UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

For the fiscal year ended December 31, 20202022

OR

For the transition period from                 to                 .

Commission File No. 1-10476

Hugoton Royalty Trust

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code

(at the office of the Corporate Trustee):

(855) 588-7839

Securities registered pursuant to Section 12(b) of the Act: None

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    YES  ☐    NO  ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    YES  ☐    NO  ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    YES  ☒    NO  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    YES  ☐    NO  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.  ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    YES  ☐    NO  ☒

The aggregate market value of units of beneficial interest held by non-affiliates of the registrant at June 30, 20202022 (the last business day of the registrant’s most recently completed second fiscal quarter) was approximately $5.6$68.4 million.

The number of units of beneficial interest outstanding as of March 15, 202113, 2023 was 40,000,000.

HUGOTON ROYALTY TRUST

20202022 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

i

HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

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

PART I

ItemITEM 1. BusinessBUSINESS

Hugoton Royalty Trust (the “Trust”) is an express trust created under the laws of Texas pursuant to the Hugoton Royalty Trust Indenture entered into on December 1, 1998 between XTO Energy Inc. (formerly known as Cross Timbers Oil Company and, hereafter, “XTO Energy”), as grantor, and NationsBank, N.A., as Trustee. Simmons Bank (the “Trustee”) is now the Trustee of the Trust. Effective December 30, 2022, Argent Trust Company began serving as agent for the Trustee.

On October 21, 2022, Simmons Bank, as Trustee, submitted a notice of resignation as trustee of the Trust to the unitholders. The Trustee’s notice of resignation stated that it would nominate Argent Trust Company, a Tennessee chartered trust company (“Argent”), as its potential successor. The Trustee’s resignation as trustee, and Argent’s appointment as successor trustee, are subject to certain conditions set forth in an agreement between Simmons Bank and Argent, including approval by the unitholders of the Trust (or a court) of (i) Argent’s appointment as successor trustee and (ii) any amendments to the indenture of the Trust necessary to permit Argent to serve as successor trustee.

At a special meeting of the Trust’s unitholders held February 23, 2023, the unitholders of the Trust voted to approve the appointment of Argent Trust Company as successor trustee to serve as trustee of the Trust once the resignation of Simmons Bank, the current Trustee of the Trust, takes effect. The proposal regarding related amendments to the indenture of the Trust did not receive sufficient votes for approval. The effective date of the Trustee’s resignation will depend on the satisfaction or waiver of the conditions set forth in the Trustee’s notice of resignation and the Trust’s definitive proxy statement, including approval of amendments to the Trust indenture (whether by unitholder approval or a court) necessary to permit Argent to serve as successor trustee.

The principal office of the Trust is 2911 Turtle Creek Blvd, Suite 850, Dallas, Texas 75219. (Telephone number 855-588-7839). The Trust’s internet web sitewebsite is www.hgt-hugoton.com. We make available free of charge, through our web site,website, our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. These reports are accessible through our internet web sitewebsite as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. Information on our website is not incorporated into this report.

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

On June 25, 2010, XTO Energy became a wholly-owned subsidiary of Exxon Mobil Corporation.

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

Net proceeds payable to the Trust depend upon production quantities, sales prices of oil and gas and costs to develop and produce oil and gas in the prior month. If monthly costs exceed revenues for any of the three

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

The Trust is not liable for any production costs or liabilities attributable to the underlying properties. If at any time the Trust receives net profits income in excess of the amount due, the Trust is not obligated to return such overpayment, but future net profits income payable to the Trust will be reduced until the overpayment, plus interest at the prime rate, is recovered.

As a working interest owner, XTO Energy can generally decline participation in any operation and allow consenting parties to conduct such operations, as provided under the operating agreements. XTO Energy also can assign, sell, or otherwise transfer its interest in the underlying properties, subject to the net profits interests, or can abandon an underlying property if it is incapable of producing in paying quantities, as determined by XTO Energy.

The oil and gas industry is highly competitive in all its phases. Operators of the properties in which the Trust holds interests encounter competition from other oil and gas companies and from individual producers and operators. Oil and natural gas are commodities, for which market prices are determined by external supply and demand factors. Current market conditions are not necessarily indicative of future conditions.

ItemITEM 1A. Risk FactorsRISK FACTORS

The following factors could cause actual results to differ materially from those contained in forward-looking statements made in this report and presented elsewhere by the Trustee from time to time. Such factors may have a material adverse effect upon the Trust’s financial condition, distributable income and changes in trust corpus.

The following discussion of risk factors should be read in conjunction with the financial statements and related notes included under Item 8. Financial Statements and Supplementary Data. Because of these and other factors, past financial performance should not be considered an indication of future performance.

in revenue, will directly decrease or increase the amount received by the Trust. If development costs and

proceedings recommenced. The proceedings have been abated pending a determination as to whether Argent Trust Company will be heard at a later date, which is still to be determined.become the successor trustee. See Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements – Note 8 – Contingencies for additional information.

Government action, policies or regulations designed to discourage production, reduce demand for, or promote alternatives to oil and natural gas could impact the price of oil and natural gas produced on the properties underlying the Trust’s net profits interests, directly as intended or through unintended consequences.

Governments around the world are considering actions intended to reduce greenhouse gas emissions by decreasing both the supply of and the demand for oil and natural gas products or promote alternatives. These include the adoption of cap and trade regimes, carbon taxes, trade tariffs, minimum renewable usage requirements, restrictive permitting, increased mileage and other efficiency standards, mandates for sales of electric vehicles, mandates for use of specific fuels or technologies, and other incentives or mandates designed to support transitioning to lower-emission energy sources. Political and other actors and their agents also increasingly seek to advance climate change objectives indirectly, such as by seeking to reduce the availability or increase the cost of financing and investment in the oil and gas sector. Depending on how policies are formulated and applied, such policies could impact the ability and costs of the operators of the properties underlying the Trust’s net profits interests to supply products, demand for their products, or the competitiveness of hydrocarbon-based products, which in turn, could reduce net proceeds to the Trust. Any policy that increases the costs for operators of the properties underlying the net profits interests or decreased market prices could have a material impact on the distributable income of the Trust.

War, terrorism, geopolitical hostilities, and other military actions or political instability could adversely affect Trust distributions or the market price of the Trust units.

There are a number of national and international events that could cause instability in global financial and energy markets. War, terrorist attacks and the threat of war or terrorist attacks, whether domestic or foreign, as well as other military or similar actions taken in response, impact the demand for and price of oil and natural gas in unpredictable ways, including increasing volatility in pricing. Actual or threatened acts of war, terrorism and other geopolitical hostilities could adversely affect Trust distributions or the market price of the Trust units in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in oil and natural gas prices, or the possibility that the infrastructure on which the operators of the underlying properties rely could be a direct target or an indirect casualty of such an event.

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

On August 27, 2018, the Trust units were delisted from the NYSE and began to be quoted on the OTCQX, which is maintained by the OTC Market Group Inc., under the symbol “HGTXU.” The Trustee received notice from the OTC Markets Group Inc. dated April 16, 2020, notifying the Trustee that the Trust was no longer in compliance with Section 3.2(a) of the Standards for Continued Qualification of the OTCQX Rules for U.S. Companies, in that as of December 31, 2019 the Trust had less than $2 million in net tangible assets, average revenue of less than

Proved reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions could cause the quantities and net present value of the reserves to be overstated.

Estimating proved oil and gas reserves is inherently uncertain. Petroleum engineers consider many factors and make assumptions in estimating reserves and future net cash flows. Those factors and assumptions include historical production from the area compared with production rates from similar producing areas, the effects of governmental regulation, assumptions about future commodity prices, production expense and development costs, taxes and capital expenditures, the availability of enhanced recovery techniques and relationships with landowners, working interest partners, pipeline companies and others. Lower oil and gas prices generally cause lower estimates of proved reserves. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variances could be material. Because the Trust owns net profits interests, it does not own a specific percentage of the oil and gas reserves. Estimated proved reserves for the net profits interests are based on estimates of reserves for the underlying properties and an allocation method that considers estimated future net proceeds and oil and gas prices. Because Trust reserve quantities are determined using an allocation formula, increases or decreases in oil and gas prices can significantly affect estimated reserves of the net profits interests.

Operational risks and hazards associated with the development and operations of the underlying properties may decrease Trust distributions.

There are operational risks and hazards associated with the production and transportation of oil and natural gas, including without limitation natural disasters, blowouts, explosions, fires, leakage of oil or natural gas, releases of other hazardous materials, mechanical failures, cratering, and pollution. Any of these or similar occurrences could result in the interruption or cessation of operations, personal injury or loss of life, property damage, damage to productive formations or equipment, damage to the environment or natural resources, or cleanup obligations. The operation of oil and gas properties is also subject to various laws and regulations. Non-compliance with such laws and regulations could subject the operator to additional costs, sanctions or liabilities. The uninsured costs resulting from any of the above or similar occurrences could be deducted as a production expense or development cost in calculating the net proceeds payable to the Trust, and would therefore reduce Trust distributions by the amount of such uninsured costs.

XTO Energy and the Trustee may be subject to attempted cybersecurity disruptions from a variety of sources including state-sponsored actors.

XTO Energy’s defensive preparedness includes multi-layered technological capabilities for prevention and detection of cybersecurity disruptions; non-technological measures such as threat information sharing with governmental and industry groups; internal training and awareness campaigns including routine testing of employee awareness and an emphasis on resiliency including business response and recovery. The Trustee also maintains robust cybersecurity protocols including, but not limited to technological capabilities that prevent and detect disruptions; computer workstations and programs protected with passwords and passphrases, as well as employee training throughout the year on banking regulations and cybersecurity followed up by testing of that knowledge. Other, non-technical protocols include securing of documents and work areas that could contain personal, non-public information. If the measures taken to protect against cybersecurity disruptions prove to be insufficient or if proprietary data is otherwise not protected, XTO Energy, the Trustee or customers, employees, or third parties could be adversely affected. The Trust is also exposed to potential harm from cybersecurity events that may affect the operations of third-parties, including our partners, suppliers, service providers (including providers of cloud-hosting services for our data or applications), and customers. Cybersecurity disruptions could cause physical harm to people or the environment; damage or destroy assets; compromise business systems; result in proprietary information being altered, lost, or stolen; result in employee, customer, or third-party information being compromised; or otherwise disrupt our business operations. We could incur significant costs to remedy the effects of a major cybersecurity disruption in addition to costs in connection with resulting regulatory actions, litigation, or reputational harm.

Future net profits may be subject to risks relating to the creditworthiness of third parties.

The Trust does not lend money and has limited ability to borrow money, which the Trustee believes limits the Trust’s risk from exposure to credit markets. The Trust’s future net profits, however, may be subject to risks relating to the creditworthiness of the operators of the underlying properties and other purchasers of crude oil and natural gas produced from the underlying properties. This creditworthiness may be impacted by the price of crude oil and natural gas.

The net profits interests can be sold and the Trust would be terminated. The Trust will also be terminated if it fails to generate sufficient gross proceeds.

The Trust may sell the net profits interests if the holders of 80% or more of the outstanding Trust units approve the sale or vote to terminate the Trust. The Trust will terminate if it fails to generate gross proceeds from the underlying properties of at least $1,000,000 per year over any successive two-year period. Sale of all of the net profits interests will terminate the Trust. The net proceeds of any sale must be for cash with the proceeds less administrative costs promptly distributed to the Trust unitholders.

The sale of the remaining net profits interests and the termination of the Trust will be taxable events to the Trust unitholders. Generally, a Trust unitholderunitholders will realize gain or loss equal to the difference between the amount realized on the sale and termination of the Trust and histheir adjusted basis in such units. Gain or loss realized by a Trust unitholder who is not a dealer with respect to such units and who has a holding period for the units of more than one year will be treated as long-term capital gain or loss except to the extent of any depletion recapture amount, which must be treated as ordinary income. Other federal and state tax issues concerning the Trust are discussed under Item 2 and Note 6 to the Trust’s financial statements, which are included herein. Each Trust unitholderunitholders should consult histheir own tax advisor regarding all Trust tax compliance matters, including federal and state tax implications concerning the sale of the net profits interests and the termination of the Trust.matters.

Trust unitholders have limited voting rights and have limited ability to enforce the Trust’s rights against XTO Energy or any other operator of the underlying properties.

The voting rights of a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. Additionally, Trust unitholders have no voting rights in XTO Energy or Exxon Mobil Corporation.

The Trust indenture and related trust law permit the Trustee and the Trust to sue XTO Energy or any other operator of the underlying properties to compel them to fulfill the terms of the conveyance of the net profits interests. If the Trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of the Trust unitholders would likely be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. Trust unitholders probably would not be able to sue XTO Energy or any other operator of the underlying properties.

Financial information of the Trust is not prepared in accordance with U.S. GAAP.

The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles or U.S. GAAP.(U.S. GAAP). Although this basis of accounting is permitted for royalty trusts by the Securities and Exchange Commission, the financial statements of the Trust differ from U.S. GAAP financial statements because net profits income is not accrued in the month of production, expenses are not recognized when incurred and cash reserves may be established for certain contingencies that would not be recorded in U.S. GAAP financial statements. See Item 8. Financial Statements and Supplementary Data – Notes to Financial Statements – Note 2 Basis of Accounting and Note 5 Development Costs for additional information.

satisfaction of such liability was not contractually limited to the assets of the Trust and the assets of the Trust and the Trustee are not adequate to satisfy such liability. As a result, Trust unitholders may be exposed to personal liability. The Trust, however, is not liable for production costs or other liabilities of the underlying properties.

Drilling oil and natural gas wells is a high-risk activity and subjects the Trust to a variety of factors that it cannot control.

Drilling oil and natural gas wells involves numerous risks, including the risk that commercially productive oil and natural gas reservoirs are not encountered. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause drilling activities to be unsuccessful. In addition, there is often uncertainty as to the future cost or timing of drilling, completing and operating wells. Further, development activities may be curtailed, delayed or canceled as a result of a variety of factors, including:

While these risks do not expose the Trust to liabilities of the drilling contractor or operator of the well, they can reduce net proceeds payable to the Trust and Trust distributions by decreasing oil and gas revenues or increasing production expense or development costs from the underlying properties. Furthermore, these risks may cause the costs of development activities on the underlying properties to exceed the revenues therefrom, thereby reducing net proceeds payable to the Trust and Trust distributions.

The underlying properties are subject to complex federal, state and local laws and regulations that could adversely affect net proceeds payable to the Trust and Trust distributions.

Extensive federal, state and local regulation of the oil and natural gas industry significantly affects operations on the underlying properties. In particular, oil and natural gas development and production are subject to stringent environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning oil and natural gas wells and other related facilities, which costs could reduce net proceeds payable to the Trust and Trust distributions. These regulations may become more demanding in the future. These regulations can often be changed by administrative agencies without formal legislation, resulting in additional costs that can impact distributions. See Item 2. Properties – Regulation, and Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations – Greenhouse Gas Emissions and Climate Change Regulations.

Cash held by the Trustee is not insured by the Federal Deposit Insurance Corporation.

Currently, cash held by the Trust reserved for the payment of accrued liabilities and estimated future expenses and distributions to unitholders is typically held in a treasury fund that under normal market conditions invests exclusively in U.S. Treasury obligations. Although the fund’s underlying investments are obligations of the

The tax treatment of an investment in Trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis.

U.S. federal tax reform legislation informally known as the Tax Cuts and Jobs Act (the “TCJA”)(TCJA) was enacted December 22, 2017, and makesmade significant changes to the federal income tax rules applicable to both individuals and entities, including changes to the effective tax rate on a Trust unitholder’s allocable share of certain income from the Trust. The TCJA is complex and lacks administrative guidance, thus, Trust unitholders should consult their tax advisor regarding the TCJA and its effect on an investment in Trust units. In addition, the current administration has generally proposed repealing fossil fuel tax subsidies, which could impact certain tax benefits available to Trust unitholders.

Any modification to the U.S. federal income tax laws or interpretations thereof (including administrative guidance relating to the TCJA) may be applied retroactively and could adversely affect our business, financial condition or results of operations. The Trust is unable to predict whether any changes or other proposals will ultimately be enacted, or whether any adverse interpretations will be used. Any such changes or interpretations could negatively impact the value of an investment in the Trust units.

ItemITEM 1B. Unresolved Staff CommentsUNRESOLVED STAFF COMMENTS

As of December 31, 2020,2022, the Trust did not have any unresolved Securities and Exchange Commission staff comments.

ItemITEM 2. PropertiesPROPERTIES

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% or more of the outstanding Trust units, or upon termination of the Trust. Otherwise, the Trust is required to sell up to 1%1 percent of the value of the net profits interests in any calendar year, pursuant to notice from XTO Energy of its desire to sell the related underlying properties. Any sale must be for cash with 80% of the proceeds distributed to the unitholders on the next declared distribution. All the underlying properties are currently owned by XTO Energy. 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 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, 20202022 is approximately seven13 years. This index is calculated using total proved reserves and estimated 20212023 production for the underlying properties. The projected 20212023 production is from proved developed producing reserves as of December 31, 2020.2022. 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 zero. As reported in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2019, the future net cash flows from proved reserves of the underlying properties as of such date were zero.approximately 81 percent natural gas and 19 percent oil. XTO Energy operates approximately 95%95 percent of 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 2020,2022, daily sales volumes from the underlying properties in the Hugoton area averaged approximately 7,0005,900 Mcf of gas and 21160 Bbls of oil.

Most of the production from the underlying properties in the Hugoton area is from the Chase formation. XTO Energy has informed the Trustee that it has begun to develop other formations that underlie the 79,500 net acres held by production by the Chase formation wells, which include the Council Grove, Morrow, Chester and St. Louis formations. 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 and plans to continue this development program sometime in the future.

Within this area, XTO Energy did not drill any new wells but didor perform 2any workovers in 2020.2022. XTO Energy has informed the Trustee that it does not plan to drill any new wells but mayor perform up to 2any workovers during 2021.2023.

XTO Energy’s future development plans for the underlying properties in the Hugoton area may include:

Effective May 1, 2014, XTO Energy entered into a gas sales and processing contract with DCP Midstream, L.P. 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. The system collects the majority of its throughput from underlying properties, which XTO Energy has advised the Trustee has beenthat the system collects approximately 7,6007,000 Mcf per day.day, of which the majority of its throughput is from underlying properties. XTO Energy receives 100% of the net value for residue gas based upon a price per MMBtu of Panhandle Eastern Pipe Line Company index. Under this contract DCP is entitled to charge a processing fee of $0.25 per Delivery Point MMBtu and a helium processing fee of $0.05 per 97% Delivery Point Mcf in addition to other deductions such as for fuel and transportation. XTO Energy has exercised its contractual right to take in kind and sell its NGLs and helium. XTO Energy sells 100% of the net value for any recovered NGLs to ONEOKan ExxonMobil affiliate at Conway pricing as posted by Oil Price Information Services minus an adjusted base differential. XTO Energy sells the helium to Air Products and Chemicals, Inc. and Air Products Helium, Inc. under a pricing formula based upon the open market crude helium sales price established by the U.S. Bureau of Land Management. Timberland Gathering & Processing Company, Inc. (“Timberland”), an affiliate of XTO Energy, provides gathering from the wellhead to DCP’s gathering system for a fee of $0.75 per Mcf of gas delivered by XTO Energy. The sales contract with DCP Midstream, L.P. has passed its primary term date of March 31, 2019, and is currently being renewed annually on an evergreen basis, and can be canceled by either party upon 180 days written notice.

Anadarko Basin

Oil and gas accumulations were discovered in the Anadarko Basin of western Oklahoma in 1945. XTO Energy is one of the largest producers in 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, the principal producing regions of the underlying properties in the Anadarko Basin. Daily sales volumes from the underlying properties in the Anadarko Basin averaged 14,800approximately 11,900 Mcf of gas and 825500 Bbls of oil in 2020.2022.

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 performed 9did not drill any wells or perform any workovers in 2020.2022. XTO Energy has informed the Trustee that it does not plan to drill any new wells but may perform up to 5two workovers in Major County during 2021.2023.

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, XTO Energy did not drill any wells or perform any workovers in 2020.2022. XTO Energy has informed the Trustee that it does not plan to drill any new wells but mayor perform up to 2any workovers in Woodward County during 2021.2023.

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, XTO Energy performed 3did not drill any wells or perform any workovers in 2020.2022. XTO Energy has informed the Trustee that it does not plan to drill any new wells but may perform up to 3 workoversone workover within the Elk City field during 2021.2023.

XTO EnergyEnergy’s future development plans to further developfor the underlying properties in the Anadarko Basin primarily through:may include:

A gathering subsidiary of XTO Energy 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 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 and other producers for at least 50% 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 for the residue gas based upon a weighted average price from

The fee is subject to an annual price renegotiation under which either party can 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 also sells gas directly to third parties. The price paid to XTO Energy 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. Neither party has 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 20202022 sales volumes from the underlying properties in the Fontenelle field averaged 9,300approximately 8,900 Mcf of natural gas and 20 Bbls of oil. XTO Energy did not drill any new wells or perform any workovers in the Green River Basin in 2020.2022. XTO Energy has advised the Trustee that it does not plan to drill any new wells or perform any workovers in the Green River Basin during 2021.2023. XTO Energy has advised the Trustee that it is continuing its efforts to reduce pipeline pressure which has shown potential for increasing production and extending field life in the Fontenelle field. XTO Energy has advised the Trustee that a salt water disposal conversion may be executed in 2021 to assist with disposal in the Fontenelle field.

Potential development activities for the underlying properties in this area include:

XTO Energy markets 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 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. The owner of the gas plant and related pipeline charges XTO Energy 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. In 2020,2022, the fuel charge was approximately 1% of the volumes produced and the fee was approximately $0.12$0.13 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 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 $0.20$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. Alternatively, the gas may be sold under a contract where XTO Energy directly sells the gas to a third party on the lease at an adjusted index

Producing Acreage, Drilling and Well Counts

For the following data, “gross” refers to the total wells or acres on the underlying properties in which XTO Energy owns a working interest and “net” refers to gross wells or acres multiplied by the percentage working interest owned by XTO Energy. Although many of XTO Energy’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 XTO Energy, while non-operated wells are managed by others.

The underlying properties are interests in developed properties located primarily in gas producing regions of Kansas, Oklahoma and Wyoming. The following is a summary of the approximate producing acreage of the underlying properties at December 31, 2020.2022. Undeveloped acreage is not significant.

The following is a summary of the producing wells on the underlying properties as of December 31, 2020:2022:

Proved reserves at December 31, 20202022 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, 2020, 2019, 2018 and 2017.2022. Miller and Lents’ primary technical person responsible for calculating the Trust’s reserves has more than ten years of experience as a reserve engineer. The estimated reserves for the underlying properties are then used by XTO Energy to

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

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

entered with any subsidiary of XTO Energy, it may charge XTO Energy a fee that may not exceed 2% 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“Significant Properties” above.

Regulation

Natural Gas Regulation

The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation and storage rates charged, tariffs, and various other matters, by the Federal Energy Regulatory Commission. 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, 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 (PL 110-140). 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.

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 allowables 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 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. ImpairmentImpairments 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, each unitholder isunitholders are taxed directly on histheir 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 2020, theThe Trust incurredalso incurs administration expenses and earnedmay earn interest income on funds held for distribution and for 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.

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”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%, 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%. Under the TCJA, for such tax years, personal exemptions and miscellaneous itemized deductions are not allowed. For such tax years,Further, the U.S. federal income tax rate applicable to corporations is 21%, and such rate applies to both ordinary income and capital gains.

Section 1411 of the Code imposes a 3.8% 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 royalty 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.

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. Simmons Bank,Argent Trust Company, agent for the Trustee, EIN: 71-0162300,62-1437218, 2911 Turtle Creek Blvd, Suite 850, Dallas, Texas, 75219, telephone number 1-855-588-7839, email address Trustee@hgt-hugoton.com, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.hgt-hugoton.com. Notwithstanding the foregoing, the middlemen holding Trust units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such Trust units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose Trust units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust units.

Unitholders should consult their tax advisor regarding trustTrust 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 it distributes all of its net income to unitholders, the Trust is not taxed at the trust level in Kansas or Oklahoma. While the Trust does not 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 the state, along with a schedule that includes information regarding distributions to unitholders. 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 interest 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).

ItemITEM 3.Legal ProceedingsLEGAL PROCEEDINGS

As previously disclosed, XTO Energy advised the Trustee that it reached a settlement with the plaintiffs in the Chieftain class action royalty case. On July 27, 2018, the final plan of allocation was approved by the court. Based on the final plan of allocation, XTO Energy advised the Trustee that it believes approximately $24.3 million in additional production costs should be allocated to the Trust. On May 2, 2018, the Trustee submitted a demand for arbitration seeking a declaratory judgment that the Chieftain settlement is not a production cost and that XTO Energy is prohibited from charging the settlement as a production cost under the conveyance or otherwise reducing the Trust’s payments now or in the future as a result of the Chieftain litigation. The Trust and XTO Energy conducted the interim hearing on the claims related to the Chieftain settlement on October 12-13, 2020. In the arbitration, the Trustee contended that the approximately $24.3 million allocation related to the Chieftain settlement was not a production cost and, therefore, there should not be a related adjustment to the Trust’s share of net proceeds. However, XTO Energy contended that the approximately $24.3 million was a production cost and should reduce the Trust’s share of net proceeds.

On January 20, 2021, the arbitration panel issued its Corrected Interim Final Award (i) “reject[ing] the Trust’s contention that XTO has no right under the Conveyance to charge the Trust with amounts XTO paid under section 1.18(a)(i) as royalty obligations to settle the Chieftain litigation” and (ii) stating “[t]he next phase will determine how much of the Chieftain settlement can be so charged, if any of it can be, in the exercise of the right found by the Panel.” TheFollowing briefing by both parties, are continuing to review the Corrected Interim Final Award and on March 26,May 18, 2021, XTO Energy submitted its brief to the Panel regardingissued its second interim final award over the amount of XTO Energy’s settlement in the Chieftainsettlement, if any, class action lawsuit that may be charged to the Trust. The Trustee has until April 23, 2021 to submit a response brief and XTO Energy will have until May 7, 2021 to submit a reply brief to the Panel regarding the amount of the Chieftain settlement, if any, that may be charged to the Trust.

ItemITEM 4.Mine Safety DisclosuresMINE SAFETY DISCLOSURES

Not Applicable.

ItemITEM 7. Trustee’sDiscussion and Analysis of Financial Condition and Results of OperationsTRUSTEE’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Calculation of Net Profits Income

The following is a summary of the calculation of net profits income received by the Trust:

Results of Operations

Years Ended December 31, 20202022 and 20192021

Net profits income for 20202022 was $0,$19,544,398, as compared with $369,458$0 for 2019. The 100% decrease in net profits income from 2019 to 20202021. This was primarily the result of lowerhigher oil and gas prices ($10.129.3 million), increased oil production ($0.9 million), and decreased development costs ($0.5 million), offset by increased production expenses ($3.2 million), net excess costs activity ($8.6 million), and increased overhead ($0.5 million), partially offset by decreased development costs ($13.63.1 million), decreased gas production expenses ($3.62.4 million), increased oil and gas production ($0.9 million), and decreased taxes, transportation and other costs ($0.72.0 million), increased overhead ($0.4 million), and decreased other proceeds ($0.1 million).

Trust administration expense was $890,855$758,312 in 20202022 as compared to $913,398$935,488 in 2019. In addition to2021. Cash reserve activity for 2022 included additions of $1,000,000 which the Trustee reserved for administrative expenses. Simmons Bank funding $282,369 towards payment of Trust expenses, the remaining cash reserve balance as of January 1, 2020 of $605,646 was utilizedfunded $935,488 for the payment of Trust expenses.expenses in 2021 for which it was reimbursed in 2022. Interest income was $2,840$16,810 in 20202022 and $21,429$0 in 2019.2021. Changes in interest income are attributable to fluctuations in net profits income, cash reserve and interest rates. Distributable income was $0$16,585,039 or $0.000000$0.414626 per unit in 20202022 and $0 or $0.000000 per unit in 2019.2021.

Net profits income is recorded when received by the Trust, which is the month following receipt by XTO Energy, and generally two months after oil and gas production. Net profits income is generally affected by three major factors:

Volumes

Gas.    Underlying gas sales volumes increased 2%decreased 4 percent from 20192021 to 20202022 primarily due to higher gas sales from new wells in Major County, Oklahoma, andbecause of natural production decline, partially offset by timing of cash receipts, partially offset by natural production decline.and decreased downtime.

Oil.    Underlying oil sales volumes increased 5%6 percent from 20192021 to 20202022 primarily due to higher oil sales from new wells in Major County, Oklahoma, andbecause of timing of cash receipts, and decreased downtime, partially offset by natural production decline.

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

Prices

Gas.    The 20202022 average gas price was $2.15$7.08 per Mcf, down 27%up 75 percent from the 20192021 average gas price of $2.95$4.05 per Mcf. Natural gas prices are affected by the level of North American production, weather, crude oil and natural gas liquids prices, the U.S. economy, storage levels and export levels of liquefied natural gas. Natural gas prices are expected to remain volatile. The average NYMEX price for November 20202022 through January 20212023 was $2.79$5.54 per MMBtu. At March 15, 2021,2023, the average NYMEX gas price for the following 12 months was $2.72$3.22 per MMBtu.

Oil.    The average oil price for 20202022 was $41.12$83.91 per Bbl, down 23%up 42 percent from the average oil price for 20192021 of $53.60$59.25 per Bbl. Oil prices are expected to remain volatile. The average NYMEX price for November 20202022 through January 20212023 was $46.77$79.78 per Bbl. At March 15, 2021,2023, the average NYMEX oil price for the following 12 months was $62.80$67.70 per Bbl.

Beginning in March 2020 and continuing into the fourth quarter of 2020, numerous events have continued to have a downward impact on sales prices of products produced from the underlying properties. The COVID-19 pandemic and the government responses to this pandemic have significantly decreased the demand for oil and gas. It is not clear at the present time when or whether pandemic restrictions will lift or when government policies may change. Additionally, market factors, including abundant supplies, have also negatively impacted prices. Even when demand returns, it could take time for these accumulated supplies to decrease and a new market equilibrium, which may be lower than the pre-pandemic equilibrium, to emerge.

Taxes, transportation and other.    Taxes, transportation and other costs generally fluctuate with changes in total revenues. Taxes, transportation and other costs decreased 8%increased 23 percent from 20192021 to 20202022 primarily because of decreasedincreased production taxes due to loweron higher revenues, and decreased property taxes, due to timing of charges,and gas deductions, partially offset by increased gas deductions including amounts related to certain adjustments previously included in gas sales revenue that are now recorded in this line item.receipt of production tax refunds.

Production expense.    Production expense decreased 22%increased 29 percent from 20192021 to 20202022 primarily because of decreasedincreased repairs and maintenance, credits received for material transfers,salt water disposal costs, plug and decreased labor,abandonment expenses, partially offset by increased plug and abandonment expense.decreased labor.

Development costs.    Development costs chargeddecreased 19 percent from 2021 to the Trust decreased 94% from 20192022 primarily because of timing of drilling costs related to 2020 primarily due to the decrease in the development budget for the drilling of four horizontalnon-operated wells in Major County, Oklahoma. The monthly deduction is based on the current level of development expenditures, budgeted future development costs and the cumulative actual costs under (over) previous deductions. Actual development costs for properties underlying the Kansas and Wyoming net profits interests were charged to the Trust as incurred during 2019 and 2020. Actual development costs for the properties underlying the Oklahoma, net profits interests were charged to the Trust as incurred once the accrual was fully depleted as of the July 2019 distribution.partially offset by equipment purchases in Wyoming. Changes in oil or natural gas prices could impact future development plans on the underlying properties. XTO Energy has advised the Trustee that this monthly deduction will continue to be evaluated and revised as necessary. For further information on development costs, see Note 5 to Financial Statements under Item 8. Financial Statements and Supplementary Data.

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

Excess costs.    If monthly costs exceed revenues for any conveyance, theseof the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming), such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits incomeproceeds from another conveyance. Underlying cumulative excess costs for the Kansas, Oklahoma and Wyoming conveyances remaining as of December 31, 2020 totaled $34.0 million ($27.2 million net to the Trust), including accrued interest of $2.1 million ($1.7 million net to the Trust).other conveyances. For further information on excess costs, including the balance and accrued interest by conveyance, see Note 4 to Financial Statements under Item 8. Financial Statements and Supplementary Data.

Fourth Quarter 2020 and 2019

During fourth quarter 2020 the Trust receivedOther Proceeds.    The calculation of net profits income totaling $0for 2021 included $96,949 ($77,559 net to the Trust) from XTO Energy due to interest received on past due payments.

Fourth Quarter 2022 and 2021

Net profits income for fourth quarter 2022 was $7,899,818 as compared with $0 for fourth quarter 2019 net profits income2021. This was primarily the result of $0 primarily due to net excess costs activity ($1.66.0 million) and higher oil and gas prices ($5.0 million), offset by increased production expenses ($1.0 million), decreased oil and gas production expenses ($1.20.8 million), decreasedincreased development costs ($0.80.6 million), decreased overhead ($0.3 million), decreasedand increased taxes, transportation and other costs ($0.2 million), and higher gas prices ($0.2 million), partially offset by decreased oil and gas production ($2.6 million), and lower oil prices ($1.70.6 million).

After adding interest income of $11,$13,446 deducting administration expense of $301,131, utilizing the remaining cash reserve balance as of October 1, 2020 of $18,751 in addition to cash funded by Simmons Bank for the payment of Trust expenses,$292,584, distributable income for fourth quarter 20202022 was $0$7,620,680 or $0.000000$0.190517 per unit. Distributable income for fourth quarter 20192021 was $0 or $0.000000 per unit.

Prices

The average fourth quarter 20202022 gas price was $2.30$7.53 per Mcf, up 4%40 percent from the fourth quarter 20192021 average price of $2.21$5.38 per Mcf. The average fourth quarter 20202022 oil price was $38.40$87.51 per Bbl, down 28%up 22 percent from the fourth quarter 20192021 average price of $53.39$71.49 per Bbl. For further information about product prices, see “Years Ended December 31, 20202022 and 20192021 – Prices” above.

Costs

Taxes, transportation and other. Taxes, transportation and other costs decreased 11%increased 25 percent for the fourth quarter primarily because of decreasedincreased production taxes due to loweron higher revenues, and decreased property taxes, due to timing of charges, partially offset by increasedand gas deductions.

Production expense. Fourth quarter production expense decreased 24%increased 35 percent primarily because of decreasedincreased repairs and maintenance and labor, partially offset by increased plug and abandonment expense.expenses.

Development costs. Development costs decreased 13% forincreased $760,102 from the fourth quarter 2021, primarily duebecause of timing of drilling costs related to the decrease in development costs for the drilling of four horizontalnon-operated wells in Major County, Oklahoma. Actual development costs for properties underlying the Kansas, Oklahoma and Wyoming net profits interests were charged to the Trust as incurred during fourth quarter 2020 and 2019. For further information on development costs, see Note 5 to Financial Statements under Item 8. Financial Statements and Supplementary Data. equipment purchases in Wyoming.

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

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

Liquidity and Capital Resources

The Trust’s only cash requirement is any declared monthly distribution of its income to unitholders, which is funded by the monthly receipt of net profits income after payment of Trust administration expenses. The Trust is not liable for any production costs or liabilities attributable to the net profits interests. If at any time the Trust receives net profits income in excess of the amount due, the Trust is not obligated to return such overpayment, but future net profits income payable to the Trust will be reduced by the overpayment, plus interest at the prime rate. The Trust may borrow funds required to pay Trust liabilities if fully repaid prior to further distributions to unitholders.

Oklahoma, (actual costs incurred through fourth quarterlower oil and gas prices during 2019 and 2020, are $28.1 million net to the Trust) which have created an excess cost position on the Oklahoma conveyance. Cash flows from these new wells have generated recoveries of excess costs in spite of losses from the other wells underlying the Oklahoma conveyance until the second quarter 2020 when they were no longer able to cover losses from the other wells resulting in an increase in excess costs. Additionally,and excess cost positions on the Kansas, Oklahoma and Wyoming conveyances havewhich resulted in no unitholder distributions between March 2018 and June 2022. All conveyances have now received enough net profits income to recoup all of the excess costs in those conveyances plus the accrued interest. The net profits income received was also sufficient to reimburse Simmons Bank for the administrative expenses that it advanced after the expense reserve was depleted in October 2020 and fund the expense reserve. As of the July 2022 distribution announcement, the expense reserve was replenished to $1,000,000.

On May 18, 2021, the arbitration panel issued its second interim final award over the amount of XTO Energy’s settlement in the Chieftain class action lawsuit that can be charged to the Trust as a production cost which XTO Energy has estimated to be approximately $14.6 million net to the Trust after the arbitration panel has determined the remaining claims and issued its final award. This adjustment would likely result in the Oklahoma conveyance returning to an excess cost position for a period of time. Excess costs on the Oklahoma conveyance would not affect net proceeds to the Trust from the Kansas conveyance for all of 2019 and 2020 and no net proceeds to the Trust from theor Wyoming conveyance for all of 2019 and 2020, with the exception of the March 2019 through May 2019 distributions.conveyances. The Trustee has prepared a preliminary budget estimating the administrative expenses for the yearnine months ending December 31, 20212023 and the three months ending March 31, 20222024 which assumes no cash inflow from either net profits income or from other sources. Following depletion ofincome. Based on the expense reserve in October 2020,above assumptions, the Trustee has sought financing to paybelieves that the Trust would be able to meet its financial obligations duringfor the one yearone-year period after the date the financial statements are issued; however, to date such financing has not become available. Theissued.

During the period of time in which the Trust received no net profits income, the Trustee is reviewingreviewed the Trust’s alternatives to continuing as a going concern, which may includeincluded a potential sale of the Trust’s assets and/or termination of the Trust. On July 2, 2021, the Trustee announced that it had entered into a purchase and sale agreement with XTO Energy pursuant to which XTO Energy would acquire for $6,600,000 in cash the net overriding royalty interest created pursuant to the net profits interest conveyances held by the Trust and certain other assets constituting substantially all of the assets of the Trust.

The consummation of the sale of the assets was subject to the satisfaction of customary closing conditions, including approval of the sale from holders of units of beneficial interest in the Trust (“Units”) holding Units representing eighty percent (80%) or more of all the Units outstanding, or a final judicial determination authorizing the Trustee to consummate the sale of the assets. The Trustee hasheld a Special Meeting of unitholders on December 10, 2021 for the purpose of approving the sale of assets. The sale was not approved by unitholders.

Execution of the purchase and sale agreement followed a process previously announced by the Trust whereby the Trustee had engaged a third party to market the Trust’s assets. Although the Trustee has decided to market the sale of the Trust’s assets, there is no assurance that

Effective August 22, 2022, the Trustee and any prospective buyer will agreeXTO Energy mutually agreed to terms ofterminate the purchase and sale or thatagreement. As a sale can be completed under the indenture, or if a sale is completed under the indenture, that there will be any funds available for distribution to unitholders. Any material sale of assets and/or terminationresult of the Trust requires unitholder approvaltermination, the Trustee refunded the deposit paid by at least 80% of all outstanding units. While such review is ongoing, Simmons Bank, as Trustee, is currently paying the expenses for the Trust, subject to its rights to be indemnified and reimbursed pursuant to the terms of the Trust indenture. However, there is nothing in the Trust indenture that requires Simmons Bank to pay the expenses for the Trust. Any funds that Simmons Bank, as Trustee, utilizes to pay expenses of the Trust must be repaid in full (including from proceeds received from a sale of the Trust’s assets, if any) before distributions to unitholders could be made. There can be no assurances that a sale of the Trust’s assets, if any, will produce net proceeds sufficient to allow distributions to the unitholders and if such proceeds are available, there is no assurance when any distribution will be made. The Trust’s financial statements do not include any adjustments that might result from the outcome of these uncertainties.

On April 1, 2020, XTO Energy, Inc. made an unsolicited offer to acquire the outstanding units of beneficial interest of the Trust for a price of $0.20 per unit. The Trustee filed its Solicitation/Recommendation Statement on April 14, 2020 taking no position. The original offer was scheduled to expire on April 28, 2020. XTO Energy extended the offering period until May 12, 2020 and again to May 26, 2020, at which time it expired. Tendered units were returned to the unitholders due to an insufficient number of units tendered. On July 9, 2020, the Trustee notified XTO Energy of the Trustee’s claim to indemnification to the Trust Estate for all liability, expense, claims, damages or loss incurred by the Trustee in connectiontogether with the administration of the Trust. The Trustee stated it anticipates seeking reimbursement from XTO Energy upon depletion of the Trust’s cash reserve. XTO Energy has responded that any indemnity claim to XTO Energy is premature before the Trust Estate is exhausted.interest.

Greenhouse Gas Emissions and Climate Change RegulationRegulations

There is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change. A number of nations and U.S. states have adopted or are considering some form of

Off-Balance Sheet Arrangements

The Trust has no off-balance sheet financing arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.

Related Party Transactions

XTO Energy operates approximately 95% of the underlying properties. In computing net proceeds, XTO Energy deducts an overhead charge for reimbursement of administrative expenses on the underlying properties it operates. As of December 31, 2020,2022, the monthly overhead charge, based on the number of operated wells, was approximately $951,000$998,000 ($761,000798,400 net to the Trust) and is subject to annual adjustment based on an oil and gas industry index as defined in the Trust Indenture.

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

Total gas sales from the underlying properties to XTO Energy’s wholly-owned subsidiaries were $1.9$6.1 million for 2020,2022, or 8%9 percent of total gas sales, $1.8$2.8 million for 2019,2021, or 5%7 percent of total gas sales.

On June 25, 2010, XTO Energy became a wholly-owned subsidiary of Exxon Mobil Corporation.

Simmons Bank, as TrusteeThe calculation of Hugoton Royalty Trust, is currently funding the expensesnet profits income for the Trust, subject to its rights to be indemnified and reimbursed pursuant2021 included $96,949 ($77,559 net to the terms of the Trust indenture. This includes reimbursementTrust) from proceedsXTO Energy due to interest received from a sale of the Trust’s assets, if any. Amount funded as of December 31, 2020 is $282,369 as reflected in Item 8. Financial Statements and Supplementary Data. Under the Trust indenture, the Trustee is entitled to an annual administrative fee for services performed which was $76,012 in 2020. See Item 11. Executive Compensation, for further information on the remuneration received by the Trustee.past due payments.

Critical Accounting Policies

The financial statements of the Trust are significantly affected by its basis of accounting and estimates related to its oil and gas properties and proved reserves, as summarized below.

All amounts included in the Trust’s financial statements are based on cash amounts received or disbursed, or on the carrying value of the net profits interests, which was derived from the historical cost of the interests at the date of their transfer from XTO Energy, less accumulated amortization to date. Accordingly, there are no fair value estimates included in the financial statements based on either exchange or non-exchange trade values.

Impairment of Net Profits Interest

The Trustee reviews the Trust’s net profits interests (“NPI”) in oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the NPI may not be recoverable. In general, the Trustee does not view temporarily low prices as an indication of impairment. The markets for crude oil and natural gas have a history of significant price volatility and though prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand. If events and circumstances indicate that the carrying value may not be recoverable, the Trustee would use the estimated undiscounted future net cash flows from the NPI to evaluate the recoverability of the Trust assets. If the undiscounted future net cash flows from the NPI are less than the NPI carrying value, the Trust would recognize an impairment loss for the difference between the NPI carrying value and the estimated fair value of the NPI. The determination as to whether the NPI is impaired requires a significant amount of judgment by the Trustee and is based on the best information available to the Trustee at the time of the evaluation, including information provided by XTO Energy such as estimates of future production and development and operating expenses.

Significantly, during the third quarter of 2019, long term gas prices used to develop projections of future cash flows declined further and excess costs on all three conveyances increased substantially. In light of these facts and circumstances, an impairment trigger event occurred in the third quarter of 2019. An assessment of the forecasted net cash flows for the NPI indicated that the estimated undiscounted future net cash flows from the NPI were below the carrying value of the NPI. During the third quarter of 2019, the NPI was written down to its fair value of zero, resulting in a $15.7 million impairment charged directly to Trust corpus, which did not affect distributable income. The fair value of the NPI was developed using estimates for future oil and gas production attributable to the Trust, future crude oil and natural gas commodity prices published by third-party industry experts (adjusted for basis differentials), estimated taxes, development and operating expenses, and a risk-adjusted discount rate. Impairments recorded for book purposes will not result in a loss for tax purposes for the unitholders until the loss is recognized.

Oil and Gas Reserves

The proved oil and gas reserves for the underlying properties are estimated by independent petroleum engineers. 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. Reserve engineering is a subjective

Not required for smaller reporting companies; the Trust has elected to omit this information.

Report of Independent Registered Public Accounting Firm

To the Unitholders of Hugoton Royalty Trust and Simmons Bank, as Trustee

Opinion on the Financial Statements

We have audited the accompanying statements of assets, liabilities and trust corpus of Hugoton Royalty Trust (the “Trust”) as of December 31, 20202022 and 2019,2021, and the related statements of distributable income and of changes in trust corpus for the years then ended, including the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of the Trust as of December 31, 20202022 and 2019,2021, and its distributable income and its changes in trust corpus for the years then ended in conformity with the modified cash basis of accounting described in Note 2.

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

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

Basis for Opinion

These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on the Trust’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the auditsaudit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Basis of Accounting

As described in Note 2, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than generally accepted accounting principles.

HUGOTON ROYALTY TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

STATEMENTS OF DISTRIBUTABLE INCOME

STATEMENTS OF CHANGES IN TRUST CORPUS

See accompanying notes to financial statements.

Hugoton Royalty Trust

NOTES TO FINANCIAL STATEMENTS

1. Trust Organization and Provisions

Hugoton Royalty Trust (the “Trust”) was created on December 1, 1998 by XTO Energy Inc. (formerly known as “Cross Timbers Oil Company” and, hereafter, “XTO Energy”). Effective on that date, XTO Energy conveyed 80% net profits interests in certain predominantly gas-producing working interest properties in Kansas, Oklahoma and Wyoming to the Trust under separate conveyances for each of the three states. In exchange for the conveyances of the net profits interests to the Trust, XTO Energy received 40 million units of beneficial interest in the Trust. The Trust’s initial public offering was in April 1999. The majority of the underlying working interest properties are currently owned and operated by XTO Energy (Note 7).

Simmons Bank is the Trustee for the Trust. Effective December 30, 2022, Argent Trust Company began serving as agent for the Trustee. The Trust indenture provides, among other provisions, that:

2. Basis of Accounting

The financial statements of the Trust are prepared on the following basis and are not intended to present financial position and results of operations in conformity with U.S. GAAP:

Hugoton Royalty Trust

NOTES TO FINANCIAL STATEMENTS—(Continued)

The most significant differences between the Trust’s financial statements and those prepared in accordance with U.S. GAAP are:

Hugoton Royalty Trust

NOTES TO FINANCIAL STATEMENTS—(Continued)

amount of XTO Energy’s settlement in the Chieftain class action lawsuit that can be charged to the Trust as a production cost which XTO Energy has estimated to be approximately $14.6 million net to the Trust after the arbitration panel has determined the remaining claims and issued its final award. This adjustment would likely result in the Oklahoma conveyance returning to an excess cost position for a period of time. Excess costs on the Oklahoma conveyance would not affect net proceeds to the Trust from the Kansas or loss incurred byWyoming conveyances. The Trustee has prepared a preliminary budget estimating the administrative expenses for the nine months ending December 31, 2023 and the three months ending March 31, 2024 which assumes no cash inflow from net profits income. Based on the above assumptions, the Trustee believes that the Trust would be able to meet its financial obligations for the one-year period after the financial statements are issued.

During the period of time in connection withwhich the administrationTrust received no net profits income, the Trustee reviewed the Trust’s alternatives to continuing as a going concern, which included a potential sale of the Trust’s assets and/or termination of the Trust. On July 2, 2021, the Trustee announced that it had entered into a purchase and sale agreement with XTO Energy pursuant to which XTO Energy would acquire for $6,600,000 in cash the net overriding royalty interest created pursuant to the net profits interest conveyances held by the Trust and certain other assets constituting substantially all of the assets of the Trust.

The consummation of the sale of the assets was subject to the satisfaction of customary closing conditions, including approval of the sale from holders of units of beneficial interest in the Trust (“Units”) holding Units representing eighty percent (80%) or more of all the Units outstanding, or a final judicial determination authorizing the Trustee to consummate the sale of the assets. The Trustee stated it anticipates seeking reimbursement fromheld a Special Meeting of unitholders on December 10, 2021 for the purpose of approving the sale of assets. The sale was not approved by unitholders.

Execution of the purchase and sale agreement followed a process previously announced by the Trust whereby the Trustee had engaged a third party to market the Trust’s assets.

Effective August 22, 2022, the Trustee and XTO Energy upon depletionmutually agreed to terminate the purchase and sale agreement. As a result of the Trust’s cash reserve.termination, the Trustee refunded the deposit paid by XTO Energy, has responded that any indemnity claim to XTO Energy is premature before the Trust Estate is exhausted.together with interest.

3. Distributions to Unitholders

The Trustee determines the amount to be distributed to unitholders each month by totaling net profits income, interest income and other cash receipts, and subtracting liabilities paid and adjustments in cash reserves established by the Trustee. The resulting amount is distributed to unitholders of record within ten business days after the monthly record date, which is the last business day of the month.

Net profits income received by the Trustee consists of net proceeds received in the prior month by XTO Energy from the underlying properties, multiplied by 80%. Net proceeds are the gross proceeds received from the sale of production, less costs. Costs generally include applicable taxes, transportation, legal and marketing charges, production expense, development and drilling costs, and overhead.

XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming). If costs exceed revenues for any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits income from the other conveyances (Note 4).

Hugoton Royalty Trust

NOTES TO FINANCIAL STATEMENTS—(Continued)

4. Excess Costs

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

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