SAN JUAN BASIN ROYALTY TRUST

The Royalty conveyed to the Trust was carved out of Southland’s (now Hilcorp’s) working interests and royalty interests in certain properties situated in the San Juan Basin. See Item 1.Business for information on the conveyance of the Royalty to the Trust. References below to “gross” wells and acres are to the interests of all persons owning interests therein, while references to “net” are to the interests of Hilcorp (from which the Royalty was carved) in such wells and acres.

Unless otherwise indicated, the following information in this Item 2 is based upon data and information furnished to the Trustee by Hilcorp.

The Subject Interests

The Subject Interests consist of working interests, royalty interests, overriding royalty interests and other contractual rights in 151,900 gross (119,000 net) producing acres in San Juan, Rio Arriba and Sandoval Counties of northwestern New Mexico. According to the information provided by Hilcorp, there were, as of December 31, 2023, 4,371 gross (827.4 net) wells on the properties underlying the Subject Interests, calculated on a well bore basis and not including multiple completions as separate wells, of which approximately 998 gross (287.9 net) wells were Multiple Completion Wells, resulting in a total of 5,444 gross (1,148.5 net) completions.

Hilcorp has informed the Trust that all of the subject acreage is held by production, and even though it has not been fully developed in every formation, Hilcorp has classified all of such acreage as developed. Production from conventional natural gas wells is primarily from the Pictured Cliffs, Mesaverde and Dakota formations, ranging in depth from 1,500 to 8,000 feet. Additional production is attributable to coal seam reserves in the Fruitland Coal formation.

Coal seam natural gas constituted approximately 10.6% of the Trust’s proved natural gas reserves as of December 31, 2023. The process of removing coal seam natural gas is often referred to as degasification or desorption. Millions of years ago, natural gas was generated in the process of coal formation and absorbed into the coal. Water later filled the natural fracture system. When the water is removed from the natural fracture system, reservoir pressure is lowered, and the natural gas desorbs from the coal. The desorbed natural gas then flows through the fracture system and is produced at the well bore. The volume of formation water production typically declines with time and the natural gas production may increase for a period of time before starting to decline. Typically, the volumes of natural gas produced from a Coal Seam Well decline more rapidly than those of Conventional Wells. In order to dispose of the formation water, surface facilities including pumping units are required. The price of coal seam natural gas is typically lower than the price of conventional natural gas. This is because the heating value of coal seam natural gas is much lower than that of conventional natural gas due to (i) ever increasing percentages of carbon dioxide in coal seam natural gas (carbon dioxide has no heating value), and (ii) the absence of heavier hydrocarbons such as ethanes, propanes, and butanes, which are present in conventional natural gas. Furthermore, the production costs and processing fees for coal seam natural gas are typically higher than the processing fees for conventional natural gas due to the cost of extracting the carbon dioxide.

The Royalty conveyed to the Trust is limited to the base of the Dakota formation, which is currently the deepest significant producing formation under acreage affected by the Royalty. Rights to production, if any, from deeper formations are retained by Hilcorp.

2024 Capital Expenditure Budget

On February 16, 2024, the Trust announced that Hilcorp had provided the Trust with its 2024 capital project plan for the Subject Interests (the “2024 Plan”), and Hilcorp has estimated its 2024 capital expenditures for the Subject Interests to be $36.0 million. This plan was updated on March 6, 2024, with a reduction of approximately $2.0 million, bringing the total estimate of 2024 capital expenditures to $34.0 million.

Hilcorp informed the Trust that its 2024 Plan will allocate approximately $25.0 million of the 2024 Plan’s budget toward two drilling projects in the Mancos formation. Approximately $8.0 million of the 2024 Plan’s budget will be allocated to 36 well recompletions and workovers scheduled to be completed in the Mesaverde and Fruitland Coal formations. Approximately $1.0 million of the 2024 Plan’s budget will be allocated to facilities projects related to natural gas compression. Hilcorp further informed the Trust that its planned project status for 2024 is subject to revision if Hilcorp revises its assumptions underlying the 2024 Plan, in which event the actual capital costs may vary from these estimates.

Oil and Natural Gas Production

The natural gas volumes reported to the Trust by Hilcorp are based on plant residue gas volumes plus equivalent volumes for natural gas liquids. Hilcorp converts one barrel of natural gas liquids to six Mcf of natural gas using industry standards. Production of oil and natural gas and related average sales prices attributable to each of the Subject Interests and the Royalty for each of the two years ended December 31, 2023, were as follows:

Production costs for natural gas and oil attributable to the Subject Interests for the two years ended December 31, 2023, were as follows:

Based on Hilcorp’s reporting methodology, the Trust recognizes production during the month in which the related Royalty Income is paid to the Trust. Royalty Income for a calendar year is based on the actual natural gas and oil production during the period beginning with November of the preceding calendar year through October of the current calendar year. Sales volumes attributable to the Royalty are determined by dividing the net profits by the Trust from the sale of oil and natural gas, respectively, by the prices received for sales of such volumes from the Subject Interests, taking into consideration production taxes attributable to the Subject Interests. Because the oil and natural gas sales attributable to the Royalty are based upon an allocation formula dependent on such factors as price and cost, including capital expenditures, the aggregate sales amounts from the Subject Interests may not provide a meaningful comparison to sales attributable to the Royalty.

Production from the Subject Interests is influenced by the line pressure of the natural gas gathering systems in the San Juan Basin. As noted above, oil and natural gas sales attributable to the Royalty are based on an allocation formula dependent on many factors, including oil and natural gas prices and capital expenditures.

Marketing

Natural gas produced in the San Juan Basin is sold in both interstate and intrastate commerce. Please refer to the discussion contained herein under “Regulation” for information as to federal regulation of prices of oil and natural gas. As part of the transition from Burlington to Hilcorp, Hilcorp has assumed, or been assigned, all the natural gas purchase, gathering and processing contracts affecting the Subject Interests. Natural gas produced from the Subject Interests is processed at the following sites: Chaco, Val Verde, Milagro, Ignacio or Kutz plants, all located in the San Juan Basin. Hilcorp sells natural gas produced from the Subject Interests under various contracts.

Hilcorp’s sales contracts with Chevron Natural Gas (“Chevron”) and EDF Trading North America LLC (“EDF”) automatically renewed for an additionalone-year term and now expire on March 31, 2025. Each of Hilcorp’s sales contracts with EDF and Chevron provides for (i) the delivery of such natural gas at various delivery points through their respective termination dates and (ii) the sale of such natural gas at prices that fluctuate in accordance with published indices for natural gas sold in the San Juan Basin. Hilcorp’s natural gas sales contract with New Mexico Gas Company, Inc. automatically renewed for an additionalone-year term and now expires on March 31, 2025. The contract provides for the sale of certain winter-only natural gas supplies processed at the Kutz plant at prices that fluctuate in accordance with published indices for natural gas sold in the San Juan Basin.

Hilcorp contracts with Enterprise Field Services, LLC (“EFS”) for the gathering and processing of certain natural gas produced from the Subject Interests. Hilcorp’s predecessor signed an agreement with EFS which was effective November 1, 2011, for a term of 15 years. Hilcorp’s predecessor has disclosed to the Trust a summary of that agreement which the Trust has reviewed with its consultants, subject to conditions of confidentiality.

Hilcorp’s predecessor entered into four contracts with Williams Four Corners, LLC (“WFC”), each of which is effective for a term of 15 years commencing April 1, 2010. The EFS and WFC contracts covered the gathering and processing of virtually all of the natural gas produced from the Subject Interests. On October 1, 2018, Harvest Midstream I, L.P., an affiliated midstream company of Hilcorp, completed the acquisition of WFC’s gas pipeline and processing facilities in the San Juan Basin. The Conveyance sets forth the processing costs that Hilcorp can charge for bothnon-affiliates and affiliates.

The Trust is not a party to any of the purchase, gathering or processing contracts, and thus the Trust has limited ability to know or affect all of the terms of such contracts. As part of the 1996 settlement of litigation filed by the Trustee in 1992 against Burlington and Southland, the Trustee and Burlington established a formal protocol pursuant to which compliance auditors retained by the Trustee have access to Burlington and its successors’ books and records, which protocol has been adopted by Hilcorp.

Oil and Natural Gas Reserves

Proved Reserves

All of the Trust’s reserves are located in the San Juan Basin. Total proved Developed and Undeveloped Oil and Natural Gas Reserves attributable to the Royalty as of December 31, 2023, were as follows:

Estimated quantities of proved Developed Oil and Natural Gas Reserves attributable to the Royalty as of December 31, 2023 and 2022 were as follows:

Proved Undeveloped Reserves

Based on information provided by Hilcorp and analysis by the Trust’s independent reserve engineer, there were 9,135 MMcf of proved undeveloped reserves identified as of December 31, 2023. There were no proved undeveloped reserves identified in 2022. The increase in proved undeveloped reserves was due to Hilcorp’s plan for two drilling projects in the Mancos formation in 2024.

Internal Controls over Reserves Estimates

The process of estimating oil and natural gas reserves is complex and requires significant judgment. The Trust, however, does not have the same level of information that generally would be available to a company with oil and natural gas operations because detailed information generally is not available to owners of royalty interests. Thus, the Trustee relies upon accumulated information and data solely provided by Hilcorp regarding the Royalty derived from the Subject Interests and provides such information for the Trust’s auditing purposes to Cawley, Gillespie & Associates, Inc. (“CG&A”). CG&A extrapolates from such Hilcorp-provided information estimates of the reserves attributable to the Subject Interests based on its expertise in the oil and natural gas fields where the Subject Interests are situated, as well as other publicly available information, and provides the results to the Trust.

The Trust maintains internal controls and procedures applicable to reserve estimation, which are reviewed annually and updated as required, and the Trust reviews the reserve reports prepared by CG&A for reasonableness. The Trust’s internal controls and procedures regarding reserve estimates require proved reserves to be determined and disclosed in compliance with SEC definitions and guidance.

Third-Party Reserves

The Trust does not maintain an internal petroleum engineering department and instead relies upon CG&A for a qualified, independent report of estimated reserves. The Trust has verified the qualifications and credentials of CG&A to prepare reserve estimates on behalf of the Trust. The independent petroleum engineers’ reports as to the proved oil and natural gas reserves as of December 31, 2022 and 2023 were prepared by CG&A. CG&A, whose firm registration number is F-693, was founded in 1961 and is nationally recognized in the evaluation of oil and natural gas properties. The technical person at CG&A primarily responsible for overseeing the reserve estimate with respect to the Trust is Zane Meekins. Mr. Meekins has been a practicing petroleum engineering consultant since 1989, with over 35 years of practice experience in petroleum engineering and is a registered professional engineer in the State of Texas (License No. 71055). Mr. Meekins graduated from Texas A&M University in 1987,summa cum laude, with a B.S. in Petroleum Engineering. Both CG&A and Mr. Meekins have indicated that they meet or exceed all requirements set forth in Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Regulation

General

Exploration for and production and sale of oil and natural gas are extensively regulated at the national, state, and local levels. These laws may govern a wide variety of matters, including allowable rates of production, transportation, marketing, pricing, well construction, water use, prevention of waste, waste disposal, pollution, and protection of the environment. These laws, regulations and orders have in the past, and may again, restrict the rate of oil and natural gas production below the rate that would otherwise exist in the absence of such laws, regulations, and orders.

Laws affecting the oil and natural gas industry and the distribution of its products are under constant review for amendment or expansion, frequently increasing the regulatory burden on operations. Numerous governmental departments and agencies are authorized by statute to issue, and have issued, rules and regulations binding on the oil and natural gas industry. Compliance with applicable laws is often difficult and costly, whilenon-compliance may result in substantial penalties. Such costs and penalties may affect the amount of Net Proceeds attributable to the Royalty that are paid to the Trust by Hilcorp or by subsequent operators of the Subject Interests.

Natural Gas

The transportation and resale of natural gas in interstate commerce, historically, have been regulated pursuant to several laws enacted by Congress and the regulations promulgated under these laws by the Federal Energy Regulatory Commission (“FERC”) and its predecessor. In the past, the federal government has regulated the prices at which natural gas could be sold in interstate commerce. Congress removed all price andnon-price controls affecting wellhead sales of natural gas under the Natural Gas Wellhead Decontrol Act effective January 1, 1993. Congress could, however, reenact controls in the future.

Any transportation of crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180 (“HMR”), including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.

Sales of natural gas are affected by the availability, terms, and cost of transportation. The price and terms for pipeline transportation remain subject to extensive federal and state regulation. Several major regulatory changes have been implemented by Congress and FERC from 1985 to the present that affect the economics of natural gas production, transportation, and sales. In addition, FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry.

Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts. The Trust cannot predict when or if any such proposals might become effective, or their effect, if any, on the Trust. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach to natural gas sales pursued since 1993 by FERC and Congress will continue.

Sales of crude oil, condensate and gas liquids are not currently regulated and are made at market prices. The ability to transport and sell petroleum products depends on pipelines that transport such products in interstate commerce and FERC regulates the rates, terms, and conditions of service by such pipelines under the Interstate Commerce Act.

Any such price ornon-price control regulations may affect the amount of Royalty and Royalty Income that is paid to the Trust by Hilcorp or subsequent operators of the Subject Interests.

Environmental Regulation

General. Activities on the Subject Interests are subject to existing stringent and complex federal, state and local laws (including case law) and regulations governing health, safety, environmental quality and pollution control. Those requirements have frequently changed, and new programs may be even more stringent. Failure to comply with applicable health, safety and environmental laws, rules and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the operations on the Subject Interests. Accordingly, these regulations often require difficult and costly compliance measures.

Waste Handling.The Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous andnon-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes the operators of the Subject Interests generate presently or in the future could be subject to regulation under RCRA and state analogs.* *Legislation has been proposed from time to time in Congress tore-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” If the EPA proposes a rulemaking for revised oil and gas waste regulations in the future, any such changes in the laws and regulations could have a resulting increase in production costs that may affect the amount of Royalty and Royalty Income that is paid to the Trust by Hilcorp or subsequent operators of the Subject Interests.

Cleanup. Under certain environmental laws and regulations, the operators of the Subject Interests could be subject to strict, joint and several liability for the removal or remediation of property contamination, whether at a drill site or a waste disposal facility, even when the operators did not cause the contamination, or their activities were in compliance with all applicable laws at the time the actions were taken. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund” law, for example, imposes liability, regardless of fault or the legality of the original conduct, on certain classes of persons for releases into the environment of a “hazardous substance.” Liable persons may include the current or previous owner and operator of a site where a hazardous substance has been disposed and persons who arranged for the disposal of a hazardous substance at a site. Under CERCLA and similar statutes, government authorities or private parties may take actions in response to threats to the public health or the environment and sue responsible persons for the associated costs; government authorities also may direct responsible persons to implement cleanup measures. Although CERCLA excludes “petroleum” from the definition of hazardous substance, in the course of operations, the working interest owner and/or the operator of Subject Interests may have generated and may generate materials that fall outside of this exclusion and that could trigger cleanup liabilities. In addition, the Subject Interests have produced oil and/or natural gas for many years, and previous operators may have disposed or released hydrocarbons, wastes or hazardous substances at the Subject Interests. The operator of the Subject Interests or the working interest owners may be responsible for all or part of the costs to clean up any such contamination. Although the Trust is not the operator of any Subject Interests, or the owner of any working interest, its ownership of the Royalty could cause it to be responsible for all or part of such costs to the extent CERCLA, or any similar statute, imposes responsibility on such parties as “owners.”

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act (“CWA”), the Safe Drinking Water Act, the Oil Pollution Act of 1990 (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into waters of the United States (“WOTUS”), as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or applicable state analog. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit from the U.S. Army Corps of Engineers (the “Corps”). In May 2023, the U.S. Supreme Court’s decision inSackett v. EPA narrowed federal jurisdiction over wetlands to “traditional navigable waters” and wetlands or other waters that have a “continuous surface connection” with or are otherwise indistinguishable from traditional navigable water. In September 2023, the EPA and the Corps published adirect-to-final rule that conforms the regulatory definition of WOTUS to the Supreme Court’s May 2023 decision inSackett. In the wake of theSackett decision, several states have developed their own wetlands policies or regulatory programs to address discharges to intra-state waters that may no longer be regulated as WOTUS.

The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. EPA and various states also impose permitting requirements for the disposal of produced water by underground injection.

The OPA is the primary federal law for oil spill liability and contains numerous requirements relating to the prevention of and response to petroleum releases into WOTUS, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

These permitting requirements could create additional production costs, and any noncompliance with the CWA or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations that the operator of the Subject Interests or the working interest owners may be responsible.

Climate Change. Mitigating climate change has become the subject of an important public policy debate and the basis for new legislation proposed by the United States Congress and certain states. Some states have adopted climate change statutes and regulations, and the Biden Administration has pursued executive actions to address climate change. At the international level, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change (“UNFCCC”) resulted in nearly 200 countries, including the United States, coming together to develop the Paris Agreement, intended to nationally determine their contributions and set greenhouse gas (“GHG”) emission reduction goals every five years beginning in 2020. In February 2021, as a party to the Paris Agreement, the U.S. announced a target to achieve a 50% to 52% reduction from 2005 levels in economy-wide GHG emissions by 2030. Accordingly, the Biden administration has set ambitious domestic targets for curbing climate change, such as making the U.S. power sector climate neutral by 2035 and achieving anet-zero emissions economy by 2050. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030, including “all feasible reductions” in the energy sector.

The Inflation Reduction Act (“IRA”) was signed into law in August 2022 and contains many provisions that address climate change by creating incentives to use alternative fuels and sources of energy: Methane Emissions and Waste Reduction Incentive Program, which requires the EPA to impose a “waste emissions charge” on certain natural gas and oil sources that are already required to report under the EPA’s Greenhouse Gas Reporting Program. To implement the program, the IRA requires revisions to GHG reporting regulations for petroleum and natural gas systems (Subpart W) by 2024. In July 2023, the EPA proposed to expand the scope of the Greenhouse Gas Reporting Program for petroleum and natural gas facilities, as required by the IRA. Among other things, the proposed rule would expand the emissions events that are subject to reporting requirements to include “other large release events” and apply reporting requirements to certain new sources and sectors. The rule is expected to be finalized in the spring of 2024 and become effective on January 1, 2025, in advance of the deadline for GHG reporting for 2024 (March 2025). The fee imposed under the Methane Emissions and Waste Reduction Incentive Program for 2024 would be $900 per ton emitted over annual methane emissions thresholds, and would increase to $1,200 in 2025, and $1,500 in 2026. The Methane Emissions Reduction Program in the IRA (Sec. 60113) also gives the Environmental Protection Agency (“EPA”) the ability to impose charges on methane emitted by certain oil and gas companies. The charges will start in 2024 and apply to facilities that emit over 25,000 metric tons of carbon dioxide equivalent unless exemptions are available. Funding under the IRA also provides grant money for methane and greenhouse gas emission mitigation activities.

The IRA aims to reduce U.S. GHG emissions by approximately 40% by 2030 compared with 2005 levels and put the United States on course for its commitment to attain anet-zero economy by 2050. In addition, many state and local governments have intensified or stated their intent to intensify efforts to support international climate commitments and treaties, in addition to developing programs that are aimed at reducing GHG emissions by means of cap and trade programs, carbon taxes, the development of greenhouse gas inventories or encouraging the use of renewable energy or alternativelow-carbon fuels. The impact such regulation may have on the amount of Royalty and Royalty Income paid to the Trust by Hilcorp or subsequent operators of the Subject Interests is difficult to predict.

In addition, federal agencies are building upon their existing programs, like those governed by the Clean Air Act, as amended (the “CAA”), to impose new climate controls. In 2009, EPA issued an “Endangerment Finding” under Section 202(a) of the CAA, concluding GHG pollution threatens the public health and welfare of future generations. And EPA has required annual reporting of GHG for persons operating certain types of industrial facilities, including oil and natural gas production, transmission and storage operations that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The data collected through the reporting rules has helped to provide a basis for promulgating GHG emission limits.

Air Emissions.** The CAA and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits. As a result, operators may need to incur capital costs in order to remain in compliance. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief fornon-compliance with air permits or other requirements of the CAA and associated state laws and regulations. The operators of the Subject Interests are responsible for maintaining compliance with all applicable air emissions regulations and holding all necessary and valid construction and operating permits for operations.

A number of those rules have addressed emissions from the oil and gas industry. On August 16, 2012, for example, the EPA issued a final rule that established new source performance standards for volatile organic compounds (“VOCs”) and sulfur dioxide, an air toxics standard for sources of oil and natural gas production, and an air toxics standard for sources of natural gas transmission and storage. That rule generally required all hydraulically fractured or refractured natural gas wells to be completed usingso-called “green completion” technology, which significantly reduces VOC emissions. Limiting those emissions of VOCs has theco-benefit of also limiting methane, a greenhouse gas. These regulations, referred to as New Source Performance Standards (“NSPS”) Subpart OOOO, also apply to storage tanks and other equipment in the affected oil and natural gas industry segments. In May 2016, EPA issued a suite of new final regulations, referred to as NSPS Subpart OOOOa, designed to limit methane, VOCs, and other emissions from new and existing sources in the oil and natural gas sector. Among other things, these rules applied green completion requirements to newly fractured andre-fractured oil wells. Rulemaking concerning regulation of greenhouse gas and other emissions from the oil and natural gas industry continues. In December 2023, EPA finalized new rules for oil and gas sources that would (i) ensure all wells are routinely monitored for leaks, (ii) encourage use of innovative and advanced monitoring, (iii) impose strengthened emission standards for certain equipment, and (iv) require states to reduce methane emissions from existing sources. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply. States have also begun to regulate through their New Source Performance Standards (“NSPS”) and other air emissions programs the emission of VOCs and methane from oil and gas production process equipment, storage tanks and produced water impoundments and other assets. The ultimate scope of these regulations remains uncertain; however, any resulting increase in production costs may affect the amount of Royalty and Royalty Income that is paid to the Trust by Hilcorp or subsequent operators of the Subject Interests.

The oil and gas industry also is likely to be indirectly affected by EPA rulemakings covering other industry sectors. For example, in 2015 EPA promulgated its Clean Power Plan, which imposed greenhouse gas emissions limits on U.S. power plants. In the Trump Administration, EPA replaced the Clean Power Plan with the Affordable Clean Energy rule, which interpreted the Clean Air Act as limiting the scope of the federal government’s authority to establishing only source-specific (or “inside the fence line”) emissions reduction requirements for coal-fired power plants. The D.C. Circuit vacated the Affordable Clean Energy rule, but the Supreme Court reversed the vacatur and ruled the Clean Power Plan was invalid. On May 11, 2023, the EPA issued a proposed rulemaking to replace the Affordable Clean Energy rule with new standards governing emissions from fossil-fuel-fired power plants(EPA-HQ-OAR-2023-0072) and supplemented its proposal on November 15, 2023. The EPA therefore may adopt more stringent limits on GHG emissions and incentivize alternative energy sources. Adoption of any such requirements could reduce demand for oil and gas generally, including oil and natural gas produced from the Subject Interests, and could increase the cost of operations of the Subject Interests, which could result in a loss of reserves or revenues to the Trust. The impact such regulation may have on the amount of Royalty and Royalty Income paid to the Trust by Hilcorp or subsequent operators of the Subject Interests is difficult to predict.

On January 20, 2021, President Biden signed an executive order that reversed the United States’ withdrawal from the Paris Agreement, and the United States formally rejoined the Paris Agreement on February 19, 2021. At the federal regulatory level, both the EPA and the Bureau of Land Management (“BLM”) have adopted regulations for the control of methane emissions, which also include leak detection and repair requirements, from the oil and gas industry. Additionally, President Biden has issued an executive order seeking to adopt new regulations and policies to address climate change and suspend, revise or rescind prior agency actions that are identified as conflicting with the Biden Administration’s climate policies. In addition, President Biden has declared that he supports federal government efforts to limit or prohibit hydraulic fracturing and banning new leases for production of minerals on federal properties, including onshore lands. Any of these actions could require Hilcorp to increase capital expenditures for the Subject Interests, decrease demand for natural gas and oil production, or limit the Subject Interests’ ability to produce natural gas or oil production. The Trust is unable to determine what, if any, the effects of such actions will have on the Subject Interests’ ability to produce natural gas and oil, and Hilcorp’s ability to pay Royalty Income to the Trust.

Hilcorp has informed the Trust that it does not believe that actions undertaken by President Biden’s administration to curtail future leases for natural gas and oil drilling on federally owned land will impact the Subject Interests because, at the present time, they do not impact current leases.

The Biden administration announced in September 2023 that it has moved to shut down future development of oil, gas and mining activity on approximately 4,200 acres in Sandoval County, New Mexico for the next 50 years. Hilcorp has informed the Trust that the proposed tracts are not within the production area of the Subject Interests or part of any future proposed development plans.

Certain Tax Considerations

The classification of the Trust’s income for purposes of the passive loss rules may be important to a Unit Holder. As a result of the Tax Reform Act of 1986, royalty income such as that derived through the Trust will generally be treated as portfolio income that may not be offset or reduced by passive losses.

The Trustee has been informed that the New Mexico Oil and Gas Proceeds and Pass-Through Entity Withholding Tax Act (the “Withholding Tax Act”) requires remitters who pay certain oil and natural gas proceeds from production on New Mexico wells to withhold income taxes from such proceeds in the case of certain nonresident recipients. The Trustee, on advice of New Mexico counsel, has observed that “net profits interests” (such as the Royalty) and other types of interests (the extent of which cannot be determined with respect to a specific share of the oil and natural gas production), as well as amounts deducted from payments that are for expenses related to oil and natural gas production, are excluded from the withholding requirements of the Withholding Tax Act. Unit Holders should consult with their individual tax advisors regarding the applicability of the Withholding Tax Act and other tax matters to distributions received from the Trust by a Unit Holder.