HGTXU

HUGOTON ROYALTY TRUST

HUGOTON ROYALTY TRUST is an American oil royalty traders company, incorporated in Texas.1 It is headquartered in Dallas, Texas.1

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Last updated Oct 20, 2026.

Overview

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  • TickerHGTXU1
  • IndustryOil Royalty Traders1
  • HeadquartersDallas, Texas1
  • Incorporated inTX2
  • Business addressC/O Argent Trust Company, 3838 Oak Lawn Ave., Suite 1720, Dallas, Tx 75219-45182

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Corporate structure

HUGOTON ROYALTY TRUST sits at the top of its group. 1 entity, 1 country on record. Switch between the flow chart and the network, and select any entity to see its details.

Major holders of HUGOTON ROYALTY TRUST

  • Christopher John Heck Filed SC 13G/A on HUGOTON ROYALTY TRUST, latest Jan 19, 2024 (4 filings since Nov 17, 2021)
  • Wells Fargo Filed SC 13G/A on HUGOTON ROYALTY TRUST, latest Feb 10, 2023 (2 filings since Jan 28, 2022)
  • HUGOTON ROYALTY TRUST Dallas, Texas

Built from major holders from Schedules 13D and 13G. Each entity in the chart links to its source.

What it owns

What HUGOTON ROYALTY TRUST reports owning in its annual reports to the SEC: buildings, land and equipment, real estate and locations, investments, intangible assets and inventory, at the end of its latest fiscal year and a year before.

Properties, in its own words

The net profits interests are the principal asset of the Trust. The Trustee cannot acquire any other assets, with the exception of certain short-term investments as specified under Item 1. Business. The Trustee may sell or otherwise dispose of all or any part of the net profits interests if approved by a vote of holders of 80 percent or more of the outstanding Trust units, or upon termination of the Trust. Otherwise, the Trust is required to sell up to 1 percent of the value of the net profits interests in any calendar year, pursuant to notice from Mach of its desire to sell the related underlying properties. Any sale must be for cash with 80 percent of the proceeds distributed to the unitholders on the next declared distribution. All the underlying properties are currently owned by Mach. Mach may sell all or any portion of the underlying properties at any time, subject to and burdened by the net profits interests.

The underlying properties are predominantly gas-producing properties with established production histories in the Hugoton area of Oklahoma and Kansas, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. The average reserve-to-production index for the underlying properties as of December 31, 2025, is approximately nine years. This index is calculated using total proved reserves and estimated 2026 production for the underlying properties. The projected 2026 production is from proved developed producing reserves as of December 31, 2025. Based on estimated future net cash flows at 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period, the future net cash flows from proved reserves of the underlying properties are approximately 55 percent natural gas and 45 percent oil. Mach operates approximately 78 percent of the underlying properties.

The rest of Item 2

Because the underlying properties are working interests, production expense, development costs and overhead are deducted in calculating net profits income. As a result, net profits income is affected by the level of maintenance and development activity on the underlying properties. See Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations. Total 2025 development costs deducted for the underlying properties were $5.3 million, an increase of $3.2 million from the prior year. Mach has informed the Trustee that there are no budgeted development costs for the underlying properties for 2026. Changes in oil or natural gas prices could impact future development plans on the underlying properties.

Significant Properties

Hugoton Area

Natural gas was discovered in the Hugoton area in 1922. With an estimated five million productive acres covering parts of Texas, Oklahoma and Kansas, the Hugoton area is one of the largest domestic natural gas producing areas. During 2025, daily sales volumes from the underlying properties in the Hugoton area averaged approximately 4,700 Mcf of gas and 30 Bbls of oil.

Most of the production from the underlying properties in the Hugoton area is from the Chase formation. Prior to April 30, 2025, XTO Energy informed the Trustee that it began to develop other formations that underlie the 79,500 net acres held by production by the Chase formation wells, which included the Council Grove, Morrow, Chester and St. Louis formations. After April 30, 2025, Mach or other operators have not advised the Trustee of any plans to develop the Hugoton Area. These formations are characterized by both oil and gas production from a variety of structural and stratigraphic traps. Prior to 2011, XTO Energy drilled wells to these formations.

Within this area, neither XTO Energy nor Mach drilled any new wells or performed any workovers in 2025. Mach has informed the Trustee that it does not plan to drill any new wells or perform any workovers during 2026.

Mach's future development plans for the underlying properties in the Hugoton area may include, but are not limited to:

1. · additional compression to lower line pressures;

2. · installing artificial lift;

3. · opening new producing zones in existing wells;

4. · restimulating producing intervals in existing wells utilizing new technology;

5. · deepening existing wells to new producing zones; and

6. · future drilling of additional wells.

Effective May 1, 2014, XTO Energy entered into a gas sales and processing contract with DCP Midstream, L.P. (“DCP”) to process all gas production from its wells attached to the Timberland Gathering System in Seward County, Kansas and in Texas and Beaver Counties, Oklahoma. When Mach purchased the properties underlying the Trust, it did not change the terms of the contracts in place. Mach has advised the Trustee that the system collects approximately 7,100 Mcf per day, of which the majority of its throughput is from underlying properties. Mach receives 95 percent of the net value for residue gas based upon a price per MMBtu of Panhandle Eastern Pipe Line Company index and 95 percent net for NGLs at Mont Belvieu pricing. Under this contract DCP is entitled to charge a processing fee of $0.26 per Delivery Point MMBtu and a helium processing fee of $0.05 per 97 percent Delivery Point Mcf in addition to other deductions such as for fuel and transportation. Timberland Gathering & Processing Company, LLC, formerly known as Timberland Gathering and Processing Company, Inc. (“Timberland”), an affiliate of Mach, provides gathering from the wellhead to DCP’s gathering system for a fee of $0.75 per Mcf of gas delivered by Mach. In January 2025, this fee was escalated for inflation to approximately $0.98 per Mcf and retroactively applied to the prior two year period as permitted by the Timberland Gas Gathering agreement.

Item 2 of the 10-K filed Mar 31, 2026.3

Leadership

Who has led HUGOTON ROYALTY TRUST, and when. Pick a name to see everywhere that person has worked.

President

  1. Keith A. Hutton2006
2010201520202025
Board members and other officers (4)

Timeline

  1. Sep 18, 20268-K Results of operations7
  2. Aug 21, 20268-K Results of operations8
  3. Jul 21, 20268-K Results of operations9
  4. Jun 18, 20268-K Results of operations10
  5. May 18, 20268-K Results of operations11
  6. Apr 20, 20268-K Results of operations12
  7. Apr 17, 20268-K Change of auditor13
  8. Mar 20, 20268-K Results of operations14
  9. Feb 17, 20268-K Results of operations15
  10. Jan 20, 20268-K Results of operations16
  11. Dec 19, 20258-K Results of operations17
  12. Nov 17, 20258-K Debt or obligation accelerated18

Calendar

When it reported results

  1. Sep 18, 2026Reported quarterly or annual results7
  2. Aug 21, 2026Reported quarterly or annual results8
  3. Jul 21, 2026Reported quarterly or annual results9
  4. Jun 18, 2026Reported quarterly or annual results10
  5. May 18, 2026Reported quarterly or annual results11
  6. Apr 20, 2026Reported quarterly or annual results12
  7. Mar 20, 2026Reported quarterly or annual results14
  8. Feb 17, 2026Reported quarterly or annual results15

Upcoming dates from Nasdaq's calendar; past results from the company's 8-K filings (Item 2.02). The full markets calendar

Filings

107 filings to the SEC since October 2021: 5 annual reports, 14 quarterly reports, 73 major events, 6 large holders, 9 other. The latest 20:

  1. Sep 18, 20268-K EDGAR
  2. Aug 21, 20268-K EDGAR
  3. Aug 14, 2026NT 10-Q EDGAR
  4. Jul 21, 20268-K EDGAR
  5. Jun 18, 20268-K EDGAR
  6. May 18, 20268-K EDGAR
  7. May 15, 2026NT 10-Q EDGAR
  8. Apr 20, 20268-K EDGAR
  9. Apr 17, 20268-K EDGAR
  10. Mar 31, 202610-K EDGAR
  11. Mar 20, 20268-K EDGAR
  12. Feb 17, 20268-K EDGAR
  13. Jan 20, 20268-K EDGAR
  14. Dec 19, 20258-K EDGAR
  15. Nov 17, 20258-K EDGAR
  16. Nov 14, 202510-Q/A EDGAR
  17. Nov 13, 202510-Q EDGAR
  18. Oct 21, 20258-K EDGAR
  19. Sep 19, 20258-K EDGAR
  20. Aug 22, 20258-K EDGAR

The 107 filings since October 2021 can be filtered by form type and year here when JavaScript is on.

Every filing from the last five years, summarized. The full record is on SEC EDGAR.

Major holders

Investors who own more than 5% of the shares must tell the SEC: a 13D if they may seek to influence the company, a 13G if they hold passively.

  • Christopher John HeckSC 13G/A, 4 filings Nov 17, 2021 to Jan 19, 202419
  • Wells FargoSC 13G/A, 2 filings Jan 28, 2022 to Feb 10, 202320

Held by these funds

The largest holders among investment managers' 13F reports for the quarter ending Jun 30, 2026. Change is in shares since the quarter before.

FundSharesValueShare of the fundChange
Pinnacle Holdings, LLC370,194$63.3K0.0%No change

13F reports cover disclosed long positions in U.S. stocks only.

SEC filer profile

How HUGOTON ROYALTY TRUST is registered with the Securities and Exchange Commission, from its EDGAR record and the cover page of its latest annual report.

  • Name on EDGARHUGOTON ROYALTY TRUST1
  • CIK0000862022
  • Employer ID (EIN)58-63792151
  • Incorporated inTexas1
  • Fiscal year endsDecember 311
  • Industry code (SIC)6792 Oil Royalty Traders1
  • SEC reviewing officeOffice of Energy & Transportation, Division of Corporation Finance1
  • Business addressC/O Argent Trust Company, 3838 Oak Lawn Ave., Suite 1720, Dallas, TX 75219-45181
  • Phone972-919-13601
  • On EDGAR sinceDec 4, 19981
  • Filings538 in all: 8-K (314), 10-Q (81), 4 (36), 10-K (24), SC 13G (10), UPLOAD (10), CORRESP (9), SC 13G/A (8)1
    All 31 form types

    DEFA14A (7), ARS (4), SC TO-T/A (4), 10-K405 (3), 3 (3), NT 10-Q (3), S-1/A (3), 10-Q/A (2), DEF 14A (2), PRE 14A (2), 25 (1), 424A (1), 424B4 (1), 5 (1), 8-A12B (1), 8-K/A (1), DEFM14A (1), PREM14A (1), S-1 (1), S-8 (1), S-8 POS (1), SC 14D9 (1), SC TO-T (1)

  • Latest filingsAnnual report (10-K) Mar 31, 2026
    Quarterly report (10-Q) Nov 13, 2025
    Proxy statement (DEF 14A) Nov 29, 2022
    Latest 8-K (8-K) Sep 18, 2026

Risk factors and legal proceedings

The risks HUGOTON ROYALTY TRUST names in Item 1A of its 10-K filed Mar 31, 2026: 23 risks under these headings, as written.3

  • The Trust may not have sufficient cash to meet its obligations during the one-year period after the date that the financial statements are issued, and the Trustee has reviewed and intends to continue to review alternatives to the Trust continuing as a going concern.
  • The market price for the Trust units may not reflect the value of the net profits interests held by the Trust.
  • Current and future oil and natural gas prices fluctuate due to a number of uncontrollable factors, and any decline will adversely affect the net proceeds payable to the Trust and Trust distributions.
  • Higher production expense and/or development costs, without concurrent increases in revenue, will directly decrease the net proceeds payable to the Trust. Certain claimed production expenses by Mach may reduce or eliminate distributions to unitholders for extended periods of time.
  • 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.
  • 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 may not be an active market for the Trust units.
  • 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.
  • Operational risks and hazards associated with the development and operations of the underlying properties may decrease Trust distributions.
  • The Trust may be subject to attempted cybersecurity disruptions from a variety of sources including state-sponsored actors.
  • Future net profits may be subject to risks relating to the creditworthiness of third parties.
  • Trust unitholders and the Trustee have no influence over the operations on, or future development of, the underlying properties.
The other 11 risks
  • The assets of the Trust represent interests in depleting assets and, if Mach, or any other operators developing the underlying properties do not perform additional successful development projects, the assets may deplete faster than expected. Eventually, the assets of the Trust will cease to produce in commercial quantities and the Trust will cease to receive proceeds from such assets.
  • Mach may transfer its interest in the underlying properties without the consent of the Trust or the Trust unitholders.
  • Mach, or any other operator of any underlying property may abandon the property, thereby terminating the related net profits interest payable to the Trust.
  • 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.
  • Trust unitholders have limited voting rights and have limited ability to enforce the Trust’s rights against XTO Energy, Mach or any other operator of the underlying properties.
  • Financial information of the Trust is not prepared in accordance with U.S. GAAP.
  • The limited liability of Trust unitholders is uncertain.
  • Drilling oil and natural gas wells is a high-risk activity and subjects the Trust to a variety of factors that it cannot control.
  • 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.
  • Cash held by the Trustee is not insured by the Federal Deposit Insurance Corporation.
  • The tax treatment of an investment in Trust units could be affected by recent and potential legislative changes, possibly on a retroactive basis.

Legal proceedings

As previously disclosed, XTO Energy advised the Trustee that it reached a settlement with the plaintiffs in the Chieftain class action royalty case. Based on the final plan of allocation approved by the court, XTO Energy advised the Trustee that it believes approximately $24.3 million in additional production costs should be allocated to the Trust. On May 2, 2018, the Trustee submitted a demand for arbitration seeking a declaratory judgment that the Chieftain settlement is not a production cost and that XTO Energy is prohibited from charging the settlement as a production cost under the conveyance or otherwise reducing the Trust’s payments now or in the future as a result of the Chieftain litigation (the "Chieftain Claim").

On January 20, 2021, the arbitration panel issued its Corrected Interim Final Award (i) “reject[ing] the Trust’s contention that XTO [Energy] has no right under the Conveyance to charge the Trust with amounts XTO [Energy] paid under section 1.18(a)(i) as royalty obligations to settle the Chieftain litigation” and (ii) stating “[t]he next phase will determine how much of the Chieftain settlement can be so charged, if any of it can be, in the exercise of the right found by the Panel.” Following briefing by both parties, on May 18, 2021, the Panel issued its second interim final award over the amount of XTO Energy’s settlement in the Chieftain class action lawsuit that can be charged to the Trust as a production cost.

In the arbitration, the Trustee also disputed certain amounts related to the computation of the Trust’s net proceeds for 2014 through 2019 and 2021 (the “Overhead Claims”).

On June 18, 2024, the Trustee and XTO Energy entered into a Settlement Agreement to resolve the pending arbitration. Pursuant to the Settlement Agreement, effective as of June 1, 2024, XTO Energy and the Trustee agreed:

The opening of Item 3, Legal Proceedings.3

Sources

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