near-term plans are focused towards 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.
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
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, 2021, our acreage position in these counties is 35,810 gross (25,655 net) acres with 17,950 gross (13,662 net) developed acres held by production and 17,860 gross (11,993 net) undeveloped acres. Our reserve estimates include 79 identified proved horizontal drilling locations and 11 proved vertical drilling locations. Our reserve estimates include the capital costs required to develop these wells. We believe the Northwest Shelf leases contain additional potential drilling locations.
Central Basin Platform - Andrews and Gaines County, 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. The working interests range from 1-100% and the net revenue interests range from 1-88%. In total as of December 31, 2021, we own 29,065 gross (20,288 net), acres with 24,203 gross (18,882 net) developed acres held by production and the remaining 4,862 gross (1,406 net) acres being undeveloped. Our reserve estimates include 2 vertical and 38 horizontal PUD wells in this area. Our reserve estimates include the capital costs required to develop these wells. We believe the Central Basin Platform leases contain additional potential drilling locations.
Delaware Basin - Culberson and Reeves County, Texas leases – In 2015, we acquired properties consisting of 19,983 gross (19,679 net) acres with an average working interest of 98% and an average net revenue interest of 79%. Since that time, we have acquired additional undeveloped acreage in and around our Culberson and Reeves County leases. In total as of December 31, 2021, we own 18,729 gross (18,437 net) acres, all of which is developed and held by production (no undeveloped acreage). Our reserve estimates include 5 vertical and 4 horizontal PUD wells. Our reserve estimates include the capital costs required to develop these wells. We believe the Delaware Basin leases contain additional potential drilling locations.
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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, 2021, our estimated proved reserves had a pre-tax PV-10 value of approximately $1,332.1 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $1,137.4 million, 100% of which relates to our properties in the Permian Basin in Texas and New Mexico. We spent approximately $95.1 million on acquisitions and capital projects during 2020 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, 2021. All of our reserves are in the Permian Basin in Texas and New Mexico.
Standardized
Measure of
Oil
Natural
Total
Pre-Tax PV-10
Discounted Future
(Bbl)
Gas (Mcf)
(Boe) (1)
Value (2)
Net Cash Flows
65,838,609
71,773,789
77,800,907
$
1,332,097,625
$
1,137,364,848
(1) Six Mcf is the equivalent of one Boe.
(2) PV-10 is a non-GAAP financial measure. See below for a reconciliation.
The Company presents 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 Annual 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 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.
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
$
1,332,098
Future income taxes, discounted at 10%
$
194,733
Standardized measure of discounted future net cash flows
$
1,137,365
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Reserve Quantity Information
Our estimates of proved reserves and related valuations are based on reports independently determined and prepared by Cawley, Gillespie & Associates, Inc., 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 and natural gas reserves is shown below.
Oil (Bbl)
Gas (Mcf)
Boe (1)
Balance, December 31, 2019
71,359,014
58,271,882
81,070,994
Extensions, discoveries and improved recovery
3,495,210
1,824,310
3,799,262
Production
(2,801,528)
(2,494,501)
(3,217,278)
Revisions of previous quantity estimates
(5,788,410)
3,703,336
(5,171,187)
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
(1) Six Mcf is the equivalent of one Boe.
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, 2021, the Company’s extensions and discoveries of 4,838 MBOE resulted primarily from new proved undeveloped locations resulting from the 2021 operated drilling program in the Northwest Shelf and Central Basin Platform as well as non-operated activity in the Northwest Shelf. Negative revisions of 2,172 MBOE were the result of Delaware PUD removal due to the 5 Year Rule, well performance, and increased cost from 2021 industry activity increase partially offset by commodity price increases.
Our proved oil and natural gas reserves are shown below.
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For the Years Ended December 31,
2021
2020
Oil (Bbls)
Developed
36,820,824
38,260,638
Undeveloped
29,017,785
28,003,648
Total
65,838,609
66,264,286
Natural Gas (Mcf)
Developed
39,748,880
34,335,520
Undeveloped
32,024,909
26,969,507
Total
71,773,789
61,305,027
Total (Boe)
Developed
43,445,637
43,983,225
Undeveloped
34,355,270
32,498,566
Total
77,800,907
76,481,791
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 generally accepted accounting principles.
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, 2021 and 2020 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, 2021 and 2020, respectively, in accordance with SEC guidelines. 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 of Henry Hub natural gas. As of December 31, 2020, our reserves are based on an SEC average price of $36.04 per Bbl of WTI oil posted and $1.99 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.
The standardized measure of discounted future net cash flows relating to the proved oil and natural gas reserves are shown below.
Standardized Measure of Discounted Future Net Cash Flows
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December 31,
2021
2020
2019
Future cash inflows
$
4,853,709,000
$
2,682,488,655
$
3,825,773,515
Future production costs
(1,395,437,250)
(821,515,126)
(964,887,856)
Future development costs
(347,757,000)
(244,323,270)
(252,457,833)
Future income taxes
(501,586,949)
(208,645,934)
(424,715,966)
Future net cash flows
2,608,927,801
1,408,004,325
2,183,711,860
10% annual discount for estimated timing of cash flows
(1,471,562,953)
(852,133,072)
(1,260,536,809)
Standardized Measure of Discounted Future Net Cash Flows
$
1,137,364,848
$
555,871,253
$
923,175,051
The changes in the standardized measure of discounted future net cash flows relating to the proved oil and natural gas reserves are shown below.
Changes in Standardized Measure of Discounted Future Net Cash Flows
2021
2020
2019
Beginning of the year
$
555,871,253
$
923,175,051
$
455,944,641
Purchase of minerals in place
33,688,718
—
598,489,190
Extensions, discoveries and improved recovery
79,003,885
61,303,074
334,641,933
Development costs incurred during the year
17,513,180
29,916,746
152,125,320
Sales of oil and gas produced, net of production costs
(154,615,685)
(70,634,853)
(137,663,314)
Sales of minerals in place
(2,523,746)
—
(30,174,528)
Accretion of discount
63,810,764
92,838,323
47,463,292
Net changes in price and production costs
636,884,944
(368,974,767)
(219,608,128)
Net change in estimated future development costs
(44,357,751)
(3,883,985)
47,617,158
Revisions of previous quantity estimates
(22,259,508)
(66,213,586)
(126,143,669)
Changes in estimated timing of cash flows
86,845,188
(139,039,115)
(107,443,484)
Net change in income taxes
(112,496,394)
97,384,365
(92,073,360)
End of the Year
$
1,137,364,848
$
555,871,253
$
923,175,051
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Our proved reserves by state as of December 31, 2021 are summarized in the table below.
Standardized
Measure of
Discounted Future
Future Capital
% of Total
Pre-tax PV-10
Net Cash Flows
Expenditures
Oil (Bbl)
Gas (Mcf)
Total (Boe)
Proved
(In thousands)
(In thousands)
(In thousands)
Texas
PD
34,437,795
37,424,268
40,675,173
52
%
$
748,346
$
638,949
$
53,892
PUD
28,054,230
31,210,705
33,256,014
43
%
516,430
440,936
280,458
Total Proved:
62,492,025
68,634,973
73,931,187
95
%
$
1,264,776
$
1,079,884
$
334,350
New Mexico
PD
2,383,029
2,324,612
2,770,464
4
%
$
46,169
$
39,420
$
1,228
PUD
963,555
814,204
1,099,256
1
%
21,153
18,061
12,179
Total Proved:
3,346,584
3,138,816
3,869,720
5
%
$
67,322
$
57,481
$
13,407
Total
PD
36,820,824
39,748,880
43,445,637
56
%
$
794,515
$
678,369
$
55,120
PUD
29,017,785
32,024,909
34,355,270
44
%
537,583
458,996
292,637
Total Proved:
65,838,609
71,773,789
77,800,907
100
%
$
1,332,098
$
1,137,365
$
347,757
Proved Reserves
We have approximately 77.8 million BOE of proved reserves, consisting of approximately 85% oil and 15% natural gas, as summarized in the table above as of December 31, 2021. Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC).
As of December 31, 2021, approximately 56% of the proved reserves have been classified as proved developed, or “PD” and the remaining 44% are proved undeveloped, or “PUD”.
As of December 31, 2021, our total proved reserves had a net pre-tax PV-10 value of approximately $1,332.1 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $1,137.4 million. Approximately $794.5 million and $678.4 million, respectively, of total proved reserves are associated with the PD reserves, which is approximately 60% of the total proved reserves’ pre-tax PV-10 value. The remaining $537.6 million and $459.0 million, respectively, are associated with PUD reserves.
Proved Undeveloped Reserves
Our reserve estimates as of December 31, 2021 include approximately 34.4 million BOE as proved undeveloped reserves. As of December 31, 2020, our reserve estimates included approximately 32.5 million BOE as proved undeveloped reserves. Below is a description of the changes in our PUD reserves from December 31, 2020 to December 31, 2021.
During the year ended December 31, 2021, we incurred costs of approximately $22.9 million to convert 2,899 MBOE of reserves from PUD to PD through development.
The increase in proved undeveloped reserves was primarily attributable to extensions of 4,110 MBOE resulting primarily from the 2021 operated drilling program in the Northwest Shelf and Central Basin Platform as well as non-operated activity in the Northwest Shelf.
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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.
Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves
Estimated Oil
Estimated Gas
Reserves
Reserves
Estimated
Year
Developed (Bbls)
Developed (Mcf)
Total Boe
Development Costs
2022
8,671,710
8,665,935
10,116,032
89,000,630
2023
12,828,397
12,188,540
14,859,821
123,533,117
2024
7,353,579
9,896,043
9,002,919
76,828,066
2025
164,099
1,274,390
376,497
3,275,000
29,017,785
32,024,908
34,355,269
$
292,636,813
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 (“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 28, 2022, 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 31 years of practical experience in petroleum engineering, with over 31 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.
Ring’s 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 15 years of practical industry experience, including over 11 years of estimating and evaluating
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reserve information. He is 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.
We encourage ongoing professional education for our engineers and 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, the 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, the 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 petroleum consultants 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 petroleum consultants 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, 2021 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
24,203
18,882
4,862
1,406
29,065
20,288
Delaware Basin
18,729
18,437
—
—
18,729
18,437
Northwest Shelf
17,950
13,662
17,860
11,993
35,810
25,655
Total
60,882
50,981
22,722
13,399
83,604
64,380
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 lessor and lessee.
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The following table sets forth the gross and net undeveloped acreage, as of December 31, 2021, under lease which would 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
2022
2023
2024
Gross
Net
Gross
Net
Gross
Net
Central Basin Platform
3,241
371
360
40
960
895
Delaware Basin
—
—
—
—
—
—
Northwest Shelf
9,946
5,626
7,818
2,032
7,088
266
Total
13,187
5,997
8,178
2,072
8,048
1,161
Production History
The following table presents the historical information about our produced natural gas and oil volumes for the years ended December 31, 2021, 2020, and 2019:
Years Ended December 31,
2021
2020
2019
Oil (Bbls)
Central Basin Platform
867,835
958,691
1,590,473
Delaware Basin
104,129
159,635
275,080
Northwest Shelf
1,714,976
1,683,202
1,670,573
Total
2,686,940
2,801,528
3,536,126
Gas (Mcf)
Central Basin Platform
171,690
268,495
315,228
Delaware Basin
288,918
468,177
939,437
Northwest Shelf
2,074,580
1,757,830
1,221,807
Total
2,535,188
2,494,502
2,476,472
Total production (BOE)
Central Basin Platform
896,087
1,003,440
1,643,011
Delaware Basin
152,282
237,665
431,653
Northwest Shelf
2,060,739
1,976,173
1,874,207
Total
3,109,108
3,217,278
3,948,871
Daily production (Boe/d)
Central Basin Platform
2,455
2,742
4,501
Delaware Basin
417
649
1,183
Northwest Shelf
5,646
5,399
5,135
Total
8,518
8,790
10,819
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Production Prices and Production Costs
The following tables provides historical pricing and costs statistics for the years ended December 31, 2021, 2020, and 2019.
Years Ended December 31,
2021
2020
2019
Average sales price:
Oil (per Bbl)
Central Basin Platform
$
67.66
$
39.64
$
53.89
Delaware Basin
65.98
35.00
52.70
Northwest Shelf
67.61
38.93
54.88
Total
$
67.56
$
38.95
$
54.27
Natural gas (per Mcf)
Central Basin Platform
$
4.63
$
1.12
$
1.70
Delaware Basin
4.75
0.54
1.01
Northwest Shelf
6.08
1.91
1.91
Total
$
5.83
$
1.57
$
1.54
Total (per Boe)
Central Basin Platform
$
66.42
$
38.17
$
52.49
Delaware Basin
54.13
24.57
35.77
Northwest Shelf
62.38
34.86
50.16
Total
$
63.14
$
35.13
$
49.56
Years Ended December 31,
2021
2020
2019
Average lease operating expenses (per Boe)
Central Basin Platform
$
15.97
$
15.44
$
14.31
Delaware Basin
32.75
19.13
14.26
Northwest Shelf
5.34
4.91
6.70
Total
$
9.75
$
9.25
$
10.69
Average gathering, transportation and
processing costs (per Boe)
Central Basin Platform
—
—
—
Delaware Basin
—
—
—
Northwest Shelf
2.10
2.07
1.53
Total
$
1.39
$
1.27
$
0.73
Average ad valorem taxes (per Boe)
Central Basin Platform
$
1.17
$
1.82
$
1.16
Delaware Basin
0.33
0.50
0.49
Northwest Shelf
0.57
0.60
0.69
Total
$
0.73
$
0.97
$
0.86
Average production taxes (per Boe)
Central Basin Platform
$
2.85
$
1.67
$
2.28
Delaware Basin
2.45
1.30
1.85
Northwest Shelf
3.01
1.64
2.45
Total
$
2.93
$
1.63
$
2.31
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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 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, 2021 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
491
333
—
—
491
333
Drilling Activity
During 2021, we drilled 11 gross (9.91 net) wells in the Northwest Shelf and Central Basin Platform in the Permian Basin. We completed and placed on production each of these wells during 2021, and completed and placed on production two gross (1.998 net) wells that were drilled in December 2020. In addition, Ring also participated in two gross (.23 net) non-operated wells in the Northwest shelf. These wells were successful and there were no dry wells.
The table below contains information regarding the number of wells drilled and participated in during the periods indicated.
For the year ended December 31,
2021
2020
2019
Gross
Net
Gross
Net
Gross
Net
Exploratory
Productive
—
—
—
—
—
—
Dry
—
—
—
—
—
—
Development
Productive
13.00
10.14
6.00
5.61
30.00
29.33
Dry
—
—
—
—
—
—
Total
Productive
13.00
10.14
6.00
5.61
30.00
29.33
Dry
—
—
—
—
—
—
Present Activities
We had no wells in the process of being drilled or completed as of December 31, 2021.
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, per BOE, were $11.88 and $11.49 for the years ended December 31, 2021 and 2020, respectively, and our average production taxes, per BOE, were $2.93 and $1.63 for the years ended December 31, 2021 and 2020, respectively. These amounts are calculated by dividing our total production costs or total production taxes by our total volume sold, in BOE.
Costs incurred for property acquisition, exploration and development activities for the years ended December 31, 2021 and 2020 are shown below:
40
Table of Contents
2021
2020
2019
Wishbone Acquisition (1)
$
—
$
—
$
304,392,921
Acquisition of proved properties
1,368,437
1,317,313
3,400,411
Divestiture of proved properties
(2,000,000)
—
(8,547,074)
Development costs
51,302,131
42,457,745
152,125,320
Total Costs Incurred
$
50,670,568
$
43,775,058
$
451,371,578
(1) Wishbone Acquisition in 2019 includes $28.3 million in fair value of stock issued as consideration in acquisitions.
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. We expect our current office space to be adequate for the foreseeable future.