UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form10-Q

For the quarterly period ended September 30, 20172018

OR

Commission File Number:1-10476

Hugoton Royalty Trust

(Exact name of registrant as specified in its charter)

c/o The Corporate Trustee:

(855)588-7839

(Registrant’s telephone number, including area code)

NONE

(Former name, former address and former fiscal year, if change since last report)

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):

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 Exchange Act Rule12b-2).    Yes  ☐    No  ☑☒

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

Outstanding as of November 1, 20172018

40,000,000

HUGOTON ROYALTY TRUST

FORM10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 20172018

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. 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, 20172018 and the distributable income and changes in trust corpus for the three-three-month and nine-month periods ended September 30, 20172018 and 20162017 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, 2017,2018, and for the three-month and nine-month periods ended September 30, 20172018 and 20162017 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

SouthwestSimmons Bank, TrusteeTrustee:

Results of Review of Financial Statements

We have reviewed the accompanying condensed statement of assets, liabilities and trust corpus of Hugoton Royalty Trust (the “Trust”) as of September 30, 2017,2018, and the related condensed statements of distributable income and of changes in trust corpus for the three-month and nine-month periods ended September 30, 2018 and 2017, and 2016. Theseincluding the related notes (collectively referred to as the “interim financial statements”). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial statements arefor them to be in conformity with the responsibilitymodified cash basis of the Trustee.accounting described in Note 1.

We conducted our reviewhave previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)., the statements of assets, liabilities and trust corpus as of December 31, 2017, and the related statements of distributable income and of changes in trust corpus for the year then ended (not presented herein), and in our report dated March 12, 2018, which included a paragraph describing the modified cash basis of accounting, 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, 2017, is fairly stated, in all material respects, in relation to the statements of assets, liabilities and trust corpus from which it has been derived.

Basis for Review Results

These interim financial statements are the responsibility of the Trust’s management. 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 review in accordance with the standards of the PCAOB. 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),PCAOB, 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.

Basis of Accounting

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, 20172018

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 indicatedindicate 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 During the quarter ended September 30, 2018, 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 productionproperties attributable to the Trust, future crude oil and natural gas commodity prices published by third-party industry experts (adjustedNPI have continued to accumulate, primarily due to the increase in the development budget for basis differentials), estimated taxes, development and operating expenses, and a risk-adjusted discount rate. The resultthe active drilling 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 downfour horizontal wells in Major County, Oklahoma, with completion currently scheduled for early 2019 (see Note 5 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.

ThereCondensed Financial Statements).There was no impairment of the NPI during the quarter ended September 30, 2017.2018.

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 NPI was written down to its fair value of $28,801,000, resulting in an impairment of $57,306,527 charged directly to Trusttrust corpus. Amortization of the net profits interests is calculated on aunit-of-production basis and charged directly to Trusttrust corpus. Accumulated amortization was $171,177,542$173,943,434 as of September 30, 20172018 and $162,874,921$173,380,675 as of December 31, 2016.2017.

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:

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 20172018 budgeted development costs for the underlying properties are between $2$25 million and $4$30 million. The 20172018 budget year generally coincides with the Trust distribution months from April 20172018 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.2019. 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 does not expect to file a Kansas income tax return for the 20172018 tax year because it expects to have no revenues, income or deductions in 20172018 attributable to properties located in Kansas. The Trust did not file a Kansas income tax return with Kansas for the 20162017 and 20152016 tax years for the same reason.

Wyoming does not impose a state income tax.

The Trust could potentially be required to bear a portion of the legal settlement costs arising from theChieftain settlement. For information on contingencies, see Note 4 to Condensed Financial Statements. In the event that the Trust is determined to be responsible for such costs, XTO will 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 legal settlement costs 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 her 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.	Contingencies

In December 2010, a royalty class action lawsuit was filed against 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 demanddemanded 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 appeal2012, then decertified 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. July 2013.

XTO Energy has informedadvised the Trustee that in December 2017, it reached a tentative settlement with the plaintiffs for $80 million and an additional $750 thousand for costs to administer the settlement following final approval. In March 2018, XTO Energy advised the Trustee that it has reached a tentative settlement forbelieved the matter and continues to negotiate the final settlement agreement. The Trustee has requestedportion of the settlement amount from XTO Energy and has been informed that at this time, the amount that XTO Energy believes should be chargedrelates to the Trust hascould be as much as $20 million, but the settlement allocable to the Trust could not been determined.be finally determined until after the judge approved the plaintiffs’ final plan of allocation. On July 27, 2018, plaintiffs submitted their final plan of allocation which was approved by the court on the same date. Based on the final plan of allocation XTO Energy has advised the Trustee that the settlement willit believes approximately $24.3 million in additional production costs should be allocated to allthe Trust. On May 2, 2018, the Trustee submitted a demand for arbitration styledSimmons Bank (successor to Southwest Bank and Bank of XTO Energy’s Oklahoma wells, the majority of which are not properties in which the Trust owns an underlying net profits interest.

The Trustee has informed XTO Energy that it intends to review any claimed reductions in payment to the Trust based on the facts and circumstances of such settlement. In light of a 2014 arbitration decision in which a three panel tribunal decided that the settlement inFankhouser v.America, N.A.) vs. XTO Energy Inc., including a new royalty calculation for future royalty payments, could not be charged to the Trust, to the extent that the claims inChieftain are similar to those inFankhouser the Trustee would likely object to such claimed reductions. Should there be a disagreement as to whether the Trust should bear its share of a settlement or judgment, the matter will be resolved by binding arbitration (the “Arbitration”) through the American Arbitration Association seeking a declaratory judgment that theChieftain settlement is not a production cost and that XTO Energy is prohibited from charging the settlement as a production cost under the termsconveyance or otherwise reducing the Trust’s payments now or in the future as a result of the Indenture creatingChieftain litigation. In the Trust.Arbitration, the Trustee also made claims for disputed amounts on the computation of the Trust’s net proceeds for 2014 through 2016 in excess of $5 million. XTO Energy filed its answer denying the Trustee’s claims. The Arbitration panel has informedbeen selected. Claims related to the Trustee that, althoughChieftainsettlement are tentatively scheduled for a final hearing beginning in March 2019. The remaining claims related to the amountcomputation of any reduction inthe Trust’s net proceeds were bifurcated and will be heard at a later date, which is not presently determinable, in its management’s opinion, the amount is not currently expectedstill to be materialdetermined.

If the approximately $24.3 million allocated portion of theChieftain settlement results in an adjustment to the Trust’s financial position or liquidity thoughshare of net proceeds, it could be material to the Trust’s annual distributable income. Additionally, XTO Energy has advised the Trustee that any reductions would result in additional excess costs exceeding revenues onunder the properties underlyingOklahoma conveyance that would likely result in no distributions under the net profits interests of the case, as applicable,Oklahoma conveyance for several monthly distributions, depending on the size of the settlement, if any, 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 theyears while these additional excess costs for those net profit interests.are recovered.

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 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.	Excess Costs

If monthly costs exceed revenues for any of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming),conveyance, 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:

Distributable Income

Quarter

For the quarter ended September 30, 2017,2018, net profits income was $688,252,$0, as compared to $1,253,498$688,252 for third quarter 2016.2017. This 45%100% decrease in net profits income is primarily the result of increased budgeted development costs ($4.6 million), lower gas prices ($1.0 million), lower gas and oil production ($0.7 million), net excess costs activity ($0.60.5 million), increased production expense ($0.6 million), higher overhead ($0.50.3 million) and increased development costs ($0.5 million), partially offset by higher gas and oil prices ($2.1 million) and decreased taxes, transportation and other costs ($0.20.1 million), partially offset by net excess costs activity ($5.0 million), and higher oil prices ($0.8 million). See “Net Profits Income” below.

After adding interest income of $2,091$6,700 and deducting administration expense of $193,023,$225,204, and reducing the cash reserve $218,504 for the payment of trust expenses, distributable income for the quarter ended September 30, 20172018 was $497,320,$0, or $0.012433$0.000000 per unit of beneficial interest. Administration expense for the quarter increased $5,131$32,181 as compared to the prior year quarter, primarily related to an increase in legal fees and 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 and interest rates. For third quarter 2016,2017, distributable income was $791,920,$497,320, or $0.019798$0.012433 per unit.

Distributions to unitholders for the quarter ended September 30, 20172018 were:

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 20162017 to third quarter 20172018 and from the first nine months of 20162017 to the comparable period in 2017:2018:

Sales Volumes

Gas

Gas sales volumes decreased 7%6% for both the third quarter and 7% for the nine-month period primarily because of natural production decline.

Oil

Oil sales volumes decreased 8%4% for the third quarter and 14%increased 1% for the nine-month period primarily because of natural production decline and the timing of cash receipts.

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 2018 average gas price was $2.47 per Mcf, a 12% decrease from the third quarter 2017 average gas price wasof $2.81 per Mcf, a 33% increase from the third quarter 2016 average gas price of $2.12 per Mcf. For the nine-month period, the average gas price increased 56%decreased 9% to $2.69 per Mcf in 2018 from $2.94 per Mcf in 2017 from $1.88 per Mcf in 2016.2017. The third quarter 20172018 gas price is primarily related to production from May through July 2017,2018, when the average NYMEX price was $3.15$2.90 per MMBtu.

Oil

The third quarter 20172018 average oil price was $43.96$66.86 per Bbl, a 2%52% increase from the third quarter 20162017 average oil price of $42.94$43.96 per Bbl. For the nine-month period, the average oil price increased 29%32% to $61.17 per Bbl in 2018 from $46.29 per Bbl in 2017 from $36.02 per Bbl in 2016.2017. The third quarter 20172018 oil price is primarily related to production from May through July 2017,2018, when the average NYMEX price was $46.81$69.36 per Bbl.

Costs

Taxes, Transportation and Other

Taxes, transportation and other costs decreased 11%increased 4% for the third quarter primarily because of decreasedincreased gas deductions related to additional gathering fees included in third quarter 2016, partially offset byand increased production taxes related to higher oil revenues, partially offset by decreased production taxes related to lower 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 decreased 2% for the nine-month period primarily because of decreased production taxes related to lower gas revenues and decreased property taxes, partially offset by increased 35%gas deductions related to additional gathering fees and increased production taxes related to higher oil revenues.

Production Expense

Production expense increased 7% for the third quarter primarily because of increased repairs and maintenance, partially offset by decreased field goods and services and environmental costs. Production expense increased 7% for the nine-month period primarily because of increased production taxes related to higher gasrepairs and oil revenues, increased gas deductions related to higher gathering fees and increased property taxes.

Production Expense

Production expense increased 18% for the third quarter primarily because of increased salt water disposal, environmental costs, andmaintenance, partially offset by decreased other field goods and services. Production expense increased 2% for the nine-month period primarily because of increased salt water disposalservices and environmental costs, partially offset by decreased labor and other field goods and services.costs.

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%763% for the third quarter and 82%613% for the nine-month period.period, primarily due to the increase in the development budget for the active drilling of four horizontal wells in Major County, Oklahoma, with completion currently scheduled for early 2019. The monthly development cost deduction will be reevaluated by XTO Energy and revised as necessary. For further information on development costs, see Note 2 to Condensed Financial Statements.

Overhead

Overhead increased 29%decreased 1% for the third quarter and 16%increased 1% for the nine-month period primarily becauseperiod. Overhead is charged by XTO Energy for administrative expenses incurred to support operations ofone-time reimbursements related to operated overhead corrections the underlying properties. Overhead fluctuates based on changes in 2016. For further informationthe active well count and drilling activity on overhead corrections, see Note 6 to Condensed Financial Statements.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. Underlying cumulative excess costs for the Kansas, Oklahoma and Wyoming conveyances remaining as of September 30, 20172018 totaled $1.1$11.9 million ($9.5 million NPI), 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.($0.1 million NPI). For further information on excess costs, including the excess cost balance and accrued interest by conveyance, see Note 5 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 willsells gas 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, 2016.2017.

Contingencies

For information on contingencies, see Note 4 to Condensed Financial Statements.

Forward-Looking Statements

Statements in this report relating to future plans, predictions, events, or conditionsregulatory or court decisions are forward-looking statements. All statements other than statements of historical fact included in this Form10-Q, including, without limitation, statements regarding the net profits interests, underlying properties, development activities, annual and monthly development, production and other costs and expenses, monthly development cost deductions, oil and gas prices and differentials to NYMEX prices, supply levels, future drilling, workover and restimulationre-stimulation plans, the outcome of litigation

or settlement discussions and the impact on Trust proceeds, distributions to unitholders, and industry and market conditions, are forward-looking statements that are subject to risks and uncertainties, which areincluding those detailed in Part I, Item 1A of the Trust’s Annual Report on Form10-K for the year ended December 31, 2016,2017, which is incorporated by this reference as though fully set forth herein. 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.

In December 2010, a royalty class action lawsuit was filed against 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 demanded 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, then decertified in July 2013.

XTO Energy advised the Trustee that in December 2017, it reached a tentative settlement with the plaintiffs for $80 million and an additional $750 thousand for costs to administer the settlement following final approval. In March 2018, XTO Energy advised the Trustee that it believed the portion of the settlement that relates to the Trust could be as much as $20 million, but the settlement allocable to the Trust could not be finally determined until after the judge approved the plaintiffs’ final plan of allocation. On July 27, 2018, plaintiffs submitted their final plan of allocation which was approved by the court on the same date. Based on the final plan of allocation XTO Energy has 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 styledSimmons Bank (successor to Southwest Bank and Bank of America, N.A.) vs. XTO Energy Inc. (the “Arbitration”) through the American Arbitration Association seeking a declaratory judgment that theChieftain 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 theChieftain litigation. In the Arbitration, the Trustee also made claims for disputed amounts on the computation of the Trust’s net proceeds for 2014 through 2016 in excess of $5 million. XTO Energy filed its answer denying the Trustee’s claims. The Arbitration panel has been selected. Claims related to theChieftainsettlement are tentatively scheduled for a final hearing beginning in March 2019. The remaining claims related to the computation of the Trust’s net proceeds were bifurcated and will be heard at a later date, which is still to be determined.

If the approximately $24.3 million allocated portion of theChieftain settlement results in an adjustment to the Trust’s share of net proceeds, it would result in additional excess costs under the Oklahoma conveyance that would likely result in no distributions under the Oklahoma conveyance for several years while these additional excess costs are recovered.

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 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.

Item 1A. Risk Factors.

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 XTO Energy may reduce or eliminate distributions to unitholders for extended periods of time.

Production expense and development costs are deducted in the calculation of the Trust’s share of net proceeds. Accordingly, higher or lower production expense and development costs, without concurrent changes in revenue, will directly decrease or increase the amount received by the Trust. If development costs and production expense for underlying properties in a particular state exceed the production proceeds from the

properties (as was the case with respect to the properties underlying the Kansas net profits interest for all of 2016 and 2017, and the first three quarters of 2018, and with respect to the properties underlying the Wyoming net profits interests for all of 2016, the first three quarters of 2017, and the first three quarters of 2018, and with respect to the properties underlying the Oklahoma net profits interest, the second and third quarters of 2018), the Trust will not receive net profits income for those properties until future net proceeds from production in that state exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs. Additionally, XTO Energy has advised the Trustee that total budgeted development costs for the underlying properties are between $25 million and $30 million for the period April 2018 through March 2019 which could continue to exceed revenues for the underlying conveyance. See “Item 1 – Financial Statements (Unaudited) – Notes to Condensed Financial Statements – Note 2 – Development Costs” for additional information.

As described in Note 4 – Contingencies to the Notes to Financial Statements, XTO Energy has advised the Trustee that it believes a portion of the settlement it has reached in theChieftain Royalty Company v. XTO Energy Inc. class action lawsuit relates to the Trust. On July 27, 2018, plaintiffs submitted their final plan of allocation which was approved by the court on the same date. XTO Energy has advised the Trustee that it believes approximately $24.3 million in additional production costs should be allocated to the Trust. The Trustee has submitted a demand for arbitration and the arbitration panel has been selected. Claims related to theChieftainsettlement are tentatively scheduled for a final hearing beginning in March 2019. The remaining claims related to the computation of the Trust’s net proceeds were bifurcated and will be heard at a later date, which is still to be determined. If the approximately $24.3 million allocated portion of theChieftain settlement results in an adjustment to the Trust’s share of net proceeds, it would result in additional excess costs under the Oklahoma conveyance that would likely result in no distributions under the Oklahoma conveyance for several years while these additional excess costs are recovered. See “Item 1 – Financial Statements (Unaudited) – Notes to Condensed Financial Statements – Note 4 – Contingencies” for additional information.

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”. Trading on the OTCQX is often characterized as thin with sporadic fluctuations in price and the availability of buyers or sellers of a security. No assurance can be given that an active trading market for our Trust units will further develop or continue. The Trust units will likely be subject to greater volatility and lower trading volumes than when the Trust units were listed on the New York Stock Exchange. This could depress the trading price of the Trust units and make it more difficult to purchase, dispose of or obtain accurate quotations as to the value of the Trust units. We currently expect the Trust units will continue to trade on the OTCQX.

Item 6. Exhibits.

Refer to Note 4 of this Quarterly Report on Form10-Q for information on legal proceedings.

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.

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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