Item 2. Properties
Item 2: Properties
General Background
Ring is currently engaged in oil and natural gas acquisition, exploration, development and production, with activities and operations currently in Texas and New Mexico. While our business model includes pursuing acquisition opportunities, our near-term focus will be on the development of our existing properties.
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, 2020, we owned interests in a total of 53,912 gross (45,053 net) developed acres and operate the vast majority of our acreage position. In addition, as of December 31, 2020, we owned interests in approximately 50,543 gross (31,692 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.
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 developed and refined an acquisition program designed to increase reserves and complement our existing core properties. We have an experienced team of management and engineering professionals who identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties.
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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, 2020, our acreage position in these counties is 46,972 gross (32,915 net) acres with 11,723 gross (8,085 net) developed and held by production and 35,249 gross (24,830 net) being undeveloped. Our reserve estimates include 72 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 a considerable number of remaining 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 the Company’s 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 1-80%. In total as of December 31, 2020, we own 38,714 gross (25,362 net), acres with 23,668 gross (18,712 net) acres developed and held by production and the remaining 15,046 gross (6,650 net) acres being undeveloped. Our reserve estimates include 2 proved vertical and 32 horizontal PUD wells. Our reserve estimates include the capital costs required to develop these wells. We believe the Central Basin Platform leases contain a considerable number of remaining 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, 2020, we own 18,769 gross (18,468 net) acres with 18,521 gross (18,256 net) acres developed and held by production and the remaining 248 gross (212 net) acres being undeveloped. Our reserve estimates include 26 proved 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 a considerable number of remaining potential drilling locations.
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 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, 2020, our estimated proved reserves had a pre-tax PV10 value of approximately $638.1 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $555.9 million, 100% of which relates to our properties in the Permian Basin in Texas and New Mexico. We spent approximately $466.9 million on acquisitions and capital projects during 2019 and 2020. We expect to further develop these properties through additional drilling.
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The following table summarizes our total net proved reserves, pre-tax PV10 value and Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2020. All of our reserves are in the Permian Basin in the States of Texas and New Mexico.
Standardized
Measure of
Oil
Natural
Total
Pre-Tax PV10
Discounted Future
(Bbl)
Gas (Mcf)
(Boe)
Value
Net Cash Flows
66,264,286
61,305,027
76,481,791
$
638,107,637
$
555,871,253
The Company presents the pre-tax PV10 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.
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)
Balance, December 31, 2018
27,809,748
52,765,698
Purchase of minerals in place
36,501,824
41,921,368
Improved recovery
4,732,449
2,530,636
Extensions and discoveries
13,295,301
5,501,627
Production
(3,536,126)
(2,476,472)
Sales of minerals in place
(758,169)
(811,279)
Upward revisions of estimates
2,731,228
1,618,234
Downward revision of estimates due to well performance
(3,699,908)
(11,680,453)
Downward revision of estimates due to commodity prices
(3,655,679)
(28,789,545)
Downward revision of estimates due to removal of undeveloped locations
(2,061,654)
(2,307,932)
Balance, December 31, 2019
71,359,014
58,271,882
Improved recovery
3,495,210
1,824,310
Production
(2,801,528)
(2,494,501)
Upward revisions of estimates
2,591,965
6,158,076
Downward revision of estimates due to well performance
(4,484,425)
44,370
Downward revision of estimates due to commodity prices
(2,313,890)
(2,303,700)
Downward revision of estimates due to removal of undeveloped locations
(1,582,060)
(195,410)
Balance, December 31, 2020
66,264,286
61,305,027
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Our proved oil and natural gas reserves are shown below.
For the Years Ended December 31,
2020
2019
Oil (Bbls)
Developed
38,260,638
41,242,064
Undeveloped
28,003,648
30,116,950
Total
66,264,286
71,359,014
Natural Gas (Mcf)
Developed
34,335,520
34,467,868
Undeveloped
26,969,507
23,804,014
Total
61,305,027
58,271,882
Total (Boe)
Developed
43,983,225
46,986,709
Undeveloped
32,498,566
34,084,285
Total
76,481,791
81,070,994
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, 2020 and 2019 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, 2020 and 2019, respectively, in accordance with SEC guidelines. 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. As of December 31, 2019, our reserves are based on an SEC average price of $52.19 per Bbl of WTI oil posted and $2.58 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
December 31,
2020
2019
Future cash flows
$
2,682,488,655
$
3,825,773,515
Future production costs
(821,515,126)
(964,887,856)
Future development costs
(244,323,270)
(252,457,833)
Future income taxes
(208,645,934)
(424,715,966)
Future net cash flows
1,408,004,325
2,183,711,860
10% annual discount for estimated timing of cash flows
(852,133,072)
(1,260,536,809)
Standardized Measure of Discounted Future Net Cash Flows
$
555,871,253
$
923,175,051
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The changes in the standardized measure of discounted future net cash flows relating to the proved oil and natural gas reserves are shown below.
2020
2019
Beginning of the year
$
923,175,051
$
455,944,641
Purchase of minerals in place
—
598,489,190
Improved recovery, less related costs
61,303,074
86,989,301
Extensions and discoveries, less related costs
—
247,652,632
Development costs incurred during the year
29,916,746
152,125,320
Sales of oil and gas produced, net of production costs
(70,634,853)
(137,663,314)
Sales of minerals in place
—
(30,174,528)
Accretion of discount
92,838,323
47,463,292
Net changes in price and production costs
(368,974,767)
(219,608,128)
Net change in estimated future development costs
(3,883,985)
47,617,158
Upward revisions
32,920,723
44,034,636
Revision of previous quantity estimates as a result well performance
(52,731,122)
(64,553,979)
Revision of previous quantity estimates as a result of commodity prices
(26,590,142)
(71,545,320)
Revision of previous quantity estimates as a result removal of uneconomic proved undeveloped locations
(19,812,745)
(34,079,006)
Revision of estimated timing of cash flows
(139,039,115)
(107,443,484)
Net change in income taxes
97,384,365
(92,073,360)
End of the Year
$
555,871,553
$
923,175,051
Our proved reserves by state as of December 31, 2020 are summarized in the table below.
Standardized
Measure of
Discounted Future
Future Capital
% of Total
Pre-tax PV10
Net Cash Flows
Expenditures
Oil (Bbl)
Gas (Mcf)
Total (Boe)
Proved
(In thousands)
(In thousands)
(In thousands)
Texas
PD
36,075,577
32,364,426
41,469,648
54
%
$
418,844
$
364,435
$
23,655
PUD
27,055,299
26,207,571
31,423,228
41
%
193,527
168,387
208,590
Total Proved:
63,130,876
58,571,997
72,892,876
95
%
$
612,371
$
532,822
$
232,245
New Mexico
PD
2,185,061
1,971,094
2,513,577
3
%
$
19,364
$
17,342
$
1,505
PUD
948,349
761,936
1,075,338
1
%
6,373
5,707
10,573
Total Proved:
3,133,410
2,733,030
3,588,915
5
%
$
25,737
$
23,049
$
12,078
Total
PD
38,260,638
34,335,520
43,983,225
57.5
%
$
438,208
$
381,777
$
25,160
PUD
28,003,648
26,969,507
32,498,566
42.5
%
199,900
174,094
219,163
Total Proved:
66,264,286
61,305,027
76,481,791
100
%
$
638,108
$
555,871
$
244,323
66,264,286
61,305,027
76,481,791
638,108
244,323
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Proved Reserves
We have approximately 76.5 million BOE of proved reserves, consisting of approximately 87% oil and 13% natural gas, as summarized in the table above as of December 31, 2020, on a net pre-tax PV10 value and Standardized Measure of Discounted Future Net Cash Flows basis. Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC).
As of December 31, 2020, approximately 57.5% of the proved reserves have been classified as proved developed, or “PD” and the remaining 42.5% are proved undeveloped, or “PUD”.
As of December 31, 2020, our total proved reserves had a net pre-tax PV10 value of approximately $638.1 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $555.9 million. Approximately $438.2 million and $381.8 million, respectively, of total proved reserves are associated with the PD reserves, which is approximately 69% of the total proved reserves’ pre-tax PV10 value. The remaining $199.9 million and $174.1 million, respectively, are associated with PUD reserves.
Proved Undeveloped Reserves
Our reserve estimates as of December 31, 2020 include approximately 32.5 million BOE as proved undeveloped reserves. As of December 31, 2019, our reserve estimates included approximately 35.1 million BOE as proved undeveloped reserves. Below is a description of the changes in our PUD reserves from December 31, 2019 to December 31, 2020.
During the year ended December 31, 2020, we incurred costs of approximately $10.0 million to convert 1,698,122 BOE of reserves from PUD to PD through development.
Other changes to our PUD reserves included:
● Upward revisions of 3,521,992 BOE as the result of a reduction in lease operating expenses in certain areas and improved offsetting production due to pump optimization and improved completion practices;
● Downward revisions of 1,794,900 BOE as the result of changes in commodity prices; and
● Downward revision of 1,614,628 BOE for the removal of locations due to lack of development within the prescribed time frame due to changes in anticipated development programs as a result of market conditions
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
2021
5,880,319
6,006,939
6,881,476
42,156,847
2022
9,345,510
9,186,059
10,876,520
72,617,289
2023
9,706,829
10,062,460
11,383,906
78,041,149
2024
3,070,990
1,714,049
3,356,665
26,348,548
28,003,648
26,969,507
32,498,566
$
219,163,833
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
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forth in the CGA letter dated February 10, 2021, 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 30 years of practical experience in petroleum engineering, with over 30 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 with over 14 years of practical industry experience, including over 10 years of estimating and evaluating 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;
● utilizing experienced reservoir engineers or those under their direct supervision to prepare reserve estimates; and
● ensuring compensation for the reserve engineers is not tied to the amount of reserves recorded.
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, the Executive Vice President of Land, Legal, Human Resources, and Marketing, and the Executive Vice President of Engineering and Corporate Strategy.
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
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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
Production Summary
Our estimated average daily total Company net production for the month of December 2020 is 9,201 BOE/d. The following table provides the calculation of this daily production rate for the month of December 2020.
Oil (Bbls)
244,857
Gas (Mcf)
242,180
Total production (BOE)
285,221
Daily production (Boe/d)
9,201
Acreage
The following table summarizes gross and net developed and undeveloped acreage as of December 31, 2020 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
23,668
18,712
15,046
6,650
38,714
25,362
Delaware Basin
18,521
18,256
248
212
18,769
18,468
Northwest Shelf
11,723
8,085
35,249
24,830
46,972
32,915
Total
53,912
45,053
50,543
31,692
104,455
76,745
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.
The following table sets forth the gross and net undeveloped acreage, as of December 31, 2020, 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:
2021
2022
2023
Gross
Net
Gross
Net
Gross
Net
Undeveloped acreage
19,350
13,252
6,409
2,259
1,978
1,908
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Production History
The following table presents the historical information about our produced natural gas and oil volumes for the years ended December 31, 2020, 2019 and 2018:
Years Ended December 31,
2020
2019
2018
Oil (Bbls)
Central Basin Platform
958,691
1,590,473
1,812,616
Delaware Basin
159,635
275,080
234,679
Northwest Shelf
1,683,202
1,670,573
—
Total
2,801,528
3,536,126
2,047,295
Gas (Mcf)
Central Basin Platform
268,495
315,228
346,115
Delaware Basin
468,177
939,437
766,062
Northwest Shelf
1,757,830
1,221,807
—
Total
2,494,502
2,476,472
1,112,177
Total production (BOE)
Central Basin Platform
1,003,440
1,643,011
1,870,302
Delaware Basin
237,665
431,653
362,356
Northwest Shelf
1,976,173
1,874,207
—
Total
3,217,278
3,948,871
2,232,658
Daily production (Boe/d)
Central Basin Platform
2,742
4,501
5,124
Delaware Basin
649
1,183
993
Northwest Shelf
5,399
5,135
—
Total
8,790
10,819
6,117
Production Prices and Production Costs
The following tables provides historical pricing and costs statistics for the years ended December 31, 2018, 2019 and 2020.
Years Ended December 31,
2020
2019
2018
Average sales price:
Oil (per Bbl)
$
38.95
$
54.27
$
56.99
Natural gas (per Mcf)
1.57
1.54
3.05
Total (per Boe)
35.13
49.56
53.78
Average production cost (including ad valorem taxes) (per Boe)
$
11.49
$
12.28
$
12.45
Average production taxes (per Boe)
1.63
2.31
2.52
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.
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Productive Wells
The following table presents our ownership as of December 31, 2020 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
610
441
—
—
610
441
Drilling Activity
During 2020, we drilled 6 gross (5.61 net) wells in the Northwest Shelf in the Permian Basin. We completed and placed on production 4 of these wells during the first quarter 2020. Two wells were drilled in December 2020 and subsequently completed and placed on production during 2021. All of these wells were successful and there were no dry wells.
The table below contains information regarding the number of wells drilled during the periods indicated.
For the year ended December 31,
2020
2019
2018
Gross
Net
Gross
Net
Gross
Net
Exploratory
Productive
—
—
—
—
—
—
Dry
—
—
—
—
—
—
Development
Productive
6.00
5.61
30.00
29.33
57.00
56.25
Dry
Total
Productive
6.00
5.61
30.00
29.33
57.00
56.25
Dry
—
—
—
—
—
—
Present Activities
There were no wells in the process of being drilled, however, there were two wells waiting to be being completed as of December 31, 2020.
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 $12.45, $12.28 and $11.49 during the years ended December 31, 2018, 2019 and 2020, respectively, and our average production taxes, per BOE, were $2.52, $2.31 and $1.63 for the years ended December 31, 2018, 2019 and 2020, respectively. These amounts are calculated by dividing our total production costs or total production taxes by our total volume sold, in BOE.
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Costs incurred for property acquisition, exploration and development activities during the years ended December 31, 2019 and 2020 are shown below:
2020
2019
Wishbone Acquisition (1)
$
—
$
304,392,921
Acquisition of proved properties
1,317,313
3,400,411
Divestiture of proved properties
—
(8,547,074)
Acquisition of unproved properties
—
—
Exploration costs
—
—
Development costs
42,457,745
152,125,320
Total Costs Incurred
$
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
Our principal executive offices are in leased office space in The Woodlands, Texas. The lease for this office space was entered into subsequent to December 31, 2020. Prior to this and throughout 2020, our principal offices were in Midland, Texas. Those offices now serve as an operations office. We also lease office space in Tulsa, Oklahoma, which serves as our current accounting office, but which will be closed following the transition of those functions to The Woodlands offices. We expect our current office space to be adequate as we move forward.
Item 3: Legal Proceedings
In the ordinary course of business, we may be, from time to time, a claimant or a defendant in various legal proceedings. We do not presently have any material litigation pending or threatened requiring disclosure under this item.
Item 4: Mine safety disclosures
Not applicable.
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PART II