# EDGAR Filing Document

**Accession Number:** 0001811074
**File Stem:** 0001104659-25-098757
**Filing Date:** 2025-10
**Character Count:** 40211
**Document Hash:** 008bb6b0aaf6b2e17d8e549f9814a63c
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0001104659-25-098757.hdr.sgml**: 20260417

**ACCESSION NUMBER**: 0001104659-25-098757

**CONFORMED SUBMISSION TYPE**: CORRESP

**PUBLIC DOCUMENT COUNT**: 3

**FILED AS OF DATE**: 20251010

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** Texas Pacific Land Corp
- **CENTRAL INDEX KEY:** 0001811074
- **STANDARD INDUSTRIAL CLASSIFICATION:** OIL ROYALTY TRADERS [6792]
- **ORGANIZATION NAME:** 01 Energy & Transportation
- **EIN:** 750279735
- **STATE OF INCORPORATION:** DE
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** CORRESP

**BUSINESS ADDRESS:**
- **STREET 1:** 2699 HOWELL STREET
- **STREET 2:** SUITE 800
- **CITY:** DALLAS
- **STATE:** TX
- **ZIP:** 75204
- **BUSINESS PHONE:** 214-969-5530

**MAIL ADDRESS:**
- **STREET 1:** 2699 HOWELL STREET
- **STREET 2:** SUITE 800
- **CITY:** DALLAS
- **STATE:** TX
- **ZIP:** 75204

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| ![](tm2528543d1_correpimg01.jpg) | ![](tm2528543d1_correpimg02.jpg) |

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October 10, 2025

**<u>VIA EDGAR</u>**

U.S. Securities and Exchange Commission

100 F Street, N.E.

Division of Corporation Finance

Office of Energy & Transportation

Washington, D.C. 20549

Attention: Joseph Klinko, Mark Wojciechowski,

Sandra Wall and Brad Skinner

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| **Re:** | **Texas Pacific Land Corporation <br> Form 10-K for the Fiscal Year ended December 31, 2024<br> Filed February 19, 2025<br> File No. 001-39804** |

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Ladies and Gentlemen:

On behalf of Texas Pacific Land Corporation (the "*Company*"), below is the response of the Company to the comments of the staff (the "*Staff*") of the Securities and Exchange Commission (the "*Commission*") set forth in the letter from the Division of Corporation Finance and Office of Energy & Transportation, dated September 19, 2025, with respect to the above-referenced filing.

To assist with your review, we have repeated the text of the Staff's comments in italic type immediately preceding our response.

<u>Form 10-K for the Fiscal Year ended December 31, 2024</u> 

<u>Properties, page 17</u>

1. *Please expand your filing to include a summary of your oil and gas reserves at fiscal year-end. Refer to the disclosure requirements in Items 1202(a)(1) through 1202(a)(4) of Regulation S-K.* 

<u>RESPONSE</u>:

The Company acknowledges the Staff's comment and respectfully advises that the Company intends to include the requested information in "Item 2. Properties" in its Form 10-K for the fiscal year ending December 31, 2025, which the Company expects to file with the Commission in February 2026. Please see the section titled "Summary of Estimated Proved Developed Producing ("PDP") Reserves" in the attached <u>Annex B</u> for an example of the Company's planned disclosure.

2. *We note that you have not previously disclosed reserves estimates in a filing with the Commission and that you are disclosing material additions to your reserves estimates. Accordingly, explain to us how you considered providing a general discussion of the technologies used to establish the appropriate level of certainty for reserves estimates from material properties included in the total reserves disclosed. See Item 1202(a)(6) of Regulation S-K.* 

<u>RESPONSE</u>:

To establish reasonable certainty for its estimated proved reserves, the technologies and economic data used in the estimation included actual production data, downhole completion information, geologic data, and historical well cost and operating expense data. The Company intends to include the requested information in "Item 2. Properties" in its Form 10-K for the fiscal year ending December 31, 2025, which the Company expects to file with the Commission in February 2026. Please see the section titled "Proved Reserves Evaluation and Review of Estimated Proved Producing Reserves" in the attached <u>Annex B</u> for an example of the Company's planned disclosure.

U.S. Securities and Exchange Commission

Division of Corporation Finance

Office of Finance

Office of Energy & Transportation

October 10, 2025

3. *Disclose and describe the internal controls you use in your reserves estimation effort. In addition, disclose the qualifications of the technical person primarily responsible for overseeing the preparation of the reserves estimates and, if you represent that a third party conducted a reserves audit, disclose the qualifications of the technical person primarily responsible for overseeing such reserves audit. See Item 1202(a)(7) of Regulation S-K.* 

<u>RESPONSE</u>:

The Company acknowledges the Staff's comment and respectfully advises that the Company intends to include the requested information in "Item 2. Properties" in its Form 10-K for the fiscal year ending December 31, 2025, which the Company expects to file with the Commission in February 2026. Please see the section titled "Proved Reserves Evaluation and Review of Estimated Proved Producing Reserves" in the attached <u>Annex B</u> for an example of the Company's planned disclosure.

4. *Expand your disclosure to include total gross and net productive wells, expressed separately for oil and gas, associated with your interests. Refer to the disclosure requirements in Item 1208(a) of Regulation S-K.* 

<u>RESPONSE</u>:

The Company acknowledges the Staff's comment and respectfully advises that the Company intends to include the requested information in "Item 2. Properties" in its Form 10-K for the fiscal year ending December 31, 2025, which the Company expects to file with the Commission in February 2026. Please see the section titled "Productive Wells" in the attached <u>Annex B</u> for an example of the Company's planned disclosure.

 

5. *Please expand your acreage disclosure to provide a break-out of gross and net developed and undeveloped acreage. Refer to the disclosure requirements in Item 1208(b) of Regulation S-K.* 

<u>RESPONSE</u>:

The Company acknowledges the Staff's comment and respectfully advises that the Company only reports reserves for producing properties and does not maintain a list of undeveloped properties. Because (i) the mineral owner of the Company's legacy non-participating royalty interest (Chevron USA, Inc.) often elects to self-develop or jointly develop minerals without leasing, and (ii) as a non-participating royalty owner, the Company has little insight into leasing and planned development, the Company believes it would be misleading to categorize all of its non-producing acreage as undeveloped acreage.

<u>Management's Discussion and Analysis of Financial Condition and Results of Operations Year Ended December 31, 2024 Compared to Year Ended December 31, 2023 Land and Resource Management, page 26</u>

6. *Please expand your disclosure to provide the last three fiscal years of production and average sales prices. Refer to the disclosure requirements in Item 1204 of Regulation S-K.* 

<u>RESPONSE</u>:

The Company acknowledges the Staff's comment and respectfully advises that the Company intends to provide the requested information in "Item 1. Business – Business Segments – Land and Resource Management" in its discussion of "Operations of the Land and Resource Management Segment" in its Form 10-K for the fiscal year ended December 31, 2025, which the Company expects to file with the Commission in February 2026. The Company believes this placement is more appropriate in "Item 1. Business" as its discussion in "Results of Operations" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" focuses on current year results as opposed to results from the prior year. Please see the section titled "Operations" in attached <u>Annex A</u> for an example of the Company's planned disclosure.

U.S. Securities and Exchange Commission

Division of Corporation Finance

Office of Finance

Office of Energy & Transportation

October 10, 2025

<u>Non-GAAP Performance Measures, page 27</u>

7. *We note your presentation of a non-GAAP financial measure titled 'Free Cash Flow'. Please address the following:* 

 

· *You identify Free Cash Flow as performance measure, but the label suggests it may be a liquidity measure. Tell us the specific facts and circumstances that led you to conclude this is a performance measure. If you continue to believe Free Cash Flow is a performance measure, tell us how you determined it is appropriate to exclude cash-based adjustments in the calculation of a performance measure. Refer to Questions 100.01 and 100.05 of the Non-GAAP Financial Measures C&DI's.* 

 

· *Regardless of whether you conclude Free Cash Flow is a performance or liquidity measure, please revise your non-GAAP reconciliation to reconcile the measure to the most directly comparable GAAP measure, rather than presenting a "compound" reconciliation from Net Income to Adjusted EBITDA then to Free Cash Flow.* 

 

· *Please disclose the reasons why you believe Free Cash Flow provides useful information to investors and any additional purposes for which management uses this measure. Refer to Items 10(e)(1)(i)(C) and (D) of Regulation S-K.* 

 

· *Finally, we note you define Free Cash Flow as Adjusted EBITDA less current income tax expense and capital expenditures. Per your consolidated Statement of Cash Flows, Cash flows from investing activities, total capital expenditures (excluding acquisitions of a business) appears to be $426.7 million ($395,577 + $1,476 + $29,696). Please revise your reconciliation accordingly, or tell us why the amount presented in the reconciliation differs from this amount, and explain the differences.* 

 

*This comment also applies to your Forms 10-Q and earnings releases.*

<u>RESPONSE</u>:

The Company acknowledges the Staff's comment and respectfully advises that the Company believes that free cash flow is an important performance metric for measuring the Company's performance for investors, and the Company does not consider this metric to be a liquidity measure. Due to the Company's unique history, a sizable amount of the Company's value is recorded at a zero-book basis (*i.e.*, approximately 800,000 surface acres and approximately 455,000 gross royalty acres in West Texas), resulting in a low book value for the Company. Further, each of the Company's business segments has high margins with low capital expenditure requirements, and the Company maintains a conservative capital structure with limited to no debt. As noted in Note 11, "Income Taxes" of the Company's Consolidated Financial Statements included in its Form 10-K for the fiscal year ended December 31, 2024, the Company's effective income tax rate was 21.6% due in large part to its low book value and high-margin business segments, thus the Company pays significant income taxes at or near the corporate tax rate. The Company further believes free cash flow demonstrates the cash available for investing and returning capital to its stockholders through dividends and share repurchases. We believe that investors appreciate that the nature of the Company's business is high margin, with a low capital expenditure burden and conservative capital structure, and that free cash flow best reflects the overall performance of the Company.

U.S. Securities and Exchange Commission

Division of Corporation Finance

Office of Finance

Office of Energy & Transportation

October 10, 2025

Secondarily, as noted in the section titled "2024 Compensation Program" in the "2024 Annual (Short-Term) Incentive Program Summary" and the "2024 Long-Term Incentive Program" sub-sections on pages 47 and 48 of its Form 10-K for the fiscal year ended December 31, 2024, incentive compensation for the Company's Named Executive Officers (the "*NEOs*") is dependent upon not only achievement of strategic objectives set by the Compensation Committee of the Board of Directors (the "*Compensation Committee*"), but also upon two performance metrics: (i) adjusted EBITDA and (ii) free cash flow. The Company reports both of these performance metrics as non-GAAP performance measures beginning on page 27 of the Form 10-K for the fiscal year ended December 31, 2024. The Compensation Committee implemented these two measures as part of the Company's incentive compensation program to increase alignment between the NEOs' interests and the interests of the Company's stockholders. Specifically, generating free cash flow enables greater returns to stockholders in the form of dividends and share repurchases. As noted on page 47 of the Company's Form 10-K for the fiscal year ended December 31, 2024, the weighting of free cash flow per fully diluted share on the Company's 2024 annual short-term incentive program was increased from 37.5% to 50% after considering feedback from the Company's stockholders, further highlighting the importance of free cash flow as a performance measure.

In further response to the Staff's comments identified in the second bullet point above, the Company intends to include a separate reconciliation of net income to free cash flow in its reconciliation of "Non-GAAP Performance Measures" in its Form 10-K for the fiscal year ending December 31, 2025, which the Company intends to file with the Commission in February 2026. Please see the attached <u>Annex C</u> for an example of the Company's planned disclosure. Additionally, the Company intends to apply these same changes to its Form 10-Q and earnings release for the third quarter of 2025, which the Company expects to file with the Commission in November 2025.

Regarding the third bullet point above, the Company intends to disclose its rationale for why it believes free cash flow provides useful information to investors and how management uses the metric to measure its own performance for compensation purposes in its Form 10-K for the fiscal year ending December 31, 2025, which the Company expects to file with the Commission in February 2026. Please see the attached <u>Annex C</u> for a draft of the Company's planned disclosure. Additionally, the Company intends to apply these same changes to its Form 10-Q and earnings release for the third quarter of 2025, which the Company intends to file with the Commission in November 2025.

Regarding the fourth bullet point above, the Company's definition of free cash flow relates specifically to ongoing capital expenditures required of its business and does not include adjustments for acquisitions of royalty interests, real estate or businesses. The Company intends to adjust its line-item descriptions in its reconciliation of net income to free cash flow to match the line-item descriptions on the statement of cash flows in its Form 10-K for the fiscal year ending December 31, 2025, which the Company expects to file with the Commission in February 2026. Please see the attached <u>Annex C</u> for an example of the Company's planned disclosure. Additionally, the Company intends to apply these same changes to its Form 10-Q and earnings release for the third quarter of 2025, which the Company intends to file with the Commission in November 2025.

<u>Supplemental Oil and Gas Reserve Information (Unaudited)</u>

<u>Analysis of Changes in Oil and Natural Gas PDP Reserves, page F-32</u>

8. *We note your disclosure on page 3 that the average realized price received per Boe during the year 2024 decreased 6.4% from the year 2023; however, the reconciliation of the changes in proved reserves during 2024 does not include a negative revision due to prices. Please review and revise your disclosure to identify and quantify the net amount of change due to the decrease in commodity prices, and any other contributing factors, including offsetting factors, so the change due to revisions of prior estimates is fully explained. Refer to the disclosure requirements in FASB ASC 932-235-50-5(a).* 

<u>RESPONSE</u>:

The Company acknowledges the Staff's comment and respectfully advises that, as noted in the second paragraph on page F-32 of its Form 10-K for the fiscal year ended December 31, 2024, reserve studies were not completed in prior periods. The comparative information presented is based upon the reserve report as of December 31, 2024, and the Company rolled back actual volumes from 2024 to 2021. Based on the conservative well life estimates used and the robust economics of Permian wells, the Company believes it is unlikely that Permian wells will need revision absent a significant market change in price. Accordingly, there were no prior estimates to be revised for these time frames. The Company intends to add a line item for revisions to this table in future years that will reflect revisions made during the year. For the Company's Form 10-K for the fiscal year ending December 31, 2025 and the Company's subsequent Form 10-K filings, a line item for revisions will be added to this table for the period from December 31, 2024 to December 31, 2025.

U.S. Securities and Exchange Commission

Division of Corporation Finance

Office of Finance

Office of Energy & Transportation

October 10, 2025

In subsequent filings, the Company intends to include all periods that are presented in the change in estimated reserves table in the summary table.

9. *Please expand the disclosure of the net developed reserves appearing below the table of changes in estimated reserves to include the volumes as of the beginning of the earliest period presented, i.e. as of December 31, 2021. Refer to the disclosure requirements in FASB ASC 932-235-50-4.* 

<u>RESPONSE</u>:

The Company acknowledges the Staff's comment and respectfully advises that the Company intends to include the earliest period presented in the summary section of "Net PDP Reserves" in its Form 10-K for the fiscal year ending December 31, 2025, which the Company expects to be file with the Commission in February 2026. This addition is reflected in <u>Annex D</u> attached hereto as an example of the Company's planned disclosure.

If you have any questions or require any additional information in connection with the filing, please do not hesitate to contact me at 214.651.5645 or via email at greg.samuel@haynesboone.com, or my colleague, Rachel O'Donnell, at 214.651.5204 or via email at rachel.odonnell@haynesboone.com.

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| Very truly yours, |
| */s/ Greg R. Samuel* |
| Haynes and Boone, LLP |

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cc: Tyler Glover, President, Chief Executive Officer and Director Chris Steddum, Chief Financial Officer Micheal W. Dobbs, Senior Vice President, Secretary and General Counsel Deloitte & Touche LLP

**Annexes A-D**

**to** 

**Texas Pacific Land Corporation's** 

**Response Letter** 

**to** 

**the Securities and Exchange Commission**

**October 10, 2025**

<u>Please note</u>: The following Annexes reflect the Company's planned disclosures to be included in its Form 10-K for the fiscal year ending December 31, 2025, and subsequent filings. Information shown in these Annexes is reflective of the fiscal year ended December 31, 2024, and will be updated as necessary in the Company's future filings. New disclosures are shown in red text and deletions from the Company's Form 10-K for the fiscal year ended December 31, 2024 are shown in strikethrough text.

**ANNEX A**

**Item 1. Business**

**Land and Resource Management**

 

*Operations*

*Oil and Gas Activity for the Year Ended December 31, 2024* 

The table below provides financial and operational data by oil and gas royalty stream for the years ended December 31, 2024, 2023, and 2022:

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|:---|:---|:---|:---|
|  | **Years Ended December 31,** | **Years Ended December 31,** | **Years Ended December 31,** |
|  | **2024** | **2023<sup>(2)</sup>** | **2022** |
| *Our share of production volumes <sup>(1)</sup>:* |  |  |  |
| &nbsp;&nbsp;&nbsp;Oil (MBbls) | 4118 | 3701 | 3401 |
| &nbsp;&nbsp;&nbsp;Natural gas (MMcf) | 17074 | 14528 | 13086 |
| &nbsp;&nbsp;&nbsp;NGL (MBbls) | 2841 | 2453 | 2208 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Equivalents (MBoe) | 9804 | 8575 | 7791 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Equivalents per day (MBoe/d) | 26.8 | 23.5 | 21.3 |
| *Oil and gas royalties (in thousands):* |  |  |  |
| &nbsp;&nbsp;&nbsp;Oil royalties | $298074 | $273304 | $307606 |
| &nbsp;&nbsp;&nbsp;Natural gas royalties | 18512 | 29915 | 74866 |
| &nbsp;&nbsp;&nbsp;NGL royalties | 56745 | 45510 | 69962 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total oil and gas royalties | $373331 | $348729 | $452434 |
| *Realized prices:* |  |  |  |
| &nbsp;&nbsp;&nbsp;Oil ($/Bbl) | $75.80 | $77.33 | $94.69 |
| &nbsp;&nbsp;&nbsp;Natural gas ($/Mcf) | $1.17 | $2.23 | $6.19 |
| &nbsp;&nbsp;&nbsp;NGL ($/Bbl) | $21.60 | $20.05 | $34.25 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Equivalents ($/Boe) | $39.87 | $42.58 | $60.81 |

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(1)* *Commonly used definitions in the oil and gas industry not previously defined: MBbls represents one thousand barrels of crude oil, condensate or NGLs. Mcf represents one thousand cubic feet of natural gas. MMcf represents one million cubic feet of natural gas. MBoe represents one thousand Boe. MBoe/d represents one thousand Boe per day.* 

 

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;*(2)* *The metrics and dollars provided for the year ended December 31, 2023 exclude the impact of the $8.7 million* recovery *of oil and gas discussed in the sub-section titled "Year Ended December 31, 2024 Compared to Year Ended December 31, 2023" under Part II, Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" on page 26 below.* 

There are a number of oil and gas wells in which we have royalty interests that have been permitted but are still awaiting drilling and completion activity. In addition, we have also identified oil and gas wells in which we have a royalty interest that have been drilled but are not yet completed ("DUC"). These permitted and DUC wells represent potential near-term candidates for further development by operators towards ultimately being placed into production. We have identified 506 permitted gross wells (an estimated 6.4 net wells) and 793 DUC wells (an estimated 13.2 net wells) subject to our royalty interest as of December 31, 2024. The number of DUC wells is determined using uniform drilling spacing units with pooled interests for all wells awaiting completion.

**ANNEX B**

**Item 2. Properties.**

*Summary of Estimated Proved Developed Producing ("PDP") Reserves*

Proved developed producing ("PDP") reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. The Company's oil and gas properties are located in the Permian Basin.

The PDP reserve estimates and their associated future net cash flows were prepared by Ryder Scott Company, L.P. ("Ryder Scott"), an independent third-party petroleum engineering firm, as of December 31, 2024. The reserve report covers only PDP reserves and does not include undeveloped minerals or royalties. The oil and natural gas PDP reserve estimates represent the Company's net ownership interest in its proved properties and were estimated in accordance with guidelines established by the SEC. Since reserve studies were not completed in prior periods and the comparative information herein is based on the reserve report as of December 31, 2024, the Company rolled back volumes from 2024 to 2021 without revisions in prior estimates for these time frames.

The following table presents estimated PDP reserves as of December 31, 2024:

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|:---|:---|
|  | **December 31,<br> 2024** |
| Estimated PDP reserves: |  |
| &nbsp;&nbsp;&nbsp;Crude Oil and Condensate (MBbls)<sup>(1)</sup> | 23326 |
| &nbsp;&nbsp;&nbsp;Natural Gas (MBbls)<sup>(1)</sup> | 137054 |
| &nbsp;&nbsp;&nbsp;Natural Gas Liquids (MBbls)<sup>(1)</sup> | 21013 |
| Total (Mboe)<sup>(1)</sup> | 67181 |

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&nbsp;&nbsp;&nbsp;&nbsp;*(1)* *Commonly used definitions in the oil and gas industry not previously defined: MBbls represents one thousand barrels of crude oil, condensate or NGLs. MMcf represents one million cubic feet of natural gas. MBoe represents one thousand Boe.* 

 

*Proved Reserves Evaluation and Review of Estimated Proved Producing Reserves*

 

The estimated reserves as of December 31, 2024 are based on reserve estimates prepared by Ryder Scott. The internal and external technical persons responsible for preparing or auditing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott is a third-party engineering firm and does not own an interest in any of our properties and is not employed by us on a contingent basis. The proved reserve analysis performed by Ryder Scott covered 100% of our total proved producing reserves for 2024. No undeveloped reserves were reported. A copy of the summary report prepared by Ryder Scott is included as Exhibit 99.1 to this Annual Report.

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible–from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations–prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a "high degree of confidence that the quantities will be recovered." All proved producing reserves as of December 31, 2024 were estimated using a deterministic method. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (i) performance-based methods, (ii) volumetric-based methods, and (iii) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. In general, our proved reserves attributable to producing wells were estimated by the performance-based method decline curve analysis, which utilized extrapolations of available historical production data. In certain cases where there was inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the estimates was inappropriate, the proved producing reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. To estimate economically recoverable proved reserves and related future net cash flows, we considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production data, downhole completion information, geologic data and historical well cost and operating expense data. The process of estimating oil, natural gas and natural gas liquids reserves is complex and requires significant judgment. As a result, our petroleum engineers and geoscience professionals have an internal controls process to ensure the integrity, accuracy and timeliness of the data used to calculate proved producing reserves relating to our assets primarily in the Permian Basin. Our internal technical staff met with Ryder Scott periodically during the period covered by the reserve report to discuss the assumptions and methods used in our proved producing reserve estimation process. As part of the preparation of the reserve analysis, we provided historical information to Ryder Scott for our properties such as ownership interest, oil and gas production, and commodity prices. Our petroleum engineers are primarily responsible for overseeing the preparation of all reserve estimates, reviewing the data provided and the results for reasonableness, and overseeing communications with our independent reserve engineer. Our engineering staff have an average of approximately 20 years of industry experience per person. Our technical staff uses historical information for our properties such as ownership interest, oil and natural gas production and commodity prices to estimate economic lives of our properties. We limited economic forecasts to 30 years.

Ryder Scott performed an independent analysis of our estimated reserves for 2024. Ryder Scott's estimates of our proved producing reserves did not differ materially from our internal estimates by more than the established audit tolerance guidelines of ten percent. As such, we used Ryder Scott's reserves estimates for 2024 proved reserves. The internal control procedures utilized in the preparation of our proved reserve estimates are intended to ensure reliability of reserve estimations, and include, but are not limited to the following:

&nbsp;&nbsp;&nbsp;&nbsp;• Review and verification of historical production data, which is based on actual production as reported
by our operators;

&nbsp;&nbsp;&nbsp;&nbsp;• Preparation of interim quarterly reserve estimates by our internal reserve engineers and supervision of
the preparation of annual reserve estimates by the primary external reserve engineers;

&nbsp;&nbsp;&nbsp;&nbsp;• Review by the reserve engineers of all of our reported proved reserves at the close of each quarter, including
the review of all significant reserve changes;

&nbsp;&nbsp;&nbsp;&nbsp;• Internal review of historical realized commodity prices and differentials from index prices compared to
the differentials used in the reserves database with such support provided to the external reserve engineer for verification and inclusion
in a reserve report, if applicable;

&nbsp;&nbsp;&nbsp;&nbsp;• Review of any differences between our internal and external reserves estimates by our management and internal
engineering staff;

&nbsp;&nbsp;&nbsp;&nbsp;• Review of our proved reserve estimates by our Audit Committee with our executive team and Ryder Scott
on an annual basis;

&nbsp;&nbsp;&nbsp;&nbsp;• Verification of property ownership by our land department; and

&nbsp;&nbsp;&nbsp;&nbsp;• No employee's compensation is tied to the amount of reserves booked.

*Productive Wells*

Productive wells consist of producing wells, wells with at least one month of reported production. As of December 31, 2024, we owned mineral or royalty interests in over [●] gross productive wells, which consisted of over [●] oil wells and over [●] natural gas wells – over [●] net oil wells and over [●] net natural gas wells.

**ANNEX C**

 

**Non-GAAP Performance Measures**

In addition to amounts presented in accordance with GAAP, we also present certain supplemental non-GAAP performance measurements. These measurements are not to be considered more relevant or accurate than the measurements presented in accordance with GAAP. In compliance with the requirements of the SEC, our non-GAAP measurements are reconciled to net income, the most directly comparable GAAP performance measure. For all non-GAAP measurements, neither the SEC nor any other regulatory body has passed judgment on these non-GAAP measurements.

*EBITDA, Adjusted EBITDA and Free Cash Flow*

EBITDA is a non-GAAP financial measurement of earnings before interest expense, taxes, depreciation, depletion and amortization. The purpose of presenting EBITDA is to highlight earnings without finance, taxes, and depreciation, depletion and amortization expense, and its use is limited to specialized analysis.

The purpose of presenting Adjusted EBITDA is to highlight earnings without non-cash activity such as share-based compensation and other non-recurring or unusual items, if applicable. As noted in Item 11. "Executive Compensation", Adjusted EBITDA is a metric used by the compensation committee of our Board of Directors to evaluate the Company's performance in determining the short-term and long-term incentive compensation of our Named Executive Officers on an annual basis. We calculate Adjusted EBITDA as EBITDA plus employee share-based compensation and less pension curtailment and settlement gain. The pension curtailment and settlement gain is related to a buyout by a third party of defined benefit obligations under our pension plan and the subsequent freezing of our pension plan, both of which occurred in the fourth quarter of 2024. We have excluded the pension curtailment and settlement gain from the calculation of Adjusted EBITDA as such gain is a non-recurring item and is not related to our core business. The purpose of presenting Adjusted EBITDA is to highlight earnings without non-cash activity such as share-based compensation and other non-recurring or unusual items, if applicable.

The purpose of presenting free cash flow is to provide investors a metric to measure the cash available for investing in future acquisitions and returning capital to our stockholders through dividends and share repurchases after current income tax expense and purchases of fixed assets. Additionally, as noted in Item 11. "Executive Compensation", free cash flow is a metric used by the compensation committee of our Board of Directors to evaluate the Company's performance in determining the short-term and long-term incentive compensation of our Named Executive Officers. To calculate free cash flow, net income is adjusted by the same items discussed above for EBITDA and Adjusted EBITDA and then further adjusted by deducting current income tax expense and purchases of fixed assets. The purpose of presenting free cash flow is to provide an additional measure of operating performance.

We have presented EBITDA, Adjusted EBITDA and free cash flow because we believe that these metrics are useful supplements to net income in analyzing the Company's operating performance, ability to fund future acquisitions, ability to return capital to our stockholders and explaining how our Named Executive Officers are compensated. Our definitions of EBITDA, Adjusted EBITDA and free cash flow may differ from computations of similarly titled measures of other companies.

The following table presents a reconciliation of net income to EBITDA and Adjusted EBITDA and free cash flow to net income for the years ended December 31, 2024 and 2023 (in thousands):

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| | | |
|:---|:---|:---|
|  | **Years Ended December 31,** | **Years Ended December 31,** |
|  | **2024** | **2023** |
| Net income | $453960 | $405645 |
| *Add:* |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Income tax expense | 124861 | 111916 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Depreciation, depletion and amortization | 25162 | 14757 |
| **EBITDA** | 603983 | 532318 |
| *Add (deduct):* |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Employee share-based compensation | 11364 | 9124 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Pension curtailment and settlement gain | (4616) |  |
| **Adjusted EBITDA** | $610731 | $541442 |

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The following table presents a reconciliation of net income to free cash flow for the years ended December 31, 2024 and 2023 (in thousands):

---

| | | |
|:---|:---|:---|
|  | **Years Ended December 31,** | **Years Ended December 31,** |
|  | **2024** | **2023** |
| Net income | $453960 | $405645 |
| *Add (deduct):* |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Income tax expense | 124861 | 111916 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Depreciation, depletion and amortization | 25162 | 14757 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Employee share-based compensation | 11364 | 9124 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Pension curtailment and settlement gain | (4616) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Current income tax expense | (120257) | (110517) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Purchase of fixed assets | (29696) | (15028) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Decrease (increase) in accounts payable related to purchases of fixed assets | 273 | (403) |
| **Free cash flow** | $461051 | $415494 |

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**ANNEX D**

**17. Supplemental Oil and Gas Reserve Information (Unaudited)**

*Analysis of Changes in Oil and Natural Gas PDP Reserves*

Proved developed producing ("PDP") reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. The Company's oil and gas properties are located in the Permian Basin.

The PDP reserve estimates and their associated future net cash flows were prepared by Ryder Scott Company, L.P. ("Ryder Scott"), an independent third-party petroleum engineering firm, as of December 31, 2024. The reserve report covers only PDP reserves and does not include undeveloped minerals or royalties. The oil and natural gas PDP reserve estimates represent the Company's net ownership interest in its proved properties and were estimated in accordance with guidelines established by the SEC. Since reserve studies were not completed in prior periods and the comparative information herein is based on the reserve report as of December 31, 2024, the Company rolled volumes backward from 2024 to 2021 without revisions in prior estimates for these time frames.

 

The following table presents changes in estimated PDP reserves and was prepared in accordance with the rules and regulations of the SEC:

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| | | | | |
|:---|:---|:---|:---|:---|
|  | **Crude Oil and<br> Condensate<br> (MBbls)<sup>(1)</sup>** | **Natural Gas<br> (MMcf)<sup>(1)</sup>** | **Natural Gas**<br> **Liquids<br> (MBbls)<sup>(1)</sup>** | **Total <br> (MBoe)<sup>(1)</sup>** |
| Net PDP reserves at January 1, 2022 | 14190 | 88579 | 13579 | 42533 |
| &nbsp;&nbsp;&nbsp;Extensions and discoveries | 5427 | 24441 | 3949 | 13449 |
| &nbsp;&nbsp;&nbsp;Acquisition of reserves | 17 | 62 | 9 | 37 |
| &nbsp;&nbsp;&nbsp;Production | (3401) | (13086) | (2208) | (7791) |
| Net PDP reserves at December 31, 2022 | 16233 | 99996 | 15329 | 48228 |
| &nbsp;&nbsp;&nbsp;Extensions and discoveries | 6858 | 31196 | 5010 | 17067 |
| &nbsp;&nbsp;&nbsp;Acquisition of reserves | 89 | 664 | 102 | 302 |
| &nbsp;&nbsp;&nbsp;Production | (3701) | (14528) | (2453) | (8575) |
| Net PDP reserves at December 31, 2023 | 19479 | 117328 | 17988 | 57022 |
| &nbsp;&nbsp;&nbsp;Extensions and discoveries | 5587 | 23483 | 3824 | 13324 |
| &nbsp;&nbsp;&nbsp;Acquisition of reserves | 2378 | 13317 | 2042 | 6639 |
| &nbsp;&nbsp;&nbsp;Production | (4118) | (17074) | (2841) | (9804) |
| Net PDP reserves at December 31, 2024 | 23326 | 137054 | 21013 | 67181 |
| Net PDP reserves |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;December 31, 2021 | 14190 | 88579 | 13579 | 42533 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;December 31, 2022 | 16233 | 99996 | 15329 | 48228 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;December 31, 2023 | 19479 | 117328 | 17988 | 57022 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;December 31, 2024 | 23326 | 137054 | 21013 | 67181 |

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&nbsp;&nbsp;&nbsp;&nbsp;*(1)* *Commonly used definitions in the oil and gas industry not previously defined: MBbls represents one thousand barrels of crude oil, condensate or NGLs. MMcf represents one million cubic feet of natural gas. MBoe represents one thousand Boe.* 

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