CROSS TIMBERS ROYALTY TRUST

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

The net profits interests comprise:

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

The underlying properties include over 2,900 producing properties with established production histories in Texas, Oklahoma and New Mexico. The average reserve-to-production index for the underlying properties as of December 31, 2024, is approximately 11 years. This index is calculated using total proved reserves and estimated 2025 production for the underlying properties. The projected 2025 production is from proved developed producing reserves as of December 31, 2024. 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 38 percent natural gas and 62 percent oil. The underlying properties also include certain nonproducing properties in Texas, Oklahoma and New Mexico that are primarily mineral interests.

Producing Acreage, Wells and Drilling

90% Net Profits Interests Underlying Royalties. Royalty and overriding royalty properties underlying the 90% net profits interests represent approximately 67 percent of the discounted future net cash flows from the Trust’s net profits interests proved reserves at December 31, 2024. Approximately 56 percent of the discounted future net cash flows from the 90% net profits interests are from gas reserves, totaling 6.9 Bcf. Oil reserves allocated to the 90% net profits interests are primarily located in West Texas and are estimated to be 226,000 Bbls at December 31, 2024.

The underlying royalties are royalty and overriding royalty interests primarily located in mature producing oil and gas fields. The most significant producing region in which the underlying royalties are located is the San Juan Basin in northwestern New Mexico. The New Mexico royalties gas production accounted for approximately 65 percent of the Trust’s net profits interests gas sales volumes and 31 percent of the net profits income for 2024. The Trust’s net profits interests estimated proved gas reserves from New Mexico totaled 5.7 Bcf at December 31, 2024, or approximately 82 percent of Trust’s net profits interests total gas reserves at that date. The majority of these wells are operated by Hilcorp Energy Company or Simcoe LLC.

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

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

Because the properties related to the 90% net profits interests are primarily royalty interests and overriding royalty interests, the net profits income from these properties is not reduced by production or development costs, with the exception of a limited number of wells that were converted to working interest after conveyance that incur production and development costs. Additionally, net profits income from these interests cannot be reduced by any excess costs of the 75% net profits interests. The Trust, therefore, should generally receive monthly net profits income from these interests, as determined by oil and gas sales volumes and prices.

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

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

Trust’s net profits interests proved reserves from the 75% net profits interests are almost entirely oil, estimated to be approximately 243,000 Bbls and represent approximately 33 percent of the discounted future net cash flows of the Trust’s net profits interests proved reserves at December 31, 2024.

The underlying working interest properties are detailed below:

The underlying working interest properties consist of 3,714 gross (3,000 net) producing acres. As of December 31, 2024, there were 1,133 gross (65.1 net) productive oil wells. There were no wells drilled in 2024, six gross (0.68 net) wells drilled in 2023, and 15 gross (1.69 net) wells drilled in 2022. As operator of the Hewitt Unit, XTO Energy has advised the Trustee that it has no plans to drill in 2025.

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

Total underlying 2024 development costs were $1,509,510, up 42 percent from 2023 development costs of $1,061,887. Development costs were higher in 2024 primarily because of the timing of the receipt of costs for drilling activity that occurred in the second half of 2023 for the Hewitt Unit.

As reported to XTO Energy by unit operators in February of each year, underlying budgeted development costs were $0.2 million for 2024 and $1.4 million for 2023 ($0.1 million and $1.1 million, respectively, net to the Trust). Actual development costs often differ from amounts budgeted because of changes in product prices and other factors that may affect the timing or selection of projects. Also, costs are deducted in the calculation of Trust net profits income several months after they are incurred by the operator. Unit operators have reported underlying budgeted costs of approximately $0.75 million for 2025 and $0.85 million for 2026 ($0.56 million and $0.64 million, respectively, net to the Trust). Changes in oil or natural gas prices could impact future development plans on the underlying properties.

If monthly costs exceed revenues for any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits income from other conveyances. Remaining cumulative excess costs for the Texas working interest conveyance totaled $4.3 million ($3.2 million net to the Trust), including accrued interest of $1.1 million ($0.8 million net to the Trust) for the period ended December 31, 2024. For information regarding the effect of excess costs on Trust net profits income, see Note 7 to Financial Statements under Item 8. Financial Statements and Supplementary Data, including the excess cost balance and accrued interest by conveyance.

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, 2024:

(a)

Based on 12-month average oil price of $72.96 per Bbl and $3.55 per Mcf for gas, based on the first-day-of-the-month price for each month in the period.

(b)

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

(c)

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

Proved reserves at December 31, 2024, 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, and is performed by XTO Energy. As a result, XTO Energy has developed internal policies and controls for estimating and recording reserves. XTO Energy’s policies regarding booking reserves require proved reserves to be in compliance with the SEC definitions and guidance. XTO Energy’s policies assign responsibilities for compliance in reserves bookings to its reserve engineering group and require that reserve estimates be made by qualified reserves estimators, as defined by the Society of Petroleum Engineers’ standards. All qualified reserves estimators are required to receive education covering the fundamentals of SEC proved reserves assignments.

The XTO Energy reserve engineering group reviews reserve estimates with third-party petroleum consultants, Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents, Ltd. estimated oil and gas reserves attributable to the underlying properties as of December 31, 2024. Miller and Lents’ primary technical person responsible for calculating the Trust’s reserves has more than 13 years of experience as a reserve engineer. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net profits interests. Numerous uncertainties are inherent in estimating reserve volumes and values, and such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimates.

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

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

(a)

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

(b)

75% Net Profits Interests average production cost per BOE for 2022 is deflated due to the receipt of oil sales volumes from the operator of the North Cowden Unit in first quarter 2022. These oil sales had been reversed by the oil purchaser in fourth quarter 2021.

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

(a)

Texas working interest underlying oil production for 2022 is higher due to the receipt of oil sales volumes from the operator of the North Cowden Unit in first quarter 2022. These oil sales had been reversed by the oil purchaser in fourth quarter 2021.

Nonproducing Acreage

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

Pricing and Sales Information

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

Regulation

Natural Gas Regulation

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

Federal Regulation of Oil

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

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

Environmental Regulation

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

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

State Regulation

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

Federal Income Taxes

For federal income tax purposes, the Trust constitutes a fixed investment trust that is taxed as a grantor trust. A grantor trust is not subject to tax at the trust level. The unitholders are considered, for federal income tax purposes, to own the Trust’s income and principal as though no trust were in existence. The income of the Trust is deemed to have been received or accrued by each unitholder at the time 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 2024, 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.

Under the TCJA, for tax years beginning after December 31, 2017, and before January 1, 2026, 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, for such tax years, personal exemptions and miscellaneous itemized deductions are not allowed. Further, the U.S. federal income tax rate applicable to corporations is 21 percent, and such rate applies to both ordinary income and capital gains.

Individuals may also incur expenses in connection with the acquisition or maintenance of Trust units. For tax years beginning before January 1, 2018, and after December 31, 2025, these expenses, which are different from a unitholder’s share of the Trust’s administrative expenses discussed above, may 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, for tax years beginning after December 31, 2017, and before January 1, 2026, miscellaneous itemized deductions are not allowed.

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

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

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

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

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

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

State Income Taxes

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

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

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

State Tax Withholding

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

Other Regulation

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