What changed in this filing

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Item 2. Properties

2023-03-09 compared with 2022-03-16 · 168 added, 103 removed, 211 unchanged (56% of the section changed)

General Background

Ring is currently engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in Texas and New Mexico.

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 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.

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 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.

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

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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, 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.

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.

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.

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.

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

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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.

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.

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All of our reserves are in the Permian Basin in Texas and New Mexico.

(Bbl) Natural

Gas (Mcf) Natural

Gas Liquids (Bbl) Total

Pre-Tax PV-10

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_____________________________

(1) Six Mcf is the equivalent of one Boe.

(1) Six Mcf is deemed 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.

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.

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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

Present value of estimated future net revenues (PV-10) $ 2,773,657

Future income taxes, discounted at 10% $ 501,543

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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.

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 and natural gas reserves is shown below.

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)

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)

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Extensions, discoveries and improved recovery 628,978 522,178 52,810 768,818

Sales of minerals in place

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 the equivalent of one Boe.

_____________________________

(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, 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.

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.

Our proved oil, natural gas and natural gas liquid reserves are shown below.

For the years ended December 31,

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 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.

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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.

1 Six Mcf is deemed the equivalent of one Boe.

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

4,853,709,000

2,682,488,655

3,825,773,515

Future production costs (2,751,896,250) (1,395,437,250) (821,515,126)

(1,395,437,250)

(821,515,126)

(964,887,856)

Future development costs (647,196,750) (347,757,000) (244,323,270)

(347,757,000)

(244,323,270)

(252,457,833)

Future income taxes (1,142,147,641) (501,586,949) (208,645,934)

(501,586,949)

(208,645,934)

(424,715,966)

Future net cash flows 5,330,720,359 2,608,927,801 1,408,004,325

2,608,927,801

1,408,004,325

2,183,711,860

10% annual discount for estimated timing of cash flows (3,058,606,841) (1,471,562,953) (852,133,072)

(1,471,562,953)

(852,133,072)

(1,260,536,809)

Standardized Measure of Discounted Future Net Cash Flows $ 2,272,113,518 $ 1,137,364,848 $ 555,871,253

1,137,364,848

The changes in the standardized measure of discounted future net cash flows relating to the proved oil and natural gas reserves are shown below.

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

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Sales of oil and gas produced, net of production costs (283,588,498) (154,615,685) (70,634,853)

(154,615,685)

(137,663,314)

Sales of minerals in place — (2,523,746) —

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Net changes in price and production costs 646,819,172 636,884,944 (368,974,767)

(368,974,767)

(219,608,128)

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)

(126,143,669)

Changes in estimated timing of cash flows (119,428,019) 86,845,188 (139,039,115)

(139,039,115)

(107,443,484)

Net change in income taxes (306,810,205) (112,496,394) 97,384,365

(112,496,394)

End of the Year $ 2,272,113,518 $ 1,137,364,848 $ 555,871,253

1,137,364,848

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

Discounted Future

Future Capital

Pre-tax PV-10

Net Cash Flows

(In thousands)

(In thousands) Future Capital

(In thousands)

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

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

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

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.

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).

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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.

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, 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.

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.

Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves

Estimated Oil

Estimated Gas

Developed (Bbls)

Developed (Mcf)

Year Estimated Oil

Developed (Bbl) Estimated Gas

Developed (Mcf) Estimated NGL

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 (“CGA”), a leader of petroleum property analysis for industry and financial institutions.

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.

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• the judgment of the personnel preparing the estimates.

Ring’s Executive Vice President of Engineering and Corporate Strategy, Mr.

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 15 years of practical industry experience, including over 11 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:

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.

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;

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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.

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 petroleum consultants that prepare estimates of proved reserves.

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

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Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.

Developed Acreage

Undeveloped Acreage

Total Acreage

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

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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 lessor and lessee.

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:

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

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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

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:

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

Central Basin Platform 1,409,211 867,835 958,691

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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

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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)

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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)

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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.

Production Prices and Production Costs

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Years ended December 31,

2022 2021 2020

Average sales price:

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Northwest Shelf 93.44 67.61 38.93

Total $ 92.80 $ 67.56 $ 38.95

Natural gas (per Mcf)

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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)

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Northwest Shelf 79.24 62.38 34.86

Total $ 76.95 $ 63.14 $ 35.13

For periods prior to July 1, 2022, sales and reserve volumes, prices, and revenues for natural gas liquids were presented with natural gas.

Years ended December 31,

2022 2021 2020

Average lease operating expenses (per Boe)

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Northwest Shelf 6.74 5.34 4.91

Total $ 10.57 $ 9.75 $ 9.25

Average gathering, transportation and

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Northwest Shelf 0.73 2.10 2.07

Total $ 0.41 $ 1.39 $ 1.27

Average ad valorem taxes (per Boe)

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Northwest Shelf 1.00 0.57 0.60

Total $ 1.04 $ 0.73 $ 0.97

Average production taxes (per Boe)

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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.

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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 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.

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.

The table below contains information regarding the number of wells drilled and participated in during the periods indicated.

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

Productive — — — — — —

Dry — — — — — —

Productive 32.00 31.35 11.00 9.91 6.00 5.61

Dry — — — — — —

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

Productive — — — — — —

Dry — — — — — —

Productive 3.00 0.33 2.00 0.23 1.00 0.11

Dry — — — — — —

Productive 3.00 0.33 2.00 0.23 1.00 0.11

Dry — — — — — —

Present Activities

We had no wells in the process of being drilled or completed as of December 31, 2021.

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, 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.

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.

Costs incurred for property acquisition, exploration and development activities for the years ended December 31, 2022, 2021 and 2020 are shown below:

Wishbone Acquisition (1)

2022 2021 2020

Stronghold Acquisition $ 177,823,787 $ — $ —

Acquisition of proved properties 1,563,703 1,368,437 1,317,313

2 unchanged sentences

Total costs incurred $ 308,695,945 $ 50,670,568 $ 43,775,058

(1) Wishbone Acquisition in 2019 includes $28.3 million in fair value of stock issued as consideration in acquisitions.

Other Properties and Commitments

3 unchanged sentences

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.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 2. Properties