Risk Factors Dashboard

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.

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.

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,

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.

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

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:

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

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.

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.

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.

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:

(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:

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.

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

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

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.

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:

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]

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:

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:

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.

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:

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.

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. Unitholders could incur significant losses on their investment in the Trust or lose their entire investment in the Trust altogether if the funds obtained from any such sale or liquidation of the net profits interests are such that there are no funds to distribute to unitholders after all financial obligations are met. 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.

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. 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. 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.

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

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