HUGOTON ROYALTY TRUST 10-K

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 No. 1-10476

Hugoton Royalty Trust

(Exact name of registrant as specified in its charter)


Texas		58-6379215
(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: None

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


Title of each class	Trading symbol	Name of each exchange on which registered
Units of Beneficial Interest	HGTXU	OTCQB

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). ☐

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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 $16.0 million.

The number of units of beneficial interest outstanding as of March 31, 2026, was 40,000,000.

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HUGOTON ROYALTY TRUST

2025 ANNUAL REPORT ON FORM 10-K

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		Page

Glossary of Terms		1

	Part I

Item 1.	Business	2
Item 1A.	Risk Factors	3
Item 1B.	Unresolved Staff Comments	9
Item 1C.	Cybersecurity	9
Item 2.	Properties	10
Item 3.	Legal Proceedings	19
Item 4.	Mine Safety Disclosures	20

	Part II

Item 5.	Market for Units of the Trust, Related Unitholder Matters and Trust Purchases of Units	20
Item 6.	[Reserved]	20
Item 7.	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 8.	Financial Statements and Supplementary Data	29
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	41
Item 9A.	Controls and Procedures	42
Item 9B.	Other Information	42
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	42

	Part III

Item 10.	Directors, Executive Officers and Corporate Governance	43
Item 11.	Executive Compensation	43
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	43
Item 13.	Certain Relationships and Related Transactions, and Director Independence	44
Item 14.	Principal Accountant Fees and Services	44

	Part IV

Item 15.	Exhibits and Financial Statement Schedules	44

Signatures		46

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HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

The following are definitions of significant terms used in this Annual Report on Form 10-K:


Bbl	Barrel (of oil)

Bcf	Billion cubic feet (of natural gas)

BOE	Barrel of oil equivalent

Mcf	Thousand cubic feet (of natural gas)

MMBtu	One million British Thermal Units, a common energy measurement

net proceeds	Gross proceeds received by XTO Energy or Mach Natural Resources 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 net profits percentage of 80%, which is paid to the Trust by Mach Natural Resources. “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:

	80% net profits interests - interests that entitle the Trust to receive 80% of the net proceeds from the underlying properties.

underlying properties	Mach’s interest in certain oil and gas properties from which the net profits interests were conveyed. The underlying properties include working interests in predominantly gas-producing properties located in Kansas, Oklahoma and Wyoming.

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

Business

Hugoton Royalty Trust (the “Trust”) is an express trust created under the laws of Texas pursuant to the Hugoton Royalty Trust Indenture entered into on December 1, 1998, between XTO Energy Inc. (formerly known as Cross Timbers Oil Company and, hereafter, “XTO Energy”), as grantor, and NationsBank, N.A., as Trustee. The current trustee of the Trust is Argent Trust Company, a Tennessee chartered trust company (“Argent”). Effective April 10, 2023, 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 April 9, 2023, and shall refer to Argent for periods on and after April 10, 2023.

The principal office of the Trust is 3838 Oak Lawn Ave, Suite 1720, Dallas, Texas 75219. (Telephone number 855-588-7839). The Trust’s internet website is www.hgt-hugoton.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.

Effective December 1, 1998, XTO Energy conveyed to the Trust 80% net profits interests in certain predominantly natural gas producing working interest properties in Kansas, Oklahoma and Wyoming under three separate conveyances. In exchange for these net profits interest conveyances to the Trust, 40 million units of beneficial interest were issued to XTO Energy. In April and May 1999, XTO Energy sold a total of 17 million units in the Trust’s initial public offering. In 1999 and 2000, XTO Energy also sold 1.3 million Trust units to certain of its officers. The Trust did not receive the proceeds from these sales of Trust units. In May 2006, XTO Energy distributed all of its remaining 21.7 million Trust units as a dividend to its common stockholders. XTO Energy currently is not a unitholder of the Trust. Units were listed and traded on the New York Stock Exchange under the symbol “HGT” until August 27, 2018, when the Trust units were delisted from the NYSE and began to be quoted on the OTCQX, which is maintained by the OTC Market Group Inc., under the symbol “HGTXU.” The Trust transitioned from the OTCQX to the OTCQB on May 19, 2020.

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

On March 25, 2025, XTO Energy informed the Trustee that it entered into a definitive agreement to divest XTO Energy’s interest in the assets underlying the Trust to Mach Natural Resources LP and its affiliates (“Mach”). The transaction closed on April 30, 2025, and Mach assumed XTO Energy’s obligations under the Trust Indenture and operatorship of applicable properties. References to working interest owner before April 30, 2025, represent XTO Energy and those on or after April 30, 2025, represent Mach.

The net profits interests entitle the Trust to receive 80% of the net proceeds from the sale of oil and gas from the underlying properties. Each month XTO Energy or Mach determines the amount of cash received from the sale of production and deducts property and production taxes, production expense, development costs and overhead.

Net proceeds payable to the Trust depend upon production quantities, sales prices of oil and gas and costs to develop and produce oil and gas in the prior month. If monthly costs exceed revenues for any of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming), such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net proceeds from other conveyances. For further information on excess costs, see Note 4 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 or Mach, as applicable, can generally decline participation in any operation and allow consenting parties to conduct such operations, as provided under the operating agreements. XTO Energy or Mach also can assign, sell,

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or otherwise transfer its interest in the underlying properties, subject to the net profits interests, or can abandon an underlying property if it is incapable of producing in paying quantities, as determined by XTO Energy or Mach.

To the extent allowed, XTO Energy or Mach, as applicable 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. See “Pricing and Sales Information” under Item 2. Properties.

Net profits income received by the Trust on or before the last business day of the month is related to net proceeds received by XTO Energy in the preceding month for periods prior to April 30, 2025, or Mach in the second preceding month for periods on or after April 30, 2025, and is generally attributable to oil and gas production two months prior. The amount to be distributed to unitholders each month by the Trustee is determined by:


Adding -
	1.	net profits income received;
	2.	interest income and any other cash receipts; and
	3.	cash available as a result of reduction of cash reserves; then

Subtracting -
	1.	liabilities paid; and
	2.	the reduction in cash available related 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.

The majority of previous net profits income received by the Trust has been attributable to natural gas. There has historically been a greater demand for gas during the winter months than the rest of the year. Otherwise, Trust income generally 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 Trust may not have sufficient cash to meet its obligations during the one-year period after the date that the financial statements are issued, and the Trustee has reviewed and intends to continue to review alternatives to the Trust continuing as a going concern.

All three of the Trust’s conveyances are in excess costs resulting in no net proceeds to the Trust and a reduction in the Trust’s expense reserve, which have resulted in no unitholder distributions since July 2023. These conditions raise substantial doubt about the

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Trust’s ability to continue as a going concern as the Trust does not have sufficient cash to meet its obligations during the one-year period after the date the financial statements are issued. The Trust’s financial statements do not include any adjustments that might result from the outcome of this uncertainty. Pursuant to the Settlement Agreement in 2024, XTO Energy advanced $500,000 to the Trust (which may be recouped, together with interest from what would otherwise be distributable net profits under any of the three conveyances; provided, however, that such recoupment does not leave the Trust with less than $250,000 of available cash). In the second quarter of 2025, XTO Energy provided the Trust with a second advance distribution of $500,000 (net to the Trust) that was intended to provide the Trustee of the Trust with liquidity to meet current and near-term financial reporting obligations. The terms of the second advance distribution are the same as the terms of the first advance distribution. There are no assurances that even with such advances, the Trust will receive net profits income sufficient to pay its obligations during the one-year period after the date the financial statements are issued. The Trustee has sought sources of financing, but currently believes that financing in an amount sufficient to satisfy the Trust's long-term liquidity needs is unlikely to be a viable option for the Trust moving forward. Nothing in the Trust Indenture obligates the Trustee to pay for the Trust’s expenses if the Trust’s cash reserves were to be completely depleted, and the Trustee currently does not intend to advance funds to the Trust. As a result, the Trustee has reviewed and intends to continue to review options for the Trust, which may include alternatives to the Trust continuing as a going concern such as seeking to terminate the Trust or marketing the Trust’s interests (which are net profits interests burdened by excess costs) for a potential sale. The Trustee has reached out to potential third parties regarding interest in the Trust’s assets, but no interest has resulted from such discussions. As a result, the Trustee believes a potential sale of the Trust’s assets may be unlikely in the near term, however it will continue to consider any and all viable options. Even if a sale of the Trust assets were to occur, there is no assurance that the proceeds would result in funds to distribute to unitholders after all financial obligations of the Trust are met. Any material sale of assets and/or termination of the Trust requires unitholder approval by at least 80 percent of all outstanding units. Once the Trust's cash reserves are depleted (anticipated to occur in the second quarter of 2026), the Trust will likely be unable to continue to make SEC filings, provide reporting to unitholders, or provide audited financial statements or third-party reserve reports. As a result, the unitholders and potential investors may have limited or no information on which to base investment decisions, which could have a negative impact on the market price for the Trust units and would likely result in removal of Trust units from the OTCQB. If the Trust is unable to continue as a going concern, unitholders could incur significant losses on their investment in the Trust or lose their entire investment in the Trust altogether. For further information see Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.

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 has historically been tied to the recent and expected levels of cash distributions on the Trust units. However, no cash distribution has occurred for 32 months as of the date of this report, March 31, 2026. The amounts available for distribution by the Trust vary in response to numerous factors outside the control of the Trust, or Mach, 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 or that distributions from the Trust will resume in 2026 or at all.

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 Mach. 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 fluctuated widely 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.

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Higher production expense and/or development costs, without concurrent increases in revenue, will directly decrease the net proceeds payable to the Trust. Certain claimed production expenses by Mach may reduce or eliminate distributions to unitholders for extended periods of time.

Production expense and development costs are deducted in the calculation of the Trust’s share of net proceeds. 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. If development costs and production expense for underlying properties in a particular state exceed the production proceeds from the properties (as has been the case with respect to the properties underlying all three of the Trust’s conveyances for the 33 months preceding the date of this report), 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. Additionally, Mach has advised the Trustee that there are no budgeted development costs for the underlying properties for 2026. See Item 2. Properties.

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 promote 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 lower 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.

There may not be an active market for the Trust units.

On August 27, 2018, the Trust units were delisted from the NYSE and began to be quoted on the OTCQX, which is maintained by the OTC Market Group Inc., under the symbol “HGTXU.” The Trustee received notice from the OTC Markets Group Inc. dated April 16, 2020, notifying the Trustee that the Trust was no longer in compliance with Section 3.2(a) of the Standards for Continued Qualification of the OTCQX Rules for U.S. Companies, in that as of December 31, 2019, the Trust had less than $2 million in net tangible assets, average revenue of less than $6 million over the past three years, and the Trust’s bid price is below $5 per share. The notice stated that if the Trust was unable to cure the deficiency by May 18, 2020, then it would be moved from OTCQX to the OTC Pink market. The Trust transitioned from the OTCQX to the OTCQB on May 19, 2020. In May 2025, trading of the Trust units was moved to the Pink market due to the fact that the Trust's cash position was such that it was unable to engage an audit firm for the 2025 fiscal year and was not able to file its quarterly report on Form 10-Q (“10-Q”) for the three months ended March 31, 2025, in a timely manner. On June 17, 2025, the Trust engaged its current auditor, Grant Thornton, and, subsequently, was able to file the 10-Q for the quarter ended March 31, 2025, on July 28, 2025. Subsequent 10-Qs have been filed timely, which brought the Trust back into compliance with the OCTQB. On August 21, 2025, the Trust's application to rejoin the OTCQB was approved and the Trust resumed trading on the OTCQB. Trading on the OTC is often characterized as thin with sporadic fluctuations in price and the availability of buyers or sellers of a security. No assurance can be given that an active trading market for the Trust units will further develop or continue or that the Trust units will continue to be traded on the OTCQB. As noted above, the Trust will likely be unable to continue to make SEC filings, provide reports to unitholders, or provide audited financial statements or third-party reserve reports once the Trust’s cash reserves are depleted (anticipated to occur in the second quarter 2026). This would likely result in removal of the Trust units from the OTCQB. If

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the units are moved to OTC Pink or elsewhere, they will likely be subject to greater volatility and lower trading volumes than when the Trust units were listed on the OTCQB. This could depress the trading price of the Trust units and make it more difficult to purchase, dispose of or obtain accurate quotations as to the value of the Trust units. No assurance can be made how such transition may affect the liquidity of the units.

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, 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.

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 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, Mach, 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.

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Trust unitholders and the Trustee have no influence over the operations on, 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 Mach, and 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.

The assets of the Trust represent interests in depleting assets and, if Mach, 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 of 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.

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

Mach 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.

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

Mach, 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 proceeds.

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 proceeds 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 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 7 to the Trust’s financial statements, which are included herein. Trust unitholders should consult their own tax advisor regarding all Trust tax compliance matters.

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Trust unitholders have limited voting rights and have limited ability to enforce the Trust’s rights against XTO Energy, Mach 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, Exxon Mobil Corporation, or Mach.

The Trust indenture and related trust law permit the Trustee and the Trust to sue XTO Energy, Mach, 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, Mach, or any other operator of the underlying properties.

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. See Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements – Note 2 Basis of Accounting for additional information.

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 the underlying properties to exceed the revenues therefrom, thereby reducing net proceeds payable to the Trust and Trust distributions.

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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 Item 2. Properties – Regulation, and Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations – Greenhouse Gas Emissions and Sustainability Regulations.

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.

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.

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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.

ITEM 2. PROPERTIES

The net profits interests are the principal asset of the Trust. The Trustee cannot acquire any other assets, with the exception of certain short-term investments as specified under Item 1. Business. The Trustee may sell or otherwise dispose of all or any part of the net profits interests if approved by a vote of holders of 80 percent or more of the outstanding Trust units, or upon termination of the Trust. Otherwise, the Trust is required to sell up to 1 percent of the value of the net profits interests in any calendar year, pursuant to notice from Mach of its desire to sell the related underlying properties. Any sale must be for cash with 80 percent of the proceeds distributed to the unitholders on the next declared distribution. All the underlying properties are currently owned by Mach. Mach 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 are predominantly gas-producing properties with established production histories in the Hugoton area of Oklahoma and Kansas, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. 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 55 percent natural gas and 45 percent oil. Mach operates approximately 78 percent of the underlying properties.

Because the underlying properties are working interests, production expense, development costs and overhead are deducted in calculating net profits income. As a result, net profits income is affected by the level of maintenance and development activity on the underlying properties. See Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations. Total 2025 development costs deducted for the underlying properties were $5.3 million, an increase of $3.2 million from the prior year. Mach has informed the Trustee that there are no budgeted development costs for the underlying properties for 2026. Changes in oil or natural gas prices could impact future development plans on the underlying properties.

Significant Properties

Hugoton Area

Natural gas was discovered in the Hugoton area in 1922. With an estimated five million productive acres covering parts of Texas, Oklahoma and Kansas, the Hugoton area is one of the largest domestic natural gas producing areas. During 2025, daily sales volumes from the underlying properties in the Hugoton area averaged approximately 4,700 Mcf of gas and 30 Bbls of oil.

Most of the production from the underlying properties in the Hugoton area is from the Chase formation. Prior to April 30, 2025, XTO Energy informed the Trustee that it began to develop other formations that underlie the 79,500 net acres held by production by the Chase formation wells, which included the Council Grove, Morrow, Chester and St. Louis formations. After April 30, 2025, Mach or other operators have not advised the Trustee of any plans to develop the Hugoton Area. These formations are characterized by both oil and gas production from a variety of structural and stratigraphic traps. Prior to 2011, XTO Energy drilled wells to these formations.

Within this area, neither XTO Energy nor Mach drilled any new wells or performed any workovers in 2025. Mach has informed the Trustee that it does not plan to drill any new wells or perform any workovers during 2026.


Mach's future development plans for the underlying properties in the Hugoton area may include, but are not limited to:
1.	additional compression to lower line pressures;
2.	installing artificial lift;

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3.	opening new producing zones in existing wells;
4.	restimulating producing intervals in existing wells utilizing new technology;
5.	deepening existing wells to new producing zones; and
6.	future drilling of additional wells.

Effective May 1, 2014, XTO Energy entered into a gas sales and processing contract with DCP Midstream, L.P. (“DCP”) to process all gas production from its wells attached to the Timberland Gathering System in Seward County, Kansas and in Texas and Beaver Counties, Oklahoma. When Mach purchased the properties underlying the Trust, it did not change the terms of the contracts in place. Mach has advised the Trustee that the system collects approximately 7,100 Mcf per day, of which the majority of its throughput is from underlying properties. Mach receives 95 percent of the net value for residue gas based upon a price per MMBtu of Panhandle Eastern Pipe Line Company index and 95 percent net for NGLs at Mont Belvieu pricing. Under this contract DCP is entitled to charge a processing fee of $0.26 per Delivery Point MMBtu and a helium processing fee of $0.05 per 97 percent Delivery Point Mcf in addition to other deductions such as for fuel and transportation. Timberland Gathering & Processing Company, LLC, formerly known as Timberland Gathering and Processing Company, Inc. (“Timberland”), an affiliate of Mach, provides gathering from the wellhead to DCP’s gathering system for a fee of $0.75 per Mcf of gas delivered by Mach. In January 2025, this fee was escalated for inflation to approximately $0.98 per Mcf and retroactively applied to the prior two year period as permitted by the Timberland Gas Gathering agreement.

Other Hugoton gas production is sold under a third-party contract that remains in effect for the life of the lease. Under the contract, 74.5 percent of the net proceeds received by the buyer from the sale of the residue gas and liquids produced from certain underlying properties are paid to either XTO Energy, before April 30, 2025, or are paid to Mach on or after April 30, 2025. The residue gas net proceeds are based upon the weighted average price of the gas sold by the buyer at its facilities, and the liquids net proceeds are based upon an average daily index sales price, less transportation, processing and storage fees incurred by the buyer. The buyer agrees to use its best efforts to take all of the gas produced, subject to its market requirements. The buyer has been taking all of the gas produced for over ten years.

Anadarko Basin

Oil and gas accumulations were discovered in the Anadarko Basin of western Oklahoma in 1945. The principal producing regions of the underlying properties in the Anadarko Basin include the Ringwood, Northwest Okeene and Cheyenne Valley fields of Major County, the Northeast Cedardale field of Woodward County and the Elk City field of Beckham County. Daily sales volumes from the underlying properties in the Anadarko Basin averaged approximately 9,900 Mcf of gas and 480 Bbls of oil in 2025.

The fields in the Major County area are characterized by oil and gas production from a variety of structural and stratigraphic traps. Productive zones include the Oswego, Red Fork, Inola, Chester, Manning, Mississippian, Hunton and Arbuckle formations. Within this area, XTO Energy did not drill any new wells in 2025. Mach drilled one new well and zero workovers in 2025. Mach has informed the Trustee that it does not plan to drill any new wells or perform any workovers in Major County during 2026.

The fields within Woodward County are characterized primarily by gas production from a variety of structural and stratigraphic traps. Productive zones include the Cottage Grove, Oswego, Chester and Mississippian formations. Within this area, neither XTO Energy nor Mach drilled any wells or perform any workovers in 2025. Mach has informed the Trustee that it does not plan to drill any new wells or perform any workovers in Woodward County during 2026.

The Elk City field on the eastern edge of Beckham County produces oil and gas from a structural anticline with stratigraphic trapping features. Production zones include the Hoxbar, Atoka and Morrow formations. Within this area, neither XTO Energy nor Mach drilled any wells or performed any workovers in 2025. Mach has informed the Trustee that it does not plan to drill any new wells or perform any workovers within the Elk City field during 2026.


Mach’s future development plans for the underlying properties in the Anadarko Basin may include, but are not limited to:
1.	mechanical stimulation of existing wells;
2.	installing artificial lift;
3.	opening new producing zones in existing wells;
4.	deepening existing wells to new producing zones; and
5.	future drilling of additional wells.

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A gathering subsidiary of XTO Energy, which was acquired by Mach on April 30, 2025, as a result of the transaction between the two companies, operates a 300-mile gathering system and pipeline in the Major County area. The gathering subsidiary and a third-party processor purchase natural gas produced at the wellhead from XTO Energy, Mach, and other producers in the area under various agreements, most of which were entered into in the 1960’s and 1970’s, and which include life-of-production terms such that the contracts will continue until there is no further production from the underlying properties, unless the production declines so that it is no longer economical to take the gas. The gathering subsidiary and the third-party processor are required to take certain minimum volumes of the gas produced but have been taking all of the volumes produced for over ten years. The gathering subsidiary gathers and transports the gas to a third-party processor, which processes the gas and pays XTO Energy, Mach, and other producers for at least 50 percent of the liquids processed based upon a weighted average sales price less transportation charges, which price may vary in the event of inadequate markets. After the gas is processed, the gathering subsidiary transports the gas via a residue pipeline to a connection with an interstate pipeline. The gathering subsidiary pays XTO Energy, or Mach on or after April 30, 2025, for the residue gas based upon a weighted average price from downstream sales to third parties, which price will vary monthly based upon market conditions. The gathering subsidiary pays this price to XTO Energy or on or after April 30, 2025, Mach, less a compression and gathering fee of approximately $0.31 per Mcf of residue gas. This gathering fee was previously approved by the Federal Energy Regulatory Commission when the gathering subsidiary was regulated. As of December 31, 2025, the gathering system was collecting approximately 6,150 Mcf per day, approximately 59 percent of which are operated by Mach. Estimated capacity of the gathering system is 21,000 Mcf per day. The gathering subsidiary also provides contract operating services to properties in Woodward County, collecting approximately 2,050 Mcf per day, for an average fee of approximately $0.53 per Mcf before April 30, 2025. On or after April 30, 2025, when Mach assumed ownership of the gathering subsidiary, the gathering subsidiary collects approximately 1,800 Mcf per day, but does not charge a fee. The gas is then purchased by DCP, who charges a $0.74 per Mcf fee. When XTO owned the properties underlying the Trust, the fee was subject to an annual price renegotiation under which either party could request that the price provided under the contract be renegotiated. The contract continues on a yearly basis, and it is subject to termination upon written notice prior to its annual renewal or in the event the parties fail to agree upon a pricing renegotiation. XTO Energy, and on or after April 30, 2025, Mach also sell gas directly to third parties. The price paid to XTO Energy, and on or after April 30, 2025, paid to Mach, is based upon the weighted average price of several published indices, which price varies upon market conditions, and includes a deduction for any transportation fees charged by the third party. None of the parties have a firm obligation to sell or purchase any specific minimum quantity of gas.

Green River Basin

The Green River Basin is located in southwestern Wyoming. Natural gas was discovered in the Fontenelle field of the Green River Basin in the early 1970’s. The producing reservoirs are the Frontier, Baxter and Dakota sandstones.

Daily 2025 sales volumes from the underlying properties in the Fontenelle field averaged approximately 8,000 Mcf of natural gas and 20 Bbls of oil. Neither XTO Energy nor Mach drilled any wells or perform any workovers in the Green River Basin in 2025. Mach has advised the Trustee that it does not plan to drill any new wells or perform any workovers in the Green River Basin during 2026.


Potential development activities for the underlying properties in this area include, but are not limited to:
1.	installing artificial lift;
2.	restimulating producing intervals utilizing new technology;
3.	additional compression to lower line pressures; and
4	opening new producing zones in existing wells.

XTO Energy, and on or after April 30, 2025, Mach, market the gas produced from the Fontenelle field and nearby properties under various marketing arrangements. Under the agreement covering the majority of the gas sold, XTO Energy, and on or after April 30, 2025, Mach, compresses the gas on the lease, transports it off the lease and compresses the gas again prior to entry into the gas plant pipeline. The pipeline transports the gas to the gas plant, where the gas is processed, then redelivered to XTO Energy, or on or after April 30, 2025, Mach. The owner of the gas plant and related pipeline charges XTO Energy, or on or after April 30, 2025, Mach, for operational fuel and processing and has agreed to accept certain volumes, which amounts can be adjusted by the owner. The owner may be able to cease taking volumes if it has valid unaddressed concerns regarding the creditworthiness of XTO Energy or, on or after April 30, 2025, Mach. In 2025, the fuel charge was less than 1 percent of the volumes produced and the fee was approximately $0.15 per MMBtu. These charges are adjusted annually based upon a published governmental economic index, and the contract renews on a year-to-year basis. XTO Energy, or on or after April 30, 2025, Mach, transports and sells this gas directly to the markets based on a spot sales price on a month-to-month term, and the volumes to be sold are generally determined upon a monthly basis. These contracts may be terminated by either party if there are credit issues with the other party. The gas not sold under the above arrangement may be gathered and sold under a similar arrangement on a month-to-month term where the fee is approximately $0.13 per MMBtu and is adjusted annually. The amount of gas that the gatherer is required to gather is limited to certain maximum volumes, and the gatherer may be able to cease taking volumes if it has valid unaddressed concerns regarding the creditworthiness of XTO Energy, or on or after April 30,

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2025, Mach. Alternatively, the gas may be sold under a contract where XTO Energy, or on or after April 30, 2025, Mach, directly sells the gas to a third party on the lease at an adjusted index price, which price varies upon market conditions. The contract continues on a month-to-month basis, and the buyer is obligated to make a good faith effort to purchase a minimum 90 percent of the gas nominated by buyer for purchase. Condensate is sold to an independent third party at market rates on a month-to-month basis. The purchaser accepts all condensate delivered at the lease, but either party may suspend performance of the contract if there are credit issues with the other party.

Producing Acreage, Drilling and Well Counts

For the following data, “gross” refers to the total wells or acres on the underlying properties in which Mach owns a working interest and “net” refers to gross wells or acres multiplied by the percentage working interest owned by Mach. Although many of Mach’s wells produce both oil and gas, a well is categorized as an oil well or a gas well based upon the ratio of oil to natural gas production. Operated wells are managed by Mach, while non-operated wells are managed by others.

The underlying properties are interests in developed properties located primarily in gas producing regions of the Hugoton Area, Anadarko Basin, and Green River Basin primarily in Kansas, Oklahoma, and Wyoming, respectively. The following is a summary of the approximate producing acreage of the underlying properties at December 31, 2025. Undeveloped acreage is not significant.


	Gross		Net
Kansas		57,354		51,562
Oklahoma		270,877		247,215
Wyoming		36,276		26,327
Total		364,507		325,104

The following is a summary of the producing wells on the underlying properties as of December 31, 2025:


	Operated Wells				Non-Operated Wells				Total (a)
	Gross		Net		Gross		Net		Gross		Net
Gas		977.0		859.3		240.0		46.4		1,217.0		905.7
Oil		33.0		28.9		23.0		5.4		56.0		34.3
Total		1,010.0		888.3		263.0		51.8		1,273.0		940.1

(a)

During 2025, 2024, and 2023 there were no exploratory wells drilled on the underlying properties. There were no dry wells drilled in 2025 and 2024 and there was one gross (0.01 net) non-operated dry well drilled in 2023. There were one gross (0.87 net), one gross (0.23 net), and three gross (1.53 net) developmental wells drilled in 2025, 2024, and 2023, respectively.

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)	Gas		Oil		Gas		Oil		from Proved Reserves (a)(c)
	(Mcf)		(Bbls)		(Mcf)		(Bbls)		Undiscounted		Discounted
Oklahoma		40,917		1,553		4,456		169	$	21,998	$	9,741
Wyoming		12,513		19		—		—		—		—
Kansas		2,087		78		—		—		—		—
Total		55,517		1,650		4,456		169	$	21,998	$	9,741

(a)

Based on 12-month average oil price of $62.83 per Bbl and $2.81 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 overhead and 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.

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


	Underlying Properties				Net Profits Interests
	Proved Reserves				Proved Reserves
(in thousands)	Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)
Proved developed producing reserves		55,517		1,650		4,456		169
Proved undeveloped reserves		—		—		—		—
Proved developed non-producing reserves		—		—		—		—
Total proved reserves		55,517		1,650		4,456		169

The process of estimating oil and gas reserves is complex and requires significant judgment as discussed in Item 1A. Risk Factors.Reserve estimates as of December 31, 2025 were based on information was provided by Mach to an independent reserves estimator and the Trustee. Mach has developed internal policies and controls for estimating and recording reserves. Mach’s policies regarding booking reserves require proved reserves to be in compliance with the SEC definitions and guidance. Mach’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.

For reserve estimates as of December 31, 2025, Mach and the Trustee reviewed reserve estimates with third-party petroleum consultants, Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”), whose firm registration number is F-693, was founded in 1961 and is a leader in the evaluation of oil and gas properties. The technical person at Cawley Gillespie primarily responsible for overseeing the reserve estimates with respect to the Underlying Properties attributable to the Trust is Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at Cawley Gillespie since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 38 years of practical experience in petroleum engineering, with over 36 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines. The estimated reserves for the underlying properties are then used by the Trustee 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.

Oil and Natural Gas Production

Trust production is recognized in the period net profits income is received, which was the month following receipt by XTO Energy for periods prior to May 31, 2025, and generally two months after the time of production. For Mach and for periods on or after May 31, 2025, Trust production is recognized in the period net profits income is received, which is the second month following receipt by Mach, and generally three months after 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.

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


	2025 (1)		2024		2023
Production
Underlying Properties
Gas - Sales (Mcf)		7,514,538		8,261,529		9,397,772
Average per day (Mcf)		22,499		22,572		25,747
Oil - Sales (Bbls)		171,448		193,204		217,440
Average per day (Bbls)		513		528		596

Net Profits Interests
Gas - Sales (Mcf)		—		—		990,526
Average per day (Mcf)		—		—		2,714
Oil - Sales (Bbls)		—		—		11,205
Average per day (Bbls)		—		—		31

Average Sales Price
Gas (per Mcf)	$	3.60	$	2.94	$	5.18
Oil (per Bbl)	$	64.72	$	73.89	$	75.88

Average Production Cost per BOE	$	23.22	$	22.24	$	18.36

(1) XTO Energy was the operator of the underlying properties until April 30, 2025. During that time, there was a two-month interval between the time of production and receipt of net profits income by the Trust. When Mach became operator on May 1, 2025, the interval increased to three months between time of production and receipt of net profits income by the Trust. This change in interval means that oil and gas sales for the year ended December 31, 2025, generally relate to 11 months of production for the period November through September.

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


	Underlying Gas Production (Mcf)
Conveyance	2025		2024		2023
Oklahoma		4,353,664		4,762,295		5,845,567
Wyoming		2,605,940		2,937,620		2,921,925
Kansas		554,934		561,614		630,280
Total		7,514,538		8,261,529		9,397,772


	Underlying Oil Production (Bbls)
Conveyance	2025		2024		2023
Oklahoma		159,118		178,951		201,461
Wyoming		5,288		5,574		6,267
Kansas		7,042		8,679		9,712
Total		171,448		193,204		217,440

Pricing and Sales Information

Prior to April 30, 2025, XTO Energy and on or after April 30, 2025, Mach sell most of their natural gas production directly to third parties, and a portion is sold to certain of XTO Energy’s or Mach’s, as applicable, wholly owned subsidiaries based on a weighted average sales price. The weighted average sales price received from the subsidiary is based upon sales to third parties for the best available price. Oil production is generally marketed at the wellhead to third parties at the best available price. Prior to April 30, 2025, XTO Energy or, on or after April 30, 2025, Mach arrange for some of their natural gas to be processed by unaffiliated third parties and market the natural gas liquids. Some of the natural gas attributable to the underlying properties is marketed under contracts existing at Trust inception. Contracts covering production from the Ringwood area of the Major County area are generally for the life of the lease. The contract with an unaffiliated third party for the majority of production from the Hugoton area is in effect through the life of the lease. If new contracts are entered with unaffiliated third parties, the proceeds from sales under those new contracts will be included in gross proceeds from the underlying properties. If new contracts are entered with any subsidiary of XTO Energy, or on or after April 30, 2025, Mach it may charge either XTO Energy or Mach, respectively, a fee that may not exceed 2 percent of the sales price of the oil and natural gas received from unaffiliated parties. The sales price is net of any deductions for transportation from the wellhead to the unaffiliated parties and any gravity or quality adjustments. For further information on these arrangements see “Significant Properties” above.

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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. The Trustee cannot predict the impact of future government regulation on any crude oil, condensate or natural gas liquids facilities, sales or transportation transactions by Mach.

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 to date.

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. The Trustee is unable to predict the operational and financial 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 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.

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

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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.

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.

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@hgt-hugoton.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.hgt-hugoton.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 Kansas, Oklahoma or Wyoming. Kansas and Oklahoma each impose a state income tax, which is potentially applicable to income from the net profits interests located in each of those states. Because the Trust distributes all of its net income to unitholders, the Trust is not taxed at the trust level in Kansas or Oklahoma. Oklahoma taxes the income of nonresidents from real property located within the state, and the Trust has been advised by counsel that Oklahoma will tax nonresidents on income from the net profits interests located within the state. Oklahoma also imposes 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). The Trust will not file an Oklahoma tax return for the 2025 tax year due to the fact that there were no revenues attributable to Oklahoma in that time period.

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Kansas also taxes the income of nonresidents from property located within the state. The Trust did not file a Kansas income tax return for the 2015 through 2021 and 2024 tax years due to the fact that there were no revenues, income, or deductions attributable to properties located in Kansas in that time period. The Trust will not file a Kansas income tax return for the 2025 tax year for the same reason.

Wyoming does not impose a state income tax.

Unitholders 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 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. Mach 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

As previously disclosed, XTO Energy advised the Trustee that it reached a settlement with the plaintiffs in the Chieftain class action royalty case. Based on the final plan of allocation approved by the court, XTO Energy advised the Trustee that it believes approximately $24.3 million in additional production costs should be allocated to the Trust. On May 2, 2018, the Trustee submitted a demand for arbitration seeking a declaratory judgment that the Chieftain settlement is not a production cost and that XTO Energy is prohibited from charging the settlement as a production cost under the conveyance or otherwise reducing the Trust’s payments now or in the future as a result of the Chieftain litigation (the "Chieftain Claim").

On January 20, 2021, the arbitration panel issued its Corrected Interim Final Award (i) “reject[ing] the Trust’s contention that XTO [Energy] has no right under the Conveyance to charge the Trust with amounts XTO [Energy] paid under section 1.18(a)(i) as royalty obligations to settle the Chieftain litigation” and (ii) stating “[t]he next phase will determine how much of the Chieftain settlement can be so charged, if any of it can be, in the exercise of the right found by the Panel.” Following briefing by both parties, on May 18, 2021, the Panel issued its second interim final award over the amount of XTO Energy’s settlement in the Chieftain class action lawsuit that can be charged to the Trust as a production cost.

In the arbitration, the Trustee also disputed certain amounts related to the computation of the Trust’s net proceeds for 2014 through 2019 and 2021 (the “Overhead Claims”).

On June 18, 2024, the Trustee and XTO Energy entered into a Settlement Agreement to resolve the pending arbitration. Pursuant to the Settlement Agreement, effective as of June 1, 2024, XTO Energy and the Trustee agreed:


•	that the value of the Chieftain Claim, with interest, to the benefit of XTO Energy is stipulated to be $18,105,467 (net to the Trust);
•	that the value of the Overhead Claims, with interest, to the benefit of the Trust is stipulated to be $17,275,086 (net to the Trust);
•	that the stipulated value of the Chieftain Claim and the Overhead Claims would be offset against one another, on a cumulative basis and without respect to which conveyance the particular claim arose, leaving a balance, to the benefit of XTO Energy of $830,381 (net to the Trust), which balance shall be treated as a production cost under the Oklahoma conveyance, and subject to the recoupment and interest charges under that conveyance; and

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      •

      that XTO Energy will provide the Trust a one-time advance distribution of $500,000 (net to the Trust), that can be treated as a production cost, except that it can be recouped, together with interest, from what would otherwise be distributable net profits under any of the three conveyances; provided, however that XTO Energy shall only be entitled to withhold distributions of net proceeds as recoupment to the extent that such recoupment does not leave the Trust with less than $250,000 of available cash.

The Trustee used the $500,000 advance distribution to partially replenish the Trust’s cash expense reserve in June 2024. The $830,381 balance due to XTO Energy was recorded as a production cost in third quarter 2024.

Additionally, the Settlement Agreement provided that XTO Energy would modify certain accounting practices with respect to the Overhead Claims effective as of June 1, 2024.

Other Lawsuits and Governmental Proceedings

Certain of the underlying properties are involved in various other lawsuits and governmental proceedings arising in the ordinary course of business. XTO Energy and Mach have each advised the Trustee that, based on the information available at this stage of the various proceedings, it does not believe that the ultimate resolution of these claims will have a material effect on the financial position or liquidity of the Trust, but may have an effect on annual distributable income.

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 began trading on the New York Stock Exchange on April 9, 1999, under the symbol “HGT.” On August 27, 2018, the Trust units were delisted from the NYSE and began to be quoted on the OTCQX, which is maintained by the OTC Market Group Inc., under the symbol “HGTXU.” The Trust transitioned from the OTCQX to the OTCQB on May 19, 2020. In May 2025, trading of the Trust units was moved to the Pink market due to the fact that the Trust’s cash position was such that it was unable to engage an audit firm for the 2025 fiscal year and was not able to file its quarterly report on Form 10-Q (“10-Q”) for the three months ended March 31, 2025, in a timely manner. On June 17, 2025, the Trust engaged its current auditor, Grant Thornton, and, subsequently, was able to file the 10-Q for the quarter ended March 31, 2025, on July 28, 2025. Subsequent 10-Qs have been filed timely, which brought the Trust back into compliance with OTCQB. On August 21, 2025, the Trust’s application to rejoin to OTCQB was approved and the Trust resumed trading on the OTCQB. Any quotations on the OTCQB reflect inter-dealer prices, without retail mark-up, mark-down, or commission and may not necessarily reflect actual transactions.

At March 23, 2026, there were 40,000,000 units outstanding and approximately 498 unitholders of record; 39,633,911 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 December 31						Three Months Ended December 31 (a)
	2025 (a)			2024 (b)			2025 (a)			2024 (b)
Sales Volumes
Gas (Mcf) (c)
Underlying properties		7,514,538			8,261,529			2,203,700			2,158,363
Average per day		22,499			22,572			23,953			23,460
Net profits interests		—			—			—			—

Oil (Bbls) (c)
Underlying properties		171,448			193,204			46,424			52,890
Average per day		513			528			505			575
Net profits interests		—			—			—			—

Average Sales Prices
Gas (per Mcf)	$	3.60		$	2.94		$	3.47		$	3.14
Oil (per Bbl)	$	64.72		$	73.89		$	62.54		$	71.53

Revenues
Gas sales	$	27,016,574		$	24,287,574		$	7,642,172		$	6,787,830
Oil sales		11,095,858			14,275,881			2,903,366			3,783,280
Total Revenues		38,112,432			38,563,455			10,545,538			10,571,110

Costs
Taxes, transportation and other		10,414,254			8,075,676			3,142,752			2,172,975
Production expense		19,689,380			22,579,104			4,842,096			5,430,311
Development costs		5,348,480			2,083,111			252,764			333,402
Overhead		13,378,580			12,347,477			2,781,246			2,881,484
Excess costs (d)		(10,700,020	)		(6,166,803	)		(473,320	)		82,371
Total Costs		38,130,674			38,918,565			10,545,538			10,900,543

Other Proceeds		18,242			355,110			—			329,433

Net Proceeds		—			—			0			—

Net Profits Percentage		80	%		80	%		80	%		80	%

Net Profits Income	$	—		$	—		$	—		$	—

(a)

XTO Energy was the operator of the underlying properties until April 30, 2025. During that time, there was a two-month interval between the time of production and receipt of net profits income by the Trust. When Mach became operator on April 30, 2025, the interval increased to three months between time of production and receipt of net profits income by the Trust. This change in interval means that: 1) oil and gas sales for the year ended December 31, 2025, generally relate to 11 months of production for the period November through September, and 2) oil and gas sales for the three months ended December 31, 2025, generally relate to production for the period July through September.

(b)

Because of the two-month interval between the time of production and receipt of net profits income by the Trust: 1) oil and gas sales for the year ended December 31, 2024, generally relate to 12 months of production for the period November through October, and 2) oil and gas sales for the three months ended December 31, 2024, generally relate to production for the period August through October.

(c)

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

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production volumes in any given period. Therefore, comparative discussion of oil and gas sales volumes is based on the underlying properties.

(d)

See Note 4 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 was $0 for both 2025 and 2024. This was primarily the result of decreased oil and gas production ($3.3 million), increased development costs ($2.6 million), increased taxes, transportation and other costs ($1.9 million), lower oil prices ($1.4 million), increased overhead ($0.8 million), and lower other proceeds ($0.3 million), partially offset by higher gas prices ($4.4 million), net excess costs activity ($3.6 million), and decreased production expense ($2.3 million).

Trust administration expense was $508,424 in 2025 as compared to $625,314 in 2024. Cash reserve activity was ($495,300) in 2025 and ($610,312) in 2024. Cash reserve activity for 2025 and 2024 included utilization of $495,300 and $610,312 respectively, for the payment of Trust expenses. Interest income was $13,124 in 2025 and $15,002 in 2024. Changes in interest income are attributable to fluctuations in net profits income, cash reserve and interest rates. Distributable income was $0 or $0.000000 per unit in 2025 and $0 or $0.000000 per unit in 2024.

Net profits income is recorded when received by the Trust, which is the month following receipt by Mach, and generally three months after oil and 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

Gas. Underlying gas sales volumes decreased 9 percent from 2024 to 2025 primarily because of timing of cash receipts, increased downtime and natural production decline.

Oil. Underlying oil sales volumes decreased 11 percent from 2024 to 2025 primarily because of timing of cash receipts and natural production decline.

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

Prices

Gas. The 2025 average gas price was $3.60 per Mcf, up 22 percent from the 2024 average gas price of $2.94 per Mcf. Natural gas prices are affected by the level of North American production, weather, crude oil and natural gas liquids 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 October 2025 through December 2025 was $3.73 per MMBtu. At March 16, 2026, the average NYMEX gas price for the following 12 months was $3.03 per MMBtu.

Oil. The average oil price for 2025 was $64.72 per Bbl, down 12 percent from the average oil price for 2024 of $73.89 per Bbl. Oil prices are expected to remain volatile. The average NYMEX price for October 2025 through December 2025 was $59.62 per Bbl. At March 16, 2026, the average NYMEX oil price for the following 12 months was $93.39 per Bbl.

Costs

The calculation of net profits income includes deductions for production expense, development costs and overhead since the related underlying properties are working interests.

Taxes, transportation and other. Taxes, transportation and other costs generally fluctuate with changes in total revenues. Taxes, transportation and other costs increased 29 percent from 2024 to 2025 primarily because of increased gas production taxes and gas deductions due to higher gas revenues.

Production expense. Production expense decreased 13 percent from 2024 to 2025 primarily because of decreased lease operating expenses.

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Development costs. Development costs increased 157 percent from 2024 to 2025 primarily because of timing of drilling costs related to non-operated wells in Major County, Oklahoma that were charged to the Trust in second quarter 2025. Changes in oil or natural gas prices could impact future development plans on the underlying properties.

Overhead. Overhead is charged by XTO Energy, Mach, and other operators for administrative expenses incurred to support operations of the underlying properties. Overhead fluctuates based on changes in the active well count and drilling activity on the underlying properties, as well as an annual cost level adjustment.

Excess costs. If monthly costs exceed revenues for any of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming), such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net proceeds from other conveyances. For further information on excess costs, including the balance and accrued interest by conveyance, see Note 4 to Financial Statements under Item 8. Financial Statements and Supplementary Data.

Other Proceeds. The calculation of net profits income for 2025 and 2024 included $0 ($0 net to the Trust) from Mach and $18,242 ($14,594 net to the Trust) and $355,110 ($284,088 net to the Trust) from XTO Energy, respectively, due to interest received on past due payments.

Fourth Quarter 2025 and 2024

Net profits income for fourth quarter 2025 was $0 as compared with $0 for fourth quarter 2024. This was primarily the result of increased taxes, transportation and other costs ($0.8 million), net excess costs activity ($0.4 million), lower oil prices ($0.4 million), and decreased oil production ($0.3 million), partially offset by higher gas prices ($0.6 million), decreased production expense ($0.5 million), higher natural gas production ($0.1 million), decreased overhead ($0.1 million), decreased development costs ($0.1 million), and decreased other proceeds ($0.3 million).

After adding interest income of $3,626, deducting administration expense of $125,379 and utilizing $121,753 of the cash reserve for the payment of Trust expenses, distributable income for fourth quarter 2025 was $0 or $0.000000 per unit. Distributable income for fourth quarter 2024 was $0 or $0.000000 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	$	0.000000
November 28, 2025	December 12, 2025		0.000000
December 31, 2025	January 15, 2026		0.000000
		$	0.000000

Volumes

Fourth quarter underlying gas sales volumes decreased 2 percent primarily because of timing of cash receipts and natural production decline. Underlying oil sales volumes increased 12 percent primarily because of timing of sales and natural production decline.

Prices

The average fourth quarter 2025 gas price was $3.47 per Mcf, up 11 percent from the fourth quarter 2024 average price of $3.14 per Mcf. The average fourth quarter 2025 oil price was $62.54 per Bbl, down 13 percent from the fourth quarter 2024 average price of $71.53 per Bbl. For further information about product prices, see “Years Ended December 31, 2025 and 2024 – Prices” above.

Costs

Taxes, transportation and other. Taxes, transportation and other costs increased 45 percent for the fourth quarter primarily because of increased production taxes due to higher gas revenues.

Production expense. Fourth quarter production expense decreased 11 percent primarily because of decreased lease operating costs.

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Development costs. Development costs decreased 24 percent for the fourth quarter primarily because of timing of drilling costs.

Overhead. Overhead is charged by XTO Energy, Mach and other operators for administrative expenses incurred to support operations of the underlying properties. Overhead fluctuates based on changes in the active well count and drilling activity on the underlying properties, as well as an annual cost level adjustment.

Excess costs. If monthly costs exceed revenues for any of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming), such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net proceeds from other conveyances. For information on excess costs, including the excess cost balance and accrued interest by conveyance, see Note 4 to Financial Statements under Item 8. Financial Statements and Supplementary Data.

Other Proceeds. The calculation of net profits income for the fourth quarter 2025 and 2024 included $0 ($0 net to the Trust) from Mach and $329,433 ($263,546 net to the Trust) from XTO Energy, respectively, due to interest received on past due payments.

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 net profits interests. 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 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.

The accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. Financial statements prepared on a going concern basis assume the realization of assets and the settlement of liabilities in the normal course of business.

Accumulated excess costs for the Kansas, Oklahoma and Wyoming conveyances have resulted in insufficient net proceeds to the Trust which have resulted in no unitholder distributions since July 2023, and a reduction in the Trust’s expense reserve. These conditions raise substantial doubt about the Trust’s ability to continue as a going concern as the Trust does not have sufficient cash to meet its obligations during the one-year period after the date that the financial statements are issued. Factors attributable to the cash shortage are primarily the previously disclosed development costs to drill four non-operated wells in Major County, Oklahoma, lower oil and natural gas prices, and excess cost positions on the Kansas, Oklahoma and Wyoming conveyances including accumulated interest.

The Trustee has prepared a preliminary budget estimating the administrative expenses for the year ending December 31, 2026, and the three months ending March 31, 2027, which assumes no cash inflow from either net profits income or from other sources other than the $500,000 second advance distribution from XTO Energy received in second quarter 2025, as described in Note 5 to the Financial Statements. Based on the preliminary budget, the Trust’s cash reserves will be depleted during the one-year period after the date that the financial statements are issued. The Trustee anticipates that the Trust's cash reserves will be depleted in the second quarter of 2026, after which the Trust will likely be unable to continue to make SEC filings, provide reporting to unitholders or provide audited financial statements or third-party reserve reports. To help control costs, the Trustee has reviewed all administrative functions and has attempted to reduce or eliminate costs for functions other than those required to comply with SEC regulations or the Trust Indenture; however, there can be no assurance that there will be sufficient funds available to continue such functions in the future. To further reduce administrative costs to the Trust, the Trustee has deferred payment of its monthly fee of approximately $7,300 since April 2024, and approximately $8,000 since April 2025. Nothing in the Trust Indenture obligates the Trustee to pay for the Trust's expenses if the Trust's expense reserve were to be completely depleted, and the Trustee currently does not intend to advance funds to the Trust.

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regarding interest in the Trust's assets but no interest has resulted from such discussions. As a result, the Trustee believes a potential sale of the Trust's assets may be unlikely in the near term, however it will continue to consider any and all viable options. Even if a sale of the Trust assets was to occur, there is no assurance that the proceeds would result in funds to distribute to unitholders after all financial obligations of the Trust are met. Any material sale of assets and/or termination of the Trust requires unitholder approval by at least 80 percent of all outstanding units.

On July 9, 2020, the Trustee notified XTO Energy of the Trustee’s claim to indemnification to the Trust Estate for all liability, expense, claims, damages or loss incurred by the Trustee in connection with the administration of the Trust. The Trustee stated it anticipates seeking reimbursement from XTO Energy upon depletion of the Trust’s cash reserve. XTO Energy responded that any indemnity claim to XTO Energy is premature before the Trust Estate is exhausted. XTO Energy's position remains unchanged. Each of XTO Energy and Mach have informed the Trustee that they currently have no intention of providing any additional financing or extending any credit to the Trustee or the Trust Estate beyond the outstanding one-time advance distributions that can be withheld by Mach from future net proceeds (Note 5).

The Trust’s financial statements do not include any adjustments that might result from the outcome of these uncertainties.

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 regulations, including carbon taxes, cap-and-trade policies and bans on drilling in certain areas or in certain ways. The Trustee anticipates that sustainability policies will increase the cost of carbon dioxide emissions over time. The Trustee is unable to predict the operational and financial 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

Mach operates approximately 78 percent of the underlying properties. In computing net proceeds, Mach deducts an overhead charge for reimbursement of administrative expenses on the underlying properties it operates. As of December 31, 2025, the monthly overhead charge, based on the number of operated wells, was approximately $921,000 ($737,000 net to the Trust) and is subject to annual adjustment based on an oil and gas industry index as defined in the Trust Indenture.

Certain of Mach’s wholly owned subsidiaries purchase natural gas and provide services for the properties operated by Mach. In the Hugoton area, Timberland provides gathering from the wellhead to DCP’s gathering system for approximately $0.75 per Mcf and an ExxonMobil affiliate purchases NGLs for a price based upon third-party sales. In January 2025, this Timberland gathering fee was escalated for inflation to approximately $0.98 per Mcf and retroactively applied to the prior two year period as permitted by the Timberland Gas Gathering agreement. A portion of the gas production in Major County, Oklahoma is sold to Ringwood Gathering Company (“RGC”) for a price based upon third-party sales. RGC retains approximately $0.31 per Mcf as a compression and gathering fee. For further information regarding natural gas sales from the underlying properties to affiliates of XTO Energy, see “Significant Properties,” under Item 2. Properties.

After the purchase of the properties underlying the Trust, total gas sales from the underlying properties to Mach’s wholly owned subsidiaries were $2 million in 2025, or 7 percent of total gas sales.

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.

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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.
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.

Oil and Gas Reserves

The proved oil and gas reserves for the underlying properties are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using 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 10 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 Mach’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 Mach 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, excess costs, reserve-to-production ratios, future production, development activities and associated operating expenses, future development plans by area, increased density drilling, 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 demand, the development and competitiveness of alternative energy sources, pricing differentials, proved reserves, future net cash flows, production levels, expense reserve budgets, availability of financing, arbitration, litigation, liquidity, financing, political and regulatory matters, such as tax and environmental policy, climate policy, trade barriers, tariffs, sanctions, competition, war and other political or security disturbances. Such forward-looking statements are based on Mach’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,” “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,

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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.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


	Page
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)	30
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 238)	31
Statements of Assets, Liabilities and Trust Corpus	32
Statements of Distributable Income	32
Statements of Changes in Trust Corpus	32
Notes to Financial Statements	33

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

Argent Trust Company and Unitholders

Hugoton Royalty Trust

Opinion on the Financial Statements

We have audited the accompanying statement of assets, liabilities and trust corpus of Hugoton Royalty Trust (the “Trust”) as of December 31, 2025, the related statements of distributable income and changes in trust corpus for the year ended December 31, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of the Trust as of December 31, 2025, and the distributable income and changes in trust corpus for the year ended December 31, 2025, in conformity with the modified cash basis of accounting described in Note 2 to the financial statements.

Substantial Doubt about the Trust’s Ability to Continue as a Going Concern

The accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. As discussed in Note 2 to the financial statements, accumulated excess costs have resulted in insufficient net proceeds to the Trust and a reduction in the Trust’s expense reserve that raise substantial doubt about its ability to continue as a going concern. The Trustee’s plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis of Accounting

As described in Note 2 to the financial statements, these financial statements have been prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on the Trust’s financial statements based on our audit. 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit 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 audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

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: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined that there are no critical audit matters.

/s/ GRANT THORNTON LLP

We have served as the Trust’s auditor since 2025.

Oklahoma City, Oklahoma

March 31, 2026

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Report of Independent Registered Public Accounting Firm

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

Opinion on the Financial Statements

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

Substantial Doubt about the Trust’s Ability to Continue as a Going Concern

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 audit. 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 audit of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit 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 audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides 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.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 31, 2025

We served as the Trust’s auditor from 2011 to 2025.

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HUGOTON ROYALTY TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS


	December 31
	2025		2024
Assets
Cash and short-term investments	$	238,435	$	233,736
Net profits interests in oil and gas properties - net (Notes 1 and 2)		—		—
	$	238,435	$	233,736

Liabilities and Trust Corpus
Distribution payable to unitholders	$	—	$	—
Expense reserve (a)(b)	$	238,435		233,736
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)		—		—
	$	238,435	$	233,736

(a)

The expense reserve allows the Trustee to pay its obligations should it be unable to pay them out of the net profits income.

(b)

Expense reserve partially replenished by one-time advance distribution of $500,000 from XTO Energy that was part of the Settlement Agreement between the Trust and XTO Energy. See Note 5 to Financial Statements.

STATEMENTS OF DISTRIBUTABLE INCOME


	Year Ended December 31
	2025			2024
Net profits income	$	—		$	—
Interest income		13,124			15,002
Total income		13,124			15,002
Administration expense		508,424			625,314
Cash reserves withheld (used) for Trust expenses		(495,300	)		(610,312	)
Distributable income	$	—		$	—
Distributable income per unit (40,000,000 units)	$	0.000000		$	0.000000

STATEMENTS OF CHANGES IN TRUST CORPUS


	Year Ended December 31
	2025		2024
Trust corpus, beginning of year	$	—	$	—
Distributable income		—		—
Distributions declared		—		—
Trust corpus, end of year	$	—	$	—

See accompanying notes to financial statements.

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HUGOTON ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

1. Trust Organization and Provisions

Hugoton Royalty Trust (the “Trust”) was created on December 1, 1998, by XTO Energy Inc. (formerly known as “Cross Timbers Oil Company” and, hereafter, “XTO Energy”). Effective on that date, XTO Energy conveyed 80% net profits interests in certain predominantly gas-producing working interest properties in Kansas, Oklahoma and Wyoming to the Trust under separate conveyances for each of the three states. In exchange for the conveyances of the net profits interests to the Trust, XTO Energy received 40 million units of beneficial interest in the Trust. The Trust’s initial public offering was in April 1999. The majority of the underlying working interest properties are currently owned and operated by Mach Natural Resources LP and its affiliates (“Mach”) (Note 8).

Effective April 10, 2023, Argent Trust Company (“Argent”) became the Trustee of the Trust. References herein to the Trustee for periods prior to April 10, 2023, shall refer to Simmons Bank, the former Trustee of the Trust. The Trust indenture provides, among other provisions, that:


1.	the Trust cannot 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 dispose of all or part of the net profits interests if approved by a vote of holders of 80 percent or more of the outstanding Trust units, or upon Trust termination. Otherwise, the Trust is required to sell up to 1 percent of the value of the net profits interests in any calendar year, pursuant to notice from Mach of its desire to sell the related underlying properties. Any sale must be for cash with 80 percent of the proceeds 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 to pay Trust liabilities if repaid in full 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 proceeds from the underlying properties falling below $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.

2. 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. 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.
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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Net profits interests in oil and gas properties

The initial carrying value of the net profits interests of $247,066,951 represents XTO Energy’s historical net book value for the interests on December 1, 1998, the date of the transfer to the Trust. During the second quarter 2016, the carrying value of the net profits interests was written down to its fair value of $28,801,000, resulting in an impairment of $57,306,527 charged directly to trust corpus. During the third quarter 2019, the carrying value of the net profits interests was written down to its fair value of zero, resulting in an impairment of $15,681,533 charged directly to trust corpus. Amortization of the net profits interests is calculated on a unit-of-production basis and charged directly to trust corpus. Accumulated amortization was $174,078,891 as of September 30, 2019, when the net profits interests was written down to its fair value of zero.

Liquidity and Going Concern

Accumulated excess costs for the Kansas, Oklahoma and Wyoming conveyances have resulted in insufficient net proceeds to the Trust which have resulted in no unitholder distributions since July 2023, and a reduction in the Trust’s expense reserve. These conditions raise substantial doubt about the Trust’s ability to continue as a going concern as the Trust does not have sufficient cash to meet its obligations during the one-year period after the date that the financial statements are issued. Factors attributable to the cash shortage are primarily the development costs to drill four non-operated wells in Major County, Oklahoma, lower oil and natural gas prices, and excess cost positions on the Kansas, Oklahoma and Wyoming conveyances including accumulated interest.

As previously disclosed, the Trustee has reviewed and may in the future review financing as an option to pay Trust obligations during the one-year period after the date the financial statements are issued; however, there can be no assurance that financing will be available on acceptable terms or at all. If financing became available to the Trust, it would have to be repaid, together with interest, and the Trust’s expense reserve would have to be replenished prior to any distributions to unitholders. The Trustee has sought sources of financing, but currently believes that financing in an amount sufficient to satisfy the Trust's long term liquidity needs is unlikely to be a viable option for the Trust moving forward. As a result, the Trustee has reviewed and intends to continue to review options for the Trust which may include alternatives to continuing as a going concern such as seeking to terminate the Trust or marketing the Trust's interest (which are net profits interests burdened by excess costs) for a potential sale. The Trustee has reached out to potential third parties regarding interest in the Trust's assets but no interest has resulted from such discussions. As a result, the Trustee believes a potential sale of the Trust's assets may be unlikely in the near term, however it will continue to consider any and all viable options. Even if a sale of the Trust assets was to occur, there is no assurance that the proceeds would result in funds to distribute to unitholders after all financial obligations of the Trust are met. Any material sale of assets and/or termination of the Trust requires unitholder approval by at least 80 percent of all outstanding units.

The Trust’s financial statements do not include any adjustments that might result from the outcome of these uncertainties.

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3. 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 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 for periods prior to April 30, 2025 or Mach in the second preceding month for periods after April 30, 2025, from the underlying properties, multiplied by 80%. Net proceeds are the gross proceeds received from the sale of production, less costs. Costs generally include applicable taxes, transportation, legal and marketing charges, production expense, development and drilling costs, and overhead.

XTO Energy or Mach, as owner of the underlying properties, compute net profits income separately for each of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming). If 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 the other conveyances (Note 4).

4. Excess Costs

If monthly costs exceed revenues for any of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming), such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net proceeds from other conveyances.

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


	Underlying
	KS		OK			WY		Total
Cumulative excess costs remaining at 12/31/24	$	1,263,171	$	1,093,891		$	7,421,195	$	9,778,257
Net excess costs (recovery) for the quarter ended 3/31/25		345,989		719,354			232,001		1,297,344
Net excess costs (recovery) for the quarter ended 6/30/25		244,538		3,594,804			832,707		4,672,049
Net excess costs (recovery) for the quarter ended 9/30/25		481,351		2,489,021			1,286,935		4,257,307
Net excess costs (recovery) for the quarter ended 12/31/25		149,166		(53,195	)		377,349		473,320
Cumulative excess costs remaining at 12/31/25		2,484,215		7,843,875			10,150,187		20,478,277
Accrued interest at 12/31/25		266,593		789,515			1,067,704		2,123,812
Total remaining to be recovered at 12/31/25	$	2,750,808	$	8,633,390		$	11,217,891	$	22,602,089


	NPI
	KS		OK			WY		Total
Cumulative excess costs remaining at 12/31/24	$	1,010,537	$	875,113		$	5,936,955	$	7,822,605
Net excess costs (recovery) for the quarter ended 3/31/25		276,791		575,483			185,601		1,037,875
Net excess costs (recovery) for the quarter ended 6/30/25		195,630		2,875,843			666,166		3,737,639
Net excess costs (recovery) for the quarter ended 9/30/25		385,081		1,991,217			1,029,548		3,405,846
Net excess costs (recovery) for the quarter ended 12/31/25		119,333		(42,556	)		301,879		378,656
Cumulative excess costs remaining at 12/31/25		1,987,372		6,275,100			8,120,149		16,382,622
Accrued interest at 12/31/25		213,274		631,612			854,164		1,699,050
Total remaining to be recovered at 12/31/25	$	2,200,646	$	6,906,712		$	8,974,313	$	18,081,671

For the year ended December 31, 2025, excess costs on properties underlying the Kansas net profits interests increased by $1,221,044 ($976,835 net to the Trust). This includes excess costs of $149,166 ($119,333 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 net profits interests were $6,749,984 ($5,399,987 net to the Trust). This includes excess cost recoveries of $53,195 ($42,556 net to the Trust) for the quarter ended December 31, 2025.

For the year ended December 31, 2025, excess costs on properties underlying the Wyoming net profits interests increased by $2,728,992 ($2,183,194 net to the Trust). This includes excess costs of $377,349 ($301,879 net to the Trust) for the quarter ended December 31, 2025.

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Underlying cumulative excess costs for the Kansas, Oklahoma and Wyoming conveyances remaining as of December 31, 2025, totaled $22.6 million ($18.1 million net to the Trust), including accrued interest of $2.1 million ($1.7 million net to the Trust).

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5. Advance Distributions

In the second quarter of 2024, XTO Energy provided the Trust an advance distribution of $500,000 (net to the Trust), that can be treated as a production cost, except that it can be recouped, together with interest, from what would otherwise be distributable net profits under any of the three conveyances; provided, however that XTO Energy shall only be entitled to withhold distributions of net proceeds as recoupment to the extent that such recoupment does not leave the Trust with less than $250,000 of available cash.


	NPI
	Total
Advance Distribution at 12/31/25	$	500,000
Accrued interest at 12/31/25		57,536
Total remaining to be recovered at 12/31/25	$	557,536

In the second quarter of 2025, XTO Energy provided the Trust with a second advance distribution of $500,000 (net to the Trust) that was intended to provide the Trustee of the Trust with liquidity to meet current and near-term financial reporting obligations. The second advance distribution can be recouped, together with interest, from what would otherwise be distributable net profits under any of the three conveyances; provided, however that recoupment from net proceeds shall only be permitted to the extent that such recoupment does not leave the Trust with less than $250,000 of available cash. Mach has assumed the right to recoup this advance following the conveyance of XTO Energy’s interest on April 30, 2025.


	Total
Advance Distribution at 12/31/25	$	500,000
Accrued interest at 12/31/25		22,081
Total remaining to be recovered at 12/31/25	$	522,081

6. Administration Expense

Administrative expenses are incurred so that the Trustee may meet its reporting obligations to the unitholders and regulatory entities and otherwise manage the administrative functions of the Trust. These obligations include, but are not limited to, all expenses, taxes, compensation to the Trustee for managing the Trust, fees to consultants, accountants, attorneys, transfer agents, other professional and expert persons, expenses for clerical and other administrative assistance, and fees and expenses for all other services. See Item 11. Executive Compensation, for further information on the remuneration received by the Trustee.

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 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 loss for tax purposes for the unitholders until the loss is recognized.

All revenues from the Trust are from sources within Kansas, Oklahoma or Wyoming. Because the Trust distributes all of its net income to unitholders, the Trust has not been taxed at the trust level in Kansas or Oklahoma. While the Trust has not owed tax, the Trustee is generally required to file Kansas and Oklahoma income tax returns reflecting the income and deductions of the Trust attributable to properties located in each state, along with a schedule that includes information regarding distributions to unitholders. However, the Trust will not file Kansas and Oklahoma income tax returns for the 2025 tax year due to the fact that there were no revenues attributable to properties located in Kansas and Oklahoma in that time period.

Wyoming does not impose a state income tax.

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

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8. Related Party Transactions

Total gas sales from the underlying properties to XTO Energy’s wholly owned subsidiaries were $2 million in 2025, or 7 percent of total gas sales, and $4.1 million in 2024, or 8 percent of total gas sales.

9. Contingencies

Litigation

Royalty Class Action and Arbitration

In the arbitration, the Trustee also disputed certain amounts related to the computation of the Trust’s net proceeds for 2014 through 2019 and 2021 (the “Overhead Claims”).


•	that the value of the Chieftain Claim, with interest, to the benefit of XTO Energy is stipulated to be $18,105,467 (net to the Trust);
•	that the value of the Overhead Claims, with interest, to the benefit of the Trust is stipulated to be $17,275,086 (net to the Trust);
•	that the stipulated value of the Chieftain Claim and the Overhead Claims would be offset against one another, on a cumulative basis and without respect to which conveyance the particular claim arose, leaving a balance, to the benefit of XTO Energy of $830,381 (net to the Trust), which balance shall be treated as a production cost under the Oklahoma conveyance, and subject to the recoupment and interest charges under that conveyance; and
•	that XTO Energy will provide the Trust an advance distribution of $500,000 (net to the Trust), that can be treated as a production cost, except that it can be recouped, together with interest, from what would otherwise be distributable net profits under any of the three conveyances; provided, however that XTO Energy shall only be entitled to withhold distributions of net proceeds as recoupment to the extent that such recoupment does not leave the Trust with less than $250,000 of available cash.

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Additionally, the Settlement Agreement provides that XTO Energy will modify certain accounting practices with respect to the Overhead Claims effective as of June 1, 2024.

As previously disclosed, the arbitration panel issued its second interim final award which resolved all issues in the arbitration and the claims are no longer a contingency.

Other Lawsuits and Governmental Proceedings

Certain of the underlying properties are involved in various other lawsuits and governmental proceedings arising in the ordinary course of business. XTO Energy and Mach have each advised the Trustee that, based on the information available at this stage of the various proceedings, they do not believe that the ultimate resolution of these claims will have a material effect on the financial position or liquidity of the Trust, but may have an effect on annual distributable income.

Other

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 by the Trust or unitholders for such amount.

10. Segment Reporting

The Trust has one business activity as the owner of an investment in net profits interests in oil and gas properties as reported in the accompanying Statements of Assets, Liabilities, and Trust Corpus, and operates in a single operating and reportable segment. Reportable segments are defined as components of an entity for which separate financial information is evaluated regularly by the chief operating decisions maker (the “CODM”), which is the Trustee. The segment participates in activities and derives its income from net profits interests in oil and gas properties as reported in the accompanying Statements of Distributable Income, and the CODM uses this in making decisions about the allocation of cash reserves for current and future Trust general and administrative expenses and the ultimate distribution (if any) to the Trust unitholders.

11. 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.

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.

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The standardized measure does not represent XTO Energy’s, Mach’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 and Mach, as applicable, 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 (Notes 3 and 4).

The average realized gas prices used to determine the standardized measure were $2.81 per Mcf in 2025, and $1.84 per Mcf in 2024. Oil prices used to determine the standardized measure were based on average realized oil prices of $62.83 per Bbl in 2025, and $72.57 per Bbl 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.

Proved Reserves


(in thousands)	Underlying Properties						Net Profits Interests
	Gas (Mcf)			Oil (Bbls)			Gas (Mcf)			Oil (Bbls)
Balance, December 31, 2023		79,022			1,434			7,329			171
Extensions, additions and discoveries		822			89			259			28
Revisions of prior estimates		(43,287	)		(338	)		(7,005	)		(164	)
Production - sales volumes		(8,262	)		(193	)		—			—
Sales in place		—			—			—			—
Balance, December 31, 2024		28,295			992			583			35
Extensions, additions and discoveries		755			104			326			45
Revisions of prior estimates		33,982			725			3,547			89
Production - sales volumes		(7,515	)		(171	)		—			—
Sales in place		—			—			—			—
Balance, December 31, 2025		55,517			1,650			4,456			169

Revisions of prior estimates of the proved gas reserves for the underlying properties in each year are primarily because of changes in the gas and oil prices. Revisions for the net profits interests may not correlate with underlying properties in any given year since the Trust’s allocated reserves reflect recovery of the Trust’s portion of production and development costs at 12-month average prices. Any conveyance where costs exceed revenues will result in zero allocated net profits interests reserves for that conveyance.

Proved Developed Reserves


(in thousands)	Underlying Properties				Net Profits Interests
	Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)
December 31, 2024		28,295		992		583		35
December 31, 2025		55,517		1,650		4,456		169

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Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves


(in thousands)	December 31
	2025		2024
Underlying Properties
Future cash inflows	$	269,272	$	123,976
Future costs:
Production		241,775		119,918
Development		—		—
Future net cash flows		27,497		4,058
10% discount factor		15,321		1,415
Standardized measure	$	12,176	$	2,643

Net Profits Interests
Future cash inflows	$	23,701	$	3,642
Future production taxes		1,703		396
Future net cash flows		21,998		3,246
10% discount factor		12,257		1,132
Standardized measure	$	9,741	$	2,114

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


(in thousands)	2025			2024
Underlying Properties
Standardized measure, January 1	$	2,643		$	23,764
Revisions:
Prices and costs		15,264			(43,642	)
Quantity estimates		(3,387	)		20,311
Accretion of discount		237			2,068
Future development costs		(5,348	)		(2,083	)
Production rates and other		(149	)		25
Net revisions		6,617			(23,321	)
Extensions, additions and discoveries		2,917			2,200
Production		(5,348	)		(2,083	)
Development costs		5,348			2,083
Sales in place		—			—
Net change		9,534			(21,121	)
Standardized measure, December 31	$	12,177		$	2,643

Net Profits Interests
Standardized measure, January 1	$	2,114		$	19,012
Extensions, additions and discoveries		2,334			1,760
Accretion of discount		189			1,654
Revisions of prior estimates, changes in price and other		5,104			(20,312	)
Sales in place		—			—
Net profits income		—			—
Standardized measure, December 31	$	9,741		$	2,114

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

On June 17, 2025, the Trustee approved the engagement of Grant Thornton LLP as the Trust’s new independent registered public accounting firm for the fiscal year ending December 31, 2025.

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ITEM 9A. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

The Trustee conducted an evaluation of the Trust’s disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, the Trustee has concluded that the Trust’s disclosure controls and procedures were effective as of the end of the period covered by this annual report. In its evaluation of disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on information provided by XTO Energy and Mach.

Trustee’s Report on Internal Control Over Financial Reporting

The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control— Integrated Framework (2013), the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2025.

Changes in Internal Control Over Financial Reporting

There were no changes in the Trust’s internal control over financial reporting during the quarter ended December 31, 2025, that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

The Trust has no directors or officers, and as a result, no such persons adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K, during the most recent fiscal quarter.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE


(a)	Directors, Officers and Committees. The Trust has no directors, executive officers, audit committee, audit committee financial expert, compensation committee or nominating committee. The Trustee is a corporate Trustee which may be removed, with or without cause, by the affirmative vote of the holders of a majority of all the units then outstanding.
(b)	Section 16(a) Beneficial Ownership Reporting Compliance. Section 16(a) of the Securities Exchange Act of 1934 requires that directors, officers, and beneficial owners of more than 10 percent of the registrant’s equity securities file initial reports of beneficial ownership and reports of changes in beneficial ownership with the Securities and Exchange Commission and the New York Stock Exchange. To the Trustee’s knowledge, based solely on the information furnished to the Trustee, the Trustee is unaware of any person that failed to file on a timely basis reports required by Section 16(a) filing requirements with respect to the Trust units of beneficial interest during and for the year ended December 31, 2025.
(c)	Code of Ethics. Because the Trust has no employees, it does not have a code of ethics. Employees of the Trustee, Argent Trust Company, must comply with the company’s code of ethics which may be found at www.argentfinancial.com.
(d)	Insider Trading Policy. Because the Trust does not have officers, directors, or employees, it has not adopted insider trading policies and procedures governing the purchase, sale and/or disposition of Trust securities by such persons.

ITEM 11. EXECUTIVE COMPENSATION


(a)	Compensation Committee Interlocks and Insider Participation/Compensation Committee Report. The Trust has no officers or directors and is administered by a trustee. The Trust does not have a compensation committee or maintain any equity compensation plans and there are no units reserved for issuance under any such plans.
(b)	Compensation of the Trustee. The Trustee was paid the following annual compensation for the fiscal years ended December 31, 2025 and 2024, as specified in the Trust indenture:


	2025		2024
Argent Trust Company, Trustee (1)	$	—	$	21,064

(1)

Under the Trust indenture, the trustee is entitled to an annual administrative fee, paid in equal monthly installments. Such fee can be adjusted annually based on an oil and gas industry index. Upon termination of the Trust, the trustee is entitled to a termination fee of $15,000. The Trustee has deferred payment of its monthly fee of approximately $7,400 since April 2024 and approximately $8,000 since April 2025.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS


(a)	Equity Compensation Plans and Trust Repurchases. The Trust has no equity compensation plans. The Trust has not repurchased any units during the fourth quarter of fiscal 2025.
(b)	Security Ownership of Certain Beneficial Owners. Based on the Trustee’s review of information filed with the SEC as of March 24, 2026, the following table sets forth information with respect to each person known to the Trustee to beneficially own more than 5 percent of the outstanding units.

(1)

Pursuant to a Schedule 13G/A filed January 19, 2024, Christopher John Heck reported as of December 31, 2023, he beneficially owned 6,220,500 units, of which he had sole voting and dispositive power with respect to 6,215,500 units and shared voting and dispositive power with respect to 5,000 units.

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(c)	Security Ownership of Management. The Trust has no directors or executive officers. Argent Trust Company, the Trustee, held as of March 23, 2026, no units in any fiduciary capacity.
(d)	Changes in Control. The Trustee knows of no arrangements which may subsequently result in a change in control of the Trust.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Prior to April 30, 2025, XTO Energy and, on or after April 30, 2025, Mach each respectively sell a portion of natural gas production from the underlying properties to certain of their wholly owned subsidiaries under contracts in existence when the Trust was created, generally at amounts approximating monthly published prices. For further information, see Item 2. Properties.

In computing net profits income paid to the Trust for the net profits interests, XTO Energy and Mach deduct an overhead charge for reimbursement of administrative expenses of operating the underlying properties. For further information, see Note 8 to Financial Statements under Item 8. Financial Statements and Supplementary Data.

As of March 10, 2026, neither XTO Energy nor Mach own any units.

See Item 11. Executive Compensation, for the remuneration received by the Trustee for the fiscal years ended December 31, 2024, through December 31, 2025.

As noted in Item 10. Directors, Executive Officers and Corporate Governance, the Trust has no directors, executive officers, audit committee, audit committee financial expert, compensation committee or nominating committee. The Trustee is a corporate trustee which may be removed, with or without cause, by the affirmative vote of the holders of a majority of all the units then outstanding.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Fees for services performed by PricewaterhouseCoopers LLP and Grant Thornton LLP for the years ended December 31, 2025 and 2024 are:


	2025		2024
Audit fees-PwC	$	83,000	$	226,000
Audit fees-Grant Thornton	$	157,500		—
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—
	$	240,500	$	226,000

As referenced in Item 10. Directors, Executive Officers and Corporate Governance, above, the Trust has no audit committee, and as a result, has no audit committee pre-approval policy with respect to fees paid to PricewaterhouseCoopers LLP and Grant Thornton LLP.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)

The following documents are filed as a part of this report:


1.	Financial Statements (included in Item 8 of this report)
	Report of Independent Registered Public Accounting Firm
	Statements of Assets, Liabilities and Trust Corpus at December 31, 2025 and 2024
	Statements of Distributable Income for the years ended December 31, 2025 and 2024
	Statements of Changes in Trust Corpus for the years ended December 31, 2025 and 2024
	Notes to Financial Statements

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2.	Financial Statement Schedules
	Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.
3.	Exhibits
	(4) (a)	Hugoton Royalty Trust Indenture by and between NationsBank, N.A., as Trustee, and Cross Timbers Oil Company (predecessor of XTO Energy) heretofore filed as Exhibit 4.1 to the Trust’s Registration Statement No. 333-68441 on Form S-1 filed with the Securities and Exchange Commission on December 4, 1998, is incorporated herein by reference.
	(b)	Amendment No. 1 to Amended and Restated Royalty Trust Indenture, dated March 24, 1999, of Hugoton Royalty Trust heretofore filed as Exhibit 4.1 to the Trust’s Current Report on Form 8-K filed with the Securities and Exchange Commission on April 5, 2023, is incorporated herein by reference.
	(c)	Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80% - Kansas) as amended and restated from Cross Timbers Oil Company (predecessor of XTO Energy) to NationsBank, N.A., as Trustee, dated December 1, 1998, heretofore filed as Exhibit 10.1.1 to the Trust’s Registration Statement No. 333-68441 on Form S-1 filed with the Securities and Exchange Commission on March 16, 1999, is incorporated herein by reference.
	(d)	Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80% - Oklahoma) as amended and restated from Cross Timbers Oil Company (predecessor of XTO Energy) to NationsBank, N.A., as Trustee, dated December 1, 1998, heretofore filed as Exhibit 10.2.1 to the Trust’s Registration Statement No. 333-68441 on Form S-1 filed with the Securities and Exchange Commission on March 16, 1999, is incorporated herein by reference.
	(e)	Net Overriding Royalty Conveyance (Hugoton Royalty Trust, 80% - Wyoming) as amended and restated from Cross Timbers Oil Company (predecessor of XTO Energy) to NationsBank, N.A., as Trustee, dated December 1, 1998, heretofore filed as Exhibit 10.3.1 to the Trust’s Registration Statement No. 333-68441 on Form S-1 filed with the Securities and Exchange Commission on March 16, 1999, is incorporated herein by reference.
	(10.1)	June 18, 2024 Settlement Agreement on Form 8-K filed with the Securities and Exchange Commission on June 21, 2024, is incorporated herein by reference.
	(8)(k)	Advanced Distribution Agreement dated April 30, 2025, by and between the Hugoton Royalty Trust and XTO Energy, Inc., is incorporated herein by reference.
	(23)	Consent of Cawley, Gillespie & Associates, INC
	(31)	Rule 13a-14(a)/15d-14(a) Certification
	(32)	Section 1350 Certification
	(97)	Hugoton Royalty Trust Executive Officer Compensation Recovery Policy is incorporated herein by reference.
	(99.1)	Cawley, Gillespie & Associates, INC

Copies of the above Exhibits are available to any unitholder, at the actual cost of reproduction, upon written request to the Argent Trust Company, 3838 Oak Lawn Ave, Suite 1720, Dallas, Texas 75219-4518.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.


	HUGOTON ROYALTY TRUST
	By	ARGENT TRUST COMPANY, TRUSTEE


Date: March 31, 2026	By	/s/ NANCY WILLIS
		Nancy Willis
		Director of Royalty Trust Services

(The Trust has no directors or executive officers.)

Name and Address

Amount and Nature
of Beneficial Ownership

Percent
of Class

Christopher John Heck

Granbury, TX 76049