PermRock Royalty Trust 10-K, filed Mar 27, 2026
PermRock Royalty Trust (PRT)
About this 10-K
PermRock Royalty Trust filed this 10-K on March 27, 2026, covering the fiscal year ended December 31, 2025.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2025
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to ___________
Commission File Number: 001-38472
PERMROCK ROYALTY TRUST
(Exact name of registrant as specified in its charter)
Delaware |
82-6725102 |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
Argent Trust Company, Trustee
3838 Oak Lawn Ave.
Suite 1720
Dallas, Texas 75219
(Address of principal executive offices)(Zip code)
(855) 588-7839
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class |
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Trading Symbol(s) |
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Name of Each Exchange on Which Registered |
Units of Beneficial Interest |
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PRT |
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New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☐ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☐ |
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Accelerated filer ☐ |
Non-accelerated filer ☑ |
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Smaller reporting company ☑ |
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Emerging growth company ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
The aggregate market value of Trust units representing beneficial interests in PermRock Royalty Trust held by non-affiliates on June 30, 2025 (the last business day of its most recently completed second fiscal quarter), was approximately $50,974,417 based on the closing price as quoted on the New York Stock Exchange. As of March 27, 2026, 12,165,732 Trust units representing beneficial interests in PermRock Royalty Trust were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None
PERMROCK ROYALTY TRUST
FORM 10-K
For the Fiscal Year Ended December 31, 2025
TABLE OF CONTENTS
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PART I |
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Business |
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1 |
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Risk Factors |
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9 |
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Unresolved Staff Comments |
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25 |
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Cybersecurity |
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25 |
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Properties |
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26 |
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Legal Proceedings |
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32 |
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Mine Safety Disclosures |
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32 |
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PART II |
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Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities |
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32 |
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Reserved |
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33 |
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Trustee’s Discussion and Analysis of Financial Condition and Results of Operations |
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34 |
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Quantitative and Qualitative Disclosures about Market Risk |
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41 |
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Financial Statements and Supplementary Data |
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42 |
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Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
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56 |
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Controls and Procedures |
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56 |
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Other Information |
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56 |
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Disclosure Regarding Foreign Jurisdictions that Prevent Inspections |
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56 |
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PART III |
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Directors, Executive Officers and Corporate Governance |
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57 |
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Executive Compensation |
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57 |
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Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters |
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57 |
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Certain Relationships and Related Transactions and Director Independence |
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58 |
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Principal Accountant Fees and Services |
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58 |
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PART IV |
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Exhibits and Financial Statement Schedules |
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60 |
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Form 10-K Summary |
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60 |
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61 |
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain information included in this Annual Report on Form 10-K (“Annual Report”) contains, and other materials filed or to be filed by the PermRock Royalty Trust (the “Trust”) with the Securities and Exchange Commission (the “SEC”) (as well as information included in oral statements or other written statements made or to be made by the Trust) may contain or include, forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and Section 27A of the Securities Act of 1933, as amended (the “Securities Act”). Such forward-looking statements may be or may concern, among other things, T2S Permian Acquisition II LLC'S ("T2S's") and Argent Trust Company’s (as the Trustee (as hereinafter defined) of the Trust) expectations, beliefs and plans regarding: (i) T2S’s capital expenditure budget and anticipated expenditures; (ii) T2S’s 2026 outlook; (iii) estimated capital required for 2026 operations; (iv) amount and timing of cash reserves by the Trustee; (v) drilling activity; (vi) estimated present value of future cash flows; (vii) characteristics of the Underlying Properties, including estimates regarding oil and gas reserves; (viii) the impact of a loss of any major customers; (ix) reliance on third parties for facilities and services; (x) the ability of T2S’s insurance coverage to cover certain claims; (xi) burdens and obligations affecting the Underlying Properties and their impact on the Underlying Properties and Net Profits Interest; (xii) the quality of T2S’s title to the Underlying Properties; (xiii) the impact of litigation on the Trust and regulatory matters; (xiv) the tax treatment of the Net Profits Interest; (xv) the treatment of the Net Profits Interest in the event of T2S’s bankruptcy; (xvi) distributions to Trust unitholders, including in the event of contingencies; (xvii) T2S's sale of its Trust units and interest in the Underlying Properties; (xiii) the actions, priorities or budget of any successor operator of the Underlying Properties or any third-party operator; and (xix) future cash retentions from distributions. Such forward-looking statements generally are accompanied by words such as “may,” “will,” “estimate,” “expect,” “predict,” “project,” “anticipate,” “goal,” “should,” “assume,” “believe,” “plan,” “intend,” or other words that convey the uncertainty of future events or outcomes. Such statements are based on certain assumptions of the Trustee, and certain assumptions of information provided to the Trust by T2S, the owner of the Underlying Properties; are based on an assessment of, and are subject to, a variety of factors deemed relevant by the Trustee and T2S; and involve risks and uncertainties. The following important factors, in addition to those discussed elsewhere in this Annual Report, could affect the future results of the energy industry in general, and T2S, and the Trust in particular, and could cause actual results to differ materially from those projected in such forward-looking statements:
ii
However, whether actual results and developments will conform with such expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in Item 1A of Part I of this Annual Report, which could affect the future results of the energy industry in general, and the Trust and T2S in particular, and could cause those results to differ materially from those expressed in such forward-looking statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on T2S’s business and the Trust. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. The Trust undertakes no obligation to publicly update or revise any forward-looking statements, except as required by applicable law.
T2S Information
As a holder of a Net Profits Interest, the Trust relies on T2S for information regarding T2S and its affiliates; the Underlying Properties, including the operations, acreage, well and completion count, working interests, production volumes, sales revenues, capital expenditures, operating expenses, reserves, drilling plans, drilling results and leasehold terms related to the Underlying Properties; and factors and circumstances that have or may affect the foregoing. See Part II, Item 9A Controls and Procedures.
iii
Glossary of Terms
average realized sales price |
The average sales price actually received for the sale of oil and natural gas, as distinguished from the NYMEX or other published prices. |
Bbl |
Barrel (of oil). |
Boe |
Barrel of oil equivalent. |
Btu |
A British Thermal Unit, a common unit of energy measurement. |
completion |
The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. |
developed oil and natural gas reserves |
Reserves of any category that can be expected to be recovered (i) 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; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. See 17 CFR § 210.4-10(aX6). |
development well |
A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. |
differential |
The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot, and the wellhead price received. |
distributable income |
An amount paid to Trust unitholders equal to the net profits income received by the Trust during a given period plus interest, less the expenses and payment of liabilities of the Trust, adjusted by any changes in cash reserves. |
estimated future net revenues |
Computed by applying current oil and natural gas prices (with consideration of price changes only to the extent provided by contractual arrangements and allowed by federal regulation) to estimated future production of proved oil and natural gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. See 17 CFR § 210.4-10(c)(4)(A). “Estimated future net revenues” are sometimes referred to in this Annual Report on Form 10-K as “estimated future net cash flows.” |
farm-in or farm-out agreement |
An agreement under which the owner of a working interest in an oil or natural gas lease typically assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in" while the interest transferred by the assignor is a "farm-out." |
field |
An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. |
GAAP |
United States generally accepted accounting principles. |
gross acres or wells |
The total acres or wells, as the case may be, in which a working interest is owned. |
MBbl |
One thousand barrels of crude oil or condensate. |
MBoe |
One thousand barrels of crude oil equivalent. |
Mcf |
One thousand cubic feet (of natural gas). |
MMBoe |
One million barrels of crude oil equivalent. |
MMBtu |
One million Btus. |
MMcf |
One million cubic feet (of natural gas). |
natural gas liquids (NGL) |
Those hydrocarbons that are separated from the gas as liquids through the process of absorption, condensation, or other methods in gas processing or cycling plants. |
iv
net profits |
Gross profits received by Boaz Energy or T2S from the sale of production from the Underlying Properties, less applicable costs, as provided in the Conveyance. |
net profits income |
Net profits multiplied by the net profits percentage of 80%, which is paid to the Trust by Boaz Energy or T2S. “Net profits income” is referred to as “royalty income” for tax reporting purposes. |
Net Profits Interest |
An interest in an oil and natural gas property measured by net profits from the sale of production, rather than a specific portion of production. An 80% net profits interest was conveyed to the Trust entitling the Trust to receive 80% of the net profits from the Underlying Properties. |
net acres or net wells |
The sum of the fractional working interests owned by a given operator in gross acres or wells, as the case may be. |
NGL non-operated |
Natural gas liquids. Working interests which are part of the Underlying Properties but are not operated by Boaz Energy or T2S. |
NYMEX |
The New York Mercantile Exchange is a commodity futures exchange that quotes prices for transactions which are the prices paid for various commodities, including oil and natural gas, throughout the world. |
plugging of abandoned wells |
Activities to remove production equipment and seal off a well at the end of a well's economic life. |
proved developed reserves |
Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. |
proved reserves |
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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
proved undeveloped reserves (PUDs) |
Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. |
PV-10 |
The present value of estimated future net revenues using a discount rate of 10% per annum. |
v
reasonable certainty |
(i) If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered or (ii) if probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. See 17 CFR § 210.4-10(a)(24). |
recompletion |
The completion for production of an existing well bore in another formation from which that well has been previously completed. |
reservoir |
A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. |
secondary recovery |
The second stage of hydrocarbon production during which an external fluid such as water or gas is injected into the reservoir through injection wells located in rock that has fluid communication with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and waterflooding. |
Tcf |
One trillion cubic feet of natural gas. |
Trust units |
Trust units representing beneficial interests in the Trust. |
Underlying Properties |
The interest in certain oil and natural gas properties from which the Net Profits Interest was conveyed by Boaz Energy. The Underlying Properties include working interests in oil and natural gas producing properties located in the Permian Basin in Texas. |
waterflood |
A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil. The water from injection wells physically sweeps the displaced oil to adjacent production wells. |
working interest |
An operating interest in an oil and natural gas property that provides the owner a specified share of production that is subject to all production expense and development costs. |
workover |
Operations on a producing well to restore or increase production. |
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PART I
Item 1. Business
General
PermRock Royalty Trust (the “Trust”) is a Delaware statutory trust formed on November 22, 2017, under the Delaware Statutory Trust Act pursuant to a trust agreement dated November 22, 2017, as amended and restated on May 4, 2018, and as amended on May 6, 2022, by and among T2S Permian Acquisitions II, LLC ("T2S") (as successor in interest to Boaz Energy II, LLC (“Boaz Energy,”)), as trustor, Simmons Bank, as trustee, and Wilmington Trust, National Association, as Delaware Trustee (the “Delaware Trustee”) (such amended and restated trust agreement, as amended to date, the “Trust Agreement”). The Trust’s affairs are administered by the Trustee (as hereinafter defined).
On November 4, 2021, Simmons Bank announced that it had entered into an agreement with Argent Trust Company (“Argent”) pursuant to which Simmons Bank would be resigning as trustee of the Trust and nominated Argent as successor trustee of the Trust. The effective date of Simmons Bank’s resignation and Argent’s appointment as successor trustee was December 30, 2022. In accordance with the successor trustee provisions of the Trust Agreement, Argent, as successor trustee of the Trust, is subject to all terms and conditions of the Trust Agreement. The defined term “Trustee” as used herein shall refer to Simmons Bank (which maintains its offices at 2200 West 7th Street, Suite 210, P.O. Box 470727, Fort Worth, Texas 76147) for periods prior to December 30, 2022, and shall refer to Argent (which maintains its offices at 3838 Oak Lawn Ave, Suite 1720, Dallas, Texas 75219) for periods on and after December 30, 2022.
The Trust was created to acquire and hold the Net Profits Interest for the benefit of the Trust unitholders. The affairs of the Trust are managed by the Trustee. Neither Boaz Energy nor its successor, T2S, have any ability to manage the operations of the Trust, and, to the fullest extent permitted by law, does not owe any fiduciary duties to the Trust or the unitholders. The Delaware Trustee has only minimal rights and duties as are necessary to satisfy the requirements of the Delaware Statutory Trust Act.
The Trust’s purpose is to own the Net Profits Interest, to distribute to the Trust unitholders cash that the Trust receives in respect of the Net Profits Interest and to perform certain administrative functions in respect of the Net Profits Interest and the Trust units. Other than the foregoing activities, the Trust does not conduct any operations or activities. The Trust derives all or substantially all of its income and cash flow from the Net Profits Interest. The Trust has no employees.
The Trust makes monthly cash distributions of all of its monthly cash receipts, after deduction of fees and expenses for the administration of the Trust and any cash reserves, to holders of its Trust units as of the applicable record date, on or before the 10th business day after the record date. Distributions generally relate to sales from a one-month period.
The Conveyance
In connection with the closing of the initial public offering of Trust units and pursuant to the Conveyance of Net Profits Interest (the “Conveyance”) effective May 4, 2018, Boaz Energy conveyed the Net Profits Interest to the Trust in exchange for Trust units. The Net Profits Interest entitles the Trust to receive 80% of the net profits from the sale of oil and natural gas production from the Underlying Properties. The Net Profits Interest is passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, costs relating to the operation of the Underlying Properties.
The Underlying Properties consist of 31,354 gross (22,394 net) acres in the Permian Basin. The Permian Basin extends over 75,000 square miles in West Texas and Southeastern New Mexico. The Underlying Properties consist of the following four operating areas:
A detailed description of the Underlying Properties is included under Item 2. Properties.
1
On January 13, 2025, the Trust announced that Boaz Energy and its affiliate Boaz Energy II Royalty, LLC entered into a Purchase and Sale Agreement on January 10, 2025 (the “Purchase and Sale Agreement”) with T2S Permian Acquisition II LLC, a Delaware limited liability company (the “Buyer” or “T2S”), with respect to the Underlying Properties.
Boaz Energy informed the Trust that, pursuant to the Purchase and Sale Agreement, Boaz Energy sold and conveyed (a) to T2S, all of Boaz Energy’s right, title and interest in and to the Underlying Properties (which shall remain burdened by the Net Profits Interest and subject to the Conveyance); and (b) to Ustx, LLC, all of Boaz Energy’s 4,884,861 Trust units representing beneficial interests in the Trust (the “Boaz Trust Units”).
Boaz Energy reported that the Purchase and Sale Agreement contained customary conditions to the parties’ obligations to consummate the closing of the transaction (the “Closing”). The Closing occurred on March 31, 2025. From and after the Closing, T2S has been the owner of the Underlying Properties (burdened by the Trust’s Net Profits Interest and subject to the Conveyance), T2S or an affiliate has been the operator of the Underlying Properties, and Ustx, LLC has been the owner of the Boaz Trust Units.
Computation of Net Profit
Net profits are computed monthly, and 80% of the aggregate net profits attributable to the sale of oil and natural gas production from the Underlying Properties received during each calendar month are paid to the Trust on or before the end of the following month.
“Gross profits” generally means the aggregate amount received by Boaz Energy or T2S from sales of oil and natural gas produced from the Underlying Properties subject to certain adjustments as described in the Conveyance. “Net profits” generally means gross profits less the costs and expenses for, among other things, drilling and development activities, production, operation, maintenance and abandonment operations, taxes, charges and assessments and insurance and, where applicable, losses, liabilities and damages, in each case as incurred by Boaz Energy or T2S and attributable to the Underlying Properties (as such items are reduced by any offset amounts, as described in the Conveyance).
The Trust is not liable to the owners of the Underlying Properties or the operators for any operating, capital or other costs or liabilities attributable to the Underlying Properties. In the event that the net profits for any computation period is a negative amount, the Trust will receive no payment for that period, and any such negative amount plus accrued interest will be deducted from gross profits in the following computation period for purposes of determining the net profits for that following computation period.
Gross profits and net profits are calculated on a cash basis, except that certain costs, primarily ad valorem taxes and expenditures of a material amount, may be determined on an accrual basis.
The Trustee is not obligated to return any cash received from the Net Profits Interest. Any overpayments made to the Trust by Boaz Energy or T2S due to adjustments to prior calculations of net profits or otherwise will reduce future amounts payable to the Trust until Boaz Energy or T2S recover the overpayments plus interest at a prime rate (as described in the Conveyance).
Boaz Energy and T2S must maintain books and records sufficient to determine the amounts payable for the Net Profits Interest to the Trust. Monthly and annually, Boaz Energy or T2S must deliver to the Trustee a statement of the computation of the net profits for each computation period. The annual computation must be audited. The Trustee has the right to inspect, review and audit the books and records maintained by Boaz Energy or T2S during normal business hours and upon reasonable notice.
Marketing and Customers
Pursuant to the terms of the Conveyance, Boaz Energy (and any successor operator) has the responsibility to market, or cause to be marketed, the oil and natural gas production attributable to the Net Profits Interest in the Underlying Properties.
During the year ended December 31, 2025, Boaz Energy, T2S, and other third-party operators of the Underlying Properties sold the oil produced from the Underlying Properties to third-party purchasers. Oil production from the Underlying Properties is typically transported by pipeline or truck from the field to the closest gathering facility or refinery. Boaz Energy sold, and T2S and other operators sell, the majority of the oil production from the Underlying Properties under contracts based on geographic location using market sensitive pricing. The price received by the operators for the oil production from the Underlying Properties is usually based on a regional price applied to equal daily quantities in the month of delivery that is then reduced for differentials based upon delivery location and oil quality.
2
All natural gas produced from the Underlying Properties is marketed and sold to third-party purchasers. In all cases, the contract price is based on a percentage of a published regional index price, after adjustments for Btu content, transportation and related charges. Natural gas production is typically transported by pipeline to the closest gathering facility. Natural gas that is processed to remove NGLs is done under a percentage of proceeds contract and the Trust’s percentage of those proceeds are included in the Net Profits Interest.
For the year ended December 31, 2025, T2S reported that Phillips 66, Plains All American Pipeline, Energy Transfer Partners, and Enterprise Crude Oil LLC accounted for 34.34%, 17.01%, 16.31%, and 14.69% respectively, of its total oil and natural gas revenues, and that no other purchaser accounted for 10% or more of the total revenue of the Underlying Properties. T2S does not believe that the loss of any of these parties as a purchaser of crude oil or natural gas production from the Underlying Properties would have a material impact on the business or operations of T2S or the Underlying Properties because of the large number of marketing firms and competitive nature of oil and gas purchasers in the Permian Basin. Oil and natural gas are currently sold to these four customers under short-term contracts at market prices.
Competition and Markets
The oil and natural gas industry is highly competitive. T2S competes with major oil and natural gas companies and independent oil and natural gas companies for oil and natural gas, equipment, personnel and markets for the sale of oil and natural gas. Many of these competitors are financially stronger than T2S, but even financially troubled competitors can affect the market because of their need to sell oil and natural gas at any price to attempt to maintain cash flow. Because T2S and the third-party operators of the Underlying Properties are subject to competitive conditions in the oil and natural gas industry, the Trust’s Net Profits Interest is indirectly subject to those same competitive conditions.
Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.
All of the Trust’s assets are located in the United States. T2S and the third-party operators of the Underlying Properties sell the oil and natural gas produced from the Underlying Properties to third-party purchasers in the United States. Demand for natural gas generally is higher in the winter months, but otherwise seasonal factors do not directly affect the Trust.
Dissolution of the Trust
The Trust is not subject to any pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time. The Trust will dissolve upon the earliest to occur of the following:
Upon dissolution of the Trust, the Trustee is obligated to sell all of the Trust’s assets, either by private sale or public auction, and, after payment or the making of reasonable provision for payment of all liabilities of the Trust, distribute the net proceeds of the sale to the Trust unitholders.
Environmental Matters and Regulation
General. For purposes of the discussion in this section, the oil and natural gas production operations conducted on the Underlying Properties are the operations of Boaz Energy, through March 31, 2025, and T2S or its affiliates for all periods after March 31, 2025. Boaz Energy’s and T2S's oil and natural gas exploration and production operations are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose significant obligations on Boaz Energy’s and T2S's operations, including, but not limited to, requirements to:
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Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of strict, joint and several liability, investigatory and remedial obligations and the issuance of injunctions limiting or prohibiting some or all of the operations on the Underlying Properties. Moreover, these laws, rules and regulations may restrict the rate of oil, natural gas and NGL production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could increase the cost to T2S of developing the Underlying Properties. Moreover, accidental releases or spills may occur in the course of operations on the Underlying Properties, causing T2S to incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.
Increased costs or operating restrictions on the Underlying Properties as a result of compliance with or liability under environmental laws could result in reduced exploratory and production activities on the Underlying Properties and, as a result, distributable cash to the Trust unitholders. The following is a summary of certain existing environmental, health and safety laws and regulations, each as amended from time to time, to which operations on the Underlying Properties are subject.
Hazardous Substances and Waste Handling
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons, or “responsible parties,” who are considered to be responsible for the release or threatened release of a “hazardous substance” from a facility into the environment. Under CERCLA, these “responsible persons” may include the owner or operator of the site, the owner or operator of site at the time of disposal, any person who arranges for disposal at the site, and any person that transports hazardous substances to a site from which there is a release of hazardous substances. These responsible persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from responsible parties the costs they incur. It is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. On September 6, 2022, EPA designated two per- and polyfluoroalkyl substances (“PFAS”) as hazardous substances under CERCLA. PFAS chemicals are known as “forever chemicals” because of their persistence in the environment. PFAS have been widely used in industrial and commercial applications since the 1950s, including the oil and gas industry, and designation of certain PFAS as a CERCLA hazardous substances increases potential risks of incurring CERCLA liabilities where they have been historically used. In April 2023, EPA issued an Advance Notice of Proposed Rulemaking asking the public for input regarding potential future hazardous substance designations of PFAS under CERCLA, and in June 2023, EPA released a framework for addressing new and new uses of PFAS under the Toxic Substances Control Act (“TSCA”). U.S. EPA’s National Enforcement and Compliance Initiatives for the fiscal years 2024-2027 listed PFAS identification and characterization of the extent of PFAS contamination as one of the agency’s new initiatives.
The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws control the management and disposal of hazardous and non-hazardous waste. These laws and regulations govern the generation, storage, treatment, transfer and disposal of wastes generated. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil, natural gas and NGLs, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil, natural gas and NGL drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil, natural gas and NGL wastes from regulation as hazardous wastes under RCRA. The consent decree required the EPA to propose a rulemaking no later than March 15, 2019, for revision of certain Subtitle D criteria regulations pertaining to oil, natural gas and NGL wastes or to sign a determination that revision of the regulations is not necessary (which deadline was extended
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to April 23, 2019, due to a lapse in appropriations). On April 23, 2019, EPA made a determination that revisions to the federal regulations for the management of exploration and production waste under Subtitle D of RCRA are not necessary and issued a report explaining the basis for its decision. In October 2023, EPA released a final rule that eliminated an exemption that allowed facilities to avoid reporting information on PFAS when those chemicals were used in small concentrations. In January 2024, the EPA announced the automatic addition of seven PFAS to the list of chemicals covered by the Toxics Release Inventory (TRI), consistent with the Fiscal Year 2020 National Defense Authorization Act, and in February 2024, EPA released two proposed regulations under RCRA, adding nine PFAS to the list of RCRA hazardous constituents. EPA stated it will continue to work to identify areas for regulatory improvements and to address emerging issues to ensure exploration and production wastes continue to be managed appropriately. Any future regulatory change due to emerging issues, a change in EPA determination, or otherwise could result in an increase in the costs to manage and dispose of wastes, which could increase the costs of T2S's operations.
Certain of the Underlying Properties have been used for oil and natural gas exploration and production for many years. Although the operators may have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of or released on or under the Underlying Properties, or on or under other offsite locations where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. The Underlying Properties and the petroleum hydrocarbons and wastes disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the owner or operator could be required to remove or remediate previously disposed wastes, to clean up contaminated property and to perform remedial operations such as restoration of pits and plugging of abandoned wells to prevent future contamination or to pay some or all of the costs of any such action.
Water Discharges
The Federal Water Pollution Control Act, also known as the “Clean Water Act” (“CWA”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Obtaining permits has the potential to delay the development of oil and natural gas projects. In addition, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. On August 29, 2023, the EPA published a final rule clarifying the federal jurisdictional reach over waters of the United States (“WOTUS”) and conforming the definition of WOTUS with the U.S. Supreme Court’s interpretation in its Sackett v. EPA decision. The scope of jurisdiction under the CWA includes (a) waters (i) currently used, or that were used in the past, or may be susceptible to use in interstate or foreign commerce, including all waters which are subject to the ebb and flow of the tide; (ii) the territorial seas; or (iii) interstate waters, and (b) only wetlands that have a “continuous surface connection” with those traditional waters. “Continuous surface connection” means when there is no clear demarcation between traditional “waters” and wetlands, which is a narrower construction of applicable wetlands than years prior, thereby eliminating some of the wetlands previously covered. On March 12, 2025, EPA issued guidance on the proper implementation of “continuous surface connection” under the definition of WOTUS. The guidance narrows wetlands jurisdiction to waters adjacent to WOTUS, “which generally means traditional navigable waters, or a relatively permanent body of water connected to a traditional navigable water,” and to wetlands with a “continuous surface connection to a requisite covered water making it difficult to determine where the water ends and wetland begins.” In the wake of the Sackett decision, several states have developed their own wetlands policies or regulatory programs to address discharges to intra-state waters that may no longer be regulated as WOTUS. Texas has not enacted any new state-level laws to fill the regulatory gap created by the Sackett v. EPA ruling; the State continues to rely primarily on federal standards and voluntary state programs. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of WOTUS in the event of a hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Oil Pollution Act of 1990, as amended, or “OPA,” amends the CWA and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into WOTUS. OPA requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil into WOTUS. EPA and various states also impose permitting requirements for the disposal of produced water by underground injection. As these requirements increase and become more strict, they could result in an increase in the costs to manage and dispose of wastes, which could increase the costs of T2S's operations. As of March 2025, the EPA announced a major initiative to reconsider and revise 1970s-era wastewater regulations (effluent guidelines) for oil and gas extraction, aiming to lower production costs and promote the treatment and beneficial reuse of produced water.
Air Emissions
The CAA and comparable state laws restrict the emission of air pollutants from many sources through air emissions permitting programs and also impose various monitoring, testing, and reporting requirements. These laws and regulations may require T2S to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or incur development expenses to install and utilize
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specific equipment or technologies to control emissions. For example, in June 2016 the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. In addition, EPA, New Mexico, Texas and other states have begun to regulate through their New Source Performance Standards (“NSPS”) and other air emissions programs the emission of VOCs and methane from oil and gas production process equipment, storage tanks and produced water impoundments and other assets. These requirements could increase the costs of development and production on the Underlying Properties, potentially impairing the economic development of the Underlying Properties and reducing the amount of cash distributable to Trust unitholders. Obtaining permits has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies may impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. As particularly related to the CAA, the EPA’s National Enforcement and Compliance Initiatives for fiscal years 2024-2027, which were updated on August 17, 2023, continued some of its initiatives from fiscal year 2020-2023, including addressing hazardous air pollutant violations in communities already highly burdened with pollution impacts and to focus on chemical accident risk prevention under Section 112(r) of the CAA with a focus on anhydrous ammonia (mainly used as a fertilizer or a refrigerant) and hydrogen fluoride (used in petrochemical manufacturing). Reducing emissions from significant sources of volatile organic compounds (“VOC”) and hazardous air pollutants could lead to increased scrutiny of air emissions from oil and gas operations. Air toxin reporting is currently voluntary, but if it became mandatory, then there may be increased costs toT2S's operations. On October 16, 2024, EPA promulgated final amendments to the National Emission Standards for Hazardous Air Pollutants (“NESHAPs”) for oil and gas production facilities and for natural gas transmission and storage facilities to remove an affirmative defense based on emissions caused by malfunctions. These amendments could ultimately increase T2S's costs of compliance. On March 8, 2024, the EPA promulgated a final rule to reduce methane and other pollution from oil and natural gas operations. This rule requires the elimination of routine flaring of natural gas and could increase T2S's cost of compliance. The Biden EPA promulgated NSPS regulations OOOOb/c which were designed to slash methane and VOC emissions from the oil and gas industry. OOOOb targets new, modified, or reconstructed sources, while OOOOc sets guidelines for existing sources. On March 12, 2025, the Trump Administration announced it is reconsidering the NSPS Subpart OOOO b/c rules. As of late 2025, the EPA is actively rolling back and delaying compliance deadlines for the 2024 OOOOb/c methane regulations. A final rule effective December 3, 2025, extends deadlines for control devices, leaks, and storage vessels, aiming to cut industry compliance costs.
Climate Change
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, ("Endangerment Finding") the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish PSD, construction and Title V operating permit reviews for certain large stationary sources. On February 18, 2026, Trump’s EPA finalized the repeal of the Endangerment Finding, which previously established that GHGs endanger public health. This move is being challenged in court by a coalition of nearly 40 states and cities. President Trump’s 2025 executive orders, particularly EO 14154 “Unleashing American Energy,” aim to dismantle federal climate change actions, accelerate fossil fuel production, and reverse environmental regulations from previous administrations.
At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted rules under authority of the CAA that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions. Under these regulations, facilities required to obtain PSD permits must meet “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore and offshore production facilities, which include certain operations on the Underlying Properties. The EPA has expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells.
Federal agencies also have begun directly regulating emissions of methane from oil and natural gas operations. For example, in June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that requires certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. However, on August 28, 2019, the EPA published a notice of reconsideration proposing to rescind methane-specific requirements for new and modified oil and gas infrastructure, which drew legal challenges. Subsequently, on November 2, 2021, EPA released a proposed rule that would limit emissions of methane—a greenhouse gas—from facilities in the oil and gas sector. In November 2022, EPA published a supplemental proposed rule that will increase monitoring and mitigation requirements related to methane and VOC emissions from the oil and gas industry. The proposed regulations, once effective, would reach new and existing facilities in the production, gathering, processing, and transmission and storage segments. Notably, the Biden administration has made
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addressing climate change a priority and is expected to take steps to reduce harmful air emissions, which could result in new efforts to set methane limits and otherwise regulate GHGs. On December 2, 2023, EPA issued a final rule to reduce emissions of methane and other harmful pollutants from oil and gas operations. The rule added new NSPS standards to reduce methane and VOCs from oil and gas operations and developed a new “super emitter” program. EPA has also proposed a new rule to establish a Waste Emission Charge that applies to methane emissions from certain oil and gas operations. On March 12, 2025, the Trump Administration announced it is reconsidering rules promulgated by the Biden Administration under NSPS Subpart OOOO b/c. As of late 2025, the EPA under the Trump administration is actively rolling back and delaying compliance deadlines for the 2024 OOOOb/c methane regulations. A final rule effective December 3, 2025, extends deadlines for control devices, leaks, and storage vessels, aiming to cut industry compliance costs.
Many states have adopted GHG emission reduction goals broadly and for specific industries, which provides for GHG regulation and limits on permitting that will affect the oil and gas industry, for example through moratoriums on drilling and limits on permitting.
On May 14, 2024, EPA promulgated its final Greenhouse Gas Reporting. The rule requires that certain sources report GHGs over 25,000 tons per year. On April 25, 2024, EPA promulgated subpart Y of the GHG reporting rule that applies to refineries. In March 2025, EPA announced that it was reconsidering the GHG reporting rule. The adoption of these regulations and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict or place a fee or charge on emissions of GHGs could result in increased compliance costs or additional operating restrictions for T2S and could have a material adverse effect on our business, financial condition and results of operations. The Trump administration has proposed rolling back the EPA's Greenhouse Gas Reporting Program (GHGRP) for most sectors while specifically postponing, until 2034, reporting requirements for the oil and gas industry. While statutory reporting under the IRA "waste emissions charge" remains in place, the broader, detailed reporting on methane and other greenhouse gases is largely being suspended. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Moreover, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or to shift away from more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could make it more difficult for T2S to engage in exploration and production activities, ultimately reducing distributable cash to Trust unitholders. Finally, many scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on operations of the Underlying Properties and, as a result, the amount of cash distributable to Trust unitholders.
Hydraulic Fracturing Activities
T2S engages in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Currently, hydraulic fracturing is generally exempt from regulation under the U.S. Safe Drinking Water Act’s Underground Injection Control program and is typically regulated by state oil and gas commissions or similar agencies.
However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances. From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In the event that new federal restrictions relating to the hydraulic fracturing process are adopted in areas where we own mineral or royalty interests, or T2S may incur additional costs or permitting requirements to comply with such federal requirements that may be significant and that could result in added delays or curtailment in or T2S's pursuit of exploration, development or production activities, which would in turn reduce the oil, natural gas and NGLs produced from the Underlying Properties.
Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states in which the Underlying Properties are located. For example, Texas has adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States
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could also elect to prohibit high volume hydraulic fracturing altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil, natural gas and NGL production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs for T2S in the production of oil, natural gas and NGLs, including from the developing shale plays, or could make it more difficult for T2S to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in T2S's completion of new oil and natural gas wells on the Underlying Properties and an associated decrease in the distributable cash in the Trust.
Endangered Species Act and Migratory Birds Treaty Act
In the United States, the Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where the Underlying Properties are located, T2S's abilities to conduct or expand operations on the Underlying Properties could be limited, or T2S could be forced to incur material additional costs. Moreover, T2S's ability to conduct drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons.
In addition, as a result of one or more settlements approved by the U.S. Fish & Wildlife Service (the “FWS”), the FWS was required to make a determination on the listing of numerous other species as endangered or threatened under the ESA by the end of the FWS’ 2017 fiscal year. The agency missed the deadline, and the review is reportedly ongoing. On August 12, 2019, the FWS finalized a package of ESA regulatory revisions addressing standards for listing, delisting, and reclassification of species, consultation parameters, and protections for threatened species, changes which are expected to ease the path for development projects On June 22, 2023, the FWS proposed to revise the 2019 final rule regarding consultation, listing and reclassification of species and designations of critical habitat, and reinstatement of the “blanket” 4(d) rules that were withdrawn in 2019. The Trump administration has proposed significant revisions to the ESA to reduce regulatory burdens on land use, effectively rolling back Biden-era protections. Key changes include removing automatic protections for “threatened” species, allowing economic impact considerations in listing decisions, narrowing “critical habitat” definitions, and redefining “harm” to exclude habitat modification. The Trump administration has reinterpreted the Migratory Bird Treaty Act (MBTA) to only prohibit the intentional killing of birds, effectively eliminating liability for industries that accidentally or incidentally kill birds during operations. This policy change, rooted in a 2017 legal opinion and reinstated in 2025, exempts activities like oil spills or power line hazards from penalties, prioritizing energy production over unintentional habitat impact
The designation of previously unidentified endangered or threatened species could cause T2S's operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. For example, the FWS officially listed the Dunes Sagebrush Lizard, whose habitat includes portions of the Permian Basin, as endangered in May 2024, prompting intense legal battles and renewed calls to review or revoke these protections, particularly from Texas officials, who argue the federal action restricts oil and gas development in the Permian Basin. Environmental groups are simultaneously moving to defend the listing against state lawsuits. When species are listed, the FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands. To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where the Underlying Properties are located, operations on the Underlying Properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon.
Employee Health and Safety
Operations on the Underlying Properties are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.
Available Information
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The Trust maintains a website at www.permrock.com. The SEC maintains an internet site that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. The Trust’s filings under the Exchange Act are available on the website and are also available electronically from the website maintained by the SEC at www.sec.gov.
Item 1A. Risk Factors
Summary of Risk Factors
The risk factors summarized and detailed below could materially harm production from the Underlying Properties, operating results and/or the Trust’s financial condition, adversely affect proceeds to the Trust and cash distributions to Trust unitholders, and/or cause the price of the Trust units to decline. These are not all the risks the Trust faces, and other factors not presently known to the Trust or that the Trust currently believes are immaterial may also affect the Trust if they occur. Where the risk factors refer to T2S, any affiliate of T2S, any successor to T2S, or any third-party operator if applicable, is included. These risks and uncertainties include, but are not limited to, the following:
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BUSINESS AND OPERATING RISKS
Oil and natural gas prices are volatile, and lower oil and natural gas prices could reduce proceeds to the Trust and cash distributions to Trust unitholders.
The Trust’s reserves and monthly cash distributions are highly dependent upon the prices realized from the sale of oil and natural gas. Oil and natural gas are commodities, and their prices can be volatile and fluctuate widely in response to market uncertainty and relatively minor changes in the supply of and demand for oil and natural gas. Factors that affect oil and natural gas prices include, among others:
These factors make it extremely difficult to predict oil and natural gas price movements or future cash distributions to unitholders. Lower oil, natural gas and natural gas liquids prices have resulted in and may result in future periods of reduced net proceeds to which the Trust is entitled. This could materially reduce or completely eliminate the amount of cash available for distribution to Trust unitholders and may ultimately reduce the amount of oil and natural gas that is economic to produce from the Underlying Properties. Sustained lower prices of oil and natural gas could also negatively affect the price of the Trust units and the qualification of the Trust units to remain listed on the New York Stock Exchange. Because the monthly distributions correlate with the
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net profits generated each month after payment of costs and expenses related to the Underlying Properties (including direct operating expenses and development expenses), future monthly distributions paid to the Trust unitholders will vary significantly from month to month and may be zero in any given month.
Pandemics and other public health concerns, including a COVID-19 pandemic resurgence or emergence of new COVID-19 variants, are possible and could adversely affect global demand for oil and gas, the operators of the Underlying Properties, the Net Profits Interest and the cash available for distribution to unitholders.
In the event of a resurgence of COVID-19, the emergence of new strains or variants of COVID-19, or the occurrence of other pandemics or public health concerns, it is not possible to predict the impact such public health concern may have on global demand for oil and gas. If prices are negatively impacted in the future, it is possible T2S, or any third-party operator of the Underlying Properties could shut in or curtail production from wells on the Underlying Properties or plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices, without the consent of the Trust or the Trust unitholders. Substantial declines in and extended periods of decreased economic activity and depressed oil, natural gas and natural gas liquids prices have previously resulted in and may in future periods result in reductions in the amount of oil and natural gas that is economic to produce from the Underlying Properties, reduced net proceeds to which the Trust is entitled, and elimination of cash available for distribution to Trust unitholders for an unknown period of time.
To the extent COVID-19, other health concerns, or related mitigation efforts adversely affect production from the Underlying Properties or the business, results of operations and financial condition of the operators of the Underlying Properties, it may also have the effect of heightening many of the other risks described in this Form 10-K.
The ability or willingness of OPEC and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices, which could reduce the amount of cash available for distribution to Trust unitholders.
The Organization of Petroleum Exporting Countries (“OPEC”) is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations, have a significant impact on global oil supply and pricing. The extent and duration of production cuts by OPEC members and other oil exporting nations to support crude oil prices have fluctuated and may continue to do so. There can be no assurance that OPEC members and other oil exporting nations will continue to agree to production cuts or other actions to support and stabilize oil prices, nor can there be any assurance that they will not further reduce oil prices or increase production. Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to continued volatility in the price of oil, which could adversely affect the financial condition and economic performance of the operators of the Underlying Properties and may reduce net profits income and significantly reduce or completely eliminate the amount of cash available for distribution to Trust unitholders for an unknown period of time.
Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the Trust units.
The value of the Trust units and the amount of future cash distributions to the Trust unitholders will depend on, among other things, the accuracy of the reserves and future production estimated to be attributable to the Trust’s interest in the Underlying Properties. It is not possible to measure underground accumulations of oil and natural gas in an exact way, and estimating reserves is inherently uncertain. Ultimately, actual production and revenues for the Underlying Properties could vary both positively and negatively and in material amounts from the estimates contained in the reserve reports. Furthermore, direct operating expenses and development expenses relating to the Underlying Properties could be substantially higher than current estimates. Petroleum engineers are required to make subjective estimates of underground accumulations of oil and natural gas based on factors and assumptions that include:
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Changes in these assumptions and amounts of actual direct operating expenses and development expenses could materially decrease reserve estimates. In addition, the quantities of recovered reserves attributable to the Underlying Properties have decreased, and may decrease in the future, as a result of future decreases in the price of oil or natural gas.
Developing oil and natural gas wells and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect future production from the Underlying Properties. Any delays, reductions or cancellations in development and producing activities could decrease revenues that are available for distribution to Trust unitholders.
Recovery of proved undeveloped reserves and the development of proved developed non-producing reserves requires capital expenditures and successful drilling operations by T2S and other third-party operators of the Underlying Properties. The reserve data included in the reserve report of T2S's independent petroleum engineer assumes a certain amount of capital expenditures will be made to develop such reserves. The Net Profits Interest bears its proportionate share of these capital expenditures. However, the development of such reserves has in the past and may in the future take longer and may require higher levels of capital expenditures than anticipated. Delays in the development of the reserves, increases in drilling and development costs (including expenses related to secondary and tertiary recovery techniques) of such reserves or decreases or continued volatility in commodity prices will reduce the future net revenues of the estimated proved undeveloped reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves have caused, and could further cause, T2S (or any successor to T2S) to reclassify certain of the proved reserves as unproved reserves. T2S has no plans for any capital projects in 2026 and may continue to delay any capital projects beyond 2026.
In addition, the process of developing oil and natural gas wells and producing oil and natural gas on the Underlying Properties is subject to numerous risks beyond T2S’s control, (or the control of any successor to T2S), including risks that could delay T2S’s, any successor to T2S’s, or any third-party operators’ current drilling or production schedule and the risk that drilling will not result in commercially viable oil or natural gas production. The ability of the operators to carry out operations or to finance planned development expenses could be materially and adversely affected by any factor that may curtail, delay, reduce or cancel development and production, including:
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In the event that planned operations by T2S or other operators, including drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, estimated future distributions to Trust unitholders may be reduced. In the event an operator incurs increased costs due to one or more of the above factors or for any other reason and is not able to recover such costs from insurance, the estimated future distributions to Trust unitholders may be reduced.
The amount of cash available for distribution by the Trust depends in part on access to and operation of gathering, transportation and processing facilities on commercially reasonable terms or otherwise. Any limitation in the availability of those facilities could interfere with sales of oil and natural gas production from the Underlying Properties.
The marketing of oil and natural gas production depends in large part on the capacity and availability of gathering systems and other pipelines, trucks, storage facilities and other transportation, processing and refining facilities. If these facilities are unavailable on commercially reasonable terms or otherwise, production from the Underlying Properties could be shut in or T2S or the third-party operators could be required to delay or discontinue drilling plans and commercial production. T2S relies (and expects to rely in the future) on facilities developed and owned by third parties in order to transport, store, process and sell the oil and natural gas production from the Underlying Properties. T2S's (or any successor to T2S's) plan to develop and sell its oil and natural gas could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to T2S on commercially reasonable terms, or otherwise.
The amount of oil and natural gas that can be produced and sold from a well is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered oil and natural gas to meet quality specifications of gathering lines or downstream transporters, excessive pressure, damage to the gathering, transportation, refining or processing facilities or lack of capacity at such facilities. Increases in activity in the Permian Basin could, in the future, contribute to bottlenecks in processing and transportation that could negatively affect the production, transportation and sale of oil and natural gas from the Underlying Properties, and these adverse effects could be disproportionately severe compared to more geographically diverse operations. If T2S, any successor to T2S, or the third-party operators are forced to reduce production due to such a curtailment, the revenues of the Trust and the amount of cash distributions to the Trust unitholders would similarly be reduced due to the reduction of profits from the sale of production.
T2S, any successor to T2S, or any third-party operator of any Underlying Property may abandon the property, thereby terminating the related Net Profits Interest payable to the Trust that is attributable to the abandoned property.
T2S, any successor to T2S, or any third-party operator of the Underlying Properties could determine during periods of low commodity prices to shut in or curtail production from wells on the Underlying Properties or plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. T2S or any other operator may abandon any well or property without the consent of the Trust or the Trust unitholders if it reasonably believes that the well or property can no longer produce oil or natural gas in commercially paying quantities. This could result in termination of the Net Profits Interest relating to the abandoned well or property. The Underlying Properties are sensitive to decreasing commodity prices. The commodity price sensitivity is due to a variety of factors that vary from well to well, including the costs associated with water handling and disposal, chemicals, surface equipment maintenance, downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result, the volatility of commodity prices may cause the expenses of certain wells to exceed the well’s revenue. If this scenario occurs, T2S, its successor, or any third-party operator may decide to shut-in the well or plug and abandon the well. This could reduce future cash distributions to Trust unitholders.
The unavailability or high cost of equipment, supplies, personnel and services could increase costs of developing and operating the Underlying Properties and result in a reduction in the amount of cash available for distribution to the Trust unitholders.
The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, supplies, personnel and services. Higher oil and natural gas prices generally stimulate demand and result in increased process for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could hinder the ability to conduct operations. The occurrence, timing and duration of these conditions in the future is impossible to predict. Such shortages could delay development and/or operating activities or cause a significant increase in
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development and operating expenses associated with the Underlying Properties, which would reduce the amount of cash received by the Trust and available for distribution to the Trust unitholders.
All of the Underlying Properties are concentrated in the Permian Basin, making the Trust vulnerable to risks associated with operating in only one major geographic area.
As a result of the Trust’s geographic concentration, an adverse development in the industry in the Permian Basin could have a greater impact on revenues of the Trust and the amount of cash distributions to the Trust unitholders than if the Underlying Properties were more geographically diverse. The Underlying Properties may also be disproportionately exposed to the impact of adverse developments in exploration and production of oil and natural gas, regional supply and demand factors, governmental regulation or midstream capacity constraints. Delays or interruptions caused by such factors could have a material adverse effect on revenues of the Trust and the amount of cash distributions to the Trust unitholders.
Similarly, the concentration of the Underlying Properties within the Permian Basin exposes the Trust to risks, which could adversely affect development activities or production relating to such formations. In addition, in areas where exploration and production activities are increasing, T2S and any successor to T2S could be subject to increasing competition for drilling rigs, equipment, services, supplies and qualified personnel, which may lead to periodic shortages or delays. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, T2S and any successor to T2S may be provided only limited, if any, notice as to when such circumstances will arise and their duration.
A bankruptcy of T2S , any successor to T2S, or any third-party operator could adversely affect the operation of the wells and the development of the proved undeveloped reserves and interrupt or decrease distributions to Trust unitholders.
The value of the Net Profits Interest and the Trust’s ultimate cash available for distribution are highly dependent on T2S’s financial condition, (and the financial condition of any successor to T2S). Neither T2S nor any other operator of the Underlying Properties has agreed with the Trust to maintain a certain net worth or to be restricted by other similar covenants. In addition, T2S's affiliate, Ustx LLC, is not required to retain ownership of its Trust units and may sell such units or distribute such units, or the proceeds from the sale thereof, to its owners. The ability to develop and operate the Underlying Properties depends on T2S’s or any successor’s future financial condition and economic performance and access to capital, which in turn will depend upon the supply of and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of T2S.
The bankruptcy of T2S, any successor to T2S or any third-party operator of the Underlying Properties could impede the operation of the wells and the development of the proved undeveloped reserves and decrease distributions to the Trust unitholders. For example:
T2S is not a reporting company and is not required to file periodic reports with the SEC pursuant to the Exchange Act. Therefore, Trust unitholders do not have access to financial information about T2S.
FINANCIAL RISKS
The reserves attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over the long term and may eventually cease, therefore, proceeds to the Trust and cash distributions to Trust unitholders will decrease over time and may eventually cease.
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The profits payable to the Trust attributable to the Net Profits Interest are derived from the sale of production of oil and natural gas from the Underlying Properties. The reserves attributable to the Underlying Properties are depleting assets, which means that the reserves and the quantity of oil and natural gas produced from the Underlying Properties will decline over time. Actual decline rates have varied and likely will continue to vary from the decline rates projected in reserve reports.
Maintenance projects on the Underlying Properties have affected and will likely continue to affect the quantity of proved reserves that can be economically produced from wells on the Underlying Properties. The timing and size of these maintenance projects will depend on, among other factors, the market prices of oil and natural gas. Neither T2S nor any successor to T2S is under contractual obligation to develop or otherwise pay maintenance or other development expenses on the Underlying Properties in the future. Furthermore, with respect to properties for which T2S or any successor to T2S is not designated as the operator, T2S has (and any successor will have) limited control over the timing or amount of those maintenance projects and other development expenses. Boaz Energy had prior to March 31, 2025, and T2S has on and after March 31, 2025, the right to non-consent and not participate in maintenance projects and other development activities on properties for which it is not the operator, in which case T2S and the Trust will not receive the production resulting from such maintenance projects and other development expenses until after payout occurs pursuant to the applicable joint operating agreement. If T2S, any successor to T2S, or any third-party operator does not implement maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by T2S or estimated in reserve reports. Furthermore, the Trust is not permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets and production attributable to the Net Profits Interest.
The Trustee reviews the Trust’s Net Profits Interest in oil and natural gas properties for impairment annually and whenever events or circumstances indicate that the carrying value of the Net Profits Interest may not be recoverable. In the event of material revisions, the Trustee reviews the impact of these revisions on the amortization of Trust Units and impairment estimates. During 2025, a material revision was made to reserves resulting in the additional recognition of amortization of Trust Units. The Trust recognized $5,905,119 of amortization of Trust Units for the year ended December 31, 2025.
In general, neither the Trustee nor T2S view temporarily low prices as an indication of impairment. The markets for crude oil and natural gas have a history of significant price volatility and though prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand. When events and circumstances indicate that the carrying value may not be recoverable, the Trustee uses the estimated undiscounted future net cash flows from the Net Profits Interest to evaluate the recoverability of the Trust assets. When the undiscounted future net cash flows from the Net Profits Interest are less than the Net Profits Interest carrying value, the Trust recognizes an impairment loss for the difference between the Net Profits Interest carrying value and the estimated fair value of the Net Profits Interest. The determination as to whether the Net Profits Interest is impaired is based on the best information available to the Trustee at the time of the evaluation, including information provided by T2S such as estimates of future production and development and operating expenses.
The Trustee determined that an impairment in the amount of $39.9 million occurred for the year ended December 31, 2025, after reviewing the undiscounted and discounted cash flow that had been revised to reflect future crude oil and natural gas commodity prices published by third-party industry experts (adjusted for base differentials) and a risk-adjusted discount rate. The Net Profits Interest was written down to its fair value of $26.6 million and the impairment is charged directly to the Trust corpus, which does not affect distributable income. For more information on impairment, see Note 3 to the financial statements included in Part II, Item 8 of this Annual Report. Impairments recorded for book purposes will not result in a loss for tax purposes for the unitholders until the loss is recognized.
An increase in the differential between the price realized by T2S or any successor to T2S for oil or natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the profits to the Trust and, therefore, the cash distributions by the Trust and the value of Trust units.
The prices received by Boaz Energy or T2S, as applicable, for their respective oil and natural gas production have generally been lower than the relevant benchmark prices, such as NYMEX. The difference between the price received and the benchmark price is called a basis differential. The differential may vary significantly due to market conditions, the quality and location of production and other factors, including a regional oversupply of oil in the Permian Basin due to take-away constraints. T2S cannot accurately predict oil or natural gas differentials in the future. Increases in the differential between the realized price of oil and natural gas and the benchmark price for oil and natural gas could reduce the profits to the Trust, the cash distributions by the Trust and the value of the Trust units.
Higher production and development costs related to the Underlying Properties and other costs and expenses incurred by the Trust without concurrent increases in revenue, will result in decreased Trust distributions.
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The Trust indirectly bears an 80% share of all costs and expenses related to the Underlying Properties, such as direct operating expenses and development expenses (including waterflood expenses), which reduces the amount of cash received by the Trust and distributed to Trust unitholders. Historical costs may not be indicative of future costs, and higher costs and expenses related to the Underlying Properties without concurrent increases in revenue will directly decrease the amount of cash received by the Trust in respect of its Net Profits Interest. In addition, cash available for distribution by the Trust will be further reduced by the Trust’s general and administrative expenses.
If direct operating expenses and development expenses on the Underlying Properties together with the other costs exceed gross profits of production from the Underlying Properties, the Trust will not receive net profits from those properties until future gross profits from production exceed the total of the excess costs, plus accrued interest at the prime rate. If the Trust does not receive net profits pursuant to the Net Profits Interest, or if such net profits are reduced, the Trust will not be able to distribute cash to the Trust unitholders, or such cash distributions will be reduced, respectively. Development activities may not generate sufficient additional revenue to repay the costs.
A significant portion of the reserves associated with and production from the Underlying Properties will be influenced by the success of secondary recovery techniques. There are uncertainties associated with such techniques and, if these recovery methods do not result in expected production levels, net profits available for distribution to Trust unitholders could be less than expected.
A significant portion of the future production from the Underlying Properties will be associated with secondary recovery projects that are in the early or intermediate stage of implementation. As a result, there can be no assurance that these operations will perform as expected or consistently with the analogous secondary recovery operations used by T2S or any successor to T2S in establishing its reserve and production estimates. As secondary recovery techniques such as waterflooding are used, the amount of oil recovered is expected to first increase as a result of such techniques and then will begin to decline over the long term. Risks associated with secondary recovery techniques include, but are not limited to, the following:
If these secondary recovery operations do not result in achieving projected production, then the reserves associated with the Underlying Properties may be less than expected.
The standardized measure of the estimated proved oil and natural gas reserves attributable to the Trust’s interest in the Underlying Properties and the associated PV-10 calculation are not necessarily the same as the current market value of those estimated reserves.
The present value of future net cash flow from the proved reserves attributable to the Trust’s interest in the Underlying Properties, or standardized measure, and the related PV-10 calculation, may not represent the current market value of the Trust’s interest in the estimated proved oil and natural gas reserves of the Underlying Properties. In accordance with SEC requirements, the Trust bases the estimated discounted future net cash flow from estimated proved reserves on the 12-month average oil index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor the Trust uses when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities-Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Trust or the oil and natural gas industry in general.
The Trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.
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Boaz Energy acquired the Underlying Properties through various acquisitions since October 2013. T2S acquired the underlying Properties from Boaz Energy on March 31,2025. The existence of a material title deficiency with respect to the Underlying Properties could reduce the value of a property or render it worthless, thus adversely affecting the Net Profits Interest and the distributions to Trust unitholders. Neither Boaz Energy nor T2S obtained title insurance covering mineral leaseholds, and Boaz Energy’s, T2S's, or any successor to T2S’s, failure to cure any title defects may cause T2S or any successor to T2S to lose its rights to production from the Underlying Properties. In the event of any such material title problem, profits available for distribution to Trust unitholders and the value of the Trust units may be reduced.
The amount of cash available for distribution by the Trust could be reduced by expenses caused by uninsured claims.
T2S maintains insurance coverage against potential losses that it believes is customary in its industry. T2S is not required to maintain any minimum levels of insurance and its ability to maintain any such coverages will depend on conditions in the insurance markets among other factors beyond T2S’s control. In addition, T2S's general liability insurance and excess liability policies do not provide coverage with respect to legal and contractual liabilities of the Trust, and the Trust does not maintain such coverage since it is passive in nature and does not have any ability to influence T2S or control the operations or development of the Underlying Properties. T2S does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to waterflooding or other completion operations. These policies may not cover fines, penalties or costs and expenses related to government-mandated remediation of pollution. In addition, these policies do not provide coverage for all liabilities, and T2S cannot assure you that the insurance coverage will be adequate to cover claims that may arise, including due to potential effects of climate change, or that T2S will be able to maintain adequate insurance at rates it considers reasonable. The occurrence of an event not fully covered by insurance could result in a significant decrease in the amount of cash available for distribution by the Trust.
War, military invasions, terrorism and continued geopolitical hostilities could adversely affect the Trust’s distributions to its unitholders or the market price of its units.
The outbreak of war, military invasions, terrorist attacks and the threat of such violence, whether domestic or foreign, as well as military or other actions taken in response to such attacks or threats, could cause instability in the global financial, oil and natural gas markets. Such geopolitical hostilities could adversely affect the Trust’s distributions to its unitholders or the market price of its units in unpredictable ways, including through the disruption of oil and natural gas supplies and markets, increased volatility in oil and natural gas prices, or the possibility that the infrastructure on which the operators of the Underlying Properties rely could be a direct target or an indirect casualty of such violence.
Future net profits income to the Trust may be subject to risks relating to the creditworthiness of third parties.
The Trust does not lend money and has limited ability to borrow money. The Trust’s future net profits income, however, may be subject to risks relating to the creditworthiness of the operators of the Underlying Properties and purchasers of the oil and natural gas produced from the Underlying Properties. This creditworthiness may be impacted by the price of oil and natural gas.
RISKS RELATED TO THE STRUCTURE OF THE TRUST
The Trust is passive in nature and neither the Trust nor the Trust unitholders have any ability to influence T2S and other third-party operators or control the operation or development of the Underlying Properties.
The Trust units are a passive investment that entitle the Trust unitholder to only receive cash distributions from the Net Profits Interest conveyed to the Trust. Trust unitholders have no voting rights with respect to T2S or any successor to T2S and, therefore, have no managerial, contractual or other ability to influence T2S’s, its successor’s, or other third-party operators’ activities or the operations of the Underlying Properties. T2S operated approximately 82% of the production from the Underlying Properties as of December 31, 2025, and is generally responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect such properties. T2S or any successor to T2S may take actions that are in its own interest that may be different from the interests of the Trust. The failure of T2S or any successor to T2S or any other third-party operator to conduct its operations, discharge its obligations and comply with regulatory requirements could have an adverse effect on the net profits payable to the Trust.
T2S may transfer all or a portion of the Underlying Properties at any time without Trust unitholder consent, subject to specified limitations.
T2S or any successor to T2S may at any time transfer all or part of the Underlying Properties, subject to and burdened by the Net Profits Interest, and may abandon its interest in any individual wells or properties if T2S or any successor to T2S, acting as a reasonable and prudent operator, believes a well or property has ceased to produce or is not capable of producing in commercially
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paying quantities. Trust unitholders are not entitled to vote on any transfer or abandonment of the Underlying Properties, and the Trust will not receive any profits from any such transfer, except in the limited circumstances when the Net Profits Interest is released in connection with such transfer, in which case the Trust will receive an amount equal to the fair value (net of sales costs) of the Net Profits Interest released. Following any sale or transfer of any of the Underlying Properties, if the Net Profits Interest is not released in connection with such sale or transfer, the Net Profits Interest would continue to burden the transferred property and net profits attributable to such property would continue to be calculated as part of the computation of net profits. T2S or any successor to T2S may assign to the transferee responsibility for all of T2S’s obligations relating to the Net Profits Interest on the portion of the Underlying Properties transferred. T2S may not pursue development projects to the same extent as Boaz Energy, if at all. Further, any transferee of the Underlying Properties may operate the Underlying Properties differently than T2S, and may determine not to pursue development projects to the same extent as T2S, if at all.
In addition, T2S or any successor to T2S may, without the consent of the Trust unitholders, require the Trust to release the Net Profits Interest associated with the sale of any interest in the Underlying Properties that accounted for no more than 1.0% of the total production from the Underlying Properties in the prior 12 months, provided that T2S or any successor to T2S may not require the release during any 365-day period of portions of the Net Profits Interest having an aggregate fair value to the Trust of greater than $500,000 (a “Qualified De Minimis Sale”). These releases will be made only in connection with a sale by T2S or any successor to T2S of the relevant Underlying Properties and the Trust will receive an amount equal to the fair value (net of sales costs) of the Net Profits Interest released.
In addition, T2S or any successor to T2S may cause the Trustee to (i) sell all or any part of the Trust estate, including all or any portion of the Net Profits Interest or (ii) release any portion of the Net Profits Interest in connection with the sale, free from and unburdened by the Net Profits Interest, by T2S and/or its affiliates or any successor to T2S of a divided or undivided portion of their interests in the Underlying Properties, if approved by Trust unitholders holding at least 75% of the outstanding Trust units, provided that, after December 31, 2025, such a sale or release shall require approval of a majority of the outstanding Trust units if T2S and its affiliates (or any successor to T2S) own less than 25% of the outstanding Trust units. The net proceeds of any such sale or the consideration received in respect of such release, as applicable, shall be distributed to the Trust unitholders in the manner approved by the Trust unitholders at such meeting.
T2S may also enter into farm-out, operating, participation and other similar agreements to develop the property without the consent or approval of the Trustee or any Trust unitholder.
The Trustee must, under certain circumstances, sell the Net Profits Interest and dissolve the Trust prior to the expected termination of the Trust. If this were to occur, Trust unitholders may not recover their investment.
The Trustee must sell the Net Profits Interest and dissolve the Trust if the holders of 75% of the outstanding units approve the sale of the Net Profits Interest or approve the dissolution of the Trust or if the Trust is judicially dissolved. The Trustee must also sell the Net Profits Interest and dissolve the Trust if the annual gross profits from the Underlying Properties attributable to the Net Profits Interest are less than $2.0 million for each of any two consecutive years. The Trust will receive the net proceeds of any such sale and will distribute such proceeds to its unitholders after deducting Trust expenses.
Conflicts of interest could arise between T2S or any successor to T2S, on the one hand, and the Trust and the Trust unitholders, on the other hand.
As working interest owners in, and the operator of substantially all of the production from the Underlying Properties, T2S and its related parties or any successor to T2S could have interests that conflict with the interests of the Trust and the Trust unitholders. For example:
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The Trust is administered by a Trustee who cannot be replaced except by a majority vote of the Trust unitholders at a special meeting, which may make it difficult for Trust unitholders to remove or replace the Trustee.
The affairs of the Trust are managed by the Trustee. The voting rights of Trust unitholders are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee, and the Trust does not intend to hold annual meetings of Trust unitholders. The Trust Agreement provides that the Trustee may only be removed and replaced by the holders of a majority of the Trust units present in person or by proxy at a meeting of such holders where a quorum is present, including Trust units held by by Ustx, LLC, an affiliate of T2S, called by either the Trustee or the holders of not less than 10% of the outstanding Trust units. As a result, it will be difficult for public Trust unitholders to remove or replace the Trustee without the cooperation of T2S so long as T2S affiliate Ustx, LLC holds a significant percentage of total Trust units. On the other hand, the Trustee is entitled to resign, in which case a successor trustee would need to be appointed either at a special meeting of the unitholders or by action of a court.
T2S’s or its successor’s ability to perform its obligations to the Trust could be limited by restrictions under its debt agreements.
T2S has various contractual obligations to the Trust under the Trust Agreement and Conveyance. Restrictions under T2S’s debt agreements may include certain covenants, financial ratios and tests, which could impair T2S's ability to fulfill its obligations to the Trust. Any requirement that T2S comply with these restrictive covenants and financial ratios and tests may materially adversely affect its ability to react to changes in market conditions, take advantage of business opportunities it believes to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in its business which may, in turn, impair T2S’s operations and its ability to perform its obligations to the Trust under the Trust Agreement and Conveyance. If T2S is unable to perform its obligations to the Trust under the Trust Agreement or Conveyance, it could have a material adverse effect on the Trust. The same risk will apply any successor to T2S.
Trust unitholders have limited ability to enforce provisions of the Conveyance creating the Net Profits Interest, and T2S’s and any successor’s liability to the Trust is limited.
The Trustee has the power and authority to cause the Trust to sue Boaz Energy, T2S, or any other future owner of the Underlying Properties to enforce the terms of the Conveyance creating the Net Profits Interest. If the Trustee does not take appropriate action to cause the Trust to enforce provisions of the Conveyance, Trust unitholders’ recourse would likely be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions or, subject to any restrictions in the governing instrument to the Trust, to bring a derivative action seeking authority to bring an action in the name of the Trust to enforce provisions of the Conveyance. As a result, Trust unitholders will not be able to sue Boaz Energy, T2S, or any future owner of the Underlying Properties to enforce these rights. However, such limitations do not apply to or otherwise limit any claims that the Trust unitholders may have under the federal securities laws. Furthermore, the Conveyance provides that, except as set forth in the Conveyance, neither Boaz Energy nor T2S is liable to the Trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts without gross negligence or willful misconduct. Further, the Trust Agreement provides that, to the fullest extent permitted by law, T2S (and any successor to T2S) shall not be subject to fiduciary duties or be liable under conflicts of interest principles.
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RISKS RELATED TO OWNERSHIP OF THE TRUST UNITS
If the Trust cannot meet the New York Stock Exchange continued listing requirements, the NYSE may delist the Trust units.
Under the continued listing requirements of the NYSE, a company will be considered to be out of compliance with the exchange’s minimum price requirement if the company’s average closing price over a consecutive 30 trading day period (“Average Closing Price”) is less than $1.00 (the “Minimum Price Requirement”). Under NYSE rules, a company that is out of compliance with the Minimum Price Requirement has a cure period of six months to regain compliance if it notifies the NYSE within 10 business days of receiving a deficiency notice of its intention to cure the deficiency. A company may regain compliance if on the last trading day of any calendar month during the cure period the company has a closing share price of at least $1.00 and an average closing share price of at least $1.00 over the 30-trading-day period ending on the last trading day of that month. If at the expiration of the cure period, both a $1.00 closing share price on the last trading day of the cure period and a $1.00 average closing share price over the 30-trading-day period ending on the last trading day of the cure period are not attained, the NYSE will commence suspension and delisting procedures. If delisted by the NYSE, a company’s shares may be transferred to the over-the-counter (“OTC”) market, a significantly more limited market than the NYSE, which could affect the market price, trading volume, liquidity and resale price of such shares. Securities that trade on the OTC markets also typically experience more volatility compared to securities that trade on a national securities exchange. During the cure period, the company’s shares would continue to trade on the NYSE, subject to compliance with other continued listing requirements.
T2S's affiliate, Ustx, LLC (or any future owner of the units currently held by Ustx, LLC,) may sell Trust units in the public or private markets, and such sales could have an adverse impact on the trading price of the Trust units.
Boaz Energy held an aggregate of 4,884,861 Trust units prior to March 31, 2025. On March 31, 2025, Boaz Energy conveyed to Ustx, LLC, an affiliate of T2S, all 4,884,861 Trust units previously held by Boaz Energy pursuant to the Purchase and Sale Agreement dated January 10, 2025. As a result of the transaction, Ustx, LLC now owns these Trust Units and may sell some or all of these Trust units in the public or private markets from time to time. Any such sales by Ustx, LLC, or by any successor or permitted transferee of Ustx, LLC could have an adverse impact on the price of the Trust units or on any trading market that may develop. On May 4, 2018, the Trust entered into a registration rights agreement for the benefit of Boaz Energy and certain of its affiliates and transferees, pursuant to which the Trust agreed to register the offering of the Trust units held by Boaz Energy and certain of its affiliates and permitted transferees upon request by Boaz Energy. The Trust filed a Registration Statement on Form S-3 on April 28, 2022 (the “Registration Statement”) seeking the registration of 5,801,675 Trust units held by Boaz Energy. The SEC confirmed the effectiveness of the Registration Statement on May 9, 2022. The Trust has not and will not receive any of the proceeds received from the sale of the Trust units., including the sale of Boaz Energy’s 4,884,861 Trust units to Ustx, LLC in 2025.
The trading price for the Trust units may not reflect the value of the Net Profits Interest held by the Trust.
The trading price for publicly traded securities similar to the Trust units tends to be tied to recent and expected levels of cash distributions as well as oil and natural gas prices. The amounts available for distribution by the Trust vary in response to numerous factors outside the control of the Trust, including prevailing prices for sales of oil and natural gas production from the Underlying Properties and the timing and amount of direct operating expenses and development expenses. Consequently, the market price for the Trust units may not necessarily be indicative of the value that the Trust would realize if it sold the Net Profits Interest to a third-party buyer. In addition, such market price may not necessarily reflect the fact that, since the assets of the Trust are depleting assets, a portion of each cash distribution paid with respect to the Trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. As a result, distributions made to a Trust unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the Trust unitholder.
Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.
Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.
LEGAL, ENVIRONMENTAL AND REGULATORY RISKS
The operations of the Underlying Properties are subject to complex federal, state, local and other laws and regulations, including environmental laws and regulations, that could adversely affect the cost, manner or feasibility of conducting operations on them or result in significant costs and liabilities, which could reduce the amount of cash available for distribution to Trust unitholders.
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The oil and natural gas exploration and production operations on the Underlying Properties are subject to stringent and comprehensive federal, state and local laws and regulations, including laws governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations, some of which are discussed under “Environmental Matters and Regulation,” may impose numerous obligations that apply to the operations on the Underlying Properties, including the requirement to obtain a permit before conducting drilling, secondary recovery, waste disposal or other regulated activities; the restriction of types, quantities and concentrations of materials that can be released into the environment; restrictions on water withdrawal and use; and the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas. Compliance with such laws and regulations may generate significant costs, such as development expenses to install pollution or safety-related controls at the operated facilities and impose substantial liabilities for pollution resulting from operations. Failure to comply with these and other laws and regulations may result in litigation, the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the operations on the Underlying Properties. Furthermore, the inability to comply with environmental laws and regulations in a cost-effective manner, such as removal and disposal of produced water and other generated oil and natural gas wastes, could impair the production of oil and natural gas from the Underlying Properties in a commercial manner, which could further result in a reduction of distributable cash to the Trust unitholders.
There is inherent risk of incurring significant environmental costs and liabilities in the course of operations on the Underlying Properties as a result of the handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to operations, and historical industry operations and waste disposal practices, which in turn could decrease the profitability of the Underlying Properties and result in a reduction of distributable cash to the Trust unitholders. As discussed under “Environmental Matters and Regulation,” T2S can also be subject to remediation costs related to contamination, which have the potential to adversely affect production on the Underlying Properties and could consequently result in a reduction of distributable cash to the Trust unitholders. Private parties, including the owners of properties upon which wells are drilled and facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose the Underlying Properties to significant liabilities that could have a material adverse effect on their financial condition and results of operations, which in turn could reduce the amount of cash available for distribution to Trust unitholders. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly operational control requirements or waste handling, storage, transport, disposal or cleanup requirements could require operations on the Underlying Properties to incur significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition, which could subsequently adversely affect the distribution of cash to the Trust unitholders.
The Trust indirectly bears 80% of all costs and expenses paid by T2S, including those related to environmental compliance and liabilities associated with the Underlying Properties, including costs and liabilities resulting from conditions that existed prior to T2S's acquisition of the Underlying Properties unless such costs and expenses result from the applicable operator’s negligence or misconduct. In addition, as a result of the increased cost of compliance, T2S may decide not to drill.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in T2S incurring increased costs, additional operating restrictions or delays and fewer potential drilling locations.
As discussed under “Environmental Matters and Regulation – Hydraulic Fracturing Activities,” in recent years there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies and to induce seismic events. As a result, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In the event that new federal restrictions relating to the hydraulic fracturing process are adopted in areas where the Underlying Properties are located, T2S and outside operators may incur additional costs or permitting requirements to comply with such federal requirements that may be significant and that could result in added delays or curtailment in the pursuit of exploration, development or production activities, which would in turn reduce the oil, natural gas and NGLs produced from the Underlying Properties.
In addition, some states such as Texas, where the Underlying Properties are located, have adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to, and litigation concerning, oil, natural gas and NGL production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs for our operators in the production of oil, natural gas and NGLs, including from the developing shale plays, or could make it more difficult for T2S and outside operators to perform hydraulic
22
fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in T2S's completion of new oil and natural gas wells on the Underlying Properties and an associated decrease in the cash distributable to Trust unitholders.
The adoption and implementation of international, federal or state climate change legislation or regulations could result in increased operating costs for T2S (or any successor to T2S) and reduced demand for the oil, natural gas and NGLs that T2S (or any successor to T2S) produces.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs, as described under “Environmental Matters and Regulation – Climate Change,” could result in increased compliance costs or additional operating restrictions and could have a material adverse effect on T2S’s business, financial condition and results of operations. Recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for operators to engage in exploration and production activities, ultimately reducing income generated from the Underlying Properties and, as a result, the cash distributable to Trust unitholders. Moreover, such new legislation or regulatory programs could also increase the cost to consumers, and thereby reduce demand for oil and natural gas, which could reduce the demand for the oil or natural gas produced and lower the value of the reserves.
The potential physical effects of climate change could disrupt production on the Underlying Properties and cause T2S, any successor to T2S, and other third-party operators to incur significant costs, thereby reducing cash distributable to Trust unitholders.
Some scientists have concluded that increasing concentrations of GHGs in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events. Extreme weather conditions can interfere with production on the Underlying Properties and increase operating expenses for T2S or any successor to T2S. Such damage or increased expenses from extreme weather may not be fully insured. If any such effects were to occur, they could have an adverse effect on T2S’s results of operations and, as a result, the cash distributable to Trust unitholders.
Additional restrictions on drilling activities intended to protect certain species of wildlife may adversely affect T2S’s and other operators’ ability to conduct drilling activities.
In the United States, the ESA restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the MBTA. To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where the Underlying Properties are located, T2S’s abilities to conduct or expand operations on the Underlying Properties could be limited, or T2S or its successor could be forced to incur material additional costs. Moreover, T2S’s drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons.
In addition, the designation of previously unidentified endangered or threatened species could cause T2S’s operations (or the operations of any other operator) to become subject to operating restrictions or bans, and limit future development activity in affected areas. For example, the U.S. Fish & Wildlife Service officially listed the Dunes Sagebrush Lizard as endangered in May 2024, prompting intense legal battles and renewed calls to review or revoke these protections, particularly from Texas officials, who argue the federal action restricts oil and gas development in the Permian Basin. Environmental groups are simultaneously moving to defend the listing against state lawsuits. When species are listed, the U.S. Fish & Wildlife Service and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands. To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where the Underlying Properties are located, operations on the Underlying Properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon.
CYBERSECURITY RISKS
The business of T2S or any successor to T2S could be negatively affected by various security threats, including cybersecurity threats, and other disruptions.
T2S faces various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of the facilities and infrastructure of T2S and of third parties on which T2S relies such as processing plants and pipelines. These threats pose a risk to the security of T2S’s systems and networks, the confidentiality, availability and integrity of its data and the physical security of its employees and assets. T2S relies on information
23
technology (“IT”) systems and networks in connection with its business activities, including certain of its exploration, development and production activities. T2S relies on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to, among other things, estimate quantities of oil, natural gas and NGL reserves, analyze seismic and drilling information, process and record financial and operating data and communicate with employees and third parties. As dependence on digital technologies has increased in the oil and gas industry, cyber incidents, including deliberate attacks and attempts to gain unauthorized access to computer systems and networks, have increased in frequency and sophistication. Boaz Energy has experienced cyber-attacks in the past. T2S has not experienced any attacks, however, it may not be successful in preventing future security breaches or cyber-attacks or mitigating their effect. Any security breach or cyber-attack could have a material adverse effect on T2S’s reputation and competitive position and could lead to losses of sensitive information, critical infrastructure or capabilities essential to T2S’s operation of the Underlying Properties, its calculation of gross and net profits and its remittance of payments in respect of the Net Profits Interest to the Trust. Cyber-attacks or security breaches also could result in litigation or regulatory action. In addition, T2S’s implementation of various procedures and controls to monitor and mitigate security threats, including cybersecurity threats, and to increase security for its information, facilities and infrastructure may result in increased capital and operating costs.
In addition to the risks presented to T2S’s systems and networks, cyber-attacks affecting oil and natural gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery to markets. A cyber-attack of this nature would be outside T2S’s ability to control but could have a material adverse effect on T2S’s business, financial condition and results of operations, and could have a material adverse effect on the Trust.
The Trustee may be subject to attempted cybersecurity disruptions from a variety of sources.
The Trustee maintains robust cybersecurity protocols including, but not limited to technological capabilities that prevent and detect disruptions; computer workstations and programs protected with passwords and passphrases, as well as employee training throughout the year on cybersecurity followed up by testing of that knowledge. Other, non-technical protocols include securing of documents and work areas that could contain personal, non-public information and independent verification of information changes by outside vendors. If the measures taken to protect against cybersecurity disruptions prove to be insufficient or if proprietary data is otherwise not protected, the Trustee could be adversely affected. The Trust is also exposed to potential harm from cybersecurity events that may affect the operations of third parties, including suppliers, service providers (including providers of cloud-hosting services for our data or applications), and customers. Cybersecurity disruptions could cause physical harm to people or the environment, damage or destroy assets; compromise business systems; result in proprietary information being altered, lost, or stolen; result in employee, customer, or third-party information being compromised; or otherwise disrupt business operations. The Trust could incur significant costs to remedy the effects of a major cybersecurity disruption in addition to costs in connection with resulting regulatory actions, litigations, or reputational harm.
TAX RISKS RELATED TO THE TRUST UNITS
The Trust has not requested a ruling from the IRS regarding the tax treatment of the Trust. If the IRS were to determine (and be sustained in that determination) that the Trust is not a “grantor trust” for U.S. federal income tax purposes, the Trust could be subject to more complex and costly tax reporting requirements that could reduce the amount of cash available for distribution to Trust unitholders.
If the Trust were not treated as a grantor trust for U.S. federal income tax purposes, the Trust should be treated as a partnership for such purposes. Although the Trust would not become subject to U.S. federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the Trust unitholders, the Trust’s tax reporting requirements would be more complex and costly to implement and maintain, and its distributions to Trust unitholders could be reduced as a result.
If the Trust were treated for U.S. federal income tax purposes as a partnership, it would likely be subject to new audit rules that alter the procedures for auditing large partnerships and assessing and collecting income taxes due (including applicable penalties and interest) as a result of an audit. These rules effectively would impose an entity level tax on the Trust, and Trust unitholders might have to bear the expense of the adjustment even if they were not Trust unitholders during the audited taxable year.
Neither Boaz Energy, nor T2S, nor the Trustee has requested a ruling from the IRS regarding the tax status of the Trust, and neither T2S, nor the Trustee can assure you that such a ruling would be granted if requested or that the IRS will not challenge these positions on audit.
Trust unitholders should be aware of any possible state tax implications of owning Trust units.
24
Trust unitholders are required to pay U.S. federal income taxes on their share of the Trust’s income, even if they do not receive any cash distributions from the Trust.
Trust unitholders are treated as if they own the Trust’s assets and receive the Trust’s income and are directly taxable thereon as though the Trust were not in existence. Because the Trust generates taxable income that can be different in amount than the cash the Trust distributes, Trust unitholders are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes, on their share of the Trust’s taxable income even if they receive no cash distributions from the Trust. Trust unitholders may not receive cash distributions from the Trust equal to their share of the Trust’s taxable income or even equal to the actual tax liability that results from that income.
A portion of any gain recognized on the disposition of the Trust units could be taxed as ordinary income.
A Trust unitholder who sells his Trust units will recognize a gain or loss equal to the difference between the amount realized and the Trust unitholder’s adjusted tax basis in those Trust units. A substantial portion of any gain recognized may be taxed as ordinary income due to potential recapture items, including depletion recapture.
The Trust generally allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the monthly record date. The IRS may challenge this treatment.
The Trust generally allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust units each month based upon the ownership of the Trust units on the monthly record date, instead of the date a particular Trust unit is transferred. The IRS could disagree with this allocation method and could assert that income and deductions of the Trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the affected Trust unitholders and result in an increase in the administrative expense of the Trust in subsequent periods.
Recent and potential changes in federal tax law may affect the tax treatment of an investment in the Trust units.
The Tax Cuts and Jobs Act (“TCJA”), enacted on December 22, 2017, made significant changes to the federal income tax rules applicable to individuals and entities, including changes that may affect the effective tax rate on a Trust unitholder’s allocable share of certain income from the Trust. Many provisions of the TCJA were modified, extended, or otherwise affected by the One, Big, Beautiful Bill Act (“OBBBA”), signed into law on July 4, 2025. Trust unitholders should consult their tax advisors regarding the TCJA, OBBBA, and the potential impact of these laws on an investment in the Trust units.
Any additional changes to U.S. federal income tax laws or to the interpretation of existing laws (including administrative guidance relating to the TCJA or OBBBA) may be applied retroactively and could adversely affect the Operator’s or the Trust’s business, financial condition, or results of operations. The Trust cannot predict whether any such changes or interpretations will be adopted or how they might be applied. Any such developments could adversely affect the value of an investment in the Trust units
Item 1B. Unresolved Staff Comments
None.
Item 1C. Cybersecurity.
The Trust does not have a board of directors, so the Trustee is responsible for oversight of the Trust’s risks from cybersecurity threats. The Trustee has dedicated personnel that are responsible for assessing and managing the Trust’s cyber risk management program, informing senior management of the Trustee regarding the prevention, detection, mitigation, and remediation of cybersecurity incidents and supervising such efforts. The Trustee’s information technology team has decades of experience selecting, deploying, and operating cybersecurity technologies, initiatives, and processes, and relies on threat intelligence as well as other information obtained from governmental, public or private sources, including external consultants engaged by the Trustee to monitor the prevention, detection, mitigation, and remediation of cybersecurity incidents. External partners are a key part of the Trustee’s cybersecurity protocols and policies. The Trustee works with leading firms in the cybersecurity industry, leveraging their technology and expertise to monitor and maintain the performance and effectiveness of products and services that are used by the Trustee.
The Trustee maintains a cyber risk management program designed to identify, assess, manage, mitigate, and respond to cybersecurity threats, which processes are integrated into the Trustee’s overall risk management process. The Trustee maintains robust cybersecurity protocols including, but not limited to technological capabilities that prevent and detect disruptions; computer workstations and programs protected with passwords and passphrases, as well as employee training throughout the year on financial regulations and cybersecurity followed up by testing of that knowledge. The protocols are based on recognized best practices and
25
standards for cybersecurity and information technology. The Trustee has an annual assessment, performed by a third-party vendor, of the Trustee’s cyber risk management program.
Other non-technical protocols include securing of documents and work areas that could contain personal, nonpublic information and independent verification of information changes by outside vendors.
The Trust faces risks from cybersecurity threats that could have a material adverse effect on its business, financial condition, results of operations, cash flows or reputation. The Trustee has experienced, and will continue to experience, cyber incidents in the normal course of its business. However, prior cybersecurity incidents have not had a material adverse effect on the Trust’s business, financial condition, results of operations, or cash flows. See “Risk Factors – Cybersecurity Risks.”
Item 2. Properties
Description of the Underlying Properties
The Underlying Properties consist of 31,354 gross (22,394 net) acres in the Permian Basin. The Permian Basin extends over 75,000 square miles in West Texas and Southeastern New Mexico, consists of multiple, stacked hydrocarbon-bearing formations and has produced over 30 billion Bbls of oil and more than 75 Tcf of natural gas since its discovery in 1921. The basin is further characterized by a favorable operating environment, high oil and liquids-rich natural gas content, significant in-place midstream infrastructure, a well-developed network of oilfield service providers and long-lived reserves with generally consistent geologic attributes and reservoir quality.
The Underlying Properties consist of long-life reserves in mature, conventional oil fields with established decline curves. As of December 31, 2025, the Underlying Properties had proved reserves of 2.8 MMBoe and 100% of the volumes and 100% of PV-10 value were attributable to proved developed reserves. Approximately 94% of the 2.8 MMBoe of proved reserves, based on PV-10 value, were operated by T2S as of December 31, 2025. For more information regarding changes in proved reserves, see Note 12 to the financial statements included in Part II, Item 8 of this Annual Report.
Major Producing Areas
The Underlying Properties consist of the following four operating areas:
The Permian Clearfork area consists of 2,434 net acres on the Central Basin Platform of the Permian Basin in Hockley and Terry Counties, Texas. A majority of the production in the Permian Clearfork area comes from wells in the Kingdom Clearfork field, which primarily produce from the Clearfork formation. Boaz Energy's waterflooding operations were first implemented in the Kingdom Clearfork field in March 2015. As of December 31, 2025, Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”) estimates the Underlying Properties in the Permian Clearfork to have 0.9 MMBoe of total proved reserves, 100% of which are proved developed reserves.
The Permian Abo area consists of 1,667 net acres on the Central Basin Platform of the Permian Basin in Terry and Cochran Counties, Texas. A majority of the production in the Permian Abo area comes from wells in the Kingdom Abo field, which primarily produce from the Abo formation. In 2011, a waterflood pilot program was implemented in the North West Terry Abo unit (“NWTA”) located in the Kingdom Abo field that converted one producing well to an injection well. Boaz Energy fully converted the field to water injection upon purchasing the NWTA in June 2016, and in January 2017 installed a new injection pump that added an additional injection capacity of 2,500 barrels of water per day. In August 2017, NWTA 313 demonstrated initial waterflood response. As of December 31, 2025, Cawley Gillespie estimates the Underlying Properties in the Permian Abo to have 0.4 MMBoe of total proved reserves, 100% of which are proved developed reserves.
The Permian Shelf area consists of 14,390 net acres on the Eastern Shelf of the Permian Basin in Glasscock, Schleicher, Stonewall and Coke Counties, Texas. A significant portion of the production in the Permian Shelf area comes from wells in the Fort McKavitt and Flowers fields, which primarily produce from the Canyon formation. As of December 31, 2025, Cawley Gillespie estimates the Underlying Properties in the Permian Shelf to have 0.3 MMBoe of total proved reserves, 100% of which are proved developed reserves.
The Permian Platform area consists of 3,903 net acres on the Central Basin Platform of the Permian Basin in Ward, Crane, Terry and Ector Counties, Texas. The properties primarily produce from the Clearfork, San Andres, and Devonian formations. As of December 31, 2025, Cawley Gillespie estimates the Underlying Properties in the Permian Platform to have 1.2 MMBoe of total proved reserves, 100% of which are proved developed.
26
Oil and Natural Gas Data
Proved Reserves
Cawley Gillespie, independent petroleum and geological engineers, estimated crude oil and natural gas (including natural gas liquids) proved reserves of the Underlying Properties’ full economic life and for the Trust life as of December 31, 2025. Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the estimates. In addition, the reserves and net revenues attributable to the Net Profits Interest include only 80% of the reserves attributable to the Underlying Properties that are expected to be produced within the term of the Net Profits Interest. The technical person primarily responsible for overseeing the review of the third-party reserve reports prior to T2S taking over operations was Marshall Eves, Boaz Energy's Chief Executive Officer. T2S’s engineering department works closely with its independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to the independent reserve engineers in their reserve estimating process. Periodically, the T2S petroleum engineer and other T2S executives meet with the independent reserve engineers to review properties and discuss methods and assumptions used by Boaz Energy, T2S and the independent reserve engineers to prepare reserve estimates.
The independent petroleum engineer’s report as to the proved oil and natural gas reserves as of December 31, 2025, was prepared by Cawley Gillespie. Cawley Gillespie, whose firm registration number is F-693, was founded in 1961 and is a leader in the evaluation of oil and gas properties. The technical person at Cawley Gillespie primarily responsible for overseeing the reserve estimates with respect to the Underlying Properties and the Net Profits Interest attributable to the Trust is Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at Cawley Gillespie since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 38 years of practical experience in petroleum engineering, with over 36 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.
Proved reserves are reserves 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 under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. If deterministic methods are used, the term "reasonable certainty" implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. If probabilistic methods are used, there should at least be a 90% probability that the quantities actually recovered will equal or exceed the estimate.
The technical and economic data used in the estimation of the proved reserves include, but are not limited to, production performance decline curve analyses, well logs, geologic maps, well-test data, production data (including flow rates), well data, historical price and cost information, and property ownership interests. Cawley Gillespie uses this technical data, together with a combination of standard engineering and geoscience methods, including the production performance, volumetric and analogy methods. After estimating the reserves of each proved developed property, it was determined that a reasonable level of certainty exists with respect to the reserves which can be expected from any individual undeveloped well in the field. The consistency of reserves attributable to the proved developed wells, which cover a wide area, further supports proved undeveloped classification.
Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of economically recoverable oil and natural gas and of future net revenues which are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read "Risk Factors" appearing elsewhere in this annual report on Form 10-K.
The following table summarizes estimated proved reserve quantities and PV-10 attributable to the Trust as of December 31, 2025:
27
|
|
Trust Net Profits Interest |
|
|||||||||||||
|
|
Oil |
|
|
Natural Gas(1) |
|
|
Total(2) |
|
|
PV-10(3)(4) |
|
||||
|
|
(MBbls) |
|
|
(MMcf) |
|
|
(MBoe) |
|
|
(in thousands) |
|
||||
Proved Developed |
|
|
975.4 |
|
|
|
748.6 |
|
|
|
1,100.2 |
|
|
$ |
31,406.4 |
|
Proved Undeveloped |
|
|
0.0 |
|
|
|
0.0 |
|
|
|
0.00 |
|
|
|
0.00 |
|
Total Proved |
|
|
975.4 |
|
|
|
748.6 |
|
|
|
1,100.2 |
|
|
$ |
31,406.4 |
|
Reserve quantities and revenues for the Net Profits Interest were estimated from projections of reserves and revenues attributable to the Underlying Properties. Since the Trust has a defined Net Profits Interest, the Trust does not own a specific percentage of the oil and natural gas reserve quantities. Accordingly, reserves allocated to the Trust pertaining to its 80% Net Profits Interest in the Underlying Properties have effectively been reduced to reflect recovery of the Trust’s 80% portion of applicable production and development costs. Because Trust reserve quantities are determined using an allocation formula, any changes in actual or assumed prices or costs will result in revisions to the estimated reserve quantities allocated to the Net Profits Interest.
Estimates of proved reserves were prepared in accordance with guidelines prescribed by the SEC and the Financial Accounting Standards Board, which require that reserve estimates be prepared under existing economic and operating conditions based upon the annual average Henry Hub spot market gas price and the average annual WTI Cushing spot market price for oil. These prices are determined as an unweighted arithmetic average of the first-day-of-the-month commodity price for the twelve months prior to the effective date of the evaluation. All prices are then further adjusted for quality, transportation fees and regional price differentials.
Information concerning changes in net proved reserves attributable to the Trust, and the calculation of the standardized measure of the related discounted future net revenues is contained in the notes to the financial statements of the Trust included in this Form 10-K. T2S has not filed reserve estimates covering the Underlying Properties with any other federal authority or agency.
Proved Undeveloped Reserves (PUDs)
The following table summarizes the changes in estimated proved undeveloped reserves of the Trust for the year ended December 31, 2025:
|
|
Oil |
|
|
Natural Gas |
|
|
Total |
|
|||
Proved Undeveloped Reserves: |
|
|
|
|
|
|
|
|
|
|||
Balance, December 31, 2024 |
|
|
171.8 |
|
|
|
757.5 |
|
|
|
298.1 |
|
Conversions into proved developed reserves |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Revisions of previous estimates |
|
|
(171.8 |
) |
|
|
(757.5 |
) |
|
|
(298.1 |
) |
Extensions and discoveries |
|
|
0.0 |
|
|
|
— |
|
|
|
0.0 |
|
Acquisition of reserves |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Balance, December 31, 2025 |
|
|
0.0 |
|
|
|
0.0 |
|
|
|
0.0 |
|
Developed and Undeveloped Acreage
28
The following table sets forth information as of December 31, 2025, relating to the leasehold acreage associated with the Underlying Properties. Developed acreage consists of acreage spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
|
|
Developed |
|
|
Undeveloped |
|
|
Total |
|
|||||||||||||||
|
|
Gross(1) |
|
|
Net(2) |
|
|
Gross(1) |
|
|
Net(2) |
|
|
Gross(1) |
|
|
Net(2) |
|
||||||
Permian Clearfork |
|
|
1,992 |
|
|
|
1,860 |
|
|
|
609 |
|
|
|
574 |
|
|
|
2,601 |
|
|
|
2,434 |
|
Permian Abo |
|
|
1,767 |
|
|
|
1,437 |
|
|
|
480 |
|
|
|
230 |
|
|
|
2,247 |
|
|
|
1,667 |
|
Permian Shelf |
|
|
10,374 |
|
|
|
7,156 |
|
|
|
8,121 |
|
|
|
7,234 |
|
|
|
18,495 |
|
|
|
14,390 |
|
Permian Platform |
|
|
4,400 |
|
|
|
1,560 |
|
|
|
3,611 |
|
|
|
2,343 |
|
|
|
8,011 |
|
|
|
3,903 |
|
Total |
|
|
18,533 |
|
|
|
12,013 |
|
|
|
12,821 |
|
|
|
10,381 |
|
|
|
31,354 |
|
|
|
22,394 |
|
Producing Wells Count
The table below summarizes the producing wells on the Underlying Properties as of December 31, 2025. Although many of these wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas production. All wells in the table below are oil wells except for 5.0 gross (3.0 net) natural gas wells.
|
|
Wells(1) |
|
|||||
|
|
Gross Wells(2) |
|
|
Net Wells(3) |
|
||
Permian Clearfork |
|
|
38 |
|
|
|
34 |
|
Permian Abo |
|
|
44 |
|
|
|
36 |
|
Permian Shelf |
|
|
170 |
|
|
|
141 |
|
Permian Platform |
|
|
174 |
|
|
|
47 |
|
Total |
|
|
426 |
|
|
|
258 |
|
Drilling Results
The following is a summary of the number of development and exploratory wells drilled and completed on the Underlying Properties during the years indicated.
29
|
|
Year Ended December 31, |
|
|||||||||||||||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||||||||||||||
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
||||||
Development Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive |
|
|
0.0 |
|
|
|
0.0 |
|
|
|
0.0 |
|
|
|
0.0 |
|
|
|
4.0 |
|
|
|
0.3 |
|
Dry holes |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Exploratory Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Dry holes |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Productive |
|
|
0.0 |
|
|
|
0.0 |
|
|
|
0.0 |
|
|
|
0.0 |
|
|
|
4.0 |
|
|
|
0.3 |
|
Dry holes |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
During 2025, there were 0 gross (0 net) producing wells and 0 injection wells drilled, and 0 producing wells converted into injection wells on the Underlying Properties. During 2024, there were 0 gross (0 net) producing wells and 0 injection wells drilled, and 2 producing wells converted into injection wells on the Underlying Properties. During 2023, there were 4 gross (0.3 net) producing wells and 0 injection wells drilled, and 0 producing wells converted into injection wells on the Underlying Properties. On June 14, 2016, and December 14, 2017, Boaz Energy acquired certain oil and gas leasehold acreages located in the State of Texas and various other related rights, permits, contracts, equipment and other assets, known, respectively, as the Memorial Acquisition and the Crane Acquisition. Revenues and direct operating expenses of the assets acquired in the Memorial Acquisition that are subject to the Net Profits Interest are referred to as the "Memorial Underlying Properties". All of the assets acquired in the Crane County Acquisition are subject to the Net Profits Interest and are referred to as the “Crane County Underlying Properties”.
Oil and Natural Gas Production
The following table presents the oil and natural gas sales volumes, average sales prices and average costs per Boe for the Underlying Properties on a historical basis for the years ended December 31, 2025, 2024, and 2023. All production derived from the Underlying Properties is from the Permian Basin.
|
|
Year Ended |
|
|
Year Ended December 31, 2024 |
|
|
Year Ended |
|
|||
Production volumes(1): |
|
|
|
|
|
|
|
|
|
|||
Oil (MBbls) |
|
|
252.8 |
|
|
|
289.9 |
|
|
|
317.8 |
|
Natural Gas (MMcf) |
|
|
312.4 |
|
|
|
341.1 |
|
|
|
387.6 |
|
Total (MBoe) |
|
|
304.9 |
|
|
|
346.7 |
|
|
|
382 |
|
Average net daily production (Boe/d) |
|
|
835.25 |
|
|
|
950.08 |
|
|
|
1,047.67 |
|
Average realized sales prices: |
|
|
|
|
|
|
|
|
|
|||
Oil ($/Bbl) |
|
$ |
64.83 |
|
|
$ |
75.33 |
|
|
$ |
76.24 |
|
Natural gas ($/Mcf) |
|
$ |
2.63 |
|
|
$ |
2.54 |
|
|
$ |
3.74 |
|
Average price per Boe |
|
$ |
56.64 |
|
|
$ |
65.93 |
|
|
$ |
67.15 |
|
Average expenses per Boe: |
|
|
|
|
|
|
|
|
|
|||
Lease operating expense |
|
$ |
18.84 |
|
|
$ |
19.64 |
|
|
$ |
19.05 |
|
Severance and ad valorem taxes |
|
$ |
4.89 |
|
|
$ |
3.83 |
|
|
$ |
5.11 |
|
Total operating expenses per Boe |
|
$ |
22.65 |
|
|
$ |
24.97 |
|
|
$ |
24.79 |
|
Production costs for oil and natural gas attributable to the Underlying Properties for the years ended December 31, 2025, 2024, and 2023, were as follows:
30
|
|
Year End |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Costs |
|
|
|
|
|
|
|
|
|
|||
Severance Tax |
|
$ |
719,981 |
|
|
$ |
831,186 |
|
|
$ |
1,032,842 |
|
Ad Valorem Tax |
|
|
772,275 |
|
|
|
497,694 |
|
|
|
922,851 |
|
Lease Operating Expense |
|
|
5,744,836 |
|
|
|
6,811,020 |
|
|
|
7,284,563 |
|
Development costs |
|
|
515,530 |
|
|
|
3,807,067 |
|
|
|
4,409,823 |
|
Direct Operating Expense |
|
|
1,161,236 |
|
|
|
1,849,266 |
|
|
|
2,194,843 |
|
Other |
|
|
1,971,219 |
|
|
|
1,773,038 |
|
|
|
2,094,993 |
|
Total costs |
|
$ |
10,885,077 |
|
|
$ |
15,569,271 |
|
|
$ |
17,939,915 |
|
Abandonment and Sale of Underlying Properties
Boaz Energy, T2S, or any successor to T2S has the right to abandon its interest in any well or property if T2S, or any successor to T2S, acting as a reasonable and prudent operator, believes a well or property ceases to produce or is not capable of producing in commercially paying quantities. Upon termination of the lease, the portion of the Net Profits Interest relating to the abandoned property will be extinguished.
T2S generally may sell all or a portion of its interests in the Underlying Properties, subject to and burdened by the Net Profits Interest, without the consent of the Trust unitholders. In addition, T2S may, under certain circumstances cause the Trust to release or sell portions of the Net Profits Interest.
Title to Properties
The Underlying Properties are or may be subject to one or more of the burdens and obligations described below. To the extent that these burdens and obligations affect T2S’s rights to production or the value of production from the Underlying Properties, they have been taken into account in calculating the Trust’s interests and in estimating the size and the value of the reserves attributable to the Underlying Properties.
T2S’s interests in the oil and natural gas properties comprising the Underlying Properties are typically subject, in one degree or another, to one or more of the following:
31
T2S believes that the burdens and obligations affecting the Underlying Properties are conventional in the industry for similar properties. T2S also believes that the existing burdens and obligations do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially adversely affect the Net Profits Interest or its value.
In order to give third parties notice of the Net Profits Interest, Boaz Energy recorded the Conveyance in Texas in the real property records in the Texas counties in which the Underlying Properties are located, or in such other public records of Texas as required under applicable law to place third parties on notice of the Conveyance.
Under Texas law, the Conveyance constitutes the conveyance of a presently vested, non-possessory interest in real property. Therefore, T2S and the Trust believe that, in a bankruptcy of T2S, the Net Profits Interest will remain outside of any T2S bankruptcy estate and will be a continuing obligation of any successor to T2S as the operator of the Underlying Properties under Texas law and, as such, outside of T2S’s bankruptcy estate.
T2S believes that its title to the Underlying Properties is, and the Trust’s title to the Net Profits Interest will be, good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions as are not so material to detract substantially from the use or value of such properties or royalty interests. Under the terms of the Conveyance, Boaz Energy has provided a special warranty of title with respect to the Net Profits Interest, subject to the burdens and obligations described in this section.
Item 3. Legal Proceedings
On October 1, 2018, a lawsuit styled Thaleia L. Marston, Trustee of the Marston Trust v. Blackbeard Operating, LLC, et.al, No. 18-10-24761 – CVW in the 143rd District Court in Ward County, Texas (the “2018 Litigation”) was filed, naming, among others, Boaz Energy and the Trust as defendants. The plaintiff is a lessor under two leases operated by Blackbeard Operating LLC. The Underlying Properties include the interests of Boaz Energy in some of the minerals covered by those leases. The litigation sought surface use damages and alleged violations of the terms of the leases, among other things. The court had set a two-day bench trial to commence May 18, 2022, but on May 10, 2022, the court granted motions for summary judgment effectively disposing of the plaintiff’s claims. At a status conference conducted on May 12, 2022, the plaintiff confirmed the court’s rulings disposed of all the plaintiff’s claims. The court held a hearing regarding attorneys’ fees in June 2022. On May 12, 2023, the court entered its final judgment, incorporating its prior order granting the defendants’ motion for summary judgment and granting defendants’ motion for attorneys’ fees, but the plaintiff then filed a notice of appeal to the Eighth Court of Appeals in El Paso County, Texas . By order dated February 5, 2025, the Court of Appeals affirmed the trial court’s judgment in favor of the defendant appellees and therefore, this case is over.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
The Trust units are listed on the New York Stock Exchange (“NYSE”) under the symbol “PRT.” On March 27, 2026, there were 12,165,732 Trust units outstanding held by 7 unitholders of record, including 7,270,551 Trust units held by beneficial owners whose shares are held in street name by brokers and nominees.
Distributions
The Trust currently makes, and expects to continue to make, monthly cash distributions of substantially all of its cash receipts, after deducting amounts for the Trust’s administrative expenses and any cash reserves withheld by the Trustee, to holders of its Trust units as of the applicable record date on or before the 10th business day after the record date.
Equity Compensation Plans
The Trust has no directors, executive officers or employees. Accordingly, the Trust does not maintain any equity compensation plans and there are no Trust units reserved for issuance under any such plans.
Unregistered Sales of Securities
32
None.
Purchases of Securities
None.
Item 6. [Reserved]
33
Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
PermRock Royalty Trust, a Delaware statutory trust formed in November 2017 by Boaz Energy, completed its initial public offering in May 2018. The Trust’s only asset and source of income is the Net Profits Interest, which entitles the Trust to receive 80% of the net profits from oil and natural gas production from the Underlying Properties. The Net Profits Interest is passive in nature and neither the Trust nor the Trustee has any management control over or responsibility for costs relating to the operation of the Underlying Properties.
The Trust is required to make monthly cash distributions of substantially all of its monthly cash receipts, after deduction of fees and expenses for the administration of the Trust and any cash reserves, to holders of its Trust units as of the applicable record date on or before the 10th business day after the record date. The Net Profits Interest is entitled to a share of the profits attributable to production. T2S typically receives payment for oil production 30 to 60 days after it is produced and for natural gas production 60 to 90 days after it is produced. The Trust is not subject to pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time. The amount of Trust revenues and cash distributions to Trust unitholders depends on, among other things:
Low oil and gas prices received for production from the Underlying Properties could cause (i) a reduction in the amount of net proceeds to which the Trust is entitled, which could materially reduce or completely eliminate the amount of cash available for distribution to Trust unitholders and (ii) a reduction in the amount of oil and natural gas that are economic to produce from the Underlying Properties.
On January 13, 2025, the Trust announced that Boaz Energy and its affiliate Boaz Energy II Royalty, LLC entered into a Purchase and Sale Agreement on January 10, 2025 with T2S Permian Acquisition II LLC ( "T2S" ) with respect to the Underlying Properties. Pursuant to the Purchase and Sale Agreement, Boaz sold and conveyed (a) to T2S all of Boaz Energy’s right, title and interest in and to the Underlying Properties (which shall remain burdened by the Net Profits Interest and subject to the Conveyance); and (b) to Ustx, LLC, all of Boaz Energy’s 4,884,861 Trust units representing beneficial interests in the Trust. Boaz Energy reported that the Purchase and Sale Agreement contained customary conditions to the parties’ obligations to consummate the (the “Closing”). The Closing occurred on March 31, 2025. From and after the Closing, the Buyer owns the Underlying Properties (burdened by the Trust’s Net Profits Interest and subject to the Conveyance, Ustx, LLC owns the Boaz Trust Units, and the Buyer has become the operator of the Underlying Properties.
2025 Recap and 2026 Outlook
T2S and its predecessor, Boaz Energy, initially established a $4.5 million capital and workover budget for 2025 for the Underlying Properties (the "2025 Plan"). In response to the market environment and economic pressures affecting the oil and gas sector during the second half of 2025, including continued commodity price volatility, increased service and labor costs, and tightening capital markets, T2S revised the Plan downward to approximately $1.0 million (the “Revised 2025 Plan”). The reduction under the Revised 2025 Plan was made to preserve liquidity, maintain financial flexibility, and align spending levels with prevailing industry and macroeconomic conditions, and was primarily related to the postponement of the drilling of two wells originally scheduled for 2025 in Crane County, Texas—one injector well and one producer well. The drilling of these two wells was postponed until T2S makes a decision to move forward based on improved market visibility and commodity price stability. The Revised 2025 Plan included T2S’s participation in two non-operated wells in the Permian Shelf Area, which were successfully drilled in 2025, but not completed until the first quarter 2026, as well as ongoing investments in workovers, waterflood pattern optimization, and the reactivation of certain shut-in wells to sustain production levels. Total capital expenditure by the end of 2025 was $515,530. T2S advised the Trustee that it believed this revision provided an appropriate balance between near-term cash preservation and the continued development of the Underlying Properties.
34
Results of Operations
|
|
Year Ended December 31, |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Net profits income |
|
$ |
5,559,315 |
|
|
$ |
5,959,482 |
|
|
$ |
7,127,379 |
|
Interest income |
|
|
48,101 |
|
|
|
58,782 |
|
|
|
58,812 |
|
Total revenue |
|
|
5,607,416 |
|
|
|
6,018,264 |
|
|
|
7,186,191 |
|
Expenditures – general and administrative |
|
|
(894,680 |
) |
|
|
(856,766 |
) |
|
|
(923,935 |
) |
Cash reserves |
|
|
(0 |
) |
|
|
(0 |
) |
|
|
(0 |
) |
Distributable income |
|
$ |
4,712,736 |
|
|
$ |
5,161,498 |
|
|
$ |
6,262,256 |
|
Distributable income per unit (12,165,732 Trust units) |
|
$ |
0.387371 |
|
|
$ |
0.424259 |
|
|
$ |
0.514745 |
|
Distributable Income
Based on 12,165,732 Trust units outstanding at each date listed below, the per unit distributions during the year ended December 31, 2025, were as follows:
Record Date |
|
Payment |
|
Distribution |
|
|
January 31, 2025 |
|
February 14, 2025 |
|
$ |
0.040276 |
|
February 28, 2025 |
|
March 14, 2025 |
|
|
0.040219 |
|
March 31, 2025 |
|
April 14, 2025 |
|
|
0.040022 |
|
April 30, 2025 |
|
May 14, 2025 |
|
|
0.023807 |
|
May 30, 2025 |
|
June 13, 2025 |
|
|
0.030511 |
|
June 30, 2025 |
|
July 15, 2025 |
|
|
0.044361 |
|
July 31, 2025 |
|
August 14, 2025 |
|
|
0.032491 |
|
August 29, 2025 |
|
September 15, 2025 |
|
|
0.027737 |
|
September 30, 2025 |
|
October 15, 2025 |
|
|
0.031139 |
|
October 31, 2025 |
|
November 17, 2025 |
|
|
0.031565 |
|
November 28, 2025 |
|
December 12, 2025 |
|
|
0.028839 |
|
December 31, 2025 |
|
January 15, 2026 |
|
|
0.016404 |
|
|
|
|
|
$ |
0.387371 |
|
Years Ended December 31, 2025, and 2024
The decrease in net profits income was primarily due to decreased oil and natural gas sales volumes and oil prices, offset somewhat by a slight increase in natural gas prices. See “Computation of Income from the Net Profits Interest Received by the Trust” below.
Interest Income. Interest income decreased slightly for the year ended December 31, 2025, as compared to the prior year, primarily due to the decrease in income available for investment, along with lower interest rates.
General and Administrative Expenditures. General and administrative expenditures increased for the year ended December 31, 2025, as compared to the prior year, primarily due to an increase in legal expenses and differences in the timing and payment of some expenses.
Cash Reserves. Pursuant to the Trust Agreement, the Trustee was authorized to begin retaining cash reserves for administrative expenses beginning in May 2019. In April 2020, the cash reserves retained reached $1,000,000 and no further cash reserves have been retained by the Trustee since April 2020. As of December 31, 2025, the Trustee continued to hold the previously retained $1,000,000 in cash reserves.
Years Ended December 31, 2024, and 2023
The decrease in net profits income was primarily due to decreased oil and natural gas sales volumes and prices. See “Computation of Income from the Net Profits Interest Received by the Trust” below.
Interest Income. Interest income decreased for the year ended December 31, 2024, as compared to the prior year, primarily due to lower interest rates, along with less cash available for investment.
35
General and Administrative Expenditures. General and administrative expenditures decreased for the year ended December 31, 2024, as compared to the prior year, primarily because of a decrease in legal fees and differences in the timing and payment of some expenses.
Cash Reserves. Pursuant to the Trust Agreement, the Trustee was authorized to begin retaining cash reserves for administrative expenses beginning in May 2019. In April 2020, the cash reserves retained reached $1,000,000 and no further cash reserves have been retained by the Trustee since April 2020. As of December 31, 2024, the Trustee continued to hold the previously retained $1,000,000 in cash reserves.
Computation of Income from the Net Profits Interest Received by the Trust
The table below outlines the computation of income from the Net Profits Interest received by the Trust for the years ended December 31, 2025, 2024, and 2023:
|
|
Year Ended December 31, |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Underlying Properties sales volumes(1): |
|
|
|
|
|
|
|
|
|
|||
Oil (Bbl) |
|
|
252,834 |
|
|
|
289,918 |
|
|
|
317,765 |
|
Natural gas (Mcf)(2) |
|
|
312,392 |
|
|
|
341,170 |
|
|
|
387,631 |
|
Average realized sales price: |
|
|
|
|
|
|
|
|
|
|||
Oil (per Bbl) |
|
$ |
64.83 |
|
|
$ |
75.33 |
|
|
$ |
76.24 |
|
Natural gas (per Mcf) |
|
|
2.63 |
|
|
|
2.54 |
|
|
|
3.74 |
|
|
|
|
|
|
|
|
|
|
|
|||
Calculation of net profits: |
|
|
|
|
|
|
|
|
|
|||
Gross profits: |
|
|
|
|
|
|
|
|
|
|||
Oil sales |
|
$ |
16,391,616 |
|
|
$ |
21,839,691 |
|
|
$ |
24,225,807 |
|
Natural gas sales |
|
|
821,346 |
|
|
|
864,891 |
|
|
|
1,454,047 |
|
Other revenue |
|
|
57,207 |
|
|
|
159,063 |
|
|
|
103,601 |
|
Divestitures (Qualified De Minimis Sales) |
|
|
0 |
|
|
|
0 |
|
|
|
— |
|
Total gross profits |
|
|
17,270,169 |
|
|
|
22,863,645 |
|
|
|
25,780,455 |
|
Costs: |
|
|
|
|
|
|
|
|
|
|||
Direct operating expenses: |
|
|
1,161,236 |
|
|
|
1,849,266 |
|
|
|
2,194,843 |
|
Lease operating expenses |
|
|
5,744,836 |
|
|
|
6,811,020 |
|
|
|
7,284,563 |
|
Severance and ad valorem taxes |
|
|
1,492,256 |
|
|
|
1,328,880 |
|
|
|
1,955,693 |
|
Development expenses |
|
|
515,530 |
|
|
|
3,807,067 |
|
|
|
4,409,823 |
|
Other expenses |
|
|
1,971,219 |
|
|
|
1,773,038 |
|
|
|
2,094,993 |
|
Total costs |
|
|
(10,885,077 |
) |
|
|
(15,569,271 |
) |
|
|
(17,939,915 |
) |
Net profits |
|
|
6,385,092 |
|
|
|
7,294,374 |
|
|
|
7,840,540 |
|
Percentage allocable to Net Profits Interest |
|
|
80 |
% |
|
|
80 |
% |
|
|
80 |
% |
Net profits income (before capital reserve) |
|
|
5,108,074 |
|
|
|
5,835,500 |
|
|
|
6,262,256 |
|
Change in Capital Reserve(3) |
|
|
451,241 |
|
|
|
123,982 |
|
|
|
828,000 |
|
Interest income from savings account |
|
|
0 |
|
|
|
0 |
|
|
|
26,947 |
|
Net profits interest audit fee |
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
Net profits income received by the Trust |
|
$ |
5,559,315 |
|
|
$ |
5,959,482 |
|
|
$ |
7,127,379 |
|
Years Ended December 31, 2025, and 2024
Important factors used in calculating the Trust’s net profits income include the volumes of oil and gas produced from the Underlying Properties and the realized prices received for the sale of those minerals, including natural gas liquids, as well as direct operating and development expenses.
Sales Volumes
Oil. Oil sales volumes decreased for the year ended December 31, 2025, as compared to the prior year. This was primarily due to decreased demand and the natural decline in production.
Natural Gas. Natural gas sales volumes decreased for the year ended December 31, 2025, as compared to the prior year. This was primarily due to decreased demand and the natural decline in production.
36
Sales Prices
Oil. The average realized oil price per Bbl decreased for the year ended December 31, 2025, as compared to the prior year. The average realized oil price per Bbl for the year ended December 31, 2025, is primarily related to production from November 2024 through October 2025, when the average NYMEX price was $67.18 per Bbl.
Natural Gas. The average realized natural gas price per Mcf increased for the year ended December 31, 2025, as compared to the prior year. The average realized natural gas price per Mcf for the year ended December 31, 2025, is primarily related to production from November 2024 through October 2025, when the average NYMEX price was $3.28 per Mcf.
Costs
Direct Operating Expenses. Direct operating expenses decreased for the year ended December 31, 2025, as compared to the prior year primarily due to a decrease in capital projects to return wells to production.
Lease Operating Expenses. Lease operating expenses decreased for the year ended December 31, 2025, as compared to the prior year primarily due to returning fewer wells to production.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes increased for the year ended December 31, 2025, as compared to the prior year primarily due to higher assessed property values driven by stronger commodity prices in 2024 and updated valuation inputs (e.g., price forecasts, production expectations, and discount rates). Because ad valorem taxes are based on the fair market value of underlying reserves and production, increases in oil and gas prices or revisions to valuation assumptions directly increase taxable values and resulting tax expense. Additionally, jurisdiction-specific changes- such as updated appraisal methodologies, higher mill levies, or reduced tax credits- may have further contributed to the year-over-year increase.
Development Expenses Related to the Underlying Properties. Development expenses related to the Underlying Properties decreased for the year ended December 31, 2025, as compared to the prior year primarily due to fewer drilling and recompletion projects.
Other Expenses. Other expenses increased for the year ended December 31, 2025, as compared to the prior year primarily due to an increase in overhead expenses.
Capital Reserve and Operator Advance. T2S is entitled under the Conveyance to reserve up to $3 million from the net profits for certain taxes and development expenses. As of December 31, 2025, the balance of funds held back by T2S to cover certain future capital expenses was $74,933 net to the Trust.
Years Ended December 31, 2024, and 2023
Important factors used in calculating the Trust’s net profits income include the volumes of oil and gas produced from the Underlying Properties and the realized prices received for the sale of those minerals, including natural gas liquids, as well as direct operating and development expenses.
Sales Volumes
Oil. Oil sales volumes decreased for the year ended December 31, 2024, as compared to the prior year. This was primarily due to decreased demand and the natural decline in production.
Natural Gas. Natural gas sales volumes decreased for the year ended December 31, 2024, as compared to the prior year. This was primarily due to decreased demand and the natural decline in production.
Sales Prices
Oil. The average realized oil price per Bbl decreased for the year ended December 31, 2024, as compared to the prior year. The average realized oil price per Bbl for the year ended December 31, 2024, is primarily related to production from November 2023 through October 2024, when the average NYMEX price was $77.34 per Bbl.
Natural Gas. The average realized natural gas price per Mcf decreased for the year ended December 31, 2024, as compared to the prior year. The average realized natural gas price per Mcf for the year ended December 31, 2024, is primarily related to production from November 2023 through October 2024, when the average NYMEX price was $2.32 per Mcf.
37
Costs
Direct Operating Expenses. Direct operating expenses decreased for the year ended December 31, 2024, as compared to the prior year primarily due to a decrease in capital projects to return wells to production.
Lease Operating Expenses. Lease operating expenses decreased for the year ended December 31, 2024, as compared to the prior year primarily due to returning fewer wells to production.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes decreased for the year ended December 31, 2024, as compared to the prior year primarily due to lower sales valuation due to decreased industry prices for oil and natural gas.
Development Expenses Related to the Underlying Properties. Development expenses related to the Underlying Properties decreased for the year ended December 31, 2024, as compared to the prior year primarily due to fewer drilling and recompletion projects.
Other Expenses. Other expenses increased for the year ended December 31, 2024, as compared to the prior year primarily due to an increase in overhead expenses.
Capital Reserve and Operator Advance. Boaz Energy, as predecessor to T2S, was entitled under the Conveyance to reserve up to $3 million from the net profits for certain taxes and development expenses. As of December 31, 2024, the balance of funds held back by Boaz Energy to cover certain future capital expenses was $526,174 net to the Trust.
Liquidity and Capital Resources
The Trust’s principal sources of liquidity and capital are cash flow generated from the Net Profits Interest and borrowings, if any, to fund administrative expenses. The Trust’s primary uses of cash are distributions to Trust unitholders, payment of Trust administrative expenses, including, if applicable, any reserves established by the Trustee for future liabilities.
Administrative expenses include the Trustee and Delaware Trustee fees, accounting, engineering, legal, tax advisory and other professional fees, and tax reporting and distribution expenses. The Trust is also responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual, quarterly and current reports to the SEC, New York Stock Exchange listing fees, independent auditor fees and registrar and transfer agent fees. If the Trustee determines that cash on hand and cash to be received in respect of the Net Profits Interest are, or will be, insufficient to cover the Trust’s liabilities and expenses, the Trustee may cause the Trust to borrow funds to pay liabilities of the Trust. If the Trustee causes the Trust to borrow funds, the Trust unitholders will not receive distributions until the borrowed funds or the amount drawn, as applicable, are repaid.
Pursuant to the Trust Agreement, the Trustee was authorized beginning May 2019 to retain cash from the distributions it receives (i) in an amount not to exceed $1.0 million at any one time to be used by the Trust in the event that its cash on hand (including available cash reserves) is not sufficient to pay ordinary course administrative expenses as they become due and (ii) in such amounts as the Trustee in its discretion deems appropriate to pay for future liabilities of the Trust. Boaz Energy provided the Trust with a $1.0 million Letter of Credit that could be drawn by the Trust to pay its administrative expenses. The Trustee is permitted to retain cash from distributions in such amount as the Trustee determines but not less than $25,000 per month or more than $100,000 per month until the reserve described in clause (i) equals or exceeds $1.0 million, at which time, the Trustee is required to release the Letter of Credit. The Letter of Credit expired May 2, 2020, as the Trustee had retained a total of $1,000,000 in cash reserves. As of December 31, 2025, the Trustee continued to hold the previously retained $1,000,000 in cash reserves.
On May 4, 2018, the Trust entered into a registration rights agreement for the benefit of Boaz Energy and certain of its affiliates and transferees, pursuant to which the Trust agreed to register the offering of the Trust units held by Boaz Energy and certain of its affiliates and permitted transferees upon request by Boaz Energy. As of March 31, 2022, Boaz Energy owned 5,878,332 Trust units of the 12,165,732 Trust units issued and outstanding. The Trust filed a Registration Statement on Form S-3 on April 28, 2022 (the “Registration Statement”) seeking the registration of 5,801,675 Trust units held by Boaz Energy. The SEC confirmed the effectiveness of the Registration Statement on May 9, 2022. The Trust has not and will not receive any of the proceeds received from the sale of the Trust units. Boaz Energy sold its remaining 4,884,861 units to Ustx, LLC as part of the sale of the assets underlying the Trust that was finalized on March 31, 2025. As of March 25, 2026, Ustx, LLC owned 4,884,861 Trust units of the 12,165,732 units issued and outstanding.
T2S Capital Expenditure Budget
38
2025 Recap and 2026 Outlook
T2S and its predecessor, Boaz Energy, initially established a $4.5 million capital and workover budget for 2025 for the Underlying Properties (the "2025 Plan"). In response to the market environment and economic pressures affecting the oil and gas sector during the second half of 2025, including continued commodity price volatility, increased service and labor costs, and tightening capital markets, T2S revised the Plan downward to approximately $1.0 million (the “Revised 2025 Plan”). The reduction under the Revised Plan was made to preserve liquidity, maintain financial flexibility, and align spending levels with prevailing industry and macroeconomic conditions, and was primarily related to the postponement of the drilling of two wells originally scheduled for 2025 in Crane County, Texas—one injector well and one producer well. The drilling of these two wells was postponed until T2S makes a decision to move forward based on improved market visibility and commodity price stability. The Revised 2025 Plan included T2S’s participation in two non-operated wells in the Permian Shelf Area, which were successfully drilled in 2025, but not completed until the first quarter 2026, as well as ongoing investments in workovers, waterflood pattern optimization, and the reactivation of certain shut-in wells to sustain production levels. Total capital expenditure by the end of 2025 was $515,000. T2S advised the Trustee that it believed this revision provided an appropriate balance between near-term cash preservation and the continued development of the Underlying Properties.
T2S advised the Trustee that it has not budgeted any capital for 2026 (the “2026 Plan”). The 2026 Plan reflects T2S’s ongoing evaluation of project economics, commodity price forecasts, and regulatory timing, and may be further adjusted based on changes in market conditions, operating performance, and capital requirements. T2S does have a workover budget of $0.75 million in 2026.
Off-Balance Sheet Arrangements
As of December 31, 2025, the Trust had no off-balance sheet arrangements.
New Accounting Pronouncements
As the Trust’s financial statements are prepared on the modified cash basis, most accounting pronouncements are not applicable to the Trust’s financial statements. No new accounting pronouncements have been adopted or issued that would impact the financial statements of the Trust.
Critical Accounting Policies and Estimates
The Trust uses the modified cash basis of accounting to report Trust receipts of the Net Profits Interest and payments of expenses incurred. The Net Profits Interest represents the right to receive revenues (oil and natural gas sales), less direct operating expenses (lease operating expenses and severance and ad valorem taxes) and development expenses of the Underlying Properties, multiplied by 80%. Cash distributions of the Trust are made based on the amount of cash received by the Trust pursuant to terms of the Conveyance creating the Net Profits Interest.
The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust’s assets, liabilities, Trust corpus, earnings and distributions as follows:
39
The financial statements of the Trust are prepared on a modified cash basis of accounting, which is considered to be the most meaningful basis of preparation for a royalty trust because monthly distributions to the Trust unitholders are based on net cash receipts. Although this basis of accounting is permitted for royalty trusts by the SEC, the financial statements of the Trust differ from financial statements prepared in accordance with GAAP because net profits income is not accrued in the month of production, expenses are not recognized when incurred and cash reserves may be established for certain contingencies, and overpayments received do not need to be paid back and are instead taken from future payments that would not be recorded in GAAP financial statements. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.
The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimated future cash flows used to determine amortization and potential impairment of the investment in the Net Profits Interest are subject to change.
Oil and Natural Gas Reserves. The proved oil and natural gas reserves for the Underlying Properties are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using prices at the date of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices. Accordingly, oil and natural gas quantities ultimately recovered and the timing of production may be substantially different from original estimates.
The Financial Accounting Standards Board requires supplemental disclosures for oil and gas producers based on a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserve quantities. Under this disclosure, future cash inflows are computed by applying the average prices during the 12-month period prior to fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month benchmark price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Future price changes are only considered to the extent provided by contractual arrangements in existence at year-end. The standardized measure of discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future cash flows relating to proved oil and natural gas reserves. Changes in any of these assumptions, including consideration of other factors, could have a significant impact on the standardized measure. The standardized measure does not necessarily result in an estimate of the current fair market value of proved reserves.
Amortization of Net Profits Interest. The Trust calculates amortization of the Net Profits Interest in oil and natural gas properties on a unit-of-production basis based on the Underlying Properties’ production and reserves. The reserves upon which the amortization rate is based are quantity estimates which are subject to numerous uncertainties inherent in the estimation of proved reserves. The volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. These estimates are expected to change as additional information becomes available in the future. Downward revisions in proved reserves may result in an increased rate of amortization. Amortization is recorded on sales volumes paid by the Trust during the relevant period and is charged directly to the Trust corpus balance. As a result, amortization does not affect the cash earnings of the Trust.
Impairment of Net Profits Interest. The Trustee reviews the Trust’s Net Profits Interest in oil and natural gas properties for impairment annually and whenever events or circumstances indicate that the carrying value of the Net Profits Interest may not be recoverable. In the event of material revisions, the Trustee reviews the impact of these revisions on the amortization of Trust Units and impairment estimates. During 2025, a material revision was made to reserves resulting in the additional recognition of amortization of Trust Units. The Trust recognized $5,905,119 of amortization of Trust Units for the year ended December 31, 2025.
In general, neither the Trustee nor T2S view temporarily low prices as an indication of impairment. The markets for crude oil and natural gas have a history of significant price volatility and though prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand. However, the prolonged historically low prices for oil and natural gas in 2025 and into the future, coupled with no development budget for T2S for 2026, caused the future undiscounted net cash flows of the Net Profits Interest to be lower than the carrying value, resulting in events and circumstances indicating that the carrying
40
value may not be recoverable. Since the undiscounted future net cash flows from the Net Profits Interest are less than the Net Profits Interest carrying value, the Trust has recognized an impairment loss for the difference between the Net Profits Interest carrying value and the estimated fair value of the Net Profits Interest. The determination as to whether the Net Profits Interest is impaired is based on the best information available to the Trustee at the time of the evaluation, including information provided by T2S such as estimates of future production and development and operating expenses.
The Trustee determined that an impairment in the amount of $39.9 million occurred for the year ended December 31, 2025, after reviewing the undiscounted and discounted cash flow that had been revised to reflect future crude oil and natural gas commodity prices published by third-party industry experts (adjusted for base differentials) and a risk-adjusted discount rate. The Net Profits Interest was written down to its fair value of $26.6 million and the impairment is charged directly to the Trust corpus, which does not affect distributable income. Impairments recorded for book purposes will not result in a loss for tax purposes for the unitholders until the loss is recognized.
There was no impairment present for the year ended December 31, 2024.
Refer to Note 2 to the financial statements included in Item 8 of this report for the Trust’s significant accounting policies.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Not applicable.
41
Item 8. Financial Statements and Supplementary Data
Financial Statements. The following documents are filed as part of the Trust’s financial statements for the year ended December 31, 2025:
|
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 410) |
43 |
|
45 |
|
|
46 |
|
|
47 |
|
|
48 |
42
400 W 6th St Suite 3200
Austin, TX 78701
512-609-1900
Report of Independent Registered Public Accounting Firm
To the Unit Holders of PermRock Royalty Trust and Argent Trust Company, Trustee
Opinion on the Financial Statements
We have audited the accompanying statements of assets, liabilities, and trust corpus of PermRock Royalty Trust (“the Trust”) as of December 31, 2025, and 2024, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the assets, liabilities, and trust corpus of the Trust as of December 31, 2025 and 2024, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2025, in conformity with the modified cash basis of accounting, which is a comprehensive basis of accounting other accounting principles generally accepted in the United States of America.
As described in Note 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
43
Weaver and Tidwell, L.L.P.
CPAs AND ADVISORS | WEAVER.COM
The Unit Holders of PermRock Royalty Trust and Argent Trust Company, Trustee
The Impact of Proved Oil and Gas Reserves on Net Profits Interests in Oil and Gas Properties, Net
The Trust’s net profits interests in oil and gas properties, net balance was $72,379,939 as of December 31, 2025, and amortization of net profits interests for the year ended December 31, 2025 was $45,784,064. As described in the financial statements, amortization of the net profits interests is calculated on a unit-of-production basis using proved reserves attributable to the Trust’s interests and is charged directly to trust corpus. As disclosed by the Trustee, 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 before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are quantities expected to be recovered through existing wells with existing equipment and operating methods in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Because proved reserves must be estimated based upon average oil and gas prices during the 12-month period prior to the fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements estimated reserve quantities can be significantly impacted by commodity-price volatility. Oil and gas quantities ultimately recovered, and the timing of production may be substantially different from original estimates. The proved oil and gas reserves for the underlying properties are estimated annually by independent petroleum engineers (specialists) using inputs that include, among others: (i) historical and forecasted production rates and decline curves, (ii) working interest and net revenue interest ownership, (iii) operating and development costs, (iv) commodity price assumptions (12-month average), and (v) applicable taxes and transportation differentials.
The principal considerations for our determination that performing procedures relating to the impact of proved oil and gas reserves on net profits interests in oil and gas properties, net and changes in trust corpus is a critical audit matter are: (i) the significant judgment by the Trustee, including the use of specialists when developing the estimates of proved oil and gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the audit evidence related to the data, methods, and assumptions used by the Trustee and its specialists in developing the estimates of the reserve quantities.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included, among others, testing the completeness and accuracy of the data related to estimates of reserve quantities. The work of the Trustee’s specialists was used in performing the procedures to evaluate the reasonableness of the reserve quantities. As a basis for using this work, the specialists’ qualifications and objectivity were understood, as well as the methods used by the specialists. The procedures performed also included tests of the data used by the specialists and an evaluation of the specialists’ results, including, among others, comparison of selected reserve quantities to historical production data, evaluation of significant assumptions, and assessment of whether the estimates were consistent with SEC Regulation S-X and ASC 932, as adapted to the modified cash basis of accounting.
WEAVER AND TIDWELL, L.L.P.
We have served as the Trust’s auditor since 2018.
Austin, Texas
March 27, 2026
Weaver and Tidwell, L.L.P.
1601 South MoPac Expressway, Suite D250 | Austin, Texas 78746
Main: 512.609.1900
44
Statement of Assets, Liabilities, and Trust Corpus
|
|
December 31, |
|
|||||
|
|
2025 |
|
|
2024 |
|
||
ASSETS |
|
|
|
|
|
|
||
Cash and Short-Term Investments |
|
$ |
1,199,573 |
|
|
$ |
1,612,261 |
|
Net Profits Interests |
|
|
26,595,875 |
|
|
|
72,379,939 |
|
TOTAL |
|
$ |
27,795,448 |
|
|
$ |
73,992,200 |
|
|
|
|
|
|
|
|
||
|
|
December 31, |
|
|||||
|
|
2025 |
|
|
2024 |
|
||
LIABILITIES & TRUST CORPUS |
|
|
|
|
|
|
||
Distribution Payable to Unitholders |
|
$ |
199,573 |
|
|
$ |
612,261 |
|
Cash Reserves |
|
|
1,000,000 |
|
|
|
1,000,000 |
|
Trust Corpus – 12,165,732 Trust Units Issued and Outstanding |
|
|
26,595,875 |
|
|
|
72,379,939 |
|
TOTAL |
|
$ |
27,795,448 |
|
|
$ |
73,992,200 |
|
These Financial Statements should be read in conjunction with the accompanying Notes to Financial Statements included herein.
45
Statement of Distributable Income
|
|
Year Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|||
Net Profits Income |
|
$ |
5,559,315 |
|
|
$ |
5,959,482 |
|
|
$ |
7,127,379 |
|
Interest Income |
|
|
48,101 |
|
|
|
58,782 |
|
|
|
58,812 |
|
Total Revenue |
|
|
5,607,416 |
|
|
|
6,018,264 |
|
|
|
7,186,191 |
|
Expenditures – General and Administrative |
|
|
(894,680 |
) |
|
|
(856,766 |
) |
|
|
(923,935 |
) |
Distributable Income |
|
$ |
4,712,736 |
|
|
$ |
5,161,498 |
|
|
$ |
6,262,256 |
|
Distributable Income per Unit – 12,165,732 Trust Units |
|
$ |
0.387371 |
|
|
$ |
0.424259 |
|
|
$ |
0.514745 |
|
These Financial Statements should be read in conjunction with the accompanying Notes to Financial Statements included herein
46
Statements of Changes in Trust Corpus
|
|
Year Ended |
|
|
Year Ended |
|
|
Year Ended |
|
|||
Trust Corpus, Beginning of Period |
|
$ |
72,379,939 |
|
|
$ |
75,876,170 |
|
|
$ |
80,041,113 |
|
Amortization/Impairment of Net Profits Interest |
|
|
(45,784,064 |
) |
|
|
(3,496,231 |
) |
|
|
(4,164,943 |
) |
Distributable Income |
|
|
4,712,736 |
|
|
|
5,161,498 |
|
|
|
6,262,256 |
|
Distributions Declared |
|
|
(4,712,736 |
) |
|
|
(5,161,498 |
) |
|
|
(6,262,256 |
) |
Trust Corpus, End of Period |
|
$ |
26,595,875 |
|
|
$ |
72,379,939 |
|
|
$ |
75,876,170 |
|
These Financial Statements should be read in conjunction with the accompanying Notes to Financial Statements included herein.
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PermRock Royalty Trust (the “Trust”) is a Delaware statutory trust formed on November 22, 2017 under the Delaware Statutory Trust Act pursuant to a trust agreement dated November 22, 2017, as amended and restated on May 4, 2018, by and among Boaz Energy II, LLC (“Boaz Energy”), as trustor, Simmons Bank, as Trustee (as hereinafter defined), and Wilmington Trust, National Association, as Delaware Trustee (the “Delaware Trustee”) (such amended and restated trust agreement, as amended to date, the “Trust Agreement”).
In accordance with the successor trustee provisions of the Trust Agreement, Argent Trust Company, as successor trustee of the Trust, is subject to all terms and conditions of the Trust Agreement. The defined term “Trustee” as used herein shall refer to Simmons Bank (which maintains its offices at 2200 West 7th Street, Suite 210, P.O. Box 470727, Fort Worth, Texas 76147) for periods prior to December 30, 2022, and shall refer to Argent Trust Company (which maintains its offices at 3838 Oak Lawn Ave, Suite 1720, Dallas, Texas 75219) for periods on and after December 30, 2022.
The Trust was created to acquire and hold the Net Profits Interest for the benefit of the Trust unitholders. In connection with the closing of the initial public offering of Trust units, on May 4, 2018, Boaz Energy conveyed the Net Profits Interest to the Trust in exchange for Trust units pursuant to a conveyance agreement between Boaz Energy, the Trustee and the Delaware Trustee (the “Conveyance”). The Net Profits Interest represents an interest in the Underlying Properties. In May 2018, Boaz Energy completed an initial public offering of 6,250,000 of the 12,165,732 total Trust units outstanding, retaining ownership of 5,915,732 Trust units.
On January 10, 2025, Boaz Energy, the former owner and operator of the Underlying Properties, entered into a Purchase and Sale Agreement with T2S (the "Buyer") with respect to the Underlying Properties. The acquisition of the Underlying Properties was finalized on March 31, 2025. The sale also included Boaz Energy's transfer of 4,884,861 units representing beneficial interests in the Trust to Ustx LLC, an affiliate of T2S.
The Net Profits Interest entitles the Trust to receive 80% of the net profits from the sale of oil and natural gas production from the Underlying Properties. The Net Profits Interest is passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, costs relating to the operation of the Underlying Properties. The Trust has and will continue to make monthly cash distributions of all of its monthly cash receipts, after deduction of fees and expenses for the administration of the Trust and any cash reserves, to holders of its Trust units as of the applicable record date on or before the 10th business day after the record date. Distributions generally relate to sales from a one-month period.
The Trustee may deposit funds awaiting distribution in an account with an FDIC-insured or national bank, including the Trustee, if the interest paid to the Trust at least equals amounts paid by the Trustee on similar deposits, and make other short-term investments with the funds distributed to the Trust.
As of March 26, 2026, Ustx, LLC owned 4,884,861 Trust units of the 12,165,732 Trust units issued and outstanding.
The Trust uses the modified cash basis of accounting to report Trust receipts of the Net Profits Interest and payments of expenses incurred. The Net Profits Interest represents the right to receive revenues (primarily oil and natural gas sales), less direct operating expenses, lease operating expenses, severance and ad valorem taxes and development expenses of the Underlying Properties, multiplied by 80%. Cash distributions of the Trust are made based on the amount of cash received by the Trust pursuant to terms of the Conveyance creating the Net Profits Interest. Certain reclassifications of prior year’s data have been made to conform to the current year presentation. These reclassifications had no impact on the Trust’s previously reported Distributable Income or Trust Corpus.
The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust’s assets, liabilities, Trust corpus, earnings and distributions as follows:
48
The financial statements of the Trust are prepared on a modified cash basis of accounting, which is considered to be the most meaningful basis of preparation for a royalty trust because monthly distributions to the Trust unitholders are based on net cash receipts. Although this basis of accounting is permitted for royalty trusts by the SEC, the financial statements of the Trust differ from financial statements prepared in accordance with GAAP because net profits income is not accrued in the month of production, expenses are not recognized when incurred and cash reserves may be established for certain contingencies that would not be recorded in GAAP financial statements. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.
The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimated future cash flows used to determine amortization and potential impairment of the investment in the Net Profits Interest are subject to change.
The Trust’s revenue and distributions are substantially dependent upon the prevailing and future prices for oil and natural gas, each of which depends on numerous factors beyond the Trust’s control such as economic conditions, the global political environment, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile and may be subject to significant fluctuations in the future.
Contingencies related to the Underlying Properties that are unfavorably resolved would generally be expected to result in reductions to cash receipts to the Trust in respect of the Net Profits Interest with corresponding reductions to cash distributions to Trust unitholders. Please see the discussion of litigation in Note 11.
49
During 2025, a material revision was made to reserves resulting in the additional recognition of amortization of Trust Units. The Trust recognized $5,905,119 of amortization of Trust Units for the year ended December 31, 2025. The Trustee determined that an impairment in the amount of $39.9 million occurred for the year ended December 31, 2025, after reviewing the undiscounted and discounted cash flow that had been revised to reflect future crude oil and natural gas commodity prices published by third-party industry experts (adjusted for base differentials) and a risk-adjusted discount rate. The Net Profits Interest was written down to its fair value of $26.6 million and the impairment is charged directly to the Trust corpus, which does not affect distributable income. Impairments recorded for book purposes will not result in a loss for tax purposes for the unitholders until the loss is recognized.
For the year ended December 31, 2024, a material revision was made to reserves resulting in recognition of $3,496,231 of amortization of Trust Units. There was no impairment as of December 31, 2024.
Tax counsel advised the Trust at the time of formation that for U.S. federal income tax purposes, the Trust is treated as a grantor trust and is not subject to federal income tax at the trust level. Trust unitholders are treated for such purposes as owning a direct interest in the assets of the Trust, and each Trust unitholder is taxed directly on its pro rata share of the income and any gain, if sold, attributable to the assets of the Trust and is entitled to claim its pro rata share of deductions and expenses attributable to the assets of the Trust. Each Trust unitholder should consult his or her own tax advisor regarding income tax requirements, if any, applicable to such unitholder’s ownership of Trust units.
5. Cash Reserves
Pursuant to the Trust Agreement, beginning in May 2019, the Trustee was authorized to begin retaining cash from the distributions the Trust receives (i) in an amount not to exceed $1.0 million at any one time to be used by the Trust in the event that its cash on hand (including available cash reserves) is not sufficient to pay ordinary course administrative expenses as they become due and (ii) in such amounts as the Trustee in its discretion deems appropriate to pay for future liabilities of the Trust. Boaz Energy provided the Trust with a $1.0 million letter of credit (the “Letter of Credit”) that could be drawn by the Trust to pay administrative expenses of the Trust. The Trustee is permitted to retain cash from distributions in such amount as the Trustee determines but not less than $25,000 per month or more than $100,000 per month until the reserve described in clause (i) equals or exceeds $1.0 million, at which time, the Trustee is required to release the Letter of Credit. The Letter of Credit expired May 2, 2020, as the Trustee had retained a total of $1,000,000 in cash reserves. As of December 31, 2025, the Trustee continued to hold the previously retained $1,000,000 in cash reserves.
T2S and any of its successors are entitled under the Conveyance to reserve up to $3 million from the net profits for certain taxes and development expenses. As of December 31, 2025, the balance of funds held back to cover certain future capital expenses was $74,933 net to the Trust.
6. Distributions to Unitholders
The Trust makes monthly cash distributions of all of its monthly cash receipts, after deduction of fees and expenses for the administration of the Trust and any cash reserves, to holders of its Trust units as of the applicable record date on or before the 10th business day after the record date.
Based on 12,165,732 Trust units outstanding at each date listed below, the monthly per unit distributions during the year ended December 31, 2025, were as follows:
50
Record Date |
|
Payment Date |
|
Distribution per Unit |
|
|
January 31, 2025 |
|
February 14, 2025 |
|
$ |
0.040276 |
|
February 28, 2025 |
|
March 14, 2025 |
|
|
0.040219 |
|
March 31, 2025 |
|
April 14, 2025 |
|
|
0.040022 |
|
April 30, 2025 |
|
May 14, 2025 |
|
|
0.023807 |
|
May 30, 2025 |
|
June 13, 2025 |
|
|
0.030511 |
|
June 30, 2025 |
|
July 15, 2025 |
|
|
0.044361 |
|
July 31, 2025 |
|
August 14, 2025 |
|
|
0.032491 |
|
August 29, 2025 |
|
September 15, 2025 |
|
|
0.027737 |
|
September 30, 2025 |
|
October 15, 2025 |
|
|
0.031139 |
|
October 31, 2025 |
|
November 17, 2025 |
|
|
0.031565 |
|
November 28, 2025 |
|
December 12, 2025 |
|
|
0.028839 |
|
December 31, 2025 |
|
January 15, 2026 |
|
|
0.016404 |
|
|
|
|
|
$ |
0.387371 |
|
7. Related Party Transactions
Trustee Administrative Fee. Under the terms of the Trust Agreement, the Trust pays an annual administrative fee to the Trustee and Delaware Trustee. The Delaware Trustee’s annual fee is $4,000. In 2025, the Trustee received $215,081 for the period from January through December 2025. For 2026, the Trustee’s annual administrative fee will be approximately $217,232. The Trustee’s annual administrative fee increased at a rate of 3% per year for the first three years of the Trust’s existence, increased at a rate of 2% in 2022 and 2023. The Trustee’s annual administrative fee will increase at a rate of 1% in 2024, will continue to increase at a rate of 1% each year until the 20th anniversary of the Trust’s formation, and then will remain flat thereafter. These costs of the Trust, which are included in administration expenses, are deducted by the Trust before distributions are made to Trust unitholders.
Agreements with Boaz Energy. On May 4, 2018, the Trust entered into a registration rights agreement for the benefit of Boaz Energy and certain of its affiliates and transferees, pursuant to which the Trust agreed to register the offering of the Trust units held by Boaz Energy and certain of its affiliates and permitted transferees upon request by Boaz Energy. The Trust filed a Registration Statement on Form S-3 on April 28, 2022 (the “Registration Statement”) seeking the registration of 5,801,675 Trust units held by Boaz Energy. The SEC confirmed the effectiveness of the Registration Statement on May 9, 2022. As of March 25, 2025, Boaz Energy owned 4,884,861 Trust units of the 12,165,732 units issued and outstanding.
On January 13, 2025, the Trust announced that Boaz Energy and its affiliate Boaz Energy II Royalty, LLC entered into a Purchase and Sale Agreement on January 10, 2025 with T2S Permian Acquisition II LLC ( "T2S" ) with respect to the Underlying Properties.
Boaz Energy informed the Trust that, pursuant to the Purchase and Sale Agreement, Boaz sold and conveyed (a) toT2S all of Boaz Energy’s right, title and interest in and to the Underlying Properties (which shall remain burdened by the Net Profits Interest and subject to the Conveyance); and (b) to Ustx, LLC, all of Boaz Energy’s 4,884,861 Trust units representing beneficial interests in the Trust.
Boaz Energy reported that the Purchase and Sale Agreement contained customary conditions to the parties’ obligations to consummate the (the “Closing”). The Closing occurred on March 31, 2025. From and after the Closing, the Buyer owns the Underlying Properties (burdened by the Trust’s Net Profits Interest and subject to the Conveyance, Ustx, LLC owns the Boaz Trust Units, and the Buyer has become the operator of the Underlying Properties.
8. Certain Contracts
The Trust is not a party to any purchase, gathering, or processing contracts. T2S and other outside operators are parties to oil and natural gas sales contracts. For the year ended December 31, 2025, T2S reported that Phillips 66, Plains All American Pipeline, Energy Transfer Partners, and Enterprise Crude Oil LLC accounted for 34.34%, 17.01%, 16.31%, and 14.69% respectively, of its total oil and natural gas revenues, and that no other purchaser accounted for 10% or more of the total revenue of the Underlying Properties. T2S does not believe that the loss of any of these parties as a purchaser of crude oil or natural gas production from the Underlying Properties would have a material impact on the business or operations of Boaz Energy or the Underlying Properties because of the large number of marketing firms and competitive nature of oil and gas purchasers in the Permian Basin. Oil and natural gas are currently sold to these four customers under short-term contracts at market prices.
51
9. Significant Customers
Information as to significant purchasers of oil and gas production attributable to the Trust’s economic interests is included in Note 8, above.
10. Development Costs
T2S and its predecessor, Boaz Energy, initially established a $4.5 million capital and workover budget for 2025 for the Underlying Properties (the "2025 Plan"). In response to the market environment and economic pressures affecting the oil and gas sector during the second half of 2025, including continued commodity price volatility, increased service and labor costs, and tightening capital markets, T2S revised the Plan downward to approximately $1.0 million (the “Revised 2025 Plan”). The reduction under the Revised 2025 Plan was made to preserve liquidity, maintain financial flexibility, and align spending levels with prevailing industry and macroeconomic conditions, and was primarily related to the postponement of the drilling of two wells originally scheduled for 2025 in Crane County, Texas—one injector well and one producer well. The drilling of these two wells was postponed until T2S makes a decision to move forward based on improved market visibility and commodity price stability. The Revised 2025 Plan included T2S’s participation in two non-operated wells in the Permian Shelf Area, which were successfully drilled in 2025, but not completed until the first quarter 2026, as well as ongoing investments in workovers, waterflood pattern optimization, and the reactivation of certain shut-in wells to sustain production levels. Total capital expenditure by the end of 2025 was $515,000. T2S advised the Trustee that it believed this revision provided an appropriate balance between near-term cash preservation and the continued development of the Underlying Properties.
T2S advised the Trustee that it has not budgeted any capital for 2026 (the “2026 Plan”). The 2026 Plan reflects T2S’s ongoing evaluation of project economics, commodity price forecasts, and regulatory timing, and may be further adjusted based on changes in market conditions, operating performance, and capital requirements. T2S does have a workover budget of $0.75 million in 2026.
11. Settlements and Litigation
On October 1, 2018, a lawsuit styled Thaleia L. Marston, Trustee of the Marston Trust v. Blackbeard Operating, LLC, et.al, No. 18-10-24761 – CVW in the 143rd District Court in Ward County, Texas (the “2018 Litigation”) was filed, naming, among others, Boaz Energy and the Trust as defendants. The plaintiff is a lessor under two leases operated by Blackbeard Operating LLC. The Underlying Properties include the interests of Boaz Energy in some of the minerals covered by those leases. The litigation sought surface use damages and alleged violations of the terms of the leases, among other things. The court had set a two-day bench trial to commence May 18, 2022, but on May 10, 2022, the court granted motions for summary judgment effectively disposing of the plaintiff’s claims. At a status conference conducted on May 12, 2022, the plaintiff confirmed the court’s rulings disposed of all the plaintiff’s claims. The court held a hearing regarding attorneys’ fees in June 2022. On May 12, 2023, the court entered its final judgment, incorporating its prior order granting the defendants’ motion for summary judgment and granting defendants’ motion for attorneys’ fees, but the plaintiff then filed a notice of appeal to the Eighth Court of Appeals in El Paso County, Texas. By order dated February 5, 2025, the Court of Appeals affirmed the trial court’s judgment in favor of the defendant appellees and therefore, this case is over.
12. Supplemental Oil and Gas Reserve Information (Unaudited)
Proved Oil and Natural Gas Reserves
Proved oil and gas reserves have been estimated by independent petroleum engineers. 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 regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors.
The following table presents a reconciliation of proved reserve quantities attributable to the Trust as of the dates indicated below:
52
|
|
Oil |
|
|
Natural Gas |
|
|
Total |
|
|||
Balance, Proved Reserves as of December 31, 2023 |
|
|
1,578 |
|
|
|
1,789 |
|
|
|
1,877 |
|
Revisions of previous estimates |
|
|
(275 |
) |
|
|
(105 |
) |
|
|
(292 |
) |
Extensions, discoveries and other additions |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Production |
|
|
(290 |
) |
|
|
(341 |
) |
|
|
(347 |
) |
Balance, Proved Reserves as of December 31, 2024 |
|
|
1,563 |
|
|
|
1,553 |
|
|
|
1,822 |
|
Revisions of previous estimates |
|
|
(335 |
) |
|
|
(492 |
) |
|
|
(417 |
) |
Extensions, discoveries and other additions |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Production |
|
|
(253 |
) |
|
|
(312 |
) |
|
|
(305 |
) |
Balance, Proved Reserves as of December 31, 2025 |
|
|
975 |
|
|
|
749 |
|
|
|
1,100 |
|
Proved developed reserves: |
|
|
|
|
|
|
|
|
|
|||
December 31, 2023 |
|
|
1,489 |
|
|
|
1,789 |
|
|
|
1,788 |
|
December 31, 2024 |
|
|
1,391 |
|
|
|
796 |
|
|
|
1,524 |
|
December 31, 2025 |
|
|
975 |
|
|
|
749 |
|
|
|
1,100 |
|
Proved undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|||
December 31, 2023 |
|
|
89 |
|
|
|
— |
|
|
|
89 |
|
December 31, 2024 |
|
|
172 |
|
|
|
758 |
|
|
|
298 |
|
December 31, 2025 |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Extensions and discoveries. During the year ended December 31, 2025, there were no extensions or discovery changes to proved reserves.
During the year ended December 31, 2024, 4 gross wells (0.3 net) were drilled in the Permian Platform area. Extensions and discoveries included 165 MBoe of proved developed and undeveloped reserves that were a result of drilling and waterflood activity.
During the year ended December 31, 2023, 6 gross wells (0.5 net) were drilled in the Permian Platform area. Extensions and discoveries included 2.4 MBoe of proved developed and undeveloped reserves that were a result of 2022 drilling activity.
Revisions of previous estimates. During the year ended December 31, 2025, revisions of previous estimates decreased proved reserves by 23%. This was primarily due to lower oil pricing and the lack of development plans by T2S. The annual average WTI Cushing spot oil price of $65.34 per Bbl used to determine reserves as of December 31, 2025, was 13% lower than the $75.48 per Bbl used to determine reserves as of December 31, 2024. The average Henry Hub spot market gas price of $3.387 per MMbtu used to determine reserves as of December 31, 2025, was 57% higher than the $2.13 per MMbtu used to determine reserves as of December 31, 2024.
During the year ended December 31, 2024, revisions of previous estimates increased proved reserves by 15%. This was primarily due to the additional drilling locations in the Peak Victor field in Crane County, Texas, as well as the addition of waterflood reserves in the Roepke filed in Crane County, Texas. The annual average WTI Cushing and Henry Hub spot oil and natural gas price of $75.48 per Bbl and $2.13 per MMbtu used to determine reserves as of December 31, 2024, was 4% and 19% lower than the $78.22 per Bbl and $2.64 per MMbtu used to determine reserves as of December 31, 2023, respectively
During the year ended December 31, 2023, revisions of previous estimates decreased proved reserves by 39%, primarily due to the removal of certain proved undeveloped reserves due to the SEC five-year booking rule, and also due to negative price revisions related to lower oil and natural gas prices. The annual average WTI Cushing and Henry Hub spot oil and natural gas price of $78.22 per Bbl and $2.64 per MMbtu used to determine reserves as of December 31, 2024, was 17% and 59% lower than the $93.67 per Bbl and $6.36 per MMbtu used to determine reserves as of December 31, 2023, respectively.
Production.
During the year ended December 31, 2025, production decreased oil reserves by 253 MBoe.
During the year ended December 31, 2024, production decreased oil reserves by 347 MBoe.
During the year ended December 31, 2023, production decreased oil reserves by 382 MBoe.
53
Standardized Measure of Discounted Future Net Cash Flows
The following is a summary of a standardized measure of discounted future net cash flows related to the Trust’s Net Profits Interest in total proved natural gas and oil reserve quantities. Information presented is based upon valuation of proved reserves by using discounted cash flows based upon average oil and gas prices during the 12-month period prior to the fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions and severance and ad valorem taxes, if any, and economic conditions, discounted at the required rate of 10%. As the Trust is not subject to taxation at the Trust level, no provision for income taxes has been made in the following disclosure. Trust prices may differ from posted NYMEX prices due to differences in product quality and property location. The impact of changes in current prices on reserves could vary significantly from year to year. Accordingly, the information presented below should not be viewed as an estimate of the fair market value of the Trust’s oil and natural gas reserves or the costs that would be incurred to acquire equivalent reserves. A market value determination would require the analysis of additional parameters.
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves attributable to the Trust was as follows as of the dates indicated (in thousands):
|
|
December 31, |
|
|
December 31, 2024 |
|
|
December 31, |
|
|||
Future costs |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
Future net cash flows |
|
|
63,815 |
|
|
|
118,584 |
|
|
|
124,680 |
|
Discount of future net cash flows at 10% |
|
|
(32,409 |
) |
|
|
(54,139 |
) |
|
|
(59,643 |
) |
Standardized measure of discounted future net cash flows |
|
$ |
31,406 |
|
|
$ |
64,445 |
|
|
$ |
65,037 |
|
Estimates of proved oil and natural gas reserves are by their nature imprecise. Estimates of future net revenue attributable to proved reserves are sensitive to the unpredictable prices of oil and natural gas and other variables. Accordingly, under the allocation method used to derive the Trust’s quantity of proved reserves, changes in prices will result in changes in quantities of proved oil and natural gas reserves and estimated future net revenues.
The changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves attributable to the Trust for the periods indicated (in thousands):
|
|
Total |
|
|||||||||
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Balance at the beginning of the period(1) |
|
$ |
64,445 |
|
|
$ |
65,037 |
|
|
$ |
145,018 |
|
Net change in prices and production costs |
|
|
(18,449 |
) |
|
|
(11,788 |
) |
|
|
(34,008 |
) |
Net change in future development costs |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Sales of oil and natural gas, net of production costs |
|
|
(8,815 |
) |
|
|
(12,715 |
) |
|
|
(14,241 |
) |
Extensions and discoveries |
|
|
— |
|
|
|
— |
|
|
|
5,801 |
|
Purchase of reserves |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Divestiture of reserves |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Revisions of previous quantity estimates |
|
|
(14,069 |
) |
|
|
12,724 |
|
|
|
(51,231 |
) |
Previously estimated development costs incurred |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Net change in income taxes |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Accretion of discount |
|
|
6,445 |
|
|
|
6,504 |
|
|
|
14,502 |
|
Changes in timing and other |
|
|
1,849 |
|
|
|
4,683 |
|
|
|
(804 |
) |
Balance at the end of the period(1) |
|
$ |
31,406 |
|
|
$ |
64,445 |
|
|
$ |
65,037 |
|
For 2025, $3.387 per MMBtu of natural gas and $65.34 per Bbl of oil were used in determining future net revenue. These prices were based on a 12-month unweighted average of the first-day-of-the-month pricing of Henry Hub natural gas and WTI oil.
For 2024, $2.130 per MMBtu of natural gas and $75.48 per Bbl of oil were used in determining future net revenue. These prices were based on a 12-month unweighted average of the first-day-of-the-month pricing of Henry Hub natural gas and WTI oil.
For 2023, $2.637 per MMBtu of natural gas and $78.22 per Bbl of oil were used in determining future net revenue. These prices were based on a 12-month unweighted average of the first-day-of-the-month pricing of Henry Hub natural gas and WTI oil.
54
13. Quarterly Schedule of Distributable Income (Unaudited)
The following is a summary of the unaudited quarterly schedule of distributable income for the year ended December 31, 2025:
2025 |
|
Net Profits |
|
|
Distributable |
|
|
Distributable |
|
|||
First Quarter |
|
$ |
1,710,763 |
|
|
$ |
1,466,195 |
|
|
$ |
0.120517 |
|
Second Quarter |
|
|
1,545,465 |
|
|
|
1,200,518 |
|
|
|
0.098679 |
|
Third Quarter |
|
|
1,246,690 |
|
|
|
1,111,576 |
|
|
|
0.091367 |
|
Fourth Quarter |
|
|
1,056,397 |
|
|
|
934,447 |
|
|
|
0.076808 |
|
Total |
|
$ |
5,559,315 |
|
|
$ |
4,712,736 |
|
|
$ |
0.387371 |
|
14. Subsequent Events
Distributions
On January 20, 2026, the Trust declared a cash distribution of $0.019386 per Trust unit to unitholders of record as of January 30, 2026. The distribution was paid on February 13, 2026.
On February 17, 2026, the Trust declared a cash distribution of $0.010831 per Trust unit to unitholders of record as of February 27, 2025. The distribution was paid on March 13, 2026.
On March 20, 2026, the Trust declared a cash distribution of $0.002995 per Trust unit to unitholders of record as of March 31, 2026. The distribution will be paid on or about April 14, 2026.
55
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures. The Trustee conducted an evaluation of the effectiveness of the Trust’s disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(a) and 15d-15(a) as of the end of the period covered by this annual report. Based on this evaluation, the Trustee has concluded that the disclosure controls and procedures of the Trust are effective as of December 31, 2025, that the information required to be disclosed by the Trust in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and such information is accumulated and communicated, as appropriate to allow timely decisions regarding required disclosure. In its evaluation of disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on information provided by Boaz Energy.
Due to the nature of the Trust as a passive entity and in light of the contractual arrangements pursuant to which the Trust was created, including the provisions of the Trust Agreement and the Conveyance of Net Profits Interest, the Trustee’s disclosure controls and procedures related to the Trust necessarily rely on (A) information provided by Boaz Energy, including information relating to results of operations, the costs and revenues attributable to the Trust’s interests under the Conveyance and other operating and historical data, plans for future operating and capital expenditures, reserve information, information relating to projected production, and other information relating to the status and results of operations of the Underlying Properties, and (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers.
Trustee’s Annual Report on Internal Control over Financial Reporting. The information required to be furnished pursuant to this item is set forth below.
The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control-Integrated Framework (2013), the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2025.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Changes in Internal Control over Financial Reporting. There were no changes in the Trust’s internal control over financial reporting during the quarter ended December 31, 2025, that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, has not evaluated and makes no statement concerning, the internal control over financial reporting of Boaz Energy or T2S.
Item 9B. Other Information
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
56
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The Trust has no directors or executive officers. The Trustee is a corporate trustee that may only be removed and replaced by the holders of a majority of the Trust units present in person or by proxy at a meeting of such holders where a quorum is present, including Trust units held by T2S, called by either the Trustee or the holders of not less than 10% of the then outstanding Trust units.
Audit Committee and Nominating Committee
Because the Trust does not have a board of directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the Trust’s directors, officers or beneficial owners of more than ten percent of a registered class of the Trust’s equity securities to file reports of ownership and changes in ownership with the SEC and to furnish the Trust with copies of all such reports.
The Trust has no directors or officers and based solely on its review of the reports received by it, the Trust believes that during 2023, no person who was a beneficial owner of more than ten percent the Trust’s Units failed to file on a timely basis any report required by Section 16(a).
Code of Ethics
Because the Trust has no employees, it does not have its own code of ethics. Employees of the Trustee, Argent Trust Company, must comply Argent Trust Company’s standards of conduct, a copy of which will be provided to unitholders without charge, upon request made to Argent Trust Company, Trustee, 3838 Oak Lawn Ave, Suite 1720, Dallas, Texas 75219, Attention: Nancy Willis.
Item 11. Executive Compensation
The Trust does not have any executive officers, directors or employees. The Trust does not have a board of directors, and it does not have a compensation committee. Pursuant to the Trust Agreement, the Trust pays an annual administrative fee to the Trustee of $180,000 per year subject to escalation, as described in Note 7 to the financial statements included in Part II, Item 8 of this Annual Report. Administrative fees paid to the Trustee in 2025 were $215,081.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
None.
The following table sets forth certain information regarding the beneficial ownership of the Trust units as of March 26, 2026, by each person who, to the Trustee’s knowledge, beneficially owns more than 5% of the outstanding Trust units.
Name and Address of Beneficial Owner |
|
Title of Class |
|
Amount and |
|
|
Percent of |
|
||
Ustx, LLC |
|
Trust units |
|
|
4,884,861 |
|
|
|
40.2 |
% |
Pursuant to the Schedule 13D dated March 31, 2025, as filed with the SEC on April 1, 2025, Ustx, LLC reported that it was the sole record and beneficial owner of 4,884,661 Trust units (the “Ustx Units”), representing 40.2% of the outstanding Trust units, and had sole voting and dispositive power over those Trust units. Further, by virtue of various ownership and control relationships, each of the following also reported pursuant to the Schedule 13D dated March 31, 2025 and filed April 1, 2025, that it may be deemed to share voting and investment power over certain of the Ustx Units as follows: (i) T2S Permian Acquisition II LLC (“T2S”), as the
57
owner of 100% of the limited liability company interests of Ustx, LLC, may be deemed to indirectly beneficially own the 4, 884,661 Ustx Units; (ii) Greenway Boaz Investments LLC, by virtue of owning approximately 50.2% of the limited liability company interests of T2S, may be deemed to share voting and investment power over 2,452,503 of the Ustx Units (20.1%); (iii) Greenway Boaz Management, LLC, the manager of Greenway Boaz Investments, LLC, may be deemed to share voting and investment power over 2,452,503 of the Ustx Units (20.1%); (iv) EnRes Capital Fund I, LP, by virtue of owning approximately 25.1% of the limited liability company interests in T2S, may be deemed to share voting and investment power over 1,223,773 of the Ustx Units (10.1%); (v) EnRes Capital BZ, LP, by virtue of owning 22.7% of the limited liability company interests in T2S, may be deemed to share voting and investment power over 1,107,908 of the Ustx Units (9.1%); and (vi) EnRes Capital Fund I GP, LLC, as the general partner of each of EnRes Capital Fund I, LP, and EnRes Capital BZ, LP, may be deemed to share voting and investment power over the combined 2,331,640 Ustx Units (19.2%) held by EnRes Capital Fund I, LP (1,223,733 Ustx Units) and EnRes Capital BZ, LP (1,108,907 Ustx Units).
As of March 28, 2026, Argent Trust Company has no beneficial ownership of or power to vote any of the outstanding Trust units.
On January 13, 2025, the Trust announced that Boaz Energy and its affiliate Boaz Energy II Royalty, LLC entered into a Purchase and Sale Agreement on January 10, 2025 with T2S Permian Acquisitions II, LLC (the “Buyer”), with respect to the Underlying Properties.
Boaz Energy informed the Trust that, pursuant to the Purchase and Sale Agreement, Boaz sold and conveyed (a) to the Buyer, all of Boaz Energy’s right, title and interest in and to the Underlying Properties (which shall remain burdened by the Net Profits Interest and subject to the Conveyance); and (b) to Ustx, LLC, an affiliate of Buyer, all of Boaz Energy’s 4,884,861 Trust units representing beneficial interests in the Trust (the “Boaz Trust Units”).
Boaz Energy reported that the Purchase and Sale Agreement contained customary conditions to the parties’ obligations to consummate the (the “Closing”). The Closing occurred on March 31, 2025. From and after the Closing, the Buyer owns the Underlying Properties (burdened by the Trust’s Net Profits Interest and subject to the Conveyance), Ustx, LLC owns the Boaz Trust Units, and the Buyer has become the operator of the Underlying Properties.
Item 13. Certain Relationships and Related Transactions and Director Independence
Trustee Administrative Fee. In 2025, the Trust paid the Trustee $215,081 in administrative fees. In 2025, the Trustee fee will be approximately $217,232. Under the terms of the Trust Agreement, the Trust pays an annual administrative fee of $180,000 to the Trustee, subject to annual escalation as described in Note 7 to the financial statements included in Part II, Item 8 of this Annual Report.
Registration Rights Agreement. The Trust and Boaz Energy are parties to a Registration Rights Agreement whereby Boaz Energy, its affiliates and certain permitted transferees holding registrable Trust units are entitled, upon receipt by the Trustee of written notice from holders of a majority of the then outstanding registrable Trust units, to demand that the Trust effect the registration of the registrable Trust units. The holders of the registrable Trust units are entitled to demand a maximum of five such registrations. In connection with the preparation and filing of any registration statement, Boaz Energy will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the Trust, which will be borne by the Trust. Any underwriting discounts and commissions will be borne by the seller of the Trust units. The foregoing description of the Registration Rights Agreement is qualified in its entirety by the terms of the Registration Rights Agreement, a copy of which is incorporated by reference as an exhibit to this Form 10-K.
Director Independence
The Trust does not have a board of directors. Further, the Trust relies on an exemption from the director independence requirements of the New York Stock Exchange set forth in Rule 10A-3(c)(7) under the Exchange Act, applicable to listed issuers organized as trusts that do not have a board of directors.
Item 14. Principal Accounting Fees and Services
58
The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustee.
The following table presents fees for professional audit services rendered by Weaver and Tidwell, L.L.P. for the audit of the Trust’s financial statements for 2025, 2024, and 2023 and fees billed for other services rendered by Weaver and Tidwell, L.L.P.
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Audit fees(1) |
|
$ |
141,962 |
|
|
$ |
140,356 |
|
|
$ |
124,008 |
|
Audit-related fees |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Tax fees |
|
|
— |
|
|
|
— |
|
|
|
— |
|
All other fees |
|
|
— |
|
|
|
— |
|
|
|
— |
|
Total fees |
|
$ |
141,962 |
|
|
$ |
140,356 |
|
|
$ |
124,008 |
|
As referenced in Item 10 above, the Trust has no audit committee, and as a result, has no audit committee pre-approval policy with respect to fees paid to Weaver and Tidwell, L.L.P.
59
PART IV
Item 15. Exhibits and Financial Statement Schedules
The following documents are filed as a part of this Annual Report on Form 10-K:
Included in Part II. Item 8 of this Annual Report on Form 10-K:
Report of Independent Registered Public Accounting Firm
Statements of Assets, Liabilities and Trust Corpus
Statements of Distributable Income
Statements of Changes in Trust Corpus
Notes to Consolidated Financial Statements
Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.
The exhibits below are filed or furnished herewith or incorporated herein by reference.
Exhibit |
|
Description of Exhibit |
3.1* |
|
|
3.2* |
|
|
3.3* |
|
|
3.4* |
|
|
4.1* |
|
|
10.1* |
|
|
10.2* |
|
|
23.1 |
|
|
31.1 |
|
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
32.1 |
|
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
97 |
|
|
99.1 |
|
* Asterisk indicates exhibit previously filed with the SEC and incorporated herein by reference.
Item 16. Form 10-K Summary
Not Applicable
60
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PERMROCK ROYALTY TRUST
By: |
Argent Trust Company, as Trustee |
|
|
By: |
Nancy Willis |
|
|
|
Nancy Willis |
|
Director of Royalty Trust Services |
|
Date: March 27, 2026 |
The registrant, PermRock Royalty Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available, and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that any such function exists pursuant to the terms of the Trust Agreement under which it serves.
61
Cawley, Gillespie & Associates, Inc.
petroleum consultants
6500 RIVER PLACE BLVD, SUITE 3-200 306 WEST SEVENTH STREET, SUITE 302 1000 LOUISIANA STREET, SUITE 1900
AUSTIN, TEXAS 78730-1111 FORT WORTH, TEXAS 76102-4987 HOUSTON, TEXAS 77002-5008
512-249-7000 817- 336-2461 713-651-9944
www.cgaus.com
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We hereby consent to the references to our firm in the form and context in which they are included in this Annual Report on Form 10-K (including any amendments thereto) filed by PermRock Royalty Trust (“Annual Report”), to our estimates of reserves and value of reserves and our report on reserves as of December 31, 2023, December 31, 2024 and December 31, 2025 of the underlying properties and net profits interest owned by PermRock Royalty Trust and to the inclusion of our report dated March 6, 2026 as an Exhibit to the Annual Report.
|
CAWLEY, GILLESPIE & ASSOCIATES, INC. |
|
|||
|
Texas Registered Engineering Firm F-693
|
|
|||
|
J. Zane Meekins, P. E. |
|
|||
|
Executive Vice President |
|
|||
|
|
||||
|
|
||||
Fort Worth, Texas
March 26, 2026
EXHIBIT 31.1
Certification Pursuant to Rule 13a-14(a) and Rule 15d-14(a)
of the Securities Exchange Act of 1934, as amended
I, Nancy Willis, certify that:
In giving the certifications in paragraphs 4 and 5 above, I have relied to the extent I consider reasonable on information provided to me by Boaz Energy II, LLC.
Date: March 27, 2026 |
|
By: |
|
/s/ Nancy Willis |
|
|
|
|
Nancy Willis Director of Royalty Trust Services |
EXHIBIT 32.1
Certification Under Section 906
of the Sarbanes-Oxley Act of 2002, 18 U.S.C. § 1350
In connection with the Annual Report of PermRock Royalty Trust (the “Trust”) on Form 10-K for the period ended December 31, 2025, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, not in its individual capacity but solely as the Trustee of the Trust, certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to her knowledge:
|
|
|
|
|
|
|
|
|
|
ARGENT TRUST COMPANY, TRUSTEE FOR PERMROCK ROYALTY TRUST |
|
|
|
|
|
||
|
|
|
|
||
Date: March 27, 2026 |
|
By: |
|
/s/ Nancy Willis |
|
|
|
|
|
Nancy Willis |
|
|
|
|
|
Director of Royalty Trust Services |
|
|
|
|
|
Argent Trust Company |
|
A signed original of this written statement required by Section 906 has been provided to PermRock Royalty Trust and will be retained by PermRock Royalty Trust and furnished to the Securities and Exchange Commission or its Staff upon request.
Exhibit 97
PermRock Royalty Trust
Executive Officer Compensation Recovery Policy
(As adopted November 22, 2023)
This Executive Officer Compensation Recovery Policy (this “Policy”) of PermRock Royalty Trust (the “Trust”) is hereby adopted as of November 22, 2023 (the “Effective Date”) by Argent Trust Company (the “Trustee”) in compliance with Section 10D of the Securities Exchange Act of 1934 and Section 303A.14 of the New York Stock Exchange (the “NYSE”) Listed Company Manual (“Section 303A.14”). Certain terms shall have the meanings set forth in “Section 3. Definitions” below.
Section 1. Recovery Requirement
Subject to Section 4 of this Policy, in the event the Trust is required to prepare an Accounting Restatement, then the Trustee hereby directs the Trust, to the fullest extent permitted by governing law, to recover from each Executive Officer the amount received by an Executive Officer, if any, of Erroneously Awarded Compensation, with such recovery occurring reasonably promptly after the Restatement Date relating to such Accounting Restatement. An Executive Officer shall be deemed to have “received” Incentive-Based Compensation in the Trust’s fiscal period during which the Financial Reporting Measure specified in the Incentive-Based Compensation award is attained, even if the payment or grant of the Incentive-Based Compensation occurs after the end of that fiscal period.
The Trustee may effect recovery in any manner consistent with applicable law including, but not limited to, (a) seeking reimbursement of all or part of any Erroneously Awarded Compensation previously received by an Executive Officer and to the extent that the Executive Officer does not reimburse such Erroneously Awarded Compensation, suing and enforcing recovery against the Executive Officer for repayment of the Erroneously Awarded Compensation, together with any expenses (including, without limitation, legal fees) incurred by the Trust in enforcing such recovery, (b) cancelling prior grants of Incentive-Based Compensation, whether vested or unvested, restricted or deferred, or paid or unpaid, and through the forfeiture of previously vested equity awards, (c) cancelling or setting-off against planned future grants of Incentive-Based Compensation, (d) deducting all or any portion of such Erroneously Awarded Compensation from any other remuneration payable by the Trust to such Executive Officer, and (e) any other method authorized by applicable law or contract.
The Trust’s right to recovery pursuant to this Policy is not dependent on if or when the Accounting Restatement is filed with the Securities and Exchange Commission.
Section 2. Incentive-Based Compensation Subject to this Policy.
This Policy applies to all Incentive-Based Compensation received by each Executive Officer on or after the Effective Date:
This Policy shall apply and govern Incentive-Based Compensation received by any Executive Officer, notwithstanding any contrary or supplemental term or condition in any document, plan or agreement including without limitation any employment contract, indemnification agreement, equity agreement, or equity plan document.
Section 3. Definitions:
For purposes of this Policy, the following terms have the meanings set forth below:
Section 4. Exceptions to Recovery
Notwithstanding the foregoing, the Trust is not required to recover Erroneously Awarded Compensation to the extent that the Trustee has made a determination that recovery would be impracticable and that:
Section 5. No Right to Indemnification or Insurance
The Trust shall not indemnify any Executive Officer against the loss of Erroneously Awarded Compensation or losses arising from any claims relating to the Trust’s enforcement of this Policy. In addition, the Trust shall not pay, or reimburse any Executive Officer for, any premiums for a third-party insurance policy purchased by the Executive Officer or any other party that would fund any of the Executive Officer’s potential recovery obligations under this Policy.
Section 6. Award Agreements and Plan Documents
The Trustee further directs the Trust to include clawback language in each of the Trust’s incentive compensation plans such that each individual who receives Incentive-Based Compensation under those plans understands and agrees that all or any portion of such Incentive-Based Compensation may be subject to recovery by the Trust, and such individual may be required to repay all or any portion of such Incentive-Based Compensation, if (i) recovery of such Incentive-Based Compensation is required by this Policy, (ii) such Incentive-Based Compensation is determined to be based on materially inaccurate financial and/or performance information (which includes, but is not limited to, statements of earnings, revenues or gains); or (iii) repayment of such Incentive-Based Compensation is required by applicable federal or state securities and/or banking laws.
Section 7. Interpretation and Amendment of this Policy
The Trustee, in its discretion, shall have the sole authority to interpret and make any determinations regarding this Policy. Any interpretation, determination, or other action made or taken by the Trustee shall be final, binding, and conclusive on all interested parties. The determination of the Trustee need not be uniform with respect to one or more officers. The Trustee may amend this Policy from time to time in its discretion and shall amend the Policy to comply with applicable law or with any rules or standards adopted by the NYSE or any national securities exchange on which the Trust’s securities are then listed. The Trustee may terminate this Policy at any time.
Any employees of the Trustee who assist in the administration of this Policy shall not be personally liable for any action, determination or interpretation made with respect to this Policy and shall be fully indemnified by the Trust to the fullest extent under applicable law and Trust policy with respect to any such action, determination or interpretation. The foregoing sentence shall not limit any other rights to indemnification of the employees of the Trustee under applicable law or Trust policy.
Section 8. Other Recoupment Rights.
The Trust intends that this Policy will be applied to the fullest extent of the law. Any right of recoupment under this Policy is in addition to, and not in lieu of, any other remedies or rights of recoupment that may be available to the Trust pursuant to the terms of any similar policy in any employment agreement, equity award agreement, or similar agreement and any other remedies available to the Trust under applicable law. Without by implication limiting the foregoing, following a restatement of the Trust’s financial statements, the Trust also shall be entitled to recover any compensation received by the Chief Executive Officer and Chief Financial Officer that is required to be recovered by Section 304 of the Sarbanes-Oxley Act of 2002.
Cawley, Gillespie & Associates, Inc.
petroleum consultants
6500 RIVER PLACE BLVD, SUITE 3-200 306 WEST SEVENTH STREET, SUITE 302 1000 LOUISIANA STREET, SUITE 1900
AUSTIN, TEXAS 78730-1111 FORT WORTH, TEXAS 76102-4987 HOUSTON, TEXAS 77002-5008
512-249-7000 817- 336-2461 713-651-9944
www.cgaus.com
March 6, 2026
Ms. Nancy Willis
PermRock Royalty Trust
Argent Trust Company, Trustee
3838 Oak Lawn Avenue, Suite 1720
Dallas TX 75219
Re: Evaluation Summary
PermRock Royalty Trust Net Profits Interest
Proved Reserves
Various Counties, Texas
As of December 31, 2025
Dear Ms. Willis:
As requested, we are submitting our estimates of proved reserves and our forecasts of the resulting economics attributable to the above captioned interests. We completed our evaluation on March 6, 2026. It is our understanding that the proved reserves estimated in this report constitute 100% of all proved reserves owned by PermRock Royalty Trust. This report has been prepared for use in filings with the Securities and Exchange Commission. In our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.
Composite reserve estimates and economic forecasts are summarized below:
|
|
|
Proved |
|
|
|
Proved |
Developed |
|
|
|
Developed |
Non- |
|
|
|
Producing |
Producing |
Proved |
Net Reserves |
|
|
|
|
Oil |
– Mbbl |
860.9 |
114.5 |
975.4 |
Gas |
– MMcf |
748.6 |
0.0 |
748.6 |
Revenue |
|
|
|
|
Oil |
– M$ |
54,494.3 |
7,250.1 |
61,744.4 |
Gas |
– M$ |
2,071.3 |
0.0 |
2,071.3 |
Severance and |
|
|
|
|
Ad Valorem Taxes |
– M$ |
0.0 |
0.0 |
0.0 |
Operating Expenses |
– M$ |
0.0 |
0.0 |
0.0 |
Investments |
– M$ |
0.0 |
0.0 |
0.0 |
Net Operating Income (BFIT) |
– M$ |
56,565.6 |
7,250.1 |
63,815.7 |
Discounted @ 10% |
– M$ |
28,158.3 |
3,248.1 |
31,406.4 |
In accordance with the Securities and Exchange Commission guidelines, the operating income (BFIT) has been discounted at an annual rate of 10% to determine its “present worth”. The
Evaluation Summary
PermRock Royalty Trust Net Profits Interests
As of December 31, 2025
Page 2 of NUMPAGES 6
discounted value shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc.
The annual average Henry Hub spot market gas price of $3.387 per MMBtu and the annual average WTI Cushing spot oil price of $65.34 per barrel were used in this report. In accordance with the Securities and Exchange Commission guidelines, these prices are determined as an unweighted arithmetic average of the first-day-of-the-month price for 12 months prior to the effective date of the evaluation. The oil and gas prices were held constant and were adjusted to wellhead prices by property based on data supplied by T2S Permian Acquisition II LLC (“T2S”). Deductions were applied to the net gas volumes for fuel and shrinkage. The adjusted volume-weighted average product prices over the life of the properties are $63.30 per barrel of oil and $2.77 per Mcf of gas.
Operating expenses and capital costs for the underlying properties were supplied by T2S and reviewed for reasonableness. Severance tax rates were specified based on published rates. Ad valorem taxes were forecast as 2.8% of net revenue. As per the Securities and Exchange Commission guidelines, neither expenses nor investments were escalated. The cost of plugging and the salvage value of equipment have not been considered.
All proved reserve classifications conform to criteria of the Securities and Exchange Commission as set forth in Rules 4-10 of Regulation S-X and defined in pages 1 and 2 of the Appendix. The proved developed non-producing reserves include those associated with behind-pipe zones, workovers and proved waterflood projects with current water injection and very minor remaining capital expenditures. The reserves and economics are predicated on the regulatory agency classifications, rules, policies, laws, taxes and royalties in effect on the effective date except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions have not been considered. The reserves were estimated using a combination of the production performance, volumetric and analogy methods, in each case as we considered to be appropriate and necessary to establish the conclusions set forth herein. The methods employed in estimating reserves are described in page 3 of the Appendix. All reserve estimates represent our best judgment based on data available at the time of preparation and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.
The reserve estimates were based on interpretations of factual data furnished by T2S and PermRock Royalty Trust. Ownership interests were supplied by and were accepted as furnished. To some extent, information from public records has been used to check and/or supplement these data. The basic engineering and geological data were utilized subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. An on-site inspection of these properties has not been made nor have the wells been tested by Cawley, Gillespie & Associates, Inc.
Cawley, Gillespie & Associates, Inc. is independent with respect to PermRock Royalty Trust as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers (“SPE Standards”). Neither Cawley, Gillespie & Associates, Inc. nor any of its employees has any interest in the subject
Evaluation Summary
PermRock Royalty Trust Net Profits Interests
As of December 31, 2025
Page 3 of NUMPAGES 6
properties. Neither the employment to make this study nor the compensation is contingent on the results of our work or the future production rates for the subject properties.
Our work-papers and related data are available for inspection and review by authorized parties.
Respectfully submitted,
|
J. Zane Meekins, P.E.
Executive Vice President
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm F-693
JZM:ptn
APPENDIX
Reserve Definitions and Classifications
|
|
The Securities and Exchange Commission, in SX Reg. 210 .4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adher ence to the following definitions of oil and gas reserves:
"(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
"(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
"(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
"(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
"(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
"(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
"(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
“(i) 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; and
“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
"(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
"(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
"(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that "a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K." This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”
"(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”
APPENDIX
Methods Employed in the Estimation of Reserves
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The four methods customarily employed in the estimation of reserves are (1) Production Performance, (2) Material Balance, (3) Volumetric and (4) Analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.
Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.
A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:
Production Performance. This method employs graphical anal yses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increas ing as production history accumulates.
Material Balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which make this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the com plexity of the reservoir and the quality and quantity of data available.
Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric meth od is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncompli cated.
Analogy. This method, which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. The analogy method may also be applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained in this manner are generally considered to have a relatively low degree of accuracy.
Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.