UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 20172022

OR

Commission File Number:1-10476

For the transition period from to .

Hugoton Royalty Trust

(Exact name of registrant as specified in its charter)

(855)588-7839c/o The Corporate Trustee:

Simmons Bank

2911 Turtle Creek Blvd, Suite 850

Dallas, Texas 75219

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code)

NONEcode (855) 588-7839

(Former name, former address and former fiscal year, if change since last report)NONE

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

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

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of RegulationS-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☐ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, 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 Rule12b-2 of the Exchange Act (check one):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 is a shell company (as defined in Rule 12b-2 of the Exchange Act Rule12b-2)Act). Yes ☐ No ☑

Indicate the number of units of beneficial interest outstanding, as of the latest practicable date:

Outstanding as of November 1, 20172022

40,000,000

HUGOTON ROYALTY TRUST

FORM10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 20172022

TABLE OF CONTENTS

HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

The following are definitions of significant terms used in this Form10-Q:

HUGOTON ROYALTY TRUST

PART I- FINANCIAL INFORMATION

Item 1. Financial Statements

The condensed financial statements included herein are presented, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Unless specified otherwise, all amounts included herein are presented in U.S. dollars. Certain information and footnote disclosures normally included in annual financial statements have been condensed or omitted pursuant to such rules and regulations, although the Trustee believes that the disclosures are adequate to make the information presented not misleading. These condensed financial statements should be read in conjunction with the financial statements and the notes thereto included in the Trust’s latest Annual Report on Form10-K. In the opinion of the Trustee, all adjustments, consisting only of normal recurring adjustments, necessary for a fair statement of the assets, liabilities and trust corpus of the Hugoton Royalty Trust at September 30, 20172022 and the distributable income and changes in trust corpus for the three-three-month and nine-month periods ended September 30, 20172022 and 20162021 have been included. Distributable income for such interim periods is not necessarily indicative of the distributable income for the full year. The condensed financial statements as of September 30, 2017, and for the three-month and nine-month periods ended September 30, 2017 and 2016 have been subjected to a review by PricewaterhouseCoopers LLP, the Trust’s independent registered public accounting firm, whose report is included herein.

Report of Independent Registered Public Accounting Firm

To the Unitholders of Hugoton Royalty Trust and

Southwest Bank, Trustee

We have reviewed the accompanying condensed statement of assets, liabilities and trust corpus of Hugoton Royalty Trust (the “Trust”) as of September 30, 2017, and the related condensed statements of distributable income and changes in trust corpus for the three-month and nine-month periods ended September 30, 2017 and 2016. These interim financial statements are the responsibility of the Trustee.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

As described in Note 1, these interim financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed interim financial statements for them to be in conformity with the basis of accounting described in Note 1.

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statement of assets, liabilities and trust corpus as of December 31, 2016, and the related statements of distributable income and changes in trust corpus for the year then ended (not presented herein), and in our report dated March 10, 2017, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying condensed statement of assets, liabilities and trust corpus as of December 31, 2016 is fairly stated, in all material respects, in relation to the statement of assets, liabilities and trust corpus from which it has been derived.

/s/ PricewaterhouseCoopers LLP

Dallas, TX

November 6, 2017

HUGOTON ROYALTY TRUST

Condensed Statements of Assets, Liabilities and Trust Corpus(Unaudited)

The accompanying notes to condensed financial statements are an integral part of these statements.

HUGOTON ROYALTY TRUST

Condensed Statements of Distributable Income(Unaudited)

The accompanying notes to condensed financial statements are an integral part of these statements.

HUGOTON ROYALTY TRUST

Condensed Statements of Changes in Trust Corpus(Unaudited)

The accompanying notes to condensed financial statements are an integral part of these statements.

HUGOTON ROYALTY TRUST

Notes to Condensed Financial Statements(Unaudited)

The financial statements of Hugoton Royalty Trust (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. generally accepted accounting principles (“GAAP”):

Costs deducted in the calculation of net proceeds for the 80% net profits interests generally include applicable taxes, transportation, marketing and legal costs, production expense, development costs, operating charges and other costs.

The Trust’s financial statements differ from those prepared in conformity with U.S. GAAP because revenues are recognized when received rather than accrued in the month of production, expenses are recognized when paid rather than when incurred and certain cash reserves may be established by the Trustee for contingencies which would not be recorded under U.S. GAAP. This comprehensive basis of accounting other than U.S. GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with U.S. GAAP, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues were received or expenses were paid. Because the Trust’s financial statements are prepared on the modified cash basis, as described above, most accounting pronouncements are not applicable to the Trust’s financial statements.

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 indicated 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.

In light of lower long term prices used to develop projections of future cash flows, continued excess costs on two conveyances and zero distributions to unitholders for the quarter ended June 30, 2016, the Trustee concluded in the second quarter of 2016 that the events or circumstances indicated the carrying value may not be recoverable and an assessment of the forecasted net cash flows was performed for the NPI. 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. The result of the assessment indicated that the estimated undiscounted future net cash flows from the NPI were below the carrying value of the NPI. The NPI was written down to its fair value of $28.8 million, resulting in a $57.3 million impairment charged directly to trust corpus, which did not affect distributable income.

There was no impairment of the NPI during the quarter ended September 30, 2017.

Net profits interests in oil and gas properties

The initial carrying value of the net profits interests of $247,066,951 represents XTO Energy’s historical net book value for the interests on December 1, 1998, the date of the transfer to the Trust. During the second quarter 2016, the carrying value of the NPInet profits interests was written down to its fair value of $28,801,000, resulting in an impairment of $57,306,527 charged directly to Trusttrust corpus. During the third quarter 2019, the carrying value of the net profits interests was written down to its fair value of zero, resulting in an impairment of $15,681,533 charged directly to trust corpus. Amortization of the net profits interests is calculated on aunit-of-production basis using proved reserves and is charged directly to Trusttrust corpus. Accumulated amortization was $171,177,542$174,078,891 as of September 30, 20172019, when the net profits interests was written down to its fair value of zero.

Liquidity and $162,874,921Going Concern

The accompanying condensed financial statements have been prepared assuming that the Trust will continue as a going concern. Financial statements prepared on a going concern basis assume the realization of assets and the settlement of liabilities in the normal course of business. Between April 2018 and October 2020, accumulated excess costs for the Kansas, Oklahoma and Wyoming conveyances resulted in insufficient net proceeds to the Trust versus its current and anticipated expenses and a reduction in the Trust’s expense reserve to zero. Following depletion of the expense reserve, ongoing expenses and accumulated excess costs continued to result in no net proceeds to the Trust through February 2022. These conditions raised substantial doubt about the Trust’s ability to continue as a going concern as the Trust did not have sufficient cash to meet its obligations during the one year period after the dates that the financial statements were issued. Factors attributable to the cash shortage were primarily the previously disclosed development costs to drill four horizontal wells in Major County, Oklahoma, lower oil and gas prices during 2019 and 2020, and excess cost positions on the Kansas, Oklahoma and Wyoming conveyances which resulted in no unitholder distributions since March 2018. 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 has been replenished to $1,000,000. The Trustee does not currently anticipate any increase to the cash reserve in 2022. 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 or Wyoming conveyances. The Trustee has prepared a preliminary budget estimating the administrative expenses for the year ending December 31, 2016.2022 and the eleven months ending November 30, 2023 which assumes no cash inflow from net profits income other than the payments received from March 2022 through October 2022 totaling approximately $14,921,000. 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 which the Trust 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 held 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 mutually agreed to terminate the purchase and sale agreement. As a result of the termination, the Trustee refunded the deposit paid by XTO Energy, together with interest.

The following summarizes actual development costs, budgeted development costs deducted in the calculation of net profits income, and the cumulative actual costs compared to the amount deducted for the underlying properties:

		Three Months Ended September 30								Nine Months Ended September 30
		2017				2016				2017				2016
Cumulative actual costs under (over) the amount deducted—beginning of period		$	(83,055	)		$	438,751			$	56,243			$	239,528
Actual costs			(434,911	)			(502,300	)			(1,774,209	)			(1,228,077	)
Budgeted costs deducted			760,000				150,000				1,960,000				1,075,000
Cumulative actual costs under (over) the amount deducted—end of period		$	242,034			$	86,451			$	242,034			$	86,451

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. XTO Energy has advised the Trustee that 2017 budgeted development costs for the underlying properties are between $2 million and $4 million. The 2017 budget year generally coincides with the Trust distribution months from April 2017 through March 2018. XTO Energy has advised the Trustee that due to increasednon-operated development activity on properties underlying the Oklahoma net profits interests, it increased the monthly development cost deduction from $200,000 to $280,000 beginning with the August 2017 distribution. 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 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. Accordingly, no provision for income taxes has been made in the financial statements. 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. Impairments recorded for book purposes will not result in a loss for tax purposes for the unitholders until the loss is recognized.

All revenues from the Trust are from sources within Kansas, Oklahoma or Wyoming. Because it distributes all of its net income to unitholders, the Trust has not been taxed at the trust level in Kansas or Oklahoma. While the Trust has not owed tax, the Trustee is generally required to file anKansas and Oklahoma income tax returnreturns reflecting the income and deductions of the Trust attributable to properties located in theeach state, along with a schedule that includes information regarding distributions to unitholders. TheHowever, the Trust doesdid not expect to file a Kansas income tax return for the 20172021 tax year because it expects to havethe Trust had no revenues, income or deductions in 20172021 attributable to properties located in Kansas. The Trust did not file a Kansas income tax return with Kansas for the 20162020 and 20152019 tax years for the same reason.

Wyoming does not impose a state income tax.

The Trust may be required to bear a portion of the settlement costs arising from the Chieftain royalty class action settlement. For information on contingencies, including the Chieftain class action, see Note 3 to Condensed Financial Statements. The Panel has determined the Trust is responsible for a portion of the costs. Pending finalization of all claims included in the arbitration, XTO Energy would have the right to deduct the costs in its calculation of the net profits income payable to the Trust from the applicable net profits interests. Thus, for unitholders, the portion of legal settlement costs for which the Trust is determined to be responsible will be reflected through a reduction in net profits income received from the Trust and thus in a reduction in the gross royalty income reported by and taxable to the unitholders. In the event that the Trustee objects to such claimed reductions, the Trustee may also incur legal fees in representing the Trust’s interests. For unitholders, such costs would be reflected through an increase in the Trust’s administrative expenses, which would be deductible by unitholders in determining the net royalty income from the Trust.

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

Unitholders should consult the Trust’s latest annual report on Form10-K for a more detailed discussion of federal and state tax matters.

4.3.	Contingencies

In December 2010, a royalty class action lawsuit was filed against

Royalty Class Action and Arbitration

As previously disclosed, XTO Energy styledChieftain Royalty Company v. XTO Energy Inc. in Coal County District Court, Oklahoma. XTO Energy removed the case to federal court in the Eastern District of Oklahoma. The plaintiffs allege that XTO Energy wrongfully deducted fees from royalty payments on Oklahoma wells, failed to make diligent efforts to secure the best terms available for the sale of gas and its constituents, and demand an accounting to determine whether they have been fully and fairly paid gas royalty interests. The case was certified as a class action in April 2012; however, on appeal in June 2012, the 10th Circuit Court of Appeals reversed the certification of the class and remanded the case back to the trial court for further proceedings. XTO Energy has informedadvised the Trustee that it has reached a tentative settlement forwith the matter and continues to negotiateplaintiffs in the Chieftain class action royalty case. On July 27, 2018 the final settlement agreement. The Trustee has requestedplan of allocation was approved by the settlement amount fromcourt. Based on the final plan of allocation, XTO Energy and has been informedadvised the Trustee that at this time,it believes approximately $24.3 million in additional production costs should be allocated to the amountTrust. 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 believesis 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.” 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. The Panel in its decision has ruled that out of the $80 million settlement, the “Trust is obligated to pay its share under the Conveyance of the $48 million that was received by the plaintiffs in the Chieftain lawsuit by virtue of the settlement of that litigation. The Trust is not been determined.obligated by the Conveyance to pay any share of the $32 million received by the lawyers for the plaintiffs in the Chieftain lawsuit by virtue of the settlement.” XTO Energy has advisedand the Trustee are in the process of determining the portion of the $48 million that the settlement willis allocable to Trust properties to be allocated to all of XTO Energy’s Oklahoma wells, the majority of which are not properties in which the Trust ownscharged as an underlying net profits interest.

The Trustee has informed XTO Energy that it intends to review any claimed reductions in paymentexcess cost to the Trust, based onbut estimate it to be approximately $14.6 million net to the facts and circumstancesTrust.

The reduction in the Trust’s share of such settlement. In lightnet proceeds from the portion of a 2014 arbitration decision in which a three panel tribunal decided that the settlement amount the Panel has ruled may be charged against the Oklahoma conveyance would result in excess costs under the Oklahoma conveyance that would likely result in no distributions under the Oklahoma conveyance while these excess costs are recovered. This award completes the portion of the arbitration related to the Fankhouser v. XTO Energy, Inc.Chieftain , including a new royalty calculation for future royalty payments, couldsettlement. Excess costs on any individual conveyance would not be chargedaffect net proceeds to the Trust on any of the other remaining conveyances.

Other Trustee claims related to disputed amounts on the computation of the Trust’s net proceeds for 2014 through 2019 and 2021 were bifurcated from the initial arbitration. Pursuant to the extent that the claims inChieftain are similar to those inFankhouserpurchase and sale agreement entered into between the Trustee would likely objectand XTO Energy, the parties had agreed to such claimed reductions. Should there bestay the arbitration from the date of execution of the purchase and sale agreement to the earlier of the termination of the purchase and sale agreement or closing date of the sale of assets. Effective August 22, 2022, the Trustee and XTO Energy mutually agreed to terminate the purchase and sale agreement. As a disagreement asresult of the termination, the stay of these arbitration proceedings between XTO Energy and the Trustee with respect to whether the Trust should bear its share of a settlement or judgment, the matter will be resolved by bindingis lifted. The arbitration through the American Arbitration Association under the terms of the Indenture creating the Trust. XTO Energy has informed the Trustee that, although the amount of any reduction in net proceeds is not presently determinable, in its management’s opinion, the amount is not currently expected to be material to the Trust’s financial position or liquidity though it could be material to the Trust’s annual distributable income. Additionally, XTO Energy has advised the Trustee that any reductions would result in costs exceeding revenues on the properties underlying the net profits interests of the case, as applicable, for several monthly distributions, depending on the size of the settlement, if any,proceedings have recommenced and the net proceeds being paid at that time, which would result in the net profits interest being limited until such time that the revenues exceed the costshearing is currently scheduled for those net profit interests.May 30-31, 2023.

Other Lawsuits and Governmental Proceedings

Certain of the underlying properties are involved in various other lawsuits and governmental proceedings arising in the ordinary course of business. XTO Energy has advised the Trustee that, based on the information available at this stage of the various proceedings, it does not believe that the ultimate resolution of these claims will have a material effect on the financial position or liquidity of the Trust, but may have an effect on annual distributable income.

Other

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

5.4.	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:conveyance as calculated by XTO Energy:

Improved gas prices in relation to costs resulted inFor the partial recoveryquarter ended September 30, 2022, net recoveries of excess costs were $260,451 ($208,361 net to the Trust) and recoveries of accrued interest were $501,345 ($401,076 net to the Trust) on properties underlying the Kansas and Wyoming net profits interests for the quarter ended September 30, 2017.interests.

UnderlyingThere are no cumulative excess costs balances remaining for the Kansas and Wyoming conveyances remainingany conveyance as of September 30, 2017 totaled $1.1 million, including accrued interest2022.

5. Administration Expense

Administrative expenses are incurred so that the Trustee may meet its reporting obligations to the unitholders and regulatory entities and otherwise manage the administrative functions of $0.2 million.the Trust. These obligations include, but are not limited to, all expenses, taxes, compensation to the Trustee for managing the Trust, fees to consultants, accountants, attorneys, transfer agents, other professional and expert persons, expenses for clerical and other administrative assistance, and fees and expenses for all other services.

6. Subsequent Events

Development Costs

XTO Energy has advised the Trustee that it has elected to participate in the August 2016 distribution includeddevelopment of aone-timenon-operated reimbursement to the Trust of approximately $450,000 related to operated overhead corrections for the period of January 2014 through May 2016. This reimbursement affected the net profits incomewell in Major County, Oklahoma. The well was proposed by Comanche Exploration Co. LLC under the Oklahoma conveyance.

a joint operating agreement. XTO Energy has advised the Trustee that development costs for the May 2016 distribution included aone-time reimbursementwell are anticipated to be approximately $5 million underlying ($4 million net to the TrustTrust), and that drilling has begun and is expected to be completed in the first quarter of approximately $788,000 related2023. However, no assurances can be made as to operated overhead corrections for the period of January 2014 through February 2016. The reimbursement affectedestimated costs or timing to complete the net profits income under the Kansas, Oklahoma and Wyoming conveyances by approximately $186,000, $320,000 and $282,000 respectively.well.

XTO Energy advisedTrustee Resignation

On October 21, 2022, the Trustee announced that net profits income for August 2016 includedit has entered into an agreement with Argent Trust Company, a deduction of approximately $500,000 in additional gathering fees for the period of December 2015 through May 2016 relatedTennessee chartered trust company (“Argent”), pursuant to a renegotiated gas purchase contract that included production from properties underlying the Oklahoma conveyance. The current contract term is December 1, 2015 until November 30, 2017.

Effective October 19, 2017, Simmons First National Corporation (“SFNC”) completed its acquisition of First Texas BHC, Inc., the parent company of Southwest Bank,which the Trustee will be resigning as trustee of the Trust and will nominate Argent as successor trustee of the Trust. SFNC isThe Trustee’s resignation as trustee, and Argent’s appointment as successor trustee, are subject to certain conditions set forth in the parentagreement, including approval by the unitholders of Simmons Bank. SFNC has announced that it intends to operate Southwest Bankthe Trust (or a court) of (i) Argent’s appointment as a separate bank subsidiary for an interim period, after which it intends to merge it into Simmons Bank. The Trustee does not anticipatesuccessor trustee and (ii) any material impactamendments to the Trust as a resultindenture of the acquisition.Trust necessary to permit Argent to serve as successor trustee.

Item 2. Trustee’s Discussion and Analysis

The following discussion should be read in conjunction with the Trustee’s discussion and analysis contained in the Trust’s 20162021 Annual Report on Form10-K, as well as the condensed financial statements and notes thereto included in this Quarterly Report on Form10-Q. The Trust’s Annual Report on Form10-K, quarterly reports on Form10-Q, current reports on Form8-K and all amendments to those reports are available on the Trust’s web sitewebsite atwww.hgt-hugoton.com.

Distributable Income

Quarter

For the quarter ended September 30, 2017,2022, net profits income was $688,252,$9,440,853 as compared to $1,253,498$0 for third quarter 2016. This 45% decrease in net profits income is2021 primarily the result of lowerdue to higher oil and gas and oil productionprices ($0.711.4 million), and net excess costs activity ($0.6 million), increased production expense ($0.6 million), higher overhead ($0.5 million) and increased development costs ($0.54.4 million), partially offset by higherdecreased oil and gas and oil pricesproduction ($2.14.4 million) and decreased, increased production expenses ($1.0 million), increased taxes, transportation and other costs ($0.7 million), increased development costs ($0.2 million), and increased overhead ($0.1 million). See “Net Profits Income” below.

After adding interest income of $2,091$3,364, increasing the expense reserve $347,549, and deducting administration expense of $193,023,$132,309, distributable income for the quarter ended September 30, 20172022 was $497,320,$8,964,359, or $0.012433$0.224109 per unit of beneficial interest. Administration expense for the quarter increased $5,131decreased $111,815 as compared to the prior year quarter, primarily related to the timing of receipt and payment of Trust expenses and terms of professional services. Changes in interest income are attributable to fluctuations in net profits income, cash reserve and interest rates. For third quarter 2016,2021, distributable income was $791,920,$0, or $0.019798$0.000000 per unit.

Distributions to unitholders for the quarter ended September 30, 20172022 were:

Nine Months

For the nine months ended September 30, 2017,2022, net profits income was $4,236,724$11,644,580 compared with $1,516,605$0 for the same 2016 period. This 179% increase in net profits income is2021 period primarily the result ofdue to higher gasoil and oilgas prices ($10.624.3 million), increased oil production ($1.4 million), and decreased development costs ($1.1 million), partially offset by decreased gas and oil production ($2.5 million), net excess costs activity ($9.1 million), increased production expenses ($2.2 million), decreased gas production ($2.1 million), increased taxes, transportation and other costs ($1.3 million), higher overhead ($1.01.4 million), increased development costsoverhead ($0.70.3 million), and higher production expensedecreased other proceeds ($0.20.1 million). See “Net Profits Income” below.

After adding interest income of $4,616$3,364, paying off the outstanding payable to Simmons Bank of $1,217,857, establishing an expense reserve of $1,000,000, and deducting administration expense of $707,060,$465,728, distributable income for the nine months ended September 30, 20172022 was $3,534,280,$8,964,359, or $0.088357$0.224109 per unit of beneficial interest. Administration expense for the nine months ended September 30, 20172022 decreased $18,169$206,070 as compared to the same 20162021 period, primarily related to the timing of receipt and payment of Trust expenses and terms of professional services. Changes in interest income are attributable to fluctuations in net profits income, cash reserve and interest rates. For the nine months ended September 30, 2016,2021, distributable income was $791,920,$0, or $0.019798$0.000000 per unit.

Net Profits Income

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:

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

The following are explanations of significant variances on the underlying properties from third quarter 20162021 to third quarter 20172022 and from the first nine months of 20162021 to the comparable period in 2017:2022:

Sales Volumes

Gas

Gas sales volumes decreased 7% for both the third quarter and for the nine-month period primarily because of natural production decline.

Oil

Oil sales volumes decreased 8%11% for third quarter and 14% for the nine-month period primarily because of natural production decline, and the timing of cash receipts. Gas sales volumes decreased 5% for the nine-month period as compared with the same 2021 periods primarily because of natural production decline, partially offset by timing of cash receipts, and decreased downtime.

Oil

Oil sales volumes decreased 37% for third quarter primarily because of timing of cash receipts, and natural production decline. Oil sales volumes increased 12% for the nine-month period as compared with the same 2021 periods primarily because 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% to 8% a year.

Sales Prices

Gas

The third quarter 20172022 average gas price was $2.81$7.73 per Mcf, a 33% increaseup 102% from the third quarter 20162021 average gas price of $2.12$3.82 per Mcf. For the nine-month period, the average gas price increased 56%92% to $2.94$6.93 per Mcf in 20172022 from $1.88$3.61 per Mcf in 2016. The third quarter 2017 gas price is primarily related to production from May through July 2017, when the average NYMEX price was $3.15 per MMBtu.2021.

Oil

The third quarter 20172022 average oil price was $43.96$104.54 per Bbl, a 2% increaseup 68% from the third quarter 20162021 average oil price of $42.94$62.18 per Bbl. For the nine-month period, the average oil price increased 29%49% to $46.29$83.09 per Bbl in 20172022 from $36.02$55.61 per Bbl in 2016. The third quarter 2017 oil price is primarily related to production from May through July 2017, when the average NYMEX price was $46.81 per Bbl.2021.

Costs

Taxes, Transportation and Other

Taxes, transportation and other costs decreased 11%increased 33% for the third quarter primarily because of decreased gas deductions related to additional gathering fees included in third quarter 2016, partially offset by increased production taxes related to higher gas revenues. For further information on additional gathering fees included in third quarter 2016, see Note 7 to Condensed Financial Statements. Taxes, transportation and other costs increased 35%22% for the nine-month period primarily because of increased production and property taxes, related to higher gas and oil revenues, increased gas deductions, related to higher gathering fees and increased property taxes.partially offset by receipt of production tax refunds.

Production Expense

Production expense increased 18%37% for the third quarter primarily because of increased salt water disposal, environmental costs, and other field goods and services. Production expense increased 2%27% for the nine-month period primarily because of increased salt water disposalrepairs and environmental costs,maintenance, and plug and abandonment expense, partially offset by decreased labor costs, and other field goods and services.timing of the annual Oklahoma Senate Bill 168 fee.

Development Costs

Development costs deducted are based on the current level of development expenditures, budgeted future development costs and the cumulative actual costs under (over) previous deductions. These development costs increased 407%503% for the third quarter and 82% for the nine-month period. The monthly development cost deduction will be reevaluated by XTO Energy and revised as necessary. For further information on developmentprimarily due to equipment purchases in Wyoming. Development costs see Note 2 to Condensed Financial Statements.

Overhead

Overhead increased 29% for the third quarter and 16%decreased 48% for the nine-month period primarily because ofone-time reimbursements timing of drilling costs related to operated overhead correctionsnon-operated wells. Changes in 2016. For further informationoil or natural gas prices could impact future development plans on overhead corrections, see Note 6the underlying properties.

XTO Energy has advised the Trustee that it has elected to Condensed Financial Statements.participate in the development of a non-operated well in Major County, Oklahoma. The well was proposed by Comanche Exploration Co. LLC under a joint operating agreement. XTO Energy has advised the Trustee that development costs for the well are anticipated to be approximately $5 million underlying ($4 million net to the Trust), and that drilling has begun and is expected to be completed in the first quarter of 2023. No assurances can be made as to the estimated costs or timing to complete the well.

Overhead

Overhead increased 3% for the third quarter and 5% for the nine-month period. 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 based on an industry index.

Excess Costs

If monthly costs exceed revenues for any conveyance, these excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits income from another conveyance. UnderlyingThere are no cumulative excess costs balances remaining for the Kansas and Wyoming conveyances remainingany conveyance as of September 30, 2017 totaled $1.1 million, including accrued interest of $0.2 million. Cumulative excess costs for the NPI remaining as of September 30, 2017 totaled $0.9 million, including accrued interest of $0.1 million.2022. For further information on excess costs, including the excess cost balance and accrued interest by conveyance, see Note 54 to Condensed Financial Statements.

Impairment of Net Profits Interest

In light of lower long term prices used to develop projections of future cash flows, continued excess costs on two conveyances and zero distributions to unitholders for the quarter ended June 30, 2016, the Trustee concluded in the second quarter of 2016 that the events or circumstances indicated the carrying value may not be recoverable and an assessment of the forecasted net cash flows was performed for the NPI. 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. The result of the assessment indicated that the estimated undiscounted future net cash flows from the NPI were below the carrying value of the NPI. The NPI was written down to its fair value of $28.8 million, resulting in a $57.3 million impairment charged directly to trust corpus, which did not affect distributable income. There was no impairment of the NPI during the quarter ended September 30, 2017.

Marketing

XTO Energy has advised the Trustee that, effective April 1, 2017, Cross Timbers Energy Services, Inc. (“CTES”), a wholly owned marketing subsidiary of XTO Energy, has assigned all gas sales contracts for production from the underlying properties to XTO Energy. XTO Energy will directly market and sell the gas to third parties. XTO Energy has advised the Trustee that there are no changes to the terms of the contracts related to the assignment and no impact on Trust distributions.

For further information regarding natural gas sales from the underlying properties to affiliates of XTO Energy, see Significant Properties, under Item 2, Properties and Note 7 to the Financial Statements under Item 8, Financial Statements and Supplementary Data of the Trust’s Annual Report on Form10-K for the year ended December 31, 2016.

Contingencies

For information on contingencies, see Note 43 to Condensed Financial Statements.

Forward-Looking Statements

Statements in this report relating to future plans, predictions, events or conditions are forward-looking statements. All statements other than statements of historical factCertain information included in this Form10-Q, including, without limitation,quarterly report and other materials filed, or to be filed, by the Trust with the Securities and Exchange Commission (as well as information included in oral statements regardingor other written statements made or to be made by XTO Energy or the net profits interests,Trustee) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the Trust, operations of the underlying properties and the oil and gas industry. Such forward-looking statements may concern, among other things, potential asset sales or termination of the Trust, excess costs, reserve-to-production ratios, future production, development activities annual and monthlyassociated operating expenses, future development plans by area, increased density drilling, maintenance projects, development, production, regulatory and other costs, and expenses, monthly development cost deductions, oil and gas prices and differentials to NYMEX prices, supply levels,expectations for future drilling, workoverdemand, the impact of inflation and restimulation plans, the outcome of litigationeconomic downturns on economic activity, government policy and its impact on Trust proceeds, distributions to unitholders,oil and industrygas prices and market conditions, arefuture demand, the development and competitiveness of alternative energy sources, pricing differentials, proved reserves, future net cash flows, production levels, expense reserve budgets, availability of financing, arbitration, litigation, liquidity, financing, political and regulatory matters, such as tax and environmental policy, climate policy, trade barriers, sanctions, competition, war and other political or security disturbances. Such forward-looking statements are based on XTO Energy’s and the Trustee’s current plans, expectations, assumptions, projections and estimates and are identified by words such as “may,” “intends,” “plans,” “anticipates,” “believes,” “estimates,” “should,” “could,” “would,” and similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are subjectdifficult to risks and uncertainties which arepredict, including those detailed in Part I, Item 1A of the Trust’s Annual Report on Form10-K for the year ended December 31, 2016,2021, which is incorporated by this reference as though fully set forth herein. Therefore, actual financial and operational results may differ materially from expectations, estimates or assumptions expressed in, implied in, or forecasted in such forward-looking statements. XTO Energy and the Trustee assume no duty to update these statements as of any future date.

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

There have beenNot applicable. Upon qualifying as a smaller reporting company, this information is no material changes in the Trust’s market risks from the information disclosed in Part II, longer required.

Item 7A of the Trust’s Annual Report on Form10-K for the year ended December 31, 2016.4.  Controls and Procedures

As of the end of the period covered by this report, the Trustee carried out an evaluation of the effectiveness of the Trust’s disclosure controls and procedures pursuant to Exchange Act Rules13a-15 and15d-15. Based upon that evaluation, the Trustee concluded that the Trust’s disclosure controls and procedures are effective in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934 and are effective in ensuring that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to the Trustee to allow timely decisions regarding required disclosure. In its evaluation of disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on information provided by XTO Energy. There has not been any change in the Trust’s internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.

PART II—II - OTHER INFORMATION

Item 1.   Legal Proceedings

ReferRoyalty Class Action and Arbitration

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 Note 4the 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 this Quarterly Reportthe Chieftain litigation. The Trust and XTO Energy conducted the interim hearing on Formthe claims related to the Chieftain settlement on October 10-Q12-13, 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.” 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. The Panel in its decision has ruled that out of the $80 million settlement, the “Trust is obligated to pay its share under the Conveyance of the $48 million that was received by the plaintiffs in the Chieftain lawsuit by virtue of the settlement of that litigation. The Trust is not obligated by the Conveyance to pay any share of the $32 million received by the lawyers for informationthe plaintiffs in the Chieftain lawsuit by virtue of the settlement.” XTO Energy and the Trustee are in the process of determining the portion of the $48 million that is allocable to Trust properties to be charged as an excess cost to the Trust, but estimate it to be approximately $14.6 million net to the Trust.

The reduction in the Trust’s share of net proceeds from the portion of the settlement amount the Panel has ruled may be charged against the Oklahoma conveyance would result in excess costs under the Oklahoma conveyance that would likely result in no distributions under the Oklahoma conveyance while these excess costs are recovered. This award completes the portion of the arbitration related to the Chieftain settlement.

Other Trustee claims related to disputed amounts on legal proceedings.the computation of the Trust’s net proceeds for 2014 through 2019 and 2021 were bifurcated from the initial arbitration and will be heard at a later date, which is still to be determined should the arbitration proceed. Pursuant to the purchase and sale agreement entered into between the Trustee and XTO Energy, the parties had agreed to stay the arbitration from the date of execution of the purchase and sale agreement to the earlier of the termination of the purchase and sale agreement or closing date of the sale of assets. Effective August 22, 2022, the Trustee and XTO Energy mutually agreed to terminate the purchase and sale agreement. As a result of the termination, the stay of these arbitration proceedings between XTO Energy and the Trustee with respect to the Trust is lifted. The arbitration proceedings have recommenced and the hearing is currently scheduled for May 30-31, 2023.

Item 1A.   Risk Factors

There have been no material changes in the risk factors disclosed under Part I, Item 1A of the Trust’s Annual Report on Form10-K for the year ended December 31, 2016.2021.

Item 6.   Exhibits

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

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