What changed in this filing

/stocks — the workspaceLOADING

Item 2. Properties

2024-03-07 compared with 2023-03-09 · 106 added, 94 removed, 285 unchanged (41% of the section changed)

6 unchanged sentences

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.

As of December 31, 2023, we owned interests in a total of 76,484 gross (65,462 net) developed acres and operate the vast

majority of our acreage position.

In addition, as of December 31, 2023, we owned interests in approximately 19,643 gross (15,073 net) undeveloped acres.

While our near-term plans are focused on drilling wells on our existing acreage to develop the potential contained therein, our long-term plans also include continuing to evaluate acquisition and leasing opportunities that can earn attractive rates of return on capital employed.

Within the Northwest Shelf, we have a total of 73 proved undeveloped locations (85% horizontal and 15% vertical) and 19 PDNP opportunities based on the reserve report as of December 31, 2022.

Our reserve estimates account for the capital costs required to develop these wells.

Within the Northwest Shelf, we have a total of 48 proved undeveloped locations (100% horizontal) and 4 PDNP opportunities based on the reserve report as of December 31, 2023.

Our reserve estimates account for the capital costs required to develop these wells and the future plugging and abandonment cost.

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.

Within the Central Basin Platform, we had a total of 163 proved undeveloped locations (13% horizontal and 87% vertical) and 238 PDNP opportunities based on the reserve report as of December 31, 2023.

Our reserve estimates account for the capital costs required to develop these wells.

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The Company's significant operations are in two core areas which it has actively drilled over the last several years located in the Northwest Shelf and the Central Basin Platform of the Permian Basin.

Northwest Shelf –Yoakum, Runnels and Coke County, Texas and Lea County, New Mexico – In 2019, we acquired properties consisting of 49,754 gross (38,230 net) acres with an average working interest of 77% and an average net revenue interest of 58%.

As of December 31, 2022, we owned interests in a total of 18,270 gross (13,930 net) developed acres and 18,539 gross (12,512 net) undeveloped acres.

As of December 31, 2022, the Company had interests in approximately 27 gross vertical and 139 horizontal producing wells, of which we operate 27 vertical and 108 horizontal wells.

Northwest Shelf –Yoakum 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, 2023, we owned interests in a total of 12,572 gross (8,751 net) developed acres and 16,258 gross (12,405 net) undeveloped acres with an average proved operated working interest of 89% and net revenue interest of 67%.

As of December 31, 2023, the Company had interests in approximately five gross vertical and 146 gross horizontal producing wells, of which we operate five vertical and 111 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.

Central Basin Platform - Andrews, Gaines, Crane, Ector, Winkler, and Ward Counties, Texas – In 2011, we acquired a 100% working interest and a 75% net revenue interest in our initial leases in Andrews and Gaines counties.

Since that time, we have acquired working and net revenue interests in additional producing leases and acquired additional undeveloped acreage in and around our Andrews County and Gaines County leases.

In 2022, we acquired properties consisting of approximately 37,000 net acres, with an average working interest of 99% and an average net revenue interest of 88% for oil and 96% for natural gas in our initial leases in Crane, Winkler, and Ward counties.

As of December 31, 2022, we owned interests in a total of 64,774 gross (54,959 net) developed acres and 3,905 gross (2,337 net) undeveloped acres.

As of December 31, 2022, the Company had interests in approximately 625 gross vertical and 195 horizontal producing wells, of which we operate 518 vertical and 193 horizontal wells.

In 2023, we acquired properties in Ector County.

As of December 31, 2023, we owned interests in a total of 63,912 gross (56,711 net) developed acres and 3,385 gross (2,668 net) undeveloped acres with an average proved operated working interest of 97% and net revenue interest of 82% in the area.

As of December 31, 2023, the Company had interests in approximately 695 gross vertical and 197 gross horizontal producing wells, of which we operate 587 vertical and 195 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 .

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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.

We do not believe any of these burdens materially interfere with our use of these properties.

Summary of Oil and Natural Gas Reserves

As of December 31, 2022, our estimated proved reserves had a pre-tax PV-10 value (present value discounted at 10%) of approximately $2,773.7 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $2,272.1 million, 100% of which relates to our properties in the Permian Basin in Texas and New Mexico.

As of December 31, 2023, our estimated proved reserves had a pre-tax PV-10 value (present value discounted at 10%) of approximately $1,647.0 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $1,399.2 million, over 99.6% of which relates to our properties in the Permian Basin in Texas.

We spent approximately $544.2 million on acquisitions and capital projects during 2023 and 2022.

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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, 2023.

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

Approximately 99.8% of our proved reserves are in the Permian Basin in Texas.

(Bbl) Natural

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("CGA"), independent petroleum engineers.

These reserves are attributable solely to properties within the United States.

These reserves are

attributable solely to properties within the United States.

A summary of the changes in quantities of proved (developed and undeveloped) oil, natural gas and natural gas liquid reserves is shown below.

Oil (Bbl) Gas (Mcf) Natural Gas Liquids (Bbl) (2)

Oil (Bbl) Gas (Mcf) (2)

Natural Gas Liquids (Bbl) (2)

Balance, December 31, 2021 65,838,609 71,773,789 — 77,800,907

7 unchanged sentences

Extensions, discoveries and improved recovery 3,098,845 4,113,480 1,014,343 4,798,768

Sales of minerals in place (4,897,921) (2,674,955) (392,953) (5,736,700)

Production (4,579,942) (6,339,158) (976,852) (6,613,320)

3 unchanged sentences

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

(2) At year-end 2022, we began reporting reserves on a three-stream basis, including natural gas liquids separately from natural gas.

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

During the year ended December 31, 2022, our extensions and discoveries of 769 MBoe (one thousand Boe) resulted primarily from the 2022 operated drilling program in the Northwest Shelf and Central Basin Platform as well as non-operated activity in the Northwest Shelf.

Revisions of 1,186 MBoe were predominately the result of converting from two-stream to three-stream reserves, the removal of proved undeveloped reserves in our Delaware asset, well performance, increased cost from 2022 industry activity, and increased commodity pricing.

(2) At year-end 2022, we began reporting reserves on a three-stream basis, including NGLs 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, five year rule and/or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

Notable changes in proved reserves for the year ended December 31, 2023 included the following:

• Extensions.

In 2023, extensions of 4.8 MMBoe were primarily the result of the successful operated drilling program and non-operated activity in the Northwest Shelf and Central Basin Platform.

• Purchase of minerals in place.

In 2023, the Company completed the acquisition of Founders oil and gas leases and related property within Ector County that resulted in 8.2 MMBoe in additional reserves.

• Sales of minerals in place.

In 2023, the Company sold 5.7 MMBoe from the divestiture of the Delaware Basin assets (30%), the New Mexico operated assets (57%), and part of the Company's assets in Gaines County (13%).

• Revision of previous estimates.

In 2023, the negative revisions of prior reserves of 9.0 MMBoe consisted of 5.3 MMBoe (59%) related to changes in price and 3.7 MMBoe (41%) related to changes in performance and other economic factors.

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

15 unchanged sentences

Total 129,759,229 138,122,143

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

Standardized Measure of Discounted Future Net Cash Flows

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Our estimates of reserves and future cash flow as of December 31, 2023 and 2022 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, 2023 and 2022, respectively, in accordance with SEC guidelines.

As of December 31, 2022, our reserves are based on an SEC average price of $90.15 per Bbl of WTI oil posted and $6.358 per MMBtu of Henry Hub natural gas.

As of December 31, 2021, our reserves are based on an SEC average price of $63.04 per Bbl of WTI oil posted and $3.598 per MMBtu Henry Hub natural gas.

As of December 31, 2023, our reserves were based on an SEC average price of $74.70 per Bbl of WTI oil posted and $2.637 per MMBtu of Henry Hub natural gas.

As of December 31, 2022, our reserves were based on an SEC average price of $90.15 per Bbl of WTI oil posted and $6.358 per MMBtu Henry Hub natural gas.

Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines.

1 Six Mcf is deemed the equivalent of one Boe.

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

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

Standardized Measure of Discounted Future Net Cash Flows

3 unchanged sentences

Future development costs (1)

(562,063,424) (647,196,750) (347,757,000)

Future income taxes (548,664,988) (1,142,147,641) (501,586,949)

2 unchanged sentences

Standardized Measure of Discounted Future Net Cash Flows $ 1,399,185,191 $ 2,272,113,518 $ 1,137,364,848

(1) Future development costs include not only development costs but also future asset retirement costs.

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.

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Our proved reserves by state as of December 31, 2023 are summarized in the table below.

Oil (Bbl) Gas (Mcf) Natural Gas Liquids (NGL) (Bbl) Total (Boe) % of Total

Oil (Bbl) Gas (Mcf) NGL (Bbl)

Total (Boe) % of Total

Proved Pre-tax PV-10

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Proved Reserves

As of December 31, 2022, we had approximately 138.1 MMBoe (one million Boe) of proved reserves, consisting of approximately 64% oil, 19% natural gas, and 17% natural gas liquids, as summarized in the table above.

As of December 31, 2023, we had approximately 129.8 MMBoe (one million Boe) of proved reserves, consisting of approximately 63% oil, 19% natural gas, and 18% NGLs, as summarized in the table above.

Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC).

As of December 31, 2022, approximately 65% of the proved reserves have been classified as proved developed, or “PD” and the remaining 35% are proved undeveloped, or “PUD”.

As of December 31, 2023, approximately 68% of the proved reserves have been classified as PD and the remaining 32% are PUD.

As of December 31, 2023, our total proved reserves had a net pre-tax PV-10 value of approximately $1,647.0 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $1,399.2 million.

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Proved Undeveloped Reserves

Our reserve estimates as of December 31, 2022 include approximately 48.0 MMBoe as proved undeveloped reserves (PUD).

Our reserve estimates as of December 31, 2023 include approximately 41.6 MMBoe as PUDs.

As of December 31, 2022, our reserve estimates included approximately 48.0 MMBoe as proved undeveloped reserves.

In accordance with our December 31, 2023 year-end independent engineering reserve report, we plan to drill our PUD drilling locations within five years of original classification.

Below is a description of the changes in our PUD reserves from December 31, 2022 to December 31, 2023.

Notable changes in proved undeveloped reserves for the year ended December 31, 2023 included the following:

• Conversions to developed.

During the year ended December 31, 2023, we incurred costs of approximately $90.3 million to convert 27 properties from PUD to PD through development.

These 27 properties produced 573 MBoe during the year ended December 31, 2023, and have reserves of 7,068 MBoe as of December 31, 2023.

The increase in proved undeveloped reserves was primarily attributable to the Stronghold Acquisition.

• Extensions.

In 2023, extensions of 3.7 MMBoe were primarily the result of the successful operated drilling program and non-operated activity in the Northwest Shelf and Central Basin Platform.

• Purchase of minerals in place.

In 2023, we completed the acquisition of Founders oil and gas leases and related property within Ector county that resulted in 3.7 MMBoe in additional reserves.

• Sales of minerals in place.

In 2023, we sold 1.3 MMBoe from the divestiture of the New Mexico operated assets (81%), and a subset of our assets in Gaines County (19%).

• Revision of previous estimates.

In 2023, the negative revisions of prior reserves of 4.9 MMBoe consisted of 0.8 MMBoe (16%) related to changes in price and 4.1 MMBoe (84%) related to changes in performance and other economic factors.

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.

Our PUD reserves are part of a management adopted development plan that schedules PUD reserves to be developed within five years of initial disclosure as proved reserves.

As of December 31, 2023, no material amount of proved undeveloped reserves were not scheduled to be converted to proved developed status within five years they were initially disclosed.

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

9 unchanged sentences

26,112,238 46,500,300 7,768,657 41,630,945 $ 408,233,882

31,692,604 51,471,400 7,772,855 48,044,027 $ 462,543,818

Preparation and Internal Controls Over Reserves Estimates

All the proved oil and natural gas reserves disclosed in this Report are based on reserve estimates determined and prepared by independent reserve engineers Cawley, Gillespie & Associates, Inc.

All the proved oil and natural gas reserves disclosed in this Report are based on reserve estimates determined and prepared by our 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.

Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated February 3, 2023, filed as an exhibit to this Annual Report on Form 10-K, was Mr.

Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated January 26, 2024, filed as an exhibit to this Annual Report, was Mr.

Zane Meekins.

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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.

The proved oil and natural gas reserves disclosed in this Annual Report are based on reserve estimates determined and prepared by our 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.

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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 data was reviewed by various levels of management for accuracy before consultation with our

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.

Internal reserve estimates were compared to those prepared by CGA to test the estimates and conclusions before the reserves were included in this Annual Report.

The accuracy of the reserve estimates is dependent on many factors, including the following:

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• 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;

• ensuring the information provided by other departments within the Company, such as accounting, land, and operations is accurate;

• communicating, collaborating, and analyzing with technical personnel in our business units;

1 unchanged sentence

• 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.

Each quarter, the Corporate Reserves team along with the Executive Vice President of Engineering and Corporate Strategy presents the status of the Company’s reserves to senior executives, and subsequently obtains approval of significant changes from key executives.

Additionally, our five-year PUD development plan is reviewed and approved annually by the Company’s Chief Executive Officer, Chief Financial Officer, Executive Vice President of Operations, and the Executive Vice President of Land, Legal, Human Resources, and Marketing.

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Summary of Oil and Natural Gas Properties and Projects

The following table summarizes gross and net developed and undeveloped acreage as of December 31, 2022 by region (net acreage is our percentage ownership of gross acreage).

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

The following table summarizes our gross and net developed and undeveloped acreage as of December 31, 2023 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, as it is de minimis.

Developed Acreage Undeveloped Acreage Total Acreage

1 unchanged sentence

Central Basin Platform 63,912 56,711 3,385 2,668 67,297 59,379

Delaware Basin 18,729 18,437 — — 18,729 18,437

Northwest Shelf 12,572 8,751 16,258 12,405 28,830 21,156

Total 76,484 65,462 19,643 15,073 96,127 80,535

Leases of undeveloped acreage will generally expire at the end of their respective primary terms unless production from such leasehold acreage has been established prior to expiration of such primary term.

If production is established on such acreage, the lease will generally remain in effect until the cessation of production from such acreage and is referred to in the industry as “Held-By-Production” or “HBP.” Leases of undeveloped acreage may terminate or expire as a result of not meeting certain drilling commitments, if any, or otherwise by not complying with the terms of a lease depending on the specific terms that are negotiated between the lessor and the lessee.

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:

If production is established on the acreage, the lease will generally remain in effect until the cessation of production from the acreage and is referred to in the industry as HBP.

Leases of undeveloped acreage may terminate or expire as a result of not meeting certain drilling commitments, if any, or otherwise by not complying with the terms of a lease depending on the specific terms that are negotiated between the lessor and the lessee.

The following table sets forth our gross and net undeveloped acreage, as of December 31, 2023, under lease that 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

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Central Basin Platform 1,800 1,046 1,240 100 720 239

Delaware Basin — — — — — —

Northwest Shelf 8,475 1,481 8,946 3,496 3,015 454

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Delaware Basin (2)

25,743 81,936 104,129

Northwest Shelf 2,207,131 1,968,693 1,714,976

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Delaware Basin (2)

11,265 96,516 288,918

Northwest Shelf 2,387,786 2,428,318 2,074,580

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Delaware Basin (2)

2,867 3,718 —

Northwest Shelf 270,167 139,615 —

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Delaware Basin (2)

30,488 101,740 152,282

Northwest Shelf 2,875,262 2,513,028 2,060,739

5 unchanged sentences

Total 18,119 12,364 8,518

(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.

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

(2) The Delaware Basin assets were sold with a closing date of May 11, 2023 and an effective date of March 1, 2023.

Production Prices and Production Costs

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Oil (per Bbl)

Central Basin Platform $ 91.72 $ 67.66 $ 39.64

Delaware Basin 95.97 65.98 35.00

Northwest Shelf 93.44 67.61 38.93

Total $ 92.80 $ 67.56 $ 38.95

$ 76.21 $ 92.80 $ 67.56

Natural gas (per Mcf) (1)

Central Basin Platform $ 3.72 $ 4.63 $ 1.12

Delaware Basin 5.26 4.75 0.54

Northwest Shelf 5.09 6.08 1.91

Total $ 4.57 $ 5.83 $ 1.57

Natural gas liquids (per Bbl) (1)

Central Basin Platform $ 20.02 $ — $ —

Delaware Basin 27.16 — —

Northwest Shelf 20.25 — —

Total $ 20.18 $ — $ —

$ 0.05 $ 4.57 $ 5.83

NGL (per Bbl) (1)

$ 11.95 $ 20.18 $ —

Total (per Boe)

Central Basin Platform $ 73.58 $ 66.42 $ 38.17

Delaware Basin 83.28 54.13 24.57

Northwest Shelf 79.24 62.38 34.86

Total $ 76.95 $ 63.14 $ 35.13

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

$ 54.60 $ 76.95 $ 63.14

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

Years ended December 31,

2023 2022 2021

Average lease operating expenses (per Boe)

Central Basin Platform $ 13.81 $ 15.97 $ 15.44

Delaware Basin 44.86 32.75 19.13

Northwest Shelf 6.74 5.34 4.91

Total $ 10.57 $ 9.75 $ 9.25

Average gathering, transportation and

processing costs (per Boe)

Central Basin Platform $ — $ — $ —

Delaware Basin — — —

Northwest Shelf 0.73 2.10 2.07

Total $ 0.41 $ 1.39 $ 1.27

Average ad valorem taxes (per Boe)

Central Basin Platform $ 1.11 $ 1.17 $ 1.82

Delaware Basin 0.41 0.33 0.50

Northwest Shelf 1.00 0.57 0.60

Total $ 1.04 $ 0.73 $ 0.97

Average production taxes (per Boe)

Central Basin Platform $ 3.64 $ 2.85 $ 1.67

Delaware Basin 3.97 2.45 1.30

Northwest Shelf 3.91 3.01 1.64

Total $ 3.80 $ 2.93 $ 1.63

The average oil sales price amounts above are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels “Bbl.” The average natural gas sales price amounts above are calculated by dividing revenue from natural gas sales by the volume of natural gas sold, in thousand cubic feet “Mcf.” The average natural gas liquids sales price amounts above are calculated by dividing revenue from natural gas liquids sales by the volume of natural gas liquids sold, in barrels “Bbl.”The total average sales price amounts are calculated by dividing total revenues by total volume sold, in Boe.

Average production costs (per Boe):

Lease operating expenses

$ 10.61 $ 10.57 $ 9.75

Gathering, transportation and processing costs

$ 0.07 $ 0.41 $ 1.39

Ad valorem taxes

$ 1.02 $ 1.04 $ 0.73

Production taxes

$ 2.74 $ 3.80 $ 2.93

The average oil sales price amounts above are calculated by dividing revenue from oil sales by the volume of oil sold, in Bbls.

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 Mcf.

The average NGL sales price amounts above are calculated by dividing revenue from NGL sales by the volume of NGLs sold, in Bbls.

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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The following table presents our ownership as of December 31, 2023 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.

Over 99.8% of such wells are in the Permian Basin in Texas.

Oil Wells Gas wells Total Wells

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Drilling Activity

During 2022, we drilled 18.00 gross (17.35 net) horizontal San Andres wells in the Northwest Shelf (16.00 1.0-mile laterals and two 1.5-mile laterals.) In addition, we drilled 14.00 gross (14.00 net) wells in the Central Basin Platform, of which nine were horizontal San Andres wells in Andrews County, Texas (four 1.0-mile laterals and five 1.5-mile laterals) and five were vertical wells in Crane County, Texas.

In addition, we also participated in three gross (0.33 net) non-operated wells in the Northwest shelf.

During 2023, as operator, we drilled a total of 31.00 gross (29.75 net) wells.

Of this, 14.00 gross (12.75 net) horizontal San Andres wells were in the Northwest Shelf (nine 1.0-mile laterals and five 1.5-mile laterals.) and 17.00 gross (17.00 net) wells were in the Central Basin Platform, of which six were horizontal San Andres wells in Andrews County, Texas (two 1.0-mile laterals and four 1.5-mile laterals) and 11.00 were vertical wells in Crane County, Texas.

In addition, we also participated in five gross (0.59 net) non-operated wells of which three were Northwest Shelf and two in Central Basin Platform.

These wells were successful and there were no dry wells.

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

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

For the year ended December 31,

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2023 2022 2021

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

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

Divestiture of proved properties (23,700) (2,000,000) —

Development costs 129,332,155 51,302,131 42,457,745

Payments to acquire oil and natural gas properties

$ 82,900,900 $ 179,387,490 $ 1,368,437

Payments to explore oil and natural gas properties

Payments to develop oil and natural gas properties 152,559,314 129,332,155 51,302,131

Total costs incurred

$ 235,460,214 $ 308,719,645 $ 52,670,568

Other Properties and Commitments

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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