AI interpretation based on checked source excerpts. Issuer assertions and evidence limitations remain explicit.
Policy quality-scores-3: six equally weighted categories. The overall score requires full coverage. Missing inputs are not zero. Qualitative grades are sourced interpretations, not probabilities. 6/6 · 29/10/2026
Moat63
Equal-weight average of four evidence-backed rubric grades (0–4), scaled to 100.
structural advantage · 3/4 · Specific land and royalty ownership creates enforceable access and production-related rights, supported by realized royalty and water revenues. Surface control and an exclusive project sourcing right demonstrate a structural advantage. The evidence does not establish basin-wide control, superior water costs or customer benefits from additional network participants.
durability · 3/4 · Royalty interests generally persist into perpetuity, subject to disclosed exceptions. Estimated net PDP reserves rose from 67.181 million Boe at year-end 2024 to 73.116 million Boe at year-end 2025; extensions exceeded production, although acquisitions contributed and revisions were negative. Depletion and operator-controlled development prevent an exceptional durability grade.
customer dependency · 2/4 · Operators using TPL's particular surface, transport corridors and disposal arrangements need access to those rights. Exclusive project sourcing provides another specific dependency. These are bounded relationships: alternative routes and sources, actual switching expenses and customer concentration are undisclosed, while project repurchase provisions acknowledge development uncertainty.
erosion resilience · 2/4 · Growing water volumes and royalty production demonstrate continued monetization, and royalty ownership avoids most well-development cost burdens. However, easement income fell in first-half 2026, development remains externally controlled, and TPL has actually absorbed disputed tax payments. Disposal regulation and recycling choices are potential erosion channels rather than demonstrated failures.
Pricing power56
Equal-weight average of four evidence-backed rubric grades (0–4), scaled to 100.
realized pricing · 2/4 · First-half 2026 average realized water pricing increased 15.5% alongside 16.4% volume growth, demonstrating favorable pricing outcomes with unspecified mix effects. Conversely, 2025 oil realization declined from $75.80 to $64.69 per barrel and equivalent realization also fell. Water evidence supports selective pricing strength, while commodity realization limits issuer-wide discretion.
retention · 2/4 · Higher first-half water sales and produced-water volumes, together with continuing royalty production, indirectly demonstrate ongoing demand for the asset base. Contracted surface use provides some continuity. Aggregate growth does not identify repeat customers, renewals or switching rates, and operator development and recycling decisions can change future demand.
margin resilience · 3/4 · First-half operating income rose from $293.8 million to $374.1 million while expenses grew more slowly than revenue. Fee-based produced-water royalties and limited royalty development-cost exposure support resilience. Higher commodity prices and $20.9 million of financed land-sale revenue also contributed; the result demonstrates operating resilience without independently proving pricing power.
contractual freedom · 2/4 · Surface revenue requires negotiated commercial agreements rather than statutory rates, and TPL obtained an exclusive project water-sourcing right. This establishes meaningful ability to negotiate terms. Produced-water payments remain contractual, unilateral repricing and escalation rights are undisclosed, and oil-and-gas royalties largely transmit commodity realizations rather than discretionary prices.
Predictability83
5 consecutive published annual periods. Equal weights: nondeclining revenue frequency; revenue-growth volatility (5–40pp); positive FCF frequency; FCF-margin volatility (3–20pp). Stability indicator, not a growth forecast.
- Nondeclining revenue years (%)
- 75.00
- Revenue growth volatility (pp)
- 19.39
- Positive FCF years (%)
- 100.00
- FCF margin volatility (pp)
- 3.58
- observedAnnualPeriods
- 5.00
Financial strength100
Equal-weight grades: debt/FCF (1–8x), net debt/earnings before interest and tax (0–5x), interest service (1–12x), current ratio (0.75–2x). Earnings use reported operating income, an original issuer-reported unadjusted EBIT reconciled to net income, income tax and signed net interest, or reported pretax profit plus reported gross interest expense. Reported EBIT is distinct from GAAP operating income and gross interest. Interest service uses earnings/interest expense; if unavailable, it uses reported operating cash flow/cash interest paid, without relabeling cash paid as accrued expense. Nonpositive cash flow/earnings score 0 for their service component; reported zero interest with a positive numerator scores 100. Net cash scores 100 for net leverage. Missing disclosures remain unavailable. General nonfinancial-company rubric, not a credit rating; exceptional and nonoperating gains are not normalized out. IFRS finance-cost and cash-flow classifications retain their reported scope.
- debtFcfGrade
- 100.00
- netDebtEbitGrade
- 100.00
- interestCoverageGrade
- 100.00
- currentRatioGrade
- 100.00
- Debt / FCF (x)
- 0.00
- Net debt / operating income (x)
- -0.24
- Interest coverage (x)
- 858.20
- Current ratio (x)
- 4.40
Capital allocation100
Three-year equal-weight indicators: pretax return on average invested capital (0–25%; equity + debt − cash, each year and its prior year), share-count growth (0–5%, lower better), share-based cost/revenue (2–20%, lower better), consolidated FCF/net income (0–1x). Return uses reported operating income, an original issuer-reported unadjusted EBIT reconciled to net income, income tax and signed net interest, or EBIT calculated from reported pretax profit plus reported gross interest expense; the issuer-reported EBIT is distinct from GAAP operating income and gross interest; exceptional/nonoperating gains are not normalized out. Share-based cost uses the reported cash-flow add-back or, if absent, separately reported recognized compensation expense; the latter never becomes an FCF adjustment. Nonpositive net income scores 0 for cash conversion; absent income/FCF stays unavailable. ROIC remains undefined for nonpositive invested capital; the explicit asset-return alternative does not change the ROIC chart. Missing financial inputs alone never trigger an alternative. Does not establish acquisition quality or buyback timing.
- 3-year pre-tax operating return (%)
- 108.13
- 3-year average dilution (%)
- -0.26
- 3-year average SBC / revenue (%)
- 1.77
- cashConversionGrade
- 100.00
Management69
Equal-weight average of four evidence-backed rubric grades (0–4), scaled to 100.
capital discipline · 3/4 · First-half operating cash flow of $334.9 million covered $139.4 million of investing outflows and $83.2 million of dividends, with cash increasing and the facility undrawn. Reported 2025 acquisition returns exceeded disclosed objectives. These demonstrate discipline, although issuer-defined returns and projects without mature commercial outcomes limit long-term allocation conclusions.
incentive alignment · 3/4 · The actual 2025 program made at least half of executive equity awards performance-based. Certified 2023–2025 awards tied earned shares to relative shareholder return and FCF per share, establishing implementation beyond intentions. This supports strong incentive alignment, while actual executive ownership and the complete effects of award terms remain unestablished.
execution · 3/4 · Water price and volume growth, higher operating cash generation and reported acquisition returns demonstrate operating execution. Desalination construction and commissioning provide a concrete development milestone, but not commercial validation. Attribution to management is partly indirect because commodity prices, customer development and acquired assets also influence reported outcomes.
governance · 2/4 · Independent director sessions, disclosed attendance and the absence of compensation-committee insider relationships support functioning oversight. They do not demonstrate exceptional accountability. The proposed Texas conversion could change shareholder enforcement, including a derivative-demand waiting period with exceptions; adoption and realized effects are not established by the September 2026 proxy.
Evidence
Organization and Description of Business Organization Texas Pacific Land Corporation (which, together with its subsidiaries as the context requires, may be referred to as “TPL,” the “Company,” “our,” “we,” or “us”) is a Delaware corporation and one of the largest land and royalty owners in the State of Texas with approximately 894,000 surface acres of land, principally concentrated in the Permian Basin.
Organization and Description of Business; approximately 894,000 surface acres; quarterly filing, dateKind=filed, 2026-08-05. · Filed 05/08/2026
Our extensive land holdings contain and are adjacent to extensive pore space, and, through various commercial agreements, we allow produced water operators to transport and dispose of produced water across our surface footprint.
Business description; commercial agreements for produced-water transport and disposal across TPL's surface footprint; dateKind=filed, 2026-08-05. · Filed 05/08/2026
Oil and Gas Royalties Overview and Management TPL Producing Horizontal Wells (Net) by OperatorRevenue Mechanics and Management By interfacing directly with operators across SLEM and Water, TPL incentivizes operators to accelerate development on TPL’s royalty acreage Advocate for royalty ownership during disputes (e.g., revenue deductions, pricing realization, ad valorem payments, etc) Experienced reservoir engineers leverage TPL’s proprietary data for internal initiatives and evaluation of external opportunities Actively monitor check stub accuracy and compliance Internally developed software applications that integrate proprietary and third-party data and software, GIS systems and capabilities, and other tools to help drive further automation, efficiency, and effectiveness Continuously screening for operator well activity updates and utilizing that data to cross-sell TPL services How TPL is Delivering Value Oil and gas royalties represent real property interests entitling the owner to a portion of the proceeds derived from the production of oil and gas TPL receives a percentage of gross revenues from oil and gas wells drilled on TPL royalty acreage Royalties are not burdened by capital costs or most operating expenses (although natural gas and NGLs may have a small set of allowable deductions) associated with well development Mineral and royalty interests exist into perpetuity Overriding royalty interests (“ORRIs”) can be an exception as they are generally tied to leases and may not exist into perpetuity (TPL owns de minimis amount of ORRIs) Responsibility of royalty owner to (i) verify “decimals” (i.e., revenue interest); (ii) ensure timely pay; (iii) inspect check stubs for production, pricing, and deductions accuracy, (iv) track development status of pre-production wells, (v) extract and analyze well reservoir performance 20 Note: Company data as of 6/30/2026.
Investor presentation, page 20; royalty mechanics, duration and exceptions; Company data as of June 30, 2026; dateKind=filed, 2026-08-05. · Filed 05/08/2026
RAW LAND DOES NOT MONETIZE ITSELF (i) Operational and legal expertise of surface estate ownership within the oil and gas industry and (ii) proactive execution are requisite towards extracting substantial cash flow from raw land Surface Estate Ownership Leveraging Ownership of Raw Surface into Cash Flow Unlike O&G royalties, there is no statutory revenue / lease / royalty rate for activities that occur within a surface estate Revenue opportunities require continual pursuit, negotiation, and commercialization $386MM FY 2025 Revenue 48% of TPL consolidated revenue Surface estate ownership allows for control over surface access, aquifers, and sub-surface pore space TPL derives three major revenue streams from its surface estate ownership SLEM Water Sales Produced Water Revenue derived by providing customers access-to or use-of TPL surface Revenue sources include pipeline easements, wellbore easements, commercial leases, and caliche/sand/materials sales Renewables and various “next generation” opportunities, including grid-connected batteries and carbon capture, provide additional potential for revenue growth TPL owns and operates infrastructure to provide water for use in oil and gas development activities TPL provides both brackish groundwater and recycled/treated water for customers both on and off TPL surface Operated model allows for sustainable management of aquifer resource TPL provides surface access to operators and midstream companies for necessary infrastructure TPL receives a volumetric royalty payment for produced water barrels that move across or are injected into TPL surface and has offtake rights to treat and resell produced water TPL does not own or operate produced water disposal wells 1 2 3 Aggregate Contribution From Surface Estate + Active Management 24
Investor presentation, page 24; surface ownership, negotiated commercialization and FY2025 surface revenue; dateKind=filed, 2026-08-05. · Filed 05/08/2026
As part of the agreement, we sold land for aggregate consideration of $42.5 million and acquired the exclusive right to source aquifer-derived water for the power generation facility and other associated aspects of the project.
Quarterly business discussion; land consideration and exclusive aquifer-derived water sourcing right for the project; dateKind=filed, 2026-08-05. · Filed 05/08/2026
F-33 Table of Contents The following table presents changes in estimated PDP reserves and was prepared in accordance with the rules and regulations of the SEC: Crude Oil and Condensate (MBbls)(1) Natural Gas (MMcf)(1) Natural Gas Liquids (MBbls)(1) Total (MBoe)(1) Net PDP reserves at December 31, 2022 16,233 99,996 15,329 48,228 Extensions and discoveries 6,858 31,196 5,010 17,067 Acquisition of reserves 89 664 102 302 Production (3,701) (14,528) (2,453) (8,575) Net PDP reserves at December 31, 2023 19,479 117,328 17,988 57,022 Extensions and discoveries 5,587 23,483 3,824 13,324 Acquisition of reserves 2,378 13,317 2,042 6,639 Production (4,118) (17,074) (2,841) (9,804) Net PDP reserves at December 31, 2024 23,326 137,054 21,013 67,181 Extensions and discoveries 5,376 30,285 4,636 15,059 Acquisition of reserves 3,352 13,876 2,237 7,902 Production (4,936) (23,359) (3,784) (12,613) Revisions (2,927) (9,844) 154 (4,413) Net PDP reserves at December 31, 2025 24,191 148,012 24,256 73,116 Net PDP reserves December 31, 2022 16,233 99,996 15,329 48,228 December 31, 2023 19,479 117,328 17,988 57,022 December 31, 2024 23,326 137,054 21,013 67,181 December 31, 2025 24,191 148,012 24,256 73,116 (1)Commonly used definitions in the oil and gas industry not previously defined: MBbls represents one thousand barrels of crude oil, condensate or NGLs.
2025 annual filing, F-33; estimated PDP reserve changes, 2022–2025, including production, acquisitions and revisions; dateKind=filed, 2026-02-18. · Filed 18/02/2026
1 Table of Contents TEXAS PACIFIC LAND CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND TOTAL COMPREHENSIVE INCOME (in thousands, except shares and per share amounts) (Unaudited) Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Revenues: Oil and gas royalties $ 145,589 $ 95,006 $ 263,756 $ 206,251 Water sales 39,733 25,577 86,596 64,390 Produced water royalties 37,075 30,737 70,604 58,437 Easements and other surface-related income 23,662 36,223 40,977 54,448 Land sales — — 20,944 — Total revenues 246,059 187,543 482,877 383,526 Expenses: Salaries and related employee expenses 15,562 14,072 30,549 28,644 Water service-related expenses 11,570 8,451 25,857 19,577 General and administrative expenses 8,004 5,693 16,635 11,765 Depreciation, depletion and amortization 16,639 13,699 30,682 25,640 Ad valorem and other taxes 2,467 1,877 5,009 4,076 Total operating expenses 54,242 43,792 108,732 89,702 Operating income 191,817 143,751 374,145 293,824 Interest expense (973) — (1,965) — Other income, net 2,854 5,240 5,082 9,561 Income before income taxes 193,698 148,991 377,262 303,385 Income tax expense 39,768 32,851 80,430 66,593 Net income $ 153,930 $ 116,140 $ 296,832 $ 236,792 Other comprehensive loss — periodic pension costs, net of income taxes for the three and six months ended June 30, 2026 and 2025 of $96, $10, $191, $21, respectively (358) (39) (717) (78) Total comprehensive income $ 153,572 $ 116,101 $ 296,115 $ 236,714 Net income per share of common stock Basic $ 2.23 $ 1.68 $ 4.30 $ 3.43 Diluted $ 2.23 $ 1.68 $ 4.30 $ 3.43 Weighted average number of shares of common stock outstanding Basic 68,974,580 68,961,978 68,966,839 68,952,087 Diluted 69,034,580 69,040,740 69,019,380 69,026,862 Cash dividends per share of common stock $ 0.60 $ 0.53 $ 1.20 $ 1.06 See accompanying notes to condensed consolidated financial statements.
Unaudited condensed consolidated income statement; three and six months ended June 30, 2026 and 2025; thousands except shares and per-share amounts; dateKind=filed, 2026-08-05. · Filed 05/08/2026
Six Months Ended June 30, 2026 2025 Water volumes (in MBbls): Water sales 134,090 115,159 Produced water royalties 857,787 722,205 Water volumes in barrels per day (in MBbls/d): Water sales 741 636 Produced water royalties 4,739 3,990 Water revenue (in thousands): Water sales $ 86,596 $ 64,390 Produced water royalties $ 70,604 $ 58,437 Easements and other surface-related income.
Water operational results; six months ended June 30, 2026 and 2025; volumes in MBbls and MBbls/d, revenue in thousands; dateKind=filed, 2026-08-05. · Filed 05/08/2026
As we are a significant land and royalty owner in the Permian Basin and not an oil and gas producer, our revenue is affected by the development decisions made by companies that operate in the areas where we own royalty interests and land.
Quarterly business discussion; dependence on development decisions by operating companies; dateKind=filed, 2026-08-05. · Filed 05/08/2026
Produced water royalties. Produced water royalties are received from the transfer or disposal of produced water on our land and are contractual and not paid as a matter of right.
Produced-water royalties; contractual payments rather than payments as a matter of right; dateKind=filed, 2026-08-05. · Filed 05/08/2026
However, indirectly, volumes may vary from period to period depending upon development activity levels and operator decisions involving recycling versus disposal of produced water.
Produced-water royalties; volume dependence on development activity and recycling-versus-disposal decisions; dateKind=filed, 2026-08-05. · Filed 05/08/2026
Saltwater disposal availability varies throughout the Permian Basin depending on regulations, permitted injected rates, and the availability of pore space and infrastructure.
Produced-water discussion; disposal availability, regulation, permitted injection rates, pore space and infrastructure; dateKind=filed, 2026-08-05. · Filed 05/08/2026
After the completion of our Corporate Reorganization, we received notice from a third party that it no longer intended to pay the ad valorem taxes related to such historical royalty interests.
Quarterly notes; third-party notice refusing historical royalty ad valorem tax payments following reorganization; dateKind=filed, 2026-08-05. · Filed 05/08/2026
In order to protect the historical royalty interests from any potential tax liens for non-payment of ad valorem taxes, we have accrued and/or paid such ad valorem taxes since January 1, 2022.
Quarterly notes; TPL accrual or payment of disputed ad valorem taxes since January 1, 2022; dateKind=filed, 2026-08-05. · Filed 05/08/2026
While we intend to seek reimbursement from the third party for such taxes, we are unable to estimate the amount and/or likelihood of such reimbursement, and accordingly, no loss recovery receivable has been recorded as of June 30, 2026.
Quarterly notes; uncertain tax reimbursement and no recovery receivable as of June 30, 2026; dateKind=filed, 2026-08-05. · Filed 05/08/2026
The increase in water sales was principally due to increases of 16.4% in water sales volumes and 15.5% in average realized pricing for the six months ended June 30, 2026 compared to the same period of 2025.
Water sales discussion; separate volume and average realized pricing changes for six months ended June 30, 2026 versus 2025; dateKind=filed, 2026-08-05. · Filed 05/08/2026
3 Table of Contents Operations Revenues from the Land and Resource Management segment for the last three years were as follows (dollars presented in thousands): Years Ended December 31, 2025 2024 2023 Segment Revenue % of Total Consolidated Revenue Segment Revenue % of Total Consolidated Revenue Segment Revenue % of Total Consolidated Revenue Oil and gas royalties $ 411,677 52 % $ 373,331 53 % $ 357,394 57 % Easements and other surface-related income 78,230 10 % 63,074 9 % 67,905 11 % Land sales 819 — % 4,388 1 % 6,806 1 % Total Revenue – Land and Resource Management segment $ 490,726 62 % $ 440,793 63 % $ 432,105 69 % Oil and Gas Activity The table below provides financial and operational data by oil and gas royalty stream for the years ended December 31, 2025, 2024, and 2023: Years Ended December 31, 2025 2024 2023(2) Our share of production volumes (1): Oil (MBbls) 4,936 4,118 3,701 Natural gas (MMcf) 23,359 17,074 14,528 NGL (MBbls) 3,784 2,841 2,453 Equivalents (MBoe) 12,613 9,804 8,575 Equivalents per day (MBoe/d) 34.6 26.8 23.5 Oil and gas royalties (in thousands): Oil royalties $ 304,930 $ 298,074 $ 273,304 Natural gas royalties 37,432 18,512 29,915 NGL royalties 69,315 56,745 45,510 Total oil and gas royalties $ 411,677 $ 373,331 $ 348,729 Realized prices: Oil ($/Bbl) $ 64.69 $ 75.80 $ 77.33 Natural gas ($/Mcf) $ 1.73 $ 1.17 $ 2.23 NGL ($/Bbl) $ 19.81 $ 21.60 $ 20.05 Equivalents ($/Boe) $ 34.18 $ 39.87 $ 42.58 (1) Commonly used definitions in the oil and gas industry: “Bbl” represents one barrel of 42 U.S.
Annual operations, page 3; 2023–2025 land-segment revenue, royalty production and realized commodity prices with units; dateKind=filed, 2026-02-18. · Filed 18/02/2026
Produced water royalties are also fee based and not directly impacted by lower commodity prices.
Produced-water royalties; fee-based payments and direct commodity-price exposure; dateKind=filed, 2026-08-05. · Filed 05/08/2026
2 Table of Contents TEXAS PACIFIC LAND CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) (Unaudited) Six Months Ended June 30, 2026 2025 Cash flows from operating activities: Net income $ 296,832 $ 236,792 Adjustments to reconcile net income to net cash provided by operating activities: Land sale with financing arrangement (20,944) — Depreciation, depletion and amortization 30,682 25,640 Share-based compensation 9,451 7,882 Deferred taxes 5,191 1,329 Other 111 — Changes in operating assets and liabilities: Operating assets, excluding income taxes (8,549) 8,154 Operating liabilities, excluding income taxes (6,549) (1,964) Income taxes payable 24,926 (207) Prepaid income taxes 3,716 — Cash provided by operating activities 334,867 277,626 Cash flows from investing activities: Purchases of fixed assets (29,201) (12,277) Acquisition of real estate (110,162) (4,505) Acquisition of royalty interests, net of post-close adjustments — (3,546) Post-close adjustment from seller related to prior year asset acquisition — 3,878 Cash used in investing activities (139,363) (16,450) Cash flows from financing activities: Dividends paid (83,183) (74,216) Shares exchanged for tax withholdings (9,113) (14,311) Cash settlement of common stock repurchases — (100) Cash used in financing activities (92,296) (88,627) Net increase in cash, cash equivalents and restricted cash 103,208 172,549 Cash, cash equivalents and restricted cash, beginning of period 145,404 371,381 Cash, cash equivalents and restricted cash, end of period $ 248,612 $ 543,930 Supplemental disclosure of cash flow information: Income taxes paid $ 46,406 $ 65,450 Interest paid $ 1,307 $ — Supplemental non-cash investing and financing information: (Decrease) increase in accounts payable related to purchases of fixed assets $ (1,360) $ 1,439 Accrued dividends on unvested stock awards $ (222) $ (411) Financing receivable from land sale $ 21,425 $ — See accompanying notes to condensed consolidated financial statements.
Unaudited cash-flow statement; six months ended June 30, 2026 and 2025, in thousands, including financed land-sale adjustment; dateKind=filed, 2026-08-05. · Filed 05/08/2026
The Credit Facility remains undrawn, and the Company is in compliance with all covenants under the Credit Facility as of June 30, 2026.
Liquidity discussion; undrawn credit facility and covenant compliance as of June 30, 2026; dateKind=filed, 2026-08-05. · Filed 05/08/2026
Capital Returns: For minerals/royalties, achieve 12% pre-tax cash flow yield for acquired minerals and royalties portfolio; for surface and water assets, achieve 8% ROIC for acquisitions closed since 2023 Royalties/minerals portfolio generated 16% pre-tax cash flow yield for 2025.
Proxy compensation discussion; acquired mineral/royalty portfolio cash-flow yield objective and reported 2025 result; dateKind=filed, 2026-09-25. · Filed 25/09/2026
Surface/water acquisitions generated a 9% ROIC for 2025 including acquisitions closed since 2023.
Proxy compensation discussion; reported 2025 ROIC for surface/water acquisitions closed since 2023; dateKind=filed, 2026-09-25. · Filed 25/09/2026
The 2025 executive compensation program consisted principally of a salary, an annual cash incentive (sometimes referred to as awards under a non-equity incentive plan), and long-term share-based compensation as discussed below: Texas Pacific Land Corporation | Proxy Statement 75 TABLE OF CONTENTS EXECUTIVE OFFICER AND DIRECTOR COMPENSATION Key Compensation Component Purpose Philosophy Base Salary • Provide a competitive level of fixed compensation • Set at a competitive level annually by the Compensation Committee and the Board, as applicable • Based on evaluation of executive officers’ performance, contributions and competitive market data Annual Cash Incentive • Align executive officer pay with performance • Reward for achievement of annual goals, both financial and non-financial • Establish strategic priorities for the year through the strategic portion of the award • Individual target levels set at a competitive level based on competitive market data and executive officers’ contribution level • Payouts heavily influenced by performance against pre-set goals • Portion of award earned through achievements against strategic priorities Long-Term Incentives • Align executive pay with long-term stockholder value creation through share ownership • Encourage long-term retention through extended vesting periods • Tie executive pay outcomes to long-term performance through performance-based awards • Individual awards set at a competitive level based on competitive market data and executive officers’ contribution level • At least 50% of each executive officer’s awards are performance-based • Performance tied to long-term share price and financial performance, based on pre-set goals As part of its compensation program, TPL also maintains a qualified defined contribution plan, which is available to employees generally, including the Named Executive Officers.
Proxy, page 75; actual 2025 executive compensation program and performance-based award mix; dateKind=filed, 2026-09-25. · Filed 25/09/2026
2023-2025 Performance Period PSU Vestings Following the end of the 2023-2025 performance period, the Compensation Committee certified the results of the PSU awards granted to our Named Executive Officers in 2023.
Proxy; certification of 2023–2025 PSU award results; dateKind=filed, 2026-09-25. · Filed 25/09/2026
The results for each are presented in the following table: PSUs Threshold (25% Payout) Target (100% Payout) Maximum (200% Payout) Actual Results Percentage of Targeted Shares Earned RTSR PSUs 25th percentile 50th percentile 90th percentile 78th percentile 171% FCF PSUs(1) $12.78/share $17.22/share $21.67/share $20.06/share 164% (1) Share amounts reflect the three-for-one stock split effected on December 22, 2025.
Proxy; certified relative-TSR and FCF PSU results and earned shares, including stock-split footnote; dateKind=filed, 2026-09-25. · Filed 25/09/2026
The Board meets at least quarterly, and the independent directors serving on the Board meet in executive session (i.e., without the presence of any non-independent directors and management) immediately following regularly scheduled Board meetings.
Proxy governance discussion; quarterly Board meetings and independent director executive sessions; dateKind=filed, 2026-09-25. · Filed 25/09/2026
All of the directors attended at least 75% of the total number of meetings held by the Board and of the committees on which they served during the Last Fiscal Year.
Proxy governance discussion; director attendance during fiscal year ended December 31, 2025; dateKind=filed, 2026-09-25. · Filed 25/09/2026
None of the persons who served on the Compensation Committee during the Last Fiscal Year is or has been an officer or employee of the Company, and none had any relationship with the Company or any of its subsidiaries during the Last Fiscal Year that would be required to be disclosed as a transaction with a related person.
Annual governance disclosure; compensation-committee employment and related-person relationships during 2025; dateKind=filed, 2026-02-18. · Filed 18/02/2026
Proposal 4: Approval of the redomestication of the Company from Delaware to Texas by conversion requires the affirmative vote of the holders of a majority of the outstanding shares of our Common Stock entitled to vote on such proposal.
Proxy Proposal 4; shareholder approval required for proposed Delaware-to-Texas conversion; dateKind=filed, 2026-09-25. · Filed 25/09/2026
A shareholder may not institute a derivative proceeding until the 91st day after the date a written demand is filed with the corporation stating with particularity the act, omission, or other matter that is the subject of the claim or challenge and requesting that the corporation take suitable action.
Proxy comparison of Delaware and Texas law; Texas derivative-demand waiting period; dateKind=filed, 2026-09-25. · Filed 25/09/2026
The foregoing waiting period is not required or, if applicable, shall terminate if: (1) the shareholder has been notified that the demand has been rejected by the corporation; (2) the corporation is suffering irreparable injury; or (3) irreparable injury to the corporation would result by waiting for the expiration of the 90-day period.
Proxy comparison of Delaware and Texas law; exceptions to derivative-demand waiting period; dateKind=filed, 2026-09-25. · Filed 25/09/2026
•Completed construction and commenced commissioning of Phase 2B produced water desalination facility in Orla, Texas with anticipated capacity of 10,000 inlet barrels per day.
Second-quarter earnings release; completed construction and commenced commissioning of desalination facility with anticipated 10,000 inlet barrels/day capacity; dateKind=filed, 2026-08-05. · Filed 05/08/2026
Average West Texas Intermediate (“WTI”) oil prices for the six months ended June 30, 2026 increased by approximately 24% compared to average WTI oil prices during the same period last year.
Quarterly market discussion; first-half 2026 average WTI oil price increase versus first-half 2025; dateKind=filed, 2026-08-05. · Filed 05/08/2026
This agreement also provides for a put option held by the developer and a call option held by us regarding our repurchase of the land if certain development milestones are not achieved.
Project agreement; developer put and TPL call concerning land repurchase if development milestones are unmet; dateKind=filed, 2026-08-05. · Filed 05/08/2026
