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


☐		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 1-10982

Cross Timbers Royalty Trust

(Exact name of registrant as specified in its charter)


Texas		75-6415930
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

c/o The Corporate Trustee:
Argent Trust Company
3838 Oak Lawn Ave, Suite 1720
Dallas, Texas 75219-4518
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code (at the office of the Corporate Trustee) (855) 588-7839

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading symbol	Name of each exchange on which registered
Units of Beneficial Interest	CRT	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, a 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	☐	Accelerated filer	☐
Non-accelerated filer		Smaller reporting company	
		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 Act). Yes  No 

The aggregate market value of units of beneficial interest held by non-affiliates of the registrant at June 30, 2025 (the last business day of the registrant’s most recently completed second fiscal quarter) was approximately $59.3 million.

The number of units of beneficial interest outstanding as of March 27, 2026, was 6,000,000.

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CROSS TIMBERS ROYALTY TRUST

2025 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS


		Page
Glossary of Terms		1

	Part I

Item 1.	Business	2
Item 1A.	Risk Factors	3
Item 1B.	Unresolved Staff Comments	8
Item 1C.	Cybersecurity	8
Item 2.	Properties	9
Item 3.	Legal Proceedings	16
Item 4.	Mine Safety Disclosures	16


	Part II

Item 5.	Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units	16
Item 6.	[Reserved]	16
Item 7.	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	22
Item 8.	Financial Statements and Supplementary Data	22
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	31
Item 9A.	Controls and Procedures	31
Item 9B.	Other Information	31
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	32

	Part III

Item 10.	Directors, Executive Officers and Corporate Governance	32
Item 11.	Executive Compensation	32
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	32
Item 13.	Certain Relationships and Related Transactions, and Director Independence	32
Item 14.	Principal Accountant Fees and Services	33

	Part IV

Item 15.	Exhibits and Financial Statement Schedules	33

Signatures		35

Table of Contents

Glossary of Terms

The following is a glossary of certain defined terms used in this Annual Report on Form 10-K.

GLOSSARY


Bbl		Barrel (of oil)
Bcf		Billion cubic feet (of natural gas)
BOE		Barrel of oil equivalent
gross acres or gross wells		The total acres or wells, as the case may be, in which a working interest is owned
Mcf		Thousand cubic feet (of natural gas)
MMBtu		One million British Thermal Units, a common energy measurement
net acres or net wells		The sum of the fractional working interests owned in gross acres or wells, as the case may be
net proceeds		Gross proceeds received by XTO Energy from sale of production from the underlying properties, less applicable costs, as defined in the net profits interest conveyances
net profits income		Net proceeds multiplied by the applicable net profits percentage of 75% or 90%, which is paid to the Trust by XTO Energy. “Net profits income” is referred to as “royalty income” for income tax purposes.
net profits interest		An interest in an oil and gas property measured by net profits from the sale of production, rather than a specific portion of production. The following defined net profits interests were conveyed to the Trust from the underlying properties:
		90% net profits interests - interests that entitle the Trust to receive 90% of the net proceeds from the underlying properties that are substantially all royalty or overriding royalty interests in Texas, Oklahoma and New Mexico
		75% net profits interests - interests that entitle the Trust to receive 75% of the net proceeds from the underlying properties that are working interests in Texas and Oklahoma
royalty interest (and overriding royalty interest)		A non-operating interest in an oil and gas property that provides the owner a specified share of production without any production expense or development costs
underlying properties		XTO Energy’s interest in certain oil and gas properties from which the net profits interests were conveyed. The underlying properties include royalty and overriding royalty interests in producing and nonproducing properties in Texas, Oklahoma and New Mexico, and working interests in producing properties located in Texas and Oklahoma.
working interest		An operating interest in an oil and gas property that provides the owner a specified share of production that is subject to all production expense and development costs

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PART I

ITEM 1. BUSINESS

Cross Timbers Royalty Trust (the “Trust”) is an express trust created under the laws of Texas pursuant to the Cross Timbers Royalty Trust Indenture entered into on February 12, 1991, between predecessors of XTO Energy Inc. (formerly known as Cross Timbers Oil Company and, hereafter, “XTO Energy”), as grantors, and NCNB Texas National Bank, as Trustee. The current trustee of the Trust is Argent Trust Company, a Tennessee chartered trust company (“Argent”). Effective December 30, 2022, Simmons Bank resigned as trustee, and Argent was appointed as the successor trustee.

The defined term “Trustee” as used herein shall refer to Simmons Bank for periods from February 20, 2018, through December 29, 2022, and shall refer to Argent for periods on and after December 30, 2022.

The principal office of the Trust is 3838 Oak Lawn Ave, Suite 1720, Dallas, Texas 75219. The telephone number of the Trust is 1-855-588-7839. The Trust’s internet website is www.crt-crosstimbers.com. We make available free of charge, through our website, our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. These reports are accessible through our internet website as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. Information on our website is not incorporated into this report.

On February 12, 1991, the predecessors of XTO Energy conveyed defined net profits interests to the Trust under five separate conveyances:


1.		one in each of the states of Texas, Oklahoma and New Mexico, to convey a 90% defined net profits interest carved out of substantially all royalty and overriding royalty interests owned by the predecessors in those states, and
2.		one in each of the states of Texas and Oklahoma, to convey a 75% defined net profits interest carved out of specific working interests owned by the predecessors in those states.

The conveyance of these net profits interests was effective for production from October 1, 1990. The net profits interests and the underlying properties are further described under Item 2. Properties.

In exchange for the net profits interests conveyed to the Trust, the predecessors of XTO Energy received 6,000,000 units of beneficial interest of the Trust. Predecessors of XTO Energy distributed units to their owners in February 1991 and November 1992, and in February 1992, sold units in the Trust’s initial public offering. Units are listed and traded on the New York Stock Exchange under the symbol “CRT”. XTO Energy currently is not a unitholder of the Trust.

On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation (“ExxonMobil”).

Under the terms of each of the five conveyances, the Trust receives net profits income from the net profits interests generally on the last business day of each month. Net profits income is determined by XTO Energy by multiplying the net profit percentage (90% or 75%) times net proceeds from the underlying properties for each conveyance during the previous month. Net proceeds are the gross proceeds received from the sale of production, less “production costs,” as defined in the conveyances. For the 90% net profits interests and the 75% net profits interests, production costs generally include applicable property taxes, transportation, marketing and other charges. For the 75% net profits interests, production costs also include capital and operating costs paid (e.g., drilling, production and other direct costs of owning and operating the property), monthly overhead charged by operators of the underlying properties, and a monthly overhead XTO Energy deducts as reimbursement for costs associated with monitoring these interests. If production costs exceed gross proceeds for any conveyance, this excess is carried forward to future monthly computations of net proceeds until the excess costs (plus interest accrued as specified in the conveyances) are completely recovered. Excess production costs and related accrued interest from one conveyance cannot be used to reduce net proceeds from any other conveyance. For further information on excess costs, see Note 7 to Financial Statements under Item 8. Financial Statements and Supplementary Data.

The Trust is not liable for any production costs or liabilities attributable to the underlying properties. If at any time the Trust receives net profits income in excess of the amount due, the Trust is not obligated to return such overpayment, but future net profits income payable to the Trust will be reduced until the overpayment, plus interest at the prime rate, is recovered.

As a working interest owner, XTO Energy can generally decline participation in any operation and allow consenting parties to conduct such operations, as provided under the operating agreements. XTO Energy also can assign, sell, or otherwise transfer its interest in the underlying properties, subject to the net profits interests, or can abandon an underlying property that is a working interest if it is incapable of producing in paying quantities, as determined by XTO Energy.

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To the extent allowed, XTO Energy is responsible for marketing its production from the underlying properties under existing sales contracts or new arrangements on the best terms reasonably obtainable in the circumstances.

Net profits income received by the Trust on or before the last business day of the month is generally attributable to oil production two months prior and gas production three months prior. The monthly distribution amount to unitholders is determined by:


Adding -
1.	net profits income received;
2.	estimated interest income to be received on the monthly distribution amount, including an adjustment for the difference between the estimated and actual interest received for the prior monthly distribution amount;
3.	cash available as a result of reduction of cash reserves; and
4.	other cash receipts; then
Subtracting -
1.	liabilities paid; and
2.	the reduction in cash available due to establishment of or increase in any cash reserve.

The monthly distribution amount is distributed to unitholders of record within ten business days after the monthly record date. The monthly record date is generally the last business day of the month. The Trustee calculates the monthly distribution amount and announces the distribution per unit at least ten days prior to the monthly record date.

The Trustee may establish cash reserves for contingencies. Cash held for such reserves, as well as for pending payment of the monthly distribution amount, may be invested in federal obligations or certificates of deposit of major banks.

The Trustee’s function is to collect the net profits income from the net profits interests, to pay all Trust expenses, and to pay the monthly distribution amount to unitholders. The Trustee’s powers are specified by the terms of the Trust indenture. The Trust cannot engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments. The Trust has no employees since all administrative functions are performed by the Trustee.

Approximately 51 percent of the net profits income received by the Trust during 2025 was attributable to natural gas, as well as 66 percent of the Trust’s estimated future net cash flows from proved reserves at December 31, 2025 (based on estimated future net cash flows using 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period). There is generally a greater demand for gas during the winter. Otherwise, Trust income is not subject to seasonal factors, nor dependent upon patents, licenses, franchises, or concessions. The Trust conducts no research activities.

The oil and gas industry is highly competitive in all its phases. Operators of the properties in which the Trust holds interests encounter competition from other oil and gas companies and from individual producers and operators. Oil and natural gas are commodities, for which market prices are determined by external supply and demand factors. Current market conditions are not necessarily indicative of future conditions.

ITEM 1A. RISK FACTORS

The following factors could cause actual results to differ materially from those contained in forward-looking statements made in this report and presented elsewhere by the Trustee from time to time. Such factors may have a material adverse effect upon the Trust’s financial condition, distributable income and changes in trust corpus.

The following discussion of risk factors should be read in conjunction with the financial statements and related notes included under Item 8. Financial Statements and Supplementary Data. Because of these and other factors, past financial performance should not be considered an indication of future performance.

The market price for the Trust units may not reflect the value of the net profits interests held by the Trust.

The public trading price for the Trust units tends to be tied to the recent and expected levels of cash distributions on the Trust units. The amounts available for distribution by the Trust vary in response to numerous factors outside the control of the Trust or XTO Energy, including prevailing prices for oil and natural gas produced from the underlying properties. The market price of the Trust units is not necessarily indicative of the value that the Trust would realize if the net profits interests were sold to a third-party buyer. In addition, such market price is not necessarily reflective of the fact that, since the assets of the Trust are depleting assets, a portion of each cash distribution paid on the Trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. There is no guarantee that distributions made to a unitholder over the life of these depleting assets will equal or exceed the purchase price paid by the unitholder.

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Current and future oil and natural gas prices fluctuate due to a number of uncontrollable factors, and any decline will adversely affect the net proceeds payable to the Trust and Trust distributions.

The Trust’s monthly cash distributions are highly dependent upon the prices realized from the sale of natural gas and oil. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and XTO Energy. Factors that contribute to price fluctuations include instability in oil-producing regions, worldwide economic conditions, weather conditions, trade barriers, tariffs, political instability, public health concerns, the supply of domestic and foreign oil, natural gas and natural gas liquids, consumer demand, the price and availability of alternative fuels, the proximity to, and capacity of, transportation facilities and the effect of worldwide energy conservation measures. Moreover, government regulations, such as regulation of natural gas transportation and price controls, environmental regulations, production restrictions, trade barriers, or tariffs, can affect product prices. Oil and natural gas prices have fluctuated wildly over the recent past and may vary significantly from period to period. Further, a significant decline in current oil or natural gas prices or lower anticipated long-term prices could have a material adverse effect on the amount of oil and natural gas that is economic to produce, Trust net profits (and therefore cash available for distribution to unitholders) and proved reserves attributable to the Trust’s interests. Adjustments impacting volume or value could also impact the reported natural gas and oil prices. The volatility of energy prices reduces the predictability of future cash distributions to Trust unitholders.

Higher production expense and/or development costs, without concurrent increases in revenue, will directly decrease the net proceeds payable to the Trust from the properties underlying the 75% net profits interests.

Production expense and development costs are deducted in the calculation of the Trust’s share of net proceeds from properties underlying the 75% net profits interests. Accordingly, higher or lower production expense and development costs, without concurrent changes in revenue, will directly decrease or increase the amount received by the Trust for its 75% net profits interests. If development costs and production expense for properties underlying the 75% net profits in a particular state exceed the production proceeds from the properties (as was the case with respect to the properties underlying the Texas working interests for all of 2024 and 2025; and with respect to the properties underlying the Oklahoma working interests for the 2024 distribution months of February through June and the 2025 distribution months of June, July, August and October), the Trust will not receive net profits income for those properties until future net proceeds from production in that state exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs.

Government action, policies or regulations designed to discourage production, reduce demand for, or promote alternatives to oil and natural gas could impact the price of oil and natural gas produced on the properties underlying the Trust’s net profits interests, directly as intended or through unintended consequences.

Governments around the world are considering actions intended to reduce greenhouse gas emissions by decreasing both the supply of and the demand for oil and natural gas products or promoting alternatives. These include the adoption of cap-and-trade regimes, carbon taxes, trade tariffs, minimum renewable usage requirements, restrictive permitting, increased mileage and other efficiency standards, mandates for sales of electric vehicles, mandates for use of specific fuels or technologies, and other incentives or mandates designed to support transitioning to lower-emission energy sources. Political and other actors and their agents also increasingly seek to advance sustainability objectives indirectly, such as by seeking to reduce the availability or increase the cost of financing and investment in the oil and gas sector. Depending on how policies are formulated and applied, such policies could impact the ability and costs of the operators of the properties underlying the Trust’s net profits interests to supply products, demand for their products, or the competitiveness of hydrocarbon-based products, which in turn, could reduce net proceeds to the Trust. Any policy that increases the costs for operators of the properties underlying the net profits interests or lowers market prices could have a material impact on the distributable income of the Trust.

War, terrorism, geopolitical hostilities, and other military actions or political instability could adversely affect Trust distributions or the market price of the Trust units.

There are a number of national and international events that could cause instability in global financial and energy markets. War, terrorist attacks and the threat of war or terrorist attacks, whether domestic or foreign, as well as other military or similar actions taken in response, impact the demand for and price of oil and natural gas in unpredictable ways, including increasing volatility in pricing. Actual or threatened acts of war, terrorism and other geopolitical hostilities could adversely affect Trust distributions or the market price of the Trust units in unpredictable ways, including through the disruption of fuel 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 an event.

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Proved reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions could cause the quantities and net present value of the reserves to be overstated.

Estimating proved oil and gas reserves is inherently uncertain. Petroleum engineers consider many factors and make assumptions in estimating reserves and future net cash flows. Those factors and assumptions include historical production from the area compared with production rates from similar producing areas, the effects of governmental regulation, assumptions about future commodity prices, production expense and development costs, taxes and capital expenditures, the availability of enhanced recovery techniques and relationships with landowners, working interest partners, pipeline companies and others. Lower oil and gas prices generally cause lower estimates of proved reserves. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variances could be material. Because the Trust owns net profits interests, it does not own a specific percentage of the oil and gas reserves. Estimated proved reserves for the net profits interests are based on estimates of reserves for the underlying properties and an allocation method that considers estimated future net proceeds and oil and gas prices. Because Trust reserve quantities are determined using an allocation formula, increases or decreases in oil and gas prices can significantly affect estimated reserves of the net profits interests.

Operational risks and hazards associated with the development and operations of the underlying properties may decrease Trust distributions.

There are operational risks and hazards associated with the production and transportation of oil and natural gas, including without limitation, natural disasters, blowouts, explosions, fires, leakage of oil or natural gas, releases of other hazardous materials, mechanical failures, cratering, and pollution. Any of these or similar occurrences could result in the interruption or cessation of operations, personal injury or loss of life, property damage, damage to productive formations or equipment, damage to the environment or natural resources, or cleanup obligations. The operation of oil and gas properties is also subject to various laws and regulations. Non-compliance with such laws and regulations could subject the operator to additional costs, sanctions or liabilities. The uninsured costs resulting from any of the above or similar occurrences could be deducted as a production expense or development cost in calculating the net proceeds payable to the Trust from properties underlying the 75% net profits interests, and would therefore reduce Trust distributions by the amount of such uninsured costs.

The Trust may be subject to attempted cybersecurity disruptions from a variety of sources including state-sponsored actors.

XTO Energy’s defensive preparedness includes multi-layered technological capabilities designed to prevent and detect cybersecurity disruptions; non-technological measures such as threat information sharing with governmental and industry groups; internal training and awareness campaigns including routine testing of employee awareness and business preparedness for response and recovery. The Trustee also 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 banking regulations and 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. If the measures taken to protect against cybersecurity disruptions prove to be insufficient or if proprietary data is otherwise not protected, XTO Energy, the Trustee or customers, employees, or third parties could be adversely affected. The Trust has limited ability to influence third parties, including our partners, suppliers, and service providers (including providers of cloud-hosting services for our data or applications), to implement strong cybersecurity controls and is exposed to potential harm from cybersecurity events that may affect their operations. 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 our business operations. We could incur significant costs to remedy the effects of a major cybersecurity disruption in addition to costs in connection with resulting regulatory actions, litigation, or reputational harm.

Future net profits 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, which the Trustee believes limits the Trust’s risk from exposure to credit markets. The Trust’s future net profits, however, may be subject to risks relating to the creditworthiness of the operators of the underlying properties and other purchasers of crude oil and natural gas produced from the underlying properties. This creditworthiness may be impacted by the price of crude oil and natural gas.

Trust unitholders and the Trustee have no influence over the operations on, or future development of, the underlying properties.

Because XTO Energy does not operate most of the underlying properties, it is unable to significantly influence the operations or future development of the underlying properties. Neither the Trustee nor the Trust unitholders can influence or control the operation or future development of the underlying properties. The failure of an operator to conduct its operations or discharge its obligations in a proper manner could have an adverse effect on the net proceeds payable to the Trust. Although XTO Energy and the other operators of the underlying properties must adhere to the standard of a prudent operator, they are under no obligation to continue operating the properties. Neither the Trustee nor Trust unitholders have the right to replace an operator.

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The assets of the Trust represent interests in depleting assets and, if XTO Energy or any other operators developing the underlying properties do not perform additional successful development projects, the assets may deplete faster than expected. Eventually, the assets of the Trust will cease to produce in commercial quantities and the Trust will cease to receive proceeds from such assets.

The net proceeds payable to the Trust are derived from the sale of hydrocarbons from depleting assets. Future maintenance and development projects on the underlying properties will affect the quantity of proved reserves and can offset the reduction in the depletion of proved reserves. The timing and size of these projects will depend on the market prices of oil and natural gas. If the operator(s) of the properties do not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by the Trust. Because the net proceeds payable to the Trust are derived from the sale of hydrocarbons from depleting assets, the portion of distributions to unitholders attributable to depletion may be considered a return on capital as opposed to a return on investment. Distributions that are a return of capital will ultimately diminish the depletion tax benefits available to the unitholders, which could reduce the market value of the units over time. Eventually, the properties underlying the Trust’s net profits interests will cease to produce in commercial quantities and the Trust will, therefore, cease to receive any net proceeds therefrom.

XTO Energy may transfer its interest in the underlying properties without the consent of the Trust or the Trust unitholders.

XTO Energy may at any time transfer all or part of its interest in the underlying properties to another party. Neither the Trust nor the Trust unitholders are entitled to vote on any transfer of the properties underlying the Trust’s net profits interests, and the Trust will not receive any proceeds of any such transfer. Following any transfer, the transferred property will continue to be subject to the net profits interests of the Trust, but the calculation, reporting and remitting of net proceeds to the Trust will be the responsibility of the transferee.

XTO Energy or any other operator of any underlying property may abandon the property, thereby terminating the related net profits interest payable to the Trust.

XTO Energy or any other operator of the underlying properties, or any transferee thereof, may abandon any well or property without the consent of the Trust or the Trust unitholders if they reasonably believe that the well or property can no longer produce in commercially economic quantities. This could result in the termination of the net profits interest relating to the abandoned well or property.

The net profits interests can be sold and the Trust would be terminated. The Trust will also be terminated if it fails to generate sufficient gross revenues.

The Trust may sell the net profits interests if the holders of 80 percent or more of the outstanding Trust units approve the sale or vote to terminate the Trust. The Trust will terminate if it fails to generate gross revenues from the underlying properties of at least $1,000,000 per year over any successive two-year period. Sale of all of the net profits interests will terminate the Trust. The net proceeds of any sale must be for cash with the proceeds less any Trust administrative costs promptly distributed to the Trust unitholders.

The sale of the remaining net profits interests and the termination of the Trust will be taxable events to the Trust unitholders. Generally, Trust unitholders will realize gain or loss equal to the difference between the amount realized on the sale and termination of the Trust and their adjusted basis in such units. Gain or loss realized by a Trust unitholder who is not a dealer with respect to such units and who has a holding period for the units of more than one year will be treated as long-term capital gain or loss except to the extent of any depletion recapture amount, which must be treated as ordinary income. Other federal and state tax issues concerning the Trust are discussed under Item 2 and Note 4 to the Trust’s financial statements, which are included herein. Trust unitholders should consult their own tax advisor regarding all Trust tax compliance matters, including federal and state tax implications concerning the sale of the net profits interests and the termination of the Trust.

Trust unitholders have limited voting rights and have limited ability to enforce the Trust’s rights against XTO Energy or any other operator of the underlying properties.

The voting rights of a Trust unitholder 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. Additionally, Trust unitholders have no voting rights in XTO Energy or ExxonMobil.

The Trust indenture and related trust law permit the Trustee and the Trust to sue XTO Energy or any other operator of the underlying properties to compel them to fulfill the terms of the conveyance of the net profits interests. If the Trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of the Trust unitholders would likely be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. Trust unitholders probably would not be able to sue XTO Energy or any other operator of the underlying properties.

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Financial information of the Trust is not prepared in accordance with U.S. GAAP.

The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles (“U.S. GAAP”). Although this basis of accounting is permitted for royalty trusts by the Securities and Exchange Commission, the financial statements of the Trust differ from U.S. GAAP financial statements 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 U.S. GAAP financial statements.

The limited liability of Trust unitholders is uncertain.

The Trust unitholders are not protected from the liabilities of the Trust to the same extent that a shareholder would be protected from a corporation’s liabilities. The structure of the Trust does not include the interposition of a limited liability entity such as a corporation or limited partnership which would provide further limited liability protection to Trust unitholders. While the Trustee is liable for any excess liabilities incurred if the Trustee fails to ensure that such liabilities are to be satisfied only out of Trust assets, under the laws of Texas, which are unsettled on this point, a unitholder may be jointly and severally liable for any liability of the Trust if the satisfaction of such liability was not contractually limited to the assets of the Trust and the assets of the Trust and the Trustee are not adequate to satisfy such liability. As a result, Trust unitholders may be exposed to personal liability. The Trust, however, is not liable for production costs or other liabilities of the underlying properties.

Drilling oil and natural gas wells is a high-risk activity and subjects the Trust to a variety of factors that it cannot control.

Drilling oil and natural gas wells involves numerous risks, including the risk that commercially productive oil and natural gas reservoirs are not encountered. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause drilling activities to be unsuccessful. In addition, there is often uncertainty as to the future cost or timing of drilling, completing and operating wells. Further, development activities may be curtailed, delayed or canceled as a result of a variety of factors, including:


1.	reduced oil or natural gas prices;
2.	unexpected drilling conditions;
3.	title problems;
4.	restricted access to land for drilling or laying pipeline;
5.	pressure or irregularities in formations;
6.	equipment failures or accidents;
7.	adverse weather conditions, natural disasters, or public health events; and
8.	costs of, or shortages or delays in the availability of, drilling rigs, labor, tubular materials, and equipment.

While these risks do not expose the Trust to liabilities of the drilling contractor or operator of the well, they can reduce net proceeds payable to the Trust and Trust distributions by decreasing oil and gas revenues or increasing production expense or development costs from the underlying properties. Furthermore, these risks may cause the costs of development activities on properties underlying the 75% net profits interests to exceed the revenues therefrom, thereby reducing net proceeds payable to the Trust and Trust distributions.

The underlying properties are subject to complex federal, state and local laws and regulations that could adversely affect net proceeds payable to the Trust and Trust distributions.

Extensive federal, state and local regulation of the oil and natural gas industry significantly affects operations on the underlying properties. In particular, oil and natural gas development and production are subject to stringent environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning oil and natural gas wells and other related facilities, which costs could reduce net proceeds payable to the Trust and Trust distributions. These regulations may become more demanding in the future. These regulations can often be changed by administrative agencies without formal legislation, resulting in additional costs that can impact distributions. See “Regulation” in Item 2. Properties, and “Greenhouse Gas Emissions and Sustainability Regulations” in Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations.

Cash held by the Trustee is not insured by the Federal Deposit Insurance Corporation.

Currently, cash held by the Trust reserved for the payment of accrued liabilities and estimated future expenses and distributions to unitholders is typically held in a treasury fund that under normal market conditions invests exclusively in U.S. Treasury obligations. Although the fund’s underlying investments are obligations of the U.S. government, the fund itself is not insured by the Federal Deposit Insurance Corporation. In the event that the fund becomes insolvent, the Trustee may be unable to recover any or all such cash from the insolvent fund. Any loss of such cash may have a material adverse effect on the Trust’s cash balances and any distributions to unitholders.

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The tax treatment of an investment in Trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis.

U.S. federal tax reform legislation informally known as the Tax Cuts and Jobs Act (“TCJA”) was enacted December 22, 2017, and made significant changes to the federal income tax rules applicable to both individuals and entities, including changes to the effective tax rate on a Trust unitholder’s allocable share of certain income from the Trust. Additionally, the One Big Beautiful Bill Act (“OBBBA”) was signed into law on July 4, 2025, and, among other items, made permanent, extended, or modified certain provisions under the TCJA. The TCJA and OBBBA are complex and Trust unitholders should consult their tax advisor regarding the TCJA and OBBBA and their effect on an investment in Trust units.

Any modification to the U.S. federal income tax laws or interpretations thereof (including administrative guidance relating to the TCJA or OBBBA) may be applied retroactively and could adversely affect our business, financial condition or results of operations. The Trust is unable to predict whether any changes or other proposals will ultimately be enacted, or whether any adverse interpretations will be used. Any such changes or interpretations could negatively impact the value of an investment in the Trust units.

ITEM 1B. UNRESOLVED STAFF COMMENTS

As of December 31, 2025, the Trust did not have any unresolved Securities and Exchange Commission staff comments.

ITEM 1C. CYBERSECURITY

The Trust does not have a board of directors; therefore, 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 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, non-public 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 Item 1A. Risk Factors – The Trust may be subject to attempted cybersecurity disruptions from a variety of sources including state-sponsored actors.

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ITEM 2. PROPERTIES

The net profits interests are the principal asset of the Trust. The Trustee cannot acquire any other asset, with the exception of certain short-term investments as specified under Item 1. Business. The Trustee is prohibited from selling any portion of the net profits interests unless approved by holders of at least 80 percent or more of the outstanding Trust units or at such time as Trust gross revenue is less than $1 million for two successive years.

The net profits interests comprise:


1.	the 90% net profits interests which are carved from:
	a)	producing royalty and overriding royalty interest properties in Texas, Oklahoma and New Mexico; and
	b)	11.11% nonparticipating royalty interests in nonproducing properties located primarily in Texas and Oklahoma; and
2.	the 75% net profits interests which are carved from working interests in four properties in Texas and three properties in Oklahoma.

All underlying royalties, underlying nonproducing royalties and underlying working interest properties are currently owned by XTO Energy or other affiliated companies of ExxonMobil. XTO Energy may sell all or any portion of the underlying properties at any time, subject to and burdened by the net profits interests.

The underlying properties include over 2,900 producing properties with established production histories in Texas, Oklahoma and New Mexico. The average reserve-to-production index for the underlying properties as of December 31, 2025, is approximately nine years. This index is calculated using total proved reserves and estimated 2026 production for the underlying properties. The projected 2026 production is from proved developed producing reserves as of December 31, 2025. Based on estimated future net cash flows at 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period, the future net cash flows from proved reserves of the underlying properties are approximately 65 percent natural gas and 35 percent oil. The underlying properties also include certain nonproducing properties in Texas, Oklahoma and New Mexico that are primarily mineral interests.

Producing Acreage, Wells and Drilling

90% Net Profits Interests Underlying Royalties. Royalty and overriding royalty properties underlying the 90% net profits interests represent approximately 89 percent of the discounted future net cash flows from the Trust’s net profits interests proved reserves at December 31, 2025. Approximately 72 percent of the discounted future net cash flows from the 90% net profits interests are from gas reserves, totaling 9.4 Bcf. Oil reserves allocated to the 90% net profits interests are primarily located in West Texas and are estimated to be 224,000 Bbls at December 31, 2025.

The underlying royalties are royalty and overriding royalty interests primarily located in mature producing oil and gas fields. The most significant producing region in which the underlying royalties are located is the San Juan Basin in northwestern New Mexico. The New Mexico royalties gas production accounted for approximately 69 percent of the Trust’s net profits interests gas sales volumes and 34 percent of the net profits income for 2025. The Trust’s net profits interests estimated proved gas reserves from New Mexico totaled 8.2 Bcf at December 31, 2025, or approximately 87 percent of Trust’s net profits interests total gas reserves at that date. The majority of these wells are operated by Hilcorp Energy Company or Simcoe LLC.

San Juan Basin oil and gas accumulations, inclusive of the Fruitland Coal, Pictured Cliffs, Mancos, Mesaverde, and Dakota formations, have produced within the basin for over 100 years. Although these reservoirs have seen almost a century of development, numerous upside opportunities are still available to basin operators via down-spacing drilling, recompletions, lateral drilling, and lease cost optimizations. Recently, operators have moved development toward the more liquid-rich portions of the basin through the following:


1.	reduced dry gas drilling with a shift toward horizontal drilling in the more liquids-rich areas;
2.	lease optimization via compression upgrades, restimulations, and improved artificial lift;
3.	basinal work to rail crude oil out of basin to improve pricing; and
4.	stable gas pipeline infrastructure.

The underlying royalties also include royalties in the Sand Hills field of Crane County, Texas. The Sand Hills field was discovered in 1931 and includes production from three main intervals, the Tubb, McKnight and Judkins. Development potential for the field includes recompletions and additional infill drilling.

Because the properties related to the 90% net profits interests are primarily royalty interests and overriding royalty interests, the net profits income from these properties is not reduced by production or development costs, with the exception of a limited number of wells that were converted to working interest after conveyance that incur production and development costs. Additionally, net profits

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income from these interests cannot be reduced by any excess costs of the 75% net profits interests. The Trust, therefore, should generally receive monthly net profits income from these interests, as determined by oil and gas sales volumes and prices.

The limited number of underlying working interest properties, referred to above, consists of five productive gross wells (0.23 net). Well counts for the underlying royalties cannot be provided because information regarding the number of wells on royalty properties is generally not made available to royalty interest owners.

75% Net Profits Interests Underlying Working Interest Properties. Underlying the 75% net profits interests are working interests in seven large, predominantly oil-producing properties in Texas and Oklahoma operated primarily by established oil companies. These properties are located in mature fields undergoing secondary or tertiary recovery operations. Most of the oil produced from the 75% net profits interest properties is sour oil, which is sold at a discount to NYMEX sweet crude oil prices. XTO Energy is the operator of the Hewitt Unit, which is one of the properties underlying the Oklahoma 75% net profits interests. With the exception of the Hewitt Unit, XTO Energy and ExxonMobil generally have little influence or control over operations on any of these properties.

Trust’s net profits interests proved reserves from the 75% net profits interests are almost entirely oil, estimated to be approximately 73,000 Bbls and represent approximately 11 percent of the discounted future net cash flows of the Trust’s net profits interests proved reserves at December 31, 2025.

The underlying working interest properties are detailed below:


			Ownership by
			XTO Energy
			Working	Revenue
Unit	County/State	Operator	Interest	Interest
North Cowden	Ector/Texas	Occidental Permian Ltd.	1.7%	1.4%
North Central Levelland	Hockley/Texas	Hilcorp Energy Company	3.2%	2.1%
Penwell	Ector/Texas	Cross Timbers Energy, LLC	5.2%	4.6%
Sharon Ridge Canyon	Borden/Texas	OXY USA WTP LP	4.3%	2.8%
Hewitt	Carter/Oklahoma	XTO Energy Inc.	11.3%	9.9%
Wildcat Jim	Carter/Oklahoma	Citation Oil & Gas Corporation	8.6%	7.5%
South Graham Deese Sand	Carter/Oklahoma	Scout Energy Management LLC	9.2%	7.4%

The underlying working interest properties consist of 3,714 gross (3,000 net) producing acres. As of December 31, 2025, there were 1,085 gross (63.5 net) productive oil wells. There were no wells drilled in 2025, no wells drilled in 2024, and six gross (0.68 net) wells drilled in 2023. As operator of the Hewitt Unit, XTO Energy has advised the Trustee that it has no plans to drill in 2026.

Because these underlying properties are working interests, production expense and development costs are deducted in calculating net profits income from the 75% net profits interests. As a result, net profits income from these interests is affected by the level of maintenance and development activity on these underlying properties. Net profits income is also dependent upon oil and gas sales volumes and prices and is subject to reduction for any prior period excess costs.

Total underlying 2025 development costs were $165,510, down 89 percent from 2024 development costs of $1,509,510. Development costs were lower in 2025 primarily because of the absence of costs incurred in 2024 for drilling activity that occurred in the second half of 2023 for the Hewitt Unit.

As reported to XTO Energy by unit operators in February of each year, underlying budgeted development costs were $0.75 million for 2025 and $0.20 million for 2024 ($0.56 million and $0.15 million, respectively, net to the Trust). Actual development costs often differ from amounts budgeted because of changes in product prices and other factors that may affect the timing or selection of projects. Also, costs are deducted in the calculation of Trust net profits income several months after they are incurred by the operator. Unit operators have reported underlying budgeted costs of approximately $0.09 million for 2026 and $0.08 million for 2027 ($0.07 million and $0.06 million, respectively, net to the Trust). Changes in oil or natural gas prices could impact future development plans on the underlying properties.

If monthly costs exceed revenues for any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits income from other conveyances. Remaining cumulative excess costs for the Texas working interest conveyance totaled $5.5 million ($4.1 million net to the Trust), including accrued interest of $1.5 million ($1.1 million net to the Trust) for the period ended December 31, 2025. For information regarding the effect of excess costs on Trust net profits income, see Note 7 to Financial Statements under Item 8. Financial Statements and Supplementary Data, including the excess cost balance and accrued interest by conveyance.

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Estimated Proved Reserves and Future Net Cash Flows

The following are proved reserves of the underlying properties, as estimated by independent engineers, and proved reserves and future net cash flows from proved reserves of the net profits interests, based on an allocation of these reserves, at December 31, 2025:


	Underlying Properties				Net Profits Interests
	Proved Reserves (a)				Proved Reserves (a)(b)				Future Net Cash Flows
(in thousands)	Oil		Gas		Oil		Gas		from Proved Reserves (a)(c)
	(Bbls)		(Mcf)		(Bbls)		(Mcf)		Undiscounted		Discounted
90% Net Profits Interests
New Mexico		37		9,050		33		8,152	$	29,828	$	16,547
Texas		174		524		156		471		10,913		6,459
Oklahoma		39		899		35		765		4,999		3,061
Total		250		10,473		224		9,388		45,740		26,067

75% Net Profits Interests
Texas		—		—		—		—		—		—
Oklahoma		681		399		73		43		4,394		3,134
Total		681		399		73		43		4,394		3,134

TOTAL		931		10,872		297		9,431	$	50,134	$	29,201

(a)

Based on 12-month average oil price of $62.98 per Bbl and $3.86 per Mcf for gas, based on the first-day-of-the-month price for each month in the period.

(b)

Since the Trust has defined net profits interests, the Trust does not own a specific percentage of the oil and gas reserves. Oil and gas reserves are allocated to the net profits interests by dividing Trust net cash inflows by 12-month average oil and gas prices. As such, reserves allocated to the Trust have been reduced to reflect recovery of the Trust’s portion of applicable production and development costs, which includes excess costs. Any conveyance where costs exceed revenues will result in zero allocated net profits interests reserves for that conveyance.

(c)

Before income taxes since future net cash flows are not subject to taxation at the trust level. Future net cash flows are discounted at an annual rate of 10 percent.

Proved reserves at December 31, 2025, consist of the following:


	Underlying Properties				Net Profits Interests
	Proved Reserves				Proved Reserves
(in thousands)	Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)
Proved developed producing reserves		931		10,872		297		9,431
Proved undeveloped reserves		—		—		—		—
Proved developed non-producing reserves		—		—		—		—
Total proved reserves		931		10,872		297		9,431

The process of estimating oil and gas reserves is complex and requires significant judgment as discussed in Item 1A. Risk Factors, and is performed by XTO Energy. As a result, XTO Energy has developed internal policies and controls for estimating and recording reserves. XTO Energy’s policies regarding booking reserves require proved reserves to be in compliance with the SEC definitions and guidance. XTO Energy’s policies assign responsibilities for compliance in reserves bookings to its reserve engineering group and require that reserve estimates be made by qualified reserves estimators, as defined by the Society of Petroleum Engineers’ standards. All qualified reserves estimators are required to receive education covering the fundamentals of SEC proved reserves assignments.

The XTO Energy reserve engineering group reviews reserve estimates with third-party petroleum consultants, Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents, Ltd. estimated oil and gas reserves attributable to the underlying properties as of December 31, 2025. Miller and Lents’ primary technical person responsible for calculating the Trust’s reserves has more than 14 years of experience as a reserve engineer. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net profits interests. Numerous uncertainties are inherent in estimating reserve volumes and values, and 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 estimates.

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Oil and Natural Gas Production

Trust production is recognized in the period net profits income is received, which is the month following receipt by XTO Energy, and generally two months after the time of oil production and three months after gas production. Oil and gas sales volumes are allocated to the net profits interests based upon a formula that considers oil and gas prices and the total amount of production expense and development costs. As such, the underlying property production volume changes may not correlate with the Trust’s net profit share of those volumes in any given period.

Oil and gas production and average sales prices attributable to the underlying properties and the net profits interests for the last three years ended December 31 were as follows:


	90% Net Profits Interests						75% Net Profits Interests						Total
	2025		2024		2023		2025		2024		2023		2025		2024		2023
Production
Underlying Properties
Oil - Sales (Bbls)		39,981		43,926		61,465		108,087		121,070		130,654		148,068		164,996		192,119
Average per day (Bbls)		110		120		168		296		331		358		406		451		526
Gas - Sales (Mcf)		981,562		1,208,304		1,764,001		118,348		8,601		9,863		1,099,910		1,216,905		1,773,864
Average per day (Mcf)		2,689		3,301		4,833		324		24		27		3,013		3,325		4,860

Net Profits Interests
Oil - Sales (Bbls)		33,100		35,706		53,783		10,347		12,710		17,348		43,447		48,416		71,131
Average per day (Bbls)		91		98		147		28		35		48		119		133		195
Gas - Sales (Mcf)		785,212		973,511		1,451,656		51,699		350		784		836,911		973,861		1,452,440
Average per day (Mcf)		2,151		2,660		3,977		142		1		2		2,293		2,661		3,979

Average Sales Price
Oil (per Bbl)	$	70.43	$	78.78	$	79.50	$	64.16	$	74.55	$	75.90	$	65.85	$	75.68	$	77.05
Gas (per Mcf)	$	4.47	$	3.92	$	5.94	$	3.79	$	11.43	$	15.76	$	4.40	$	3.97	$	6.00

Average Production Cost per BOE (a)	$	2.29	$	2.33	$	1.67	$	51.17	$	54.04	$	53.09	$	21.14	$	19.55	$	15.62

(a)

Total average production cost per BOE includes production from the properties underlying the 90% net profits interests, which are substantially all royalty and overriding royalty interests with insignificant production costs.

Oil and gas production by conveyance attributable to the underlying properties for the last three years ended December 31 were as follows:


	Underlying Gas Production (Mcf)
Conveyance	2025		2024		2023
New Mexico royalty interest		730,994		809,160		1,397,441
Oklahoma royalty interest		131,121		282,154		196,718
Texas royalty interest		119,447		116,990		169,842
Oklahoma working interest (a)		112,541		1,969		2,147
Texas working interest		5,807		6,632		7,716
Total		1,099,910		1,216,905		1,773,864

(a)

Oklahoma working interest underlying gas production for 2025 is higher due to out-of-period residue gas sales for the Hewitt Unit.


	Underlying Oil Production (Bbls)
Conveyance	2025		2024		2023
New Mexico royalty interest		1,647		4,010		2,340
Oklahoma royalty interest		8,866		11,527		18,928
Texas royalty interest		29,468		28,389		40,197
Oklahoma working interest		85,433		97,042		103,957
Texas working interest		22,654		24,028		26,697
Total		148,068		164,996		192,119

Nonproducing Acreage

The underlying nonproducing royalties in Texas, Oklahoma and New Mexico were nonproducing at the date of the Trust’s creation. The Trust is entitled to 10 percent of oil and gas production attributable to the underlying mineral interests, but is not entitled to delay rental payments or lease bonuses. There has been no significant development of such nonproducing acreage since the Trust’s creation.

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Pricing and Sales Information

Oil and gas are generally sold from the underlying properties at market-sensitive prices. The majority of sales from the underlying working interest properties are to major oil and gas companies. Information about purchasers of oil and gas from royalty properties is generally not provided by operators to XTO Energy as a royalty owner, or to the Trust.

Regulation

Natural Gas Regulation

The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation and storage rates charged, tariffs, and various other matters, by the Federal Energy Regulatory Commission (“FERC”). Federal price controls on wellhead sales of domestic natural gas terminated on January 1, 1993. While natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. On August 8, 2005, Congress enacted the Energy Policy Act of 2005 (the “Energy Policy Act”). The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act, including enforcement rules and new annual reporting requirements for certain sellers of natural gas. It is impossible to predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, such proposals might have on the operations of the underlying properties.

Federal Regulation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The net price received from the sale of these products is affected by market transportation costs. Under rules adopted by FERC effective January 1995, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances.

On December 19, 2007, the President signed into law the Energy Independence & Security Act of 2007 (PL 110-140) (“EISA”). The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations, and establishes penalties for violations thereunder. XTO Energy has advised the Trustee that it cannot predict the impact of future government regulation on any crude oil, condensate or natural gas liquids facilities, sales or transportation transactions.

Environmental Regulation

Companies engaged in the oil and gas industry are subject to federal, state and local laws regulating the discharge of materials into the environment. Those laws may impact operations of the underlying properties. No material expenses have been incurred on the underlying properties in complying with environmental laws and regulations. XTO Energy does not expect future compliance to have a material impact on the Trust.

There is a focus by local, national and international regulatory bodies on greenhouse gas (“GHG”) emissions and sustainability. Several states have adopted sustainability legislation and regulations, and various other regulatory bodies have announced their intent to regulate GHG emissions or adopt sustainability regulations. XTO Energy is unable to predict the impact of potential regulations to operators of the underlying properties, and it is possible that operators of the underlying properties could face increases in operating costs in order to comply with sustainability or GHG emissions legislation, which costs could reduce net proceeds payable to the Trust and Trust distributions.

State Regulation

The various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells, and the prevention of waste of oil and gas resources. The rates of production may be regulated and the maximum daily production allowable from both oil and gas wells may be established on a market demand or conservation basis, or both.

Federal Income Taxes

For federal income tax purposes, the Trust constitutes a fixed investment trust that is taxed as a grantor trust. A grantor trust is not subject to tax at the trust level. The unitholders are considered, for federal income tax purposes, to own the Trust’s income and principal as though no trust were in existence. The income of the Trust is deemed to have been received or accrued by each unitholder at the time

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such income is received or accrued by the Trust and not when distributed by the Trust. Impairments recorded for book purposes will not result in a loss for tax purposes for the unitholders until the loss is recognized.

Because the Trust is a grantor trust for federal tax purposes, unitholders are taxed directly on their proportionate share of income, deductions, and credits of the Trust consistent with each such unitholder’s taxable year and method of accounting and without regard to the taxable year or method of accounting employed by the Trust. The income of the Trust consists primarily of a specified share of the net profits from the sale of oil and natural gas produced from the underlying properties. During 2025, the Trust incurred administration expenses and earned interest income on funds held for distribution and on the cash reserve maintained for the payment of contingent and future obligations of the Trust.

The Trust generally allocates its items of income, gain, loss and deduction between transferors and transferees of the units each month based upon the ownership of the Trust units on the monthly record date, instead of on the basis of the date a particular unit is transferred. It is possible that the Internal Revenue Service (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 unitholders affected by the issue and result in an increase in the administrative expense of the Trust in subsequent periods.

The net profits interests constitute “economic interests” in oil and gas properties for federal tax purposes. Each unitholder is entitled to amortize the cost of the units through cost depletion over the life of the net profits interests or, if greater, through percentage depletion equal to 15 percent of gross income from such net profits interests, limited to 100 percent of the net income from such net profits interests. Unlike cost depletion, percentage depletion is not limited to a unitholder’s depletable tax basis in the units. Rather, a unitholder is entitled to a percentage depletion deduction as long as the applicable underlying properties generate gross income. Unitholders should compute both percentage depletion and cost depletion from each property and claim the larger amount as a deduction on their income tax returns.

Unitholders must maintain records of their adjusted basis in their Trust units (generally their cost less prior depletion deductions), make adjustments for depletion deductions to such basis, and use the adjusted basis for the computation of gain or loss on the disposition of the Trust units.

If a taxpayer disposes of any “Section 1254 property” (certain oil, gas, geothermal or other mineral property), and the adjusted basis of such property includes adjustments for depletion deductions under Section 611 of the Internal Revenue Code (the “Code”), the taxpayer generally must recapture the amount deducted for depletion as ordinary income (to the extent of gain realized on such disposition). This depletion recapture rule applies to any disposition of Section 1254 property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the U.S. Treasury Regulations govern dispositions of property after March 13, 1995.

Interest and net profits income attributable to ownership of units and any gain on the sale thereof are considered portfolio income, and not income from a “passive activity,” to the extent a unitholder acquires and holds units as an investment and not in the ordinary course of a trade or business. Therefore, interest and net profits income attributable to ownership of units generally may not be offset by losses from any passive activities.

On July 4, 2025, the OBBBA was signed into law. The legislation introduces several significant federal income tax changes, including the permanent extension of the income tax rates established by the TCJA, the continued suspension of miscellaneous itemized deductions, and the reinstatement of favorable tax treatment for certain business provisions. The OBBBA contains multiple effective dates, with some provisions taking effect in 2025 and others phased in through 2027. Unitholders are encouraged to consult their own tax advisor regarding the potential income tax consequences of the OBBBA and its impact on their ownership of Trust units.

Under the TCJA and OBBBA, for tax years beginning after December 31, 2017, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 37 percent, and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and qualified dividends of individuals is 20 percent. Under the TCJA and OBBBA, for such tax years, personal exemptions and miscellaneous itemized deductions are not allowed. Further, the U.S. federal income tax rate applicable to corporations is 21 percent, and such rate applies to both ordinary income and capital gains.

Individuals may also incur expenses in connection with the acquisition or maintenance of Trust units. For tax years beginning before January 1, 2018, these expenses, which are different from a unitholder’s share of the Trust’s administrative expenses discussed above, could be deductible as “miscellaneous itemized deductions” only to the extent that such expenses exceed 2 percent of the individual’s adjusted gross income. Under the TCJA and OBBBA, for tax years beginning after December 31, 2017, miscellaneous itemized deductions are not allowed.

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Section 1411 of the Code imposes a 3.8 percent Medicare tax on certain investment income earned by individuals, estates, and trusts. For these purposes, investment income generally will include a unitholder’s allocable share of the Trust’s interest and net profits income plus the gain recognized from a sale of Trust units. In the case of an individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all investments, or (ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels depending on such individual’s federal income tax filing status. In the case of an estate or trust, the tax is imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

The difference between the per-unit taxable income for any period and the per-unit cash distributions, if any, reported for such period is attributable to (i) items that reduce cash distributions but are not currently deductible, such as an increase in the cash reserve maintained by the Trust for the payment of future expenditures; (ii) the current deduction of expenses that are paid with amounts previously reserved; (iii) items that increase cash distributions but do not constitute taxable income, such as a decrease in the cash reserve maintained by the Trust and/or a return of capital; and (iv) items that constitute taxable income due to the recovery of prior period expense adjustments. Because of these types of items and when the Trustee elects to reserve amounts from monthly distributions to maintain an administrative expense reserve, the taxable income per period frequently differs from the actual amount distributed to unitholders.

Pursuant to the Foreign Account Tax Compliance Act (commonly referred to as “FATCA”), distributions from the Trust to “foreign financial institutions” and certain other “non-financial foreign entities” may be subject to U.S. withholding taxes. Specifically, certain “withholdable payments” (including certain royalties, interest and other gains or income from U.S. sources) made to a foreign financial institution or non-financial foreign entity will generally be subject to the withholding tax unless the foreign financial institution or non-financial foreign entity complies with certain information reporting, withholding, identification, certification and related requirements imposed by FATCA. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules.

The Treasury Department issued guidance providing that the FATCA withholding rules described above generally will apply to qualifying payments made after June 30, 2014. Foreign unitholders are encouraged to consult their own tax advisor regarding the possible implications of these withholding provisions on their investment in Trust units.

Some Trust units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a customer in street name, collectively referred to herein as “middlemen”). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. Argent Trust Company, EIN: 62-1437218, 3838 Oak Lawn Ave, Suite 1720, Dallas, Texas, 75219, telephone number 1-855-588-7839, email address trustee@crt-crosstimbers.com, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.crt-crosstimbers.com. Notwithstanding the foregoing, the middlemen holding Trust units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such Trust units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose Trust units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust units.

Unitholders should consult their tax advisor regarding Trust tax compliance matters.

State Income Taxes

All revenues from the Trust are from sources within Texas, Oklahoma or New Mexico. Because the Trust distributes all of its net income to unitholders, the Trust is not taxed at the trust level in New Mexico or Oklahoma. While the Trust is not expected to owe tax, the Trustee is required to file an Oklahoma income tax return reflecting the income and deductions of the Trust attributable to properties located in that state, along with a schedule that includes information regarding distributions to unitholders. Oklahoma and New Mexico tax the income of nonresidents from real property located within those states, and the Trust has been advised by counsel that such states will tax nonresidents on income from the net profits interests located in those states. Oklahoma and New Mexico also impose a corporate income tax that may apply to unitholders organized as corporations (subject to certain exceptions for S corporations and limited liability companies, depending on their treatment for federal tax purposes).

Texas imposes a franchise tax at a rate of 0.75 percent on gross revenues less certain deductions, as specifically set forth in the Texas franchise tax statutes. Entities subject to tax generally include trusts and most other types of entities that provide limited liability protection, unless otherwise exempt. Trusts that receive at least 90 percent of their federal gross income from certain passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10 percent of their income from operating an active trade or business, generally are exempt from the Texas franchise tax as “passive entities.” The Trust has been and expects to continue to be exempt from Texas franchise tax as a passive entity. Because the Trust should be exempt from Texas franchise tax at the trust level as a passive entity, each unitholder that is a taxable entity under the Texas franchise tax

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generally will be required to include its Texas portion of trust revenues in its own Texas franchise tax computation. This revenue is sourced to Texas under provisions of the Texas Administrative Code providing that such income is sourced according to the principal place of business of the Trust, which is Texas.

Each unitholder should consult their own tax advisor regarding state income tax requirements, if any, applicable to such person’s ownership of Trust units.

State Tax Withholding

Several states have enacted legislation requiring state income tax withholding from payments to nonresident recipients of oil and gas proceeds. After consultation with its tax counsel, the Trustee believes that it is not required to withhold on payments made to the unitholders. However, regulations are subject to change by the various states, which could change this conclusion. Should amounts be withheld on payments made to the Trust or the unitholders, distributions to the unitholders would be reduced by the required amount, subject to the filing of a claim for refund or credit (to the extent available) by the Trust or unitholders for such amount.

Other Regulation

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws, including, but not limited to, regulations and laws relating to environmental protection, occupational safety, resource conservation and equal employment opportunity. XTO Energy has advised the Trustee that it does not believe that compliance with these laws will have any material adverse effect upon the unitholders.

ITEM 3. LEGAL PROCEEDINGS

Certain of the underlying properties are involved in various lawsuits and certain governmental proceedings arising in the ordinary course of business. XTO Energy has advised the Trustee that it does not believe that the ultimate resolution of these claims will have a material effect on the annual distributable income, financial position or liquidity of the Trust.

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.

PART II

ITEM 5. MARKET FOR UNITS OF THE TRUST, RELATED UNITHOLDER MATTERS AND TRUST PURCHASES OF UNITS

Units of Beneficial Interest

The units of beneficial interest in the Trust are listed and traded on the New York Stock Exchange under the symbol “CRT”.

At March 18, 2026, there were 6,000,000 units outstanding and approximately 145 unitholders of record; 5,968,235 of these units were held by depository institutions.

The Trust has no equity compensation plans, nor has it purchased any units during the period covered by this report.

See Item 1. Business for a description of the Trustee’s obligations to make monthly distributions and how the monthly distribution amount is determined under the indenture.

ITEM 6. [RESERVED]

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ITEM 7. TRUSTEE’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Calculation of Net Profits Income

The following is a summary of the calculation of net profits income received by the Trust:


	Year Ended						Three Months Ended
	December 31 (a)						December 31 (a)
	2025			2024			2025			2024
Sales Volumes
Oil (Bbls) (b)
Underlying properties		148,068			164,996			35,469			38,048
Average per day		406			451			386			414
Net profits interests		43,447			48,416			12,304			13,312

Gas (Mcf) (b)
Underlying properties		1,099,910			1,216,905			375,383			236,400
Average per day		3,013			3,325			4,080			2,570
Net profits interests		836,911			973,861			264,832			182,612

Average Sales Price
Oil (per Bbl)	$	65.85		$	75.68		$	62.42		$	72.32
Gas (per Mcf)	$	4.40		$	3.97		$	4.39		$	3.78

Revenues
Oil sales	$	9,750,308		$	12,486,106		$	2,214,151		$	2,751,440
Gas sales		4,838,877			4,833,282			1,646,350			893,454
Total Revenues		14,589,185			17,319,388			3,860,501			3,644,894

Costs
Taxes, transportation and other		1,720,700			1,982,031			561,487			406,306
Production expense (c)		7,005,064			7,191,977			1,621,647			1,844,738
Development costs		165,510			1,509,510			332			6,734
Excess costs (d)		(848,521	)		(853,410	)		(235,874	)		(327,715	)
Total Costs		8,042,753			9,830,108			1,947,592			1,930,063

Net Proceeds	$	6,546,432		$	7,489,280		$	1,912,909		$	1,714,831

Net Profits Income	$	5,738,240		$	6,563,177		$	1,629,528		$	1,462,841

(a)

Because of the interval between time of production and receipt of net profits income by the Trust, oil and gas sales for the year ended December 31 generally relate to oil production from November through October and gas production from October through September, while oil and gas sales for the quarter ended December 31 generally relate to oil production from August through October and gas production from July through September.

(b)

Oil and gas sales volumes are allocated to the net profits interests by dividing Trust net cash inflows by average sales prices. As oil and gas prices change, the Trust’s allocated production volumes are impacted as the quantity of production necessary to cover expenses changes inversely with price. As such, the underlying property production volume changes may not correlate with the Trust’s allocated production volumes in any given period. Therefore, comparative discussion of oil and gas sales volumes is based on the underlying properties.

(c)

Production expense includes an overhead charge which is deducted and retained by the operator. XTO Energy deducts an overhead charge as reimbursement for costs associated with monitoring these interests. See Note 5 to Financial Statements under Item 8. Financial Statements and Supplementary Data.

(d)

See Note 7 to Financial Statements under Item 8. Financial Statements and Supplementary Data.

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Results of Operations

Years Ended December 31, 2025 and 2024

Net profits income for 2025 was $5,738,240 as compared with $6,563,177 for 2024. The 13 percent decrease in net profits income from 2024 to 2025 was primarily the result of lower oil prices ($1.3 million), decreased oil production ($0.9 million), and decreased gas production ($0.6 million), partially offset by decreased development costs ($1.0 million), higher gas prices ($0.6 million), decreased taxes, transportation and other costs ($0.2 million), and decreased production expenses ($0.2 million). During 2025 and 2024, 51 percent and 46 percent, respectively, of net profits income was derived from gas sales.

Trust administration expense was $847,078 in 2025 as compared to $945,612 in 2024. Cash reserve activity was $450,000 in 2025 and $0 in 2024. As of December 31, 2025, the reserve is funded at $1,450,000. Interest income was $49,682 in 2025 and $60,253 in 2024. Changes in interest income are attributable to fluctuations in net profits income and interest rates.

Net profits income is recorded when received by the Trust, which is the month following receipt by XTO Energy, and generally two months after oil production and three months after gas production. Net profits income is generally affected by three major factors:


1.	oil and gas sales volumes;
2.	oil and gas sales prices; and
3.	costs deducted in the calculation of net profits income.

Volumes

Oil. Underlying oil sales volumes decreased 10 percent from 2024 to 2025 primarily because of timing of cash receipts and natural production decline.

Gas. Underlying gas sales volumes decreased 10 percent from 2024 to 2025 primarily due to the absence of out-of-period revenues related to non-operated properties in the Oklahoma royalty interest net profits interests, timing of cash receipts, and natural production decline, partially offset by out-of-period revenues related to Hewitt Unit residue gas sales.

The estimated rate of natural production decline on the underlying oil and gas properties is approximately 6 to 8 percent a year.

Prices

Oil. The average oil price for 2025 was $65.85 per Bbl, down 13 percent from the 2024 average oil price of $75.68 per Bbl. Oil prices are expected to remain volatile. The average NYMEX price for November 2025 through January 2026 was $59.29 per Bbl. At March 13, 2026, the average NYMEX oil price for the following 12 months was $83.43 per Bbl.

Gas. The 2025 average gas price was $4.40 per Mcf, up 11 percent from the 2024 average gas price of $3.97 per Mcf. Natural gas prices are affected by natural gas liquids prices, the level of North American production, weather, crude oil prices, the U.S. economy, storage levels and export levels of liquefied natural gas. Natural gas prices are expected to remain volatile. The average NYMEX price for fourth quarter 2025 was $3.07 per MMBtu. At March 13, 2026, the average NYMEX gas price for the following 12 months was $3.84 per MMBtu.

Costs

Because properties underlying the 90% net profits interests are primarily royalty and overriding royalty interests, the calculation of net profits income from these interests includes deductions for production and property taxes, legal costs, and marketing and transportation charges. In addition to these costs, the calculation of net profits income from the 75% net profits interests includes deductions for production expense and development costs since the related underlying properties are working interests. Net profits income is calculated monthly for each of the five conveyances under which the net profits interests were conveyed to the Trust. If monthly costs exceed revenues for any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits income from other conveyances. Costs have never exceeded revenues from the 90% net profits interests, nor are they expected to in the future. For further information on excess costs, see Note 7 to Financial Statements under Item 8. Financial Statements and Supplementary Data.

Total costs deducted in the calculation of net profits income were $8.0 million in 2025 and $9.8 million in 2024. The 18 percent decrease in costs from 2024 to 2025 is attributable to decreased development costs ($1.3 million), decreased taxes, transportation and other costs ($0.3 million), and decreased production expenses ($0.2 million).

Unit operators of the properties underlying the 75% net profits interests have reported underlying budgeted development costs of approximately $0.09 million for 2026 and $0.08 million for 2027 ($0.07 million and $0.06 million, respectively, net to the Trust), as

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compared to underlying budgeted development costs of $0.75 million ($0.56 million net to the Trust) and actual development costs of $0.17 million ($0.12 million net to the Trust) for 2025. Actual development costs often differ from amounts budgeted because of changes in product prices and other factors that may affect the timing or selection of projects. Changes in oil or natural gas prices could impact future development plans on the underlying properties.

Fourth Quarter 2025 and 2024

During the quarter ended December 31, 2025, the Trust received net profits income totaling $1,629,528, compared with fourth quarter 2024 net profits income of $1,462,841. This 11 percent increase in net profits income is primarily the result of increased gas production ($0.4 million), higher gas prices ($0.2 million), and decreased production expenses ($0.2 million), partially offset by lower oil prices ($0.3 million), increased taxes, transportation and other costs ($0.1 million), decreased oil production ($0.1 million) and net excess costs activity ($0.1 million).

Administration expense was $131,453, cash reserve activity was $150,000, and Trust interest income was $12,965, resulting in fourth quarter 2025 distributable income of $1,361,040, or $0.226840 per unit. Distributable income for fourth quarter 2024 was $1,317,594, or $0.219599 per unit.

Distributions to unitholders for the quarter ended December 31, 2025, were:


Record Date	Payment Date	Per Unit
October 31, 2025	November 17, 2025	$	0.075205
November 28, 2025	December 12, 2025		0.036930
December 31, 2025	January 15, 2026		0.114705
		$	0.226840

Volumes

Fourth quarter 2025 underlying oil sales volumes were down 7 percent from fourth quarter 2024 primarily because of timing of cash receipts and natural production decline. Underlying gas sales volumes for fourth quarter 2025 were up 59 percent from fourth quarter 2024 because of out-of-period revenues related to Hewitt Unit residue gas sales and timing of cash receipts, partially offset by natural production decline.

Prices

The average fourth quarter 2025 oil price was $62.42 per Bbl, down 14 percent from the fourth quarter 2024 average price of $72.32 per Bbl. The average fourth quarter 2025 gas price was $4.39 per Mcf, up 16 percent from the fourth quarter 2024 average price of $3.78 per Mcf. For further information about oil and gas prices, see “Years Ended December 31, 2025 and 2024 – Prices” above.

Costs

Costs deducted in the calculation of fourth quarter 2025 net profits income increased 1 percent from fourth quarter 2024. This increase was primarily attributable to increased taxes, transportation and other costs ($0.1 million) and net excess costs activity ($0.1 million), partially offset by decreased production expenses ($0.2 million). For further information about development and excess costs, see “Years Ended December 31, 2025 and 2024 – Costs” above.

Liquidity and Capital Resources

The Trust’s only cash requirement is any declared monthly distribution of its income to unitholders, which is funded by the monthly receipt of net profits income after payment of Trust administration expenses. The Trust is not liable for any production costs or liabilities attributable to the underlying properties. If at any time the Trust receives net profits income in excess of the amount due, the Trust is not obligated to return such overpayment, but future net profits income payable to the Trust will be reduced by the overpayment, plus interest at the prime rate. The Trustee may establish cash reserves for certain contingencies. The Trust may borrow funds required to pay Trust liabilities if fully repaid prior to further distributions to unitholders.

The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust’s liquidity or the availability of capital resources.

Greenhouse Gas Emissions and Sustainability Regulations

There is an increased focus by local, national and international regulatory bodies on greenhouse gas (“GHG”) emissions and sustainability. A number of nations and U.S. states have adopted or are considering some form of sustainability legislation and

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regulations, including carbon taxes, cap-and-trade policies and bans on drilling in certain areas or in certain ways. XTO Energy has informed the Trustee that it continues to anticipate that sustainability policies will increase the cost of carbon dioxide emissions over time. XTO Energy is unable to predict the impact of potential regulations to operators of the underlying properties, and it is possible that the operators of the underlying properties could face increases in operating costs in order to comply with sustainability or GHG emissions legislation, which costs could reduce or eliminate net proceeds payable to the Trust and Trust distributions.

Off-Balance Sheet Arrangements

The Trust has no off-balance sheet financing arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.

Related Party Transactions

The underlying properties from which the net profits interests were carved are currently owned by XTO Energy or other affiliated companies of ExxonMobil.

Approximately 21 of the underlying royalty interests burden working interests in properties operated by XTO Energy. XTO Energy operates the Hewitt Unit which is one of the properties underlying the Oklahoma 75% net profits interests. Other than these properties, XTO Energy and ExxonMobil do not operate or control any of the underlying properties or related working interests.

In computing net proceeds for the 75% net profits interests (Note 3), XTO Energy deducts an overhead charge as reimbursement for costs associated with monitoring these interests. This overhead charge at December 31, 2025, was approximately $53,620 per month, or $643,440 annually (net to the Trust of $40,215 per month, or $482,580 annually), and is subject to annual adjustment based on an oil and gas industry index.

XTO Energy deducts a monthly overhead charge for reimbursement of administrative expenses as operator of the Hewitt Unit, which is one of the properties underlying the Oklahoma 75% net profits interests. As of December 31, 2025, this charge was approximately $37,104 per month, or $445,248 annually (net to the Trust of $27,828 per month, or $333,936 annually), and is subject to annual adjustment based on an oil and gas industry index.

On June 25, 2010, XTO Energy became a wholly owned subsidiary of ExxonMobil.

Critical Accounting Policies

The financial statements of the Trust are significantly affected by its basis of accounting and estimates related to its oil and gas properties and proved reserves, as summarized below.

Basis of Accounting

The Trust’s financial statements are prepared on a modified cash basis, which is a comprehensive basis of accounting other than U.S. GAAP. This method of accounting is consistent with reporting of taxable income to Trust unitholders. The most significant differences between the Trust’s financial statements and those prepared in accordance with U.S. GAAP are:


1.	net profits income is recognized in the month received rather than accrued in the month of production;
2.	expenses are recognized when paid rather than when incurred; and
3.	cash reserves may be established by the Trustee for certain contingencies that would not be recorded under U.S. GAAP.

This comprehensive basis of accounting other than U.S. GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. For further information regarding the Trust’s basis of accounting, see Note 2 to Financial Statements under Item 8. Financial Statements and Supplementary Data.

All amounts included in the Trust’s financial statements are based on cash amounts received or disbursed, or on the carrying value of the net profits interests, which was derived from the historical cost of the interests at the date of their transfer from XTO Energy, less accumulated amortization to date. Accordingly, there are no fair value estimates included in the financial statements based on either exchange or non-exchange trade values.

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Impairment of Net Profits Interests

The Trustee reviews the Trust’s net profits interests (“NPI”) in oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the NPI may not be recoverable. In general, the Trustee does not 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. If events and circumstances indicate the carrying value may not be recoverable, the Trustee would use the estimated undiscounted future net cash flows from the NPI to evaluate the recoverability of the Trust assets. If the undiscounted future net cash flows from the NPI are less than the NPI carrying value, the Trust would recognize an impairment loss for the difference between the NPI carrying value and the estimated fair value of the NPI. The determination as to whether the NPI is impaired requires a significant amount of judgment by the Trustee and is based on the best information available to the Trustee at the time of the evaluation, including commodity pricing and other information provided by XTO Energy such as estimates of future production and development and operating expenses.

During 2025, including fourth quarter, no trigger event occurred that would indicate a need for an impairment assessment. Accordingly, there was no impairment of the NPI as of December 31, 2025. Any impairment recorded for book purposes will not result in a deductible loss for tax purposes for the unitholders until the loss is recognized.

Net profits interests in oil and gas properties

The initial carrying value of the net profits interests of $61,100,449 was XTO Energy’s historical net book value of the interests on February 12, 1991, the date of the transfer to the Trust. Amortization of the net profits interests is calculated on a unit‑of‑production basis using proved reserves and is charged directly to trust corpus. Accumulated amortization was $58,942,029 as of December 31, 2025, and $58,667,105 as of December 31, 2024. Amortization of the NPI does not impact unitholder distributions or the determination of proved reserves.

Oil and Gas Reserves

The proved oil and gas reserves for the underlying properties are estimated by independent petroleum engineers. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net profits interests. 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 12-month average prices, based on the first-day-of-the-month price for each month in the period, estimated reserve quantities can be significantly impacted by changes in product prices. Accordingly, oil and gas quantities ultimately recovered and the timing of production may be substantially different from original estimates.

The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Note 8 to Financial Statements under Item 8. Financial Statements and Supplementary Data, is prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures, including recovery of cumulative excess costs remaining at year end. Discounted future net cash flows are calculated using a 10 percent rate. Changes in any of these assumptions, including consideration of other factors, could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent XTO Energy’s or the Trustee’s estimated current market value of proved reserves.

Forward-Looking Statements

Certain information included in this annual report and other materials filed, or to be filed, by the Trust with the Securities and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by XTO Energy or the Trustee) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the Trust, operations of the underlying properties and the oil and gas industry. Such forward-looking statements may concern, among other things, development activities, future development plans, increased density drilling, reserve-to-production ratios, future production, future net cash flows, maintenance projects, development, production, regulatory and other costs, oil and gas prices and expectations for future demand, the impact of inflation and economic downturns on economic activity, government policy and its impact on oil and gas prices and future supply and demand, the development and competitiveness of alternative energy sources, pricing differentials, proved reserves, production levels, arbitration, litigation, liquidity, financing, political and regulatory matters, such as tax and environmental policy, climate policy, trade barriers, tariffs, sanctions, war and other geopolitical or security disturbances, and competition. Such forward-looking statements are based on XTO Energy’s and the Trustee’s current plans, expectations, assumptions, projections and estimates and are identified by words such as “may,” “expects,” “intends,” “plans,” “projects,” “anticipates,” “predicts,” “believes,” “goals,” “estimates,” “should,”

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“could,” “would,” and similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual financial and operational results may differ materially from expectations, estimates or assumptions expressed in, implied in, or forecasted in such forward-looking statements. Some of the risk factors that could cause actual results to differ materially are explained in Item 1A. Risk Factors.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required for smaller reporting companies; the Trust has elected to omit this information.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


	Page
Report of Independent Registered Public Accounting Firm (PCAOB 238)	23
Statements of Assets, Liabilities and Trust Corpus	24
Statements of Distributable Income	24
Statements of Changes in Trust Corpus	24
Notes to Financial Statements	25

All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto.

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Report of Independent Registered Public Accounting Firm

To the Unitholders of Cross Timbers Royalty Trust and Argent Trust Company, as Trustee

Opinion on the Financial Statements

We have audited the accompanying statements of assets, liabilities and trust corpus of Cross Timbers Royalty Trust (the “Trust”) as of December 31, 2025 and 2024, and the related statements of distributable income and of changes in trust corpus for the years then ended, including 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 its distributable income and its changes in trust corpus for the years then ended in conformity with the modified cash basis of accounting described in Note 2.

Basis for Opinion

These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on the Trust’s 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 of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits 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 Trust’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 audits also included evaluating the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Basis of Accounting

As described in Note 2, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than generally accepted accounting principles.

Critical Audit Matters

Critical audit matters are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. We determined there are no critical audit matters.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 27, 2026

We have served as the Trust’s auditor since 2011.

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Cross Timbers Royalty Trust

Statements of Assets, Liabilities and Trust Corpus


	December 31
	2025		2024
Assets
Cash and short-term investments	$	2,133,676	$	1,369,379
Interest to be received		4,554		4,211
Net profits interests in oil and gas properties - net (Notes 1 and 2)		2,158,420		2,433,344
	$	4,296,650	$	3,806,934
Liabilities and Trust Corpus
Distribution payable to unitholders	$	688,230	$	373,590
Expense reserve (a)		1,450,000		1,000,000
Trust corpus (6,000,000 units of beneficial interest authorized and outstanding)		2,158,420		2,433,344
	$	4,296,650	$	3,806,934

(a)

Expense reserve allows the Trustee to pay its obligations should it be unable to pay them out of the net profits income. The reserve is currently funded at $1,450,000.

Statements of Distributable Income


	Year Ended December 31
	2025		2024
Net profits income	$	5,738,240	$	6,563,177
Interest income		49,682		60,253
Total income		5,787,922		6,623,430
Administration expense		847,078		945,612
Expense reserve		450,000		—
Distributable income	$	4,490,844	$	5,677,818
Distributable income per unit (6,000,000 units)	$	0.748474	$	0.946303

Statements of Changes in Trust Corpus


	Year Ended December 31
	2025			2024
Trust corpus, beginning of year	$	2,433,344		$	2,671,583
Amortization of net profits interests		(274,924	)		(238,239	)
Distributable income		4,490,844			5,677,818
Distributions declared		(4,490,844	)		(5,677,818	)
Trust corpus, end of year	$	2,158,420		$	2,433,344

See accompanying notes to financial statements.

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CROSS TIMBERS ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

Trust Organization and Provisions

Cross Timbers Royalty Trust (the “Trust”) was created on February 12, 1991, by predecessors of XTO Energy Inc. (“XTO Energy”), when the following net profits interests were conveyed under five separate conveyances to the Trust effective October 1, 1990, in exchange for 6,000,000 units of beneficial interest in the Trust:

      1.

      90% net profits interests in certain producing and nonproducing royalty and overriding royalty interest properties in Texas, Oklahoma and New Mexico; and

      2.

      75% net profits interests in certain working interest properties in Texas and Oklahoma.

The underlying properties from which the net profits interests were carved are currently owned by XTO Energy or other affiliated companies of ExxonMobil (Note 5). The Trust’s initial public offering was in February 1992.

Effective December 30, 2022, Argent Trust Company (“Argent”) became the Trustee of the Trust. The defined term “Trustee” as used herein shall refer to Simmons Bank for periods from February 20, 2018, through December 29, 2022, and shall refer to Argent for periods on and after December 30, 2022.

The Trust indenture provides, among other provisions, that:


1.	the Trust may not engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments;
2.	the Trust may not dispose of all or part of the net profits interests unless approved by holders of 80 percent or more of the outstanding Trust units, or upon Trust termination, and any sale must be for cash with the proceeds promptly distributed to the unitholders on the next declared distribution;
3.	the Trustee may establish a cash reserve for payment of any liability that is contingent or not currently payable;
4.	the Trustee may borrow funds required to pay Trust liabilities if fully repaid prior to further distributions to unitholders;
5.	the Trustee will make monthly cash distributions to unitholders (Note 3); and
6.	the Trust will terminate upon the first occurrence of:
	a)	disposition of all net profits interests pursuant to terms of the Trust indenture;
	b)	gross revenue of the Trust is less than $1 million per year for two successive years; or
	c)	a vote of holders of 80 percent or more of the outstanding Trust units to terminate the Trust in accordance with provisions of the Trust indenture.

Basis of Accounting

The financial statements of the Trust are prepared on the following basis and are not intended to present financial position and results of operations in conformity with U.S. generally accepted accounting principles (“U.S. GAAP”):


1.	net profits income is recorded in the month received by the Trustee (Note 3);
2.	interest income, interest to be received and distribution payable to unitholders include interest to be earned on net profits income from the monthly record date (last business day of the month) through the date of the next distribution;
3.	trust expenses are recorded based on liabilities paid and cash reserves established by the Trustee for liabilities and contingencies; and
4.	distributions to unitholders are recorded when declared by the Trustee (Note 3).

The most significant differences between the Trust’s financial statements and those prepared in accordance with U.S. GAAP are:


1.	net profits income is recognized in the month received rather than accrued in the month of production;
2.	expenses are recognized when paid rather than when incurred; and
3.	cash reserves may be established by the Trustee for certain contingencies that would not be recorded under U.S. GAAP.

This comprehensive basis of accounting corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with U.S. GAAP, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues were received or expenses were paid. Because the Trust’s financial statements are prepared on the modified cash basis, as described above, most accounting pronouncements are not applicable to the Trust’s financial statements.

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Impairment of Net Profits Interests

During 2025, including fourth quarter, no trigger event occurred that would indicate a need for an impairment assessment. Accordingly, there was no impairment of the NPI as of December 31, 2025. Any impairment recorded for book purposes will not result in a deductible loss by the unitholders for tax purposes until the loss is recognized.

Net profits interests in oil and gas properties

The initial carrying value of the net profits interests of $61,100,449 was XTO Energy’s historical net book value of the interests on February 12, 1991, the date of the transfer to the Trust. Amortization of the net profits interests is calculated on a unit‑of‑production basis using proved reserves and charged directly to trust corpus. Accumulated amortization was $58,942,029 as of December 31, 2025, and $58,667,105 as of December 31, 2024. Amortization of the NPI does not impact unitholder distributions or the determination of proved reserves.

Distributions to Unitholders

The Trustee determines the amount to be distributed to unitholders each month by totaling net profits income, interest income and other cash receipts, and subtracting liabilities paid and adjustments in cash reserves established by the Trustee. The resulting amount (with estimated interest to be received on such amount through the distribution date) is distributed to unitholders of record within ten business days after the monthly record date, which is the last business day of the month.

Net profits income received by the Trustee consists of net proceeds received in the prior month by XTO Energy from the underlying properties multiplied by the net profits percentage of 90% or 75%. Net proceeds are the gross proceeds received from the sale of production, less applicable costs. For the 90% net profits interests, such costs generally include production and property taxes, legal costs, and marketing and transportation charges. In addition to these costs, the 75% net profits interests include deductions for production expense and development costs.

XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the five conveyances. If costs exceed gross proceeds for any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits income from the other conveyances (Note 7).

Income Taxes

For federal income tax purposes, the Trust constitutes a fixed investment trust that is taxed as a grantor trust. A grantor trust is not subject to tax at the trust level. Accordingly, no provision for income taxes has been made in the financial statements. The unitholders are considered, for federal income tax purposes, to own the Trust’s income and principal as though no trust were in existence. The income of the Trust is deemed to have been received or accrued by each unitholder at the time such income is received or accrued by the Trust and not when distributed by the Trust. Impairments recorded for book purposes will not result in a deductible loss by the unitholders for tax purposes until the loss is recognized.

On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was signed into law. The legislation introduces several significant federal income tax changes, including the permanent extension of the income tax rates established by the Tax Cuts and Jobs Act, the continued suspension of miscellaneous itemized deductions, and the reinstatement of favorable tax treatment for certain business provisions. The OBBBA contains multiple effective dates, with some provisions taking effect in 2025 and others phased in through 2027. Unitholders are encouraged to consult their own tax advisor regarding the potential income tax consequences of the OBBBA and its impact on their ownership of Trust units.

All revenues from the Trust are from sources within Texas, Oklahoma or New Mexico. Because the Trust distributes all of its net income to unitholders, the Trust has not been taxed at the trust level in New Mexico or Oklahoma. While the Trust has not owed tax, the Trustee is required to file an Oklahoma income tax return reflecting the income and deductions of the Trust attributable to properties located in that state, along with a schedule that includes information regarding distributions to unitholders. Oklahoma and New Mexico

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tax the income of nonresidents from real property located within those states, and the Trust has been advised by counsel that such states will tax nonresidents on income from the net profits interests located in those states. Oklahoma and New Mexico also impose a corporate income tax that may apply to unitholders organized as corporations (subject to certain exceptions for S corporations and limited liability companies, depending on their treatment for federal income tax purposes).

Each unitholder should consult their own tax advisor regarding income tax requirements, if any, applicable to such person’s ownership of Trust units.

Related Party Transactions

The underlying properties from which the net profits interests were carved are currently owned by XTO Energy or other affiliated companies of ExxonMobil.

On June 25, 2010, XTO Energy became a wholly owned subsidiary of ExxonMobil.

Contingencies

Several states have enacted legislation requiring state income tax withholding from payments made to nonresident recipients of oil and gas proceeds. After consultation with its tax counsel, the Trustee believes that it is not required to withhold on payments made to the unitholders. However, regulations are subject to change by the various states, which could change this conclusion. Should amounts be withheld on payments made to the Trust or the unitholders, distributions to the unitholders would be reduced by the required amount, subject to the filing of a claim for refund or credit (to the extent available) by the Trust or unitholders for such amount.

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Excess Costs

The following summarizes excess costs activity, cumulative excess costs balances and accrued interest to be recovered by conveyance as calculated by XTO Energy:


	Underlying
	TX WI		OK WI			Total
Cumulative excess costs remaining at 12/31/24	$	3,140,906	$	—		$	3,140,906
Net excess costs (recovery) for the quarter ended 3/31/25		66,655		—			66,655
Net excess costs (recovery) for the quarter ended 6/30/25		297,144		71,926			369,070
Net excess costs (recovery) for the quarter ended 9/30/25		250,251		(71,926	)		178,325
Net excess costs (recovery) for the quarter ended 12/31/25		235,909		—			235,909
Cumulative excess costs remaining at 12/31/25		3,990,865		—			3,990,865
Accrued interest at 12/31/25		1,467,432		—			1,467,432
Total remaining to be recovered at 12/31/25	$	5,458,297	$	—		$	5,458,297

	NPI
	TX WI		OK WI			Total
Cumulative excess costs remaining at 12/31/24	$	2,355,680	$	—		$	2,355,680
Net excess costs (recovery) for the quarter ended 3/31/25		49,991		—			49,991
Net excess costs (recovery) for the quarter ended 6/30/25		222,858		53,945			276,803
Net excess costs (recovery) for the quarter ended 9/30/25		187,689		(53,945	)		133,744
Net excess costs (recovery) for the quarter ended 12/31/25		176,932		—			176,932
Cumulative excess costs remaining at 12/31/25		2,993,150		—			2,993,150
Accrued interest at 12/31/25		1,100,573		—			1,100,573
Total remaining to be recovered at 12/31/25	$	4,093,723	$	—		$	4,093,723

For the year ended December 31, 2025, excess costs on properties underlying the Texas working interest conveyance increased by $849,959 ($637,470 net to the Trust). This includes net excess costs of $235,909 ($176,932 net to the Trust) for the quarter ended December 31, 2025.

For the year ended December 31, 2025, excess costs on properties underlying the Oklahoma working interest conveyance were fully recovered. In addition, recoveries of accrued interest were $1,438 ($1,079 net to the Trust), for the year ended December 31, 2025. This includes recoveries of accrued interest of $35 ($26 net to the Trust) for the quarter ended December 31, 2025.

Underlying cumulative excess costs for the Texas working interest conveyance remaining as of December 31, 2025, totaled $5.5 million ($4.1 million net to the Trust), including accrued interest of $1.5 million ($1.1 million net to the Trust).

Supplemental Oil and Gas Reserve Information (Unaudited)

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.

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Standardized Measure

The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using assumptions required by the Financial Accounting Standards Board. Such assumptions include the use of 12-month average prices for oil and gas, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures to produce the proved reserves, including recovery of cumulative excess costs remaining at year end. Future net cash flows are discounted at an annual rate of 10 percent. No provision is included for federal income taxes since future net cash flows are not subject to taxation at the trust level.

The standardized measure does not represent XTO Energy’s or the Trustee’s estimate of future cash flows or the value of proved oil and gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, prices used to determine the standardized measure are influenced by supply and demand as affected by recent economic conditions as well as other factors and may not be the most representative in estimating future revenues or reserve data.

Estimated costs to plug and abandon wells on the underlying working interest properties at the end of their productive lives have not been deducted from cash flows since this is not a legal obligation of the Trust. These costs are the legal obligation of XTO Energy as the owner of the underlying working interests and will only be deducted from net proceeds payable to the Trust if net proceeds from the related conveyance exceed such costs when paid, subject to excess cost carryforward provisions (Note 3).

Because overhead costs charged by XTO Energy are deducted in the calculation of net proceeds, the standardized measure for the underlying properties and net profits interests have been reduced by these estimated overhead costs. See Note 5 to Financial Statements under Item 8. Financial Statements and Supplementary Data for more information on overhead costs charged by XTO Energy.

Oil prices used to determine the standardized measure were based on average realized oil prices of $62.98 per Bbl in 2025, and $72.96 per Bbl in 2024. The weighted average realized gas prices used to determine the standardized measure were $3.86 per Mcf in 2025, and $3.55 per Mcf in 2024.

Reserve quantities and revenues for the net profits interests were estimated from projections of reserves and revenues attributable to the underlying properties. Since the Trust has defined net profits interests, the Trust does not own a specific percentage of the oil and gas reserves. Oil and gas reserves are allocated to the net profits interests by dividing Trust net cash inflows by 12-month average oil and gas prices. Any fluctuations in 12-month average prices or estimated costs will result in revisions to the estimated reserve quantities allocated to the net profits interests, which may not correlate with revisions of underlying proved reserves. Significant revisions in reserves could potentially impact the pace of the amortization of the net profits interests.

Proved Reserves


	Net Profits Interests
	90% Net						75% Net												Underlying
	Profits Interests						Profits Interests						Total						Properties
(in thousands)	Oil			Gas			Oil			Gas			Oil			Gas			Oil			Gas
	(Bbls)			(Mcf)			(Bbls)			(Mcf)			(Bbls)			(Mcf)			(Bbls)			(Mcf)
Balance, December 31, 2023		270			10,917			278			132			548			11,049			1,387			12,693
Extensions, additions and discoveries		5			44			—			—			5			44			6			49
Revisions of prior estimates		(14	)		(3,037	)		(22	)		(6	)		(36	)		(3,043	)		73			(3,191	)
Production		(35	)		(974	)		(13	)		—			(48	)		(974	)		(165	)		(1,217	)
Balance, December 31, 2024		226			6,950			243			126			469			7,076			1,301			8,334
Extensions, additions and discoveries		2			44			—			—			2			44			3			49
Revisions of prior estimates		29			3,179			(160	)		(31	)		(131	)		3,148			(225	)		3,589
Production		(33	)		(785	)		(10	)		(52	)		(43	)		(837	)		(148	)		(1,100	)
Balance, December 31, 2025		224			9,388			73			43			297			9,431			931			10,872

Extensions, additions and discoveries of proved gas reserves are primarily because of development in the Mid-Continent area. Revisions of prior estimates are primarily related to changes in prices and costs.

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Proved Developed Reserves

       
      Net Profits Interests

       
      90% Net

      75% Net

      Underlying

       
      Profits Interests

      Profits Interests

      Total

      Properties

      (in thousands)

      Oil

      Gas

      Oil

      Gas

      Oil

      Gas

      Oil

      Gas

       
      (Bbls)

      (Mcf)

      (Bbls)

      (Mcf)

      (Bbls)

      (Mcf)

      (Bbls)

      (Mcf)

December 31, 2024

226

6,950

243

126

469

7,076

1,301

8,334

December 31, 2025

224

9,388

73

43

297

9,431

931

10,872

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves


	90% Net						75% Net
	Profits Interests						Profits Interests						Total
(in thousands)	December 31,						December 31,						December 31,
	2025			2024			2025			2024			2025			2024
Net Profits Interests
Future cash inflows	$	50,407		$	38,435		$	4,735		$	18,922		$	55,142		$	57,357
Future production taxes		(4,666	)		(3,343	)		(341	)		(1,362	)		(5,007	)		(4,705	)
Future net cash flows		45,741			35,092			4,394			17,560			50,135			52,652
10% discount factor		(19,674	)		(14,234	)		(1,260	)		(7,088	)		(20,934	)		(21,322	)
Standardized measure	$	26,067		$	20,858		$	3,134		$	10,472		$	29,201		$	31,330

Underlying Properties
Future cash inflows													$	100,480		$	124,574
Future costs														(43,801	)		(62,171	)
Future net cash flows														56,679			62,403
10% discount factor														(23,516	)		(25,252	)
Standardized measure													$	33,163		$	37,151

Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves


	90% Net						75% Net
(in thousands)	Profits Interests						Profits Interests						Total
	2025			2024			2025			2024			2025		2024
Net Profits Interests
Standardized measure, January 1	$	20,859		$	33,086		$	10,471		$	11,617		$	31,330	$	44,703
Extensions, additions and discoveries		153			319			—			—			153		319
Accretion of discount		1,811			2,846			946			1,049			2,757		3,895
Revisions of prior estimates, changes in price and other		8,214			(9,715	)		(7,515	)		(1,309	)		699		(11,024	)
Net profits income		(4,970	)		(5,677	)

CROSS TIMBERS ROYALTY TRUST 10-K