UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

For the quarterly period ended June 30, 2018

OR

Commission File Number: 1-10476

Hugoton Royalty Trust

(Exact name of registrant as specified in its charter)

c/o The Corporate Trustee:

Simmons Bank

P.O. Box 470727

Fort Worth, Texas 76147

(Address of principal executive offices) (Zip Code)

(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 Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☐    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-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 Rule 12b-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 Rule 12b-2).    Yes  ☐    No  ☒

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

Outstanding as of August 1, 2018

40,000,000

HUGOTON ROYALTY TRUST

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2018

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HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

The following are definitions of significant terms used in this Form 10-Q:

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HUGOTON ROYALTY TRUST

PART I - FINANCIAL INFORMATION

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 Form 10-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 June 30, 2018 and the distributable income and changes in trust corpus for the three-month and six-month periods ended June 30, 2018 and 2017 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 June 30, 2018, and for the three-month and six-month periods ended June 30, 2018 and 2017 have been subjected to a review by PricewaterhouseCoopers LLP, the Trust’s independent registered public accounting firm, whose report is included herein.

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Report of Independent Registered Public Accounting Firm

To the Unitholders of Hugoton Royalty Trust and

Simmons Bank, Trustee:

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 June 30, 2018, and the related condensed statements of distributable income and of changes in trust corpus for the three-month and six-month periods ended June 30, 2018 and 2017, including 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 for them to be in conformity with the modified cash basis of accounting described in Note 1.

We have 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 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 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.

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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.

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HUGOTON ROYALTY TRUST

Condensed Statements of Distributable Income (Unaudited)

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

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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.

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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”):

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.

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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. There was no impairment of the NPI during the quarter ended June 30, 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 trust corpus. Amortization of the net profits interests is calculated on a unit-of-production basis and charged directly to trust corpus. Accumulated amortization was $173,943,434 as of June 30, 2018 and $173,380,675 as of December 31, 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 2018 budgeted development costs for the underlying properties are between $25 million and $30 million. The 2018 budget year generally coincides with the Trust distribution months from April 2018 through March 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.

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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 Kansas and Oklahoma income tax returns reflecting the income and deductions of the Trust attributable to properties located in each state, along with a schedule that includes information regarding distributions to unitholders. However, the Trust does not expect to file a Kansas income tax return for the 2018 tax year because it expects to have no revenues, income or deductions in 2018 attributable to properties located in Kansas. The Trust did not file a Kansas income tax return for the 2017 and 2016 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 the Chieftain 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 Form 10-K for a more detailed discussion of federal and state tax matters.

In December 2010, a royalty class action lawsuit was filed against XTO Energy styled Chieftain 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.

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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 cannot be finally determined until after the judge approves the 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. XTO Energy is analyzing the final plan of allocation to calculate the impact on the Trust and will report to the Trustee when that analysis is complete. XTO Energy has advised the Trustee that depending on its analysis of the final plan of allocation, the portion of the settlement XTO Energy believes should be allocated to the Trust may exceed $20 million. On May 2, 2018, the Trustee submitted a demand for arbitration styled Simmons 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 the Chieftain settlement is not a production cost and that XTO Energy is prohibited from charging the settlement as a production cost under the conveyance or otherwise reducing the Trust’s payments now or in the future as a result of the Chieftain litigation. 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 parties have begun the process of assembling an arbitration panel.

If $20 million or more of the Chieftain settlement is required to be borne by the Trust, it would result in excess costs under the Oklahoma conveyance that, based on recent distribution levels under such conveyance, would likely result in no distributions under the Oklahoma conveyance for several years.

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.

If monthly costs exceed revenues for any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net proceeds from other conveyances.

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

For the quarter ended June 30, 2018, lower gas prices in relation to costs resulted in net excess costs on properties underlying the Kansas net profits interests. Increased budgeted development costs caused costs to exceed revenues on properties underlying the Oklahoma net profits interests. Lower gas prices and increased budgeted development costs caused costs to exceed revenues on properties underlying the Wyoming net profits interests.

Underlying cumulative excess costs for the Kansas, Oklahoma and Wyoming conveyances remaining as of June 30, 2018 totaled $6.2 million, including accrued interest of $0.1 million.

The following discussion should be read in conjunction with the Trustee’s discussion and analysis contained in the Trust’s 2017 Annual Report on Form 10-K, as well as the condensed financial statements and notes thereto included in this Quarterly Report on Form 10-Q. The Trust’s Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available on the Trust’s web site at www.hgt-hugoton.com.

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Distributable Income

Quarter

For the quarter ended June 30, 2018, net profits income was $0, as compared to $1,324,846 for second quarter 2017. This decrease in net profits income is primarily the result of increased development costs ($4.8 million), decreased gas production ($0.6 million), decreased gas prices ($0.5 million), partially offset by net excess costs activity ($4.1 million), increased oil prices ($0.4 million), and decreased production and property taxes ($0.1 million). See “Net Profits Income” below.

After adding interest income of $6,457, deducting administration expense of $358,657, and reducing the cash reserve $352,200 for the payment of Trust expenses, distributable income for the quarter ended June 30, 2018 was $0, or $0.000000 per unit of beneficial interest. Administration expense for the quarter increased $182,486 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 second quarter 2017, distributable income was $1,150,280 or $0.028757 per unit.

Distributions to unitholders for the quarter ended June 30, 2018 were:

Six Months

For the six months ended June 30, 2018, net profits income was $1,590,949 compared with $3,548,472 for the same 2017 period. This decrease in net profits income is primarily the result of increased development costs ($5.0 million), decreased gas production ($1.2 million), decreased gas prices ($1.1 million) and increased production expenses ($0.4 million), partially offset by net excess costs activity ($4.8 million), increased oil prices ($0.7 million), and decreased taxes, transportation, and other ($0.2 million). See “Net Profits Income” below.

After adding interest income of $9,755, deducting administration expense of $660,455, and increasing the expense reserve by $570,209, distributable income for the six months ended June 30, 2018 was $370,040, or $0.009251 per unit of beneficial interest. Administration expense for the six months ended June 30, 2018 increased $146,418 as compared to the same 2017 period, 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 the six months ended June 30, 2017, distributable income was $3,036,960 or $0.075924 per unit.

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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:

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

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The following are explanations of significant variances on the underlying properties from second quarter 2017 to second quarter 2018 and from the first six months of 2017 to the comparable period in 2018:

Sales Volumes

Gas

Gas sales volumes decreased 9% for second quarter and 8% for the six-month period as compared with the same 2017 periods primarily due to natural production decline.

Oil

Oil sales volumes increased 4% for second quarter and 4% for the six-month period as compared with the same 2017 periods primarily due to the timing of cash receipts 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 second quarter 2018 average gas price was $2.64 per Mcf, a 7% decrease from the second quarter 2017 average gas price of $2.83 per Mcf. For the six-month period, the average gas price decreased 6% to $2.81 per Mcf in 2018 from $3.00 per Mcf in 2017. The second quarter 2018 gas price is primarily related to production from February through April 2018, when the average NYMEX price was $2.99 per MMBtu.

Oil

The second quarter 2018 average oil price was $60.85 per Bbl, a 26% increase from the second quarter 2017 average oil price of $48.42 per Bbl. The year-to-date average oil price increased 23% to $58.39 per Bbl in 2018 from $47.50 per Bbl in 2017. The second quarter 2018 oil price is primarily related to production from February through April 2018, when the average NYMEX price was $63.84 per Bbl.

Costs

Taxes, Transportation and Other

Taxes, transportation and other costs decreased 7% for the second quarter and 6% for the six-month period primarily because of decreased production taxes related to lower gas revenues.

Production Expense

Production expense increased 1% for the second quarter primarily because of increased maintenance activity, partially offset by a decrease in other field goods and services. Production expense increased 6% for the six-month period primarily because of increased maintenance activity and labor, partially offset by decreased other field goods and services costs.

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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 994% for the second quarter and 517% for the six-month period. 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 1% for the quarter and 2% for the six-month period. Overhead is charged by XTO Energy 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. Underlying cumulative excess costs for the Kansas, Oklahoma and Wyoming conveyances remaining as of June 30, 2018 totaled $6.2 million ($4.9 million NPI), including accrued interest of $0.1 million ($0.1 million NPI). For further information on excess costs, see Note 5 to Condensed Financial Statements.

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 sells gas directly 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 Form 10-K for the year ended December 31, 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 regulatory or court decisions are forward-looking statements. All statements other than statements of historical fact included in this Form 10-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, drilling, workover and re-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, including those detailed in Part I, Item 1A of the Trust’s Annual Report on Form 10-K for the year ended December 31, 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.

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There have been no material changes in the Trust’s market risks from the information disclosed in Part II, Item 7A of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2017.

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 Rules 13a-15 and 15d-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.

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PART II - OTHER INFORMATION

In December 2010, a royalty class action lawsuit was filed against XTO Energy styled Chieftain 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.

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 cannot be finally determined until after the judge approves the 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. XTO Energy is analyzing the final plan of allocation to calculate the impact on the Trust and will report to the Trustee when that analysis is complete. XTO Energy has advised the Trustee that depending on its analysis of the final plan of allocation, the portion of the settlement XTO Energy believes should be allocated to the Trust may exceed $20 million. On May 2, 2018, the Trustee submitted a demand for arbitration styled Simmons 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 the Chieftain settlement is not a production cost and that XTO Energy is prohibited from charging the settlement as a production cost under the conveyance or otherwise reducing the Trust’s payments now or in the future as a result of the Chieftain litigation. 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 parties have begun the process of assembling an arbitration panel.

If $20 million or more of the Chieftain settlement is required to be borne by the Trust, it would result in excess costs under the Oklahoma conveyance that, based on recent distribution levels under such conveyance, would likely result in no distributions under the Oklahoma conveyance for several years.

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.

The Trust’s failure to regain and maintain compliance with the continued listing standards of the NYSE, will likely result in the delisting of the Trust’s units from the NYSE.

The Trust units are currently listed for trading on the NYSE. The continued listing of the Trust units on the NYSE is subject to the Trust’s compliance with a number of listing standards. To maintain compliance with these continued listing standards, the Trust is required, among other things, to maintain an average closing price per unit of $1.00 or more over a successive 30 trading-day period. On February 26, 2018, the Trustee received written notification from the NYSE that the average closing price of the Trust units had fallen below $1.00 per unit over a successive 30 trading-day period as of February 22, 2018, and, as a result, the average closing price per unit of the units was below the minimum average

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closing price required to maintain listing on the NYSE. In addition, the Trust units could be delisted if the trading price of the Trust units on the NYSE is abnormally low, which has generally been interpreted to mean at levels below $0.16 per unit. In this event, the Trust units would be delisted immediately and suspended from trading on the NYSE. Delisting could negatively impact the trading volume and liquidity of the Trust units. Additionally, delisting from the NYSE may decrease the attractiveness of the Trust units to investors, which could result in a further decline in the market price of the Trust units. The commencement of delisting procedures by the NYSE remains, at all times, at the discretion of the NYSE.

The Trust could have regained compliance if at any time in the six-month period following receipt of the notice, the closing price of its units on the last trading day of any month was at least $1.00 and the 30 trading-day average closing price of its units on such day was also at least $1.00.

Since the Trust has not regained compliance with the referenced continued listing standards, the Trustee is investigating alternative listing arrangements for the Trust units. Notice of any delisting from the NYSE or change in listing arrangements will be provided to unitholders by press release and Form 8-K.

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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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