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; 10 Table of Contents 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. 11 Table of Contents 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, 12 Table of Contents 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. 13 Table of Contents 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. 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. 14 Table of Contents 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. 15 Table of Contents 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 16 Table of Contents 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 17 Table of Contents 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 [email protected], 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. 18 Table of Contents 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.