HUGOTON ROYALTY TRUST - Quarter Report: 2013 September (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

For the quarterly period ended September 30, 2013

OR

Commission File Number: 1-10476

Hugoton Royalty Trust

(Exact name of registrant as specified in its charter)

(877) 228-5083

(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  x    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 or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).    Yes  ¨    No  x

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

Outstanding as of October 1, 2013

40,000,000

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HUGOTON ROYALTY TRUST

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED September 30, 2013

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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

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 Form 10-K. In the opinion of the trustee, all adjustments, consisting only of normal recurring adjustments, necessary to present fairly the assets, liabilities and trust corpus of the Hugoton Royalty Trust at September 30, 2013 and the distributable income and changes in trust corpus for the three- and nine-month periods ended September 30, 2013 and 2012 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, 2013, and for the three-month and nine-month periods ended September 30, 2013 and 2012 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

Bank of America, N.A., Trustee:

We have reviewed the accompanying condensed statement of assets, liabilities and trust corpus of Hugoton Royalty Trust (the “Trust”) as of September 30, 2013, and the related condensed statements of distributable income and changes in trust corpus for the three-month and nine-month periods ended September 30, 2013 and 2012. 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 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, 2012, 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 8, 2013, 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, 2012 is fairly stated in all material respects in relation to the statement of assets, liabilities and trust corpus from which it has been derived.

PricewaterhouseCoopers LLP

Dallas, TX

November 12, 2013

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HUGOTON ROYALTY TRUST

Condensed Statements of Assets, Liabilities and Trust Corpus

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 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.

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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.

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. Amortization of the net profits interests is calculated on a unit-of-production basis and charged directly to trust corpus. Accumulated amortization was $145,555,071 as of September 30, 2013 and $137,173,974 as of December 31, 2012.

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:

The monthly development cost deduction was $500,000 from the January 2012 distribution through the July 2013 distribution. XTO Energy has advised the trustee that as a result of increased development activity it increased the monthly development cost deduction from $500,000 to $600,000 beginning with the August 2013 distribution and it expects it to remain at that level through the December 2013 distribution. XTO Energy has advised the trustee that total 2013 budgeted development costs for the underlying properties are between $6 million and $8 million. 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 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. 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.

Because the trust is a grantor trust for federal tax purposes, each unitholder is taxed directly on his proportionate share of income, deductions and credits of the trust consistent with each such unitholder’s taxable year and method of accounting and without regard to the taxable year or method of accounting employed by the trust. The income of the trust consists primarily of a specified share of the net profits from the sale of oil and natural gas produced from the underlying properties. During the first nine months of 2013, the trust incurred administration expenses and earned interest income on funds held for distribution and for the cash reserve maintained for the payment of contingent and future obligations of the trust. In addition, the trust received proceeds attributable to the sale of certain properties underlying the Oklahoma net profits interests (see discussion in Note 6).

The net profits interests constitute “economic interests” in oil and gas properties for federal tax purposes. Each unitholder is entitled to amortize the cost of the units through cost depletion over the life of the net profits interests or, if greater, through percentage depletion equal to 15 percent of gross income. Unlike cost depletion, percentage depletion is not limited to a unitholder’s depletable tax basis in the units. Rather, a unitholder is entitled to a percentage depletion deduction as long as the applicable underlying properties generate gross income. Unitholders may compute both percentage depletion and cost depletion from each property and claim the larger amount as a deduction on their income tax returns.

If a taxpayer disposes of any “Section 1254 property” (certain oil, gas, geothermal or other mineral property), and the adjusted basis of such property includes adjustments for depletion deductions under Section 611 of the Internal Revenue Code (the “Code”), the taxpayer generally must recapture the amount deducted for depletion as ordinary income (to the extent of gain realized on the disposition of the property). This depletion recapture rule applies to any disposition of property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the U.S. Treasury Regulations govern dispositions of property after March 13, 1995. The Internal Revenue Service likely will take the position that a unitholder must recapture depletion upon the disposition of a unit.

Interest and net profits income attributable to ownership of units and any gain on the sale thereof are considered portfolio income, and not income from a “passive activity,” to the extent a unitholder acquires and holds units as an investment and not in the ordinary course of a trade or business. Therefore, interest and net profits income attributable to ownership of units generally may not be offset by losses from any passive activities.

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6%, and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and qualified dividends of individuals is 20%. Such marginal tax rates may be effectively increased by up to 1.2% due to the phaseout of personal exemptions and the limitations on itemized deductions. The highest marginal U.S. federal income tax rate applicable to corporations is 35%, and such rate applies to both ordinary income and capital gains.

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Section 1411 of the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income generally will include a unitholder’s allocable share of the trust’s interest and royalty income plus the gain recognized from a sale of trust units. In the case of an individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all investments, or (ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels depending on such individual’s federal income tax filing status. In the case of an estate or trust, the tax is imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Pending the outcome of arbitration proceedings between the trust and XTO, the trust may be required to bear a portion of the legal settlement costs arising from the Fankhouser settlement (discussed in Note 5). 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 addition to the potential settlement costs, the trustee has also incurred legal fees in representing the trust’s interests in the ongoing arbitration and other pending litigation matters also discussed in Note 5. For unitholders, such costs will be reflected through an increase in the trust’s administrative expenses, which are deductible by unitholders in determining the net royalty income from the trust.

The difference between the per-unit taxable income for any period and the per-unit cash distributions, if any, reported for such period is attributable to (i) items that are not currently deductible, such as an increase in the cash reserve maintained by the trust for the payment of future expenditures, (ii) the current deduction of expenses that are paid with amounts previously reserved and (iii) items that do not constitute taxable income, such as a decrease in the cash reserve maintained by the trust and/or a return of capital. In 2012 and 2013, the trustee has elected to reserve amounts from monthly distributions in anticipation of legal fees related to current and anticipated litigation (see discussion in Note 5), so the taxable income per period has frequently differed from the actual amount distributed to unitholders.

Individuals may also incur expenses in connection with the acquisition or maintenance of trust units. These expenses, which are different from a unitholder’s share of the trust’s administrative expenses discussed above, may be deductible as “miscellaneous itemized deductions” only to the extent that such expenses exceed 2 percent of the individual’s gross income.

Some trust units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a customer in street name, collectively referred to herein as “middlemen”). Therefore, the trustee considers the trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. U.S. Trust, Bank of America Private Wealth Management, EIN: 56-0906609, Post Office Box 830650, Dallas, Texas, 75283-0650, telephone number 1-877-228-5083, email address trustee1@hugotontrust.com, is the representative of the trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the trust as a WHFIT. Tax information is also posted by the trustee at www.hugotontrust.com. Notwithstanding the foregoing, the middlemen holding trust units on behalf of unitholders, and not the trustee of the trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such trust units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose trust units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the trust units.

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Unitholders should consult their tax advisors regarding trust tax compliance matters.

All revenues from the trust are from sources within Kansas, Oklahoma or Wyoming. Kansas and Oklahoma each impose a state income tax, which is potentially applicable to income from the net profits interests located in each of those states. Because it distributes all of its net income to unitholders, the trust has not been taxed at the trust level in Kansas or Oklahoma. While the trust has not owed tax, the trustee is required to file a return with Kansas and Oklahoma 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. Oklahoma taxes the income of nonresidents from real property located within the state, and the trust has been advised by counsel that Oklahoma will tax nonresidents on income from the net profits interest located within the state. Kansas also taxes the income of nonresidents from property located within the state. However, for tax years beginning after December 31, 2012, Kansas allows individuals to deduct certain amounts, including net income from royalties reported on schedule E of their Form 1040 federal individual income tax return, from their federal adjusted gross income when calculating their Kansas taxable income. This deduction applies to amounts reported as royalty income that are received from grantor trusts, such as the trust. Kansas and Oklahoma also impose a corporate income tax that may apply to unitholders organized as corporations (subject to certain exceptions for S corporations and limited liability companies, depending on their treatment for federal tax purposes).

Wyoming does not have a state income tax.

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

An amended petition for a class action lawsuit, Beer, et al. v. XTO Energy Inc., was filed in January 2006 in the District Court of Texas County, Oklahoma by certain royalty owners of natural gas wells in Oklahoma and Kansas. The plaintiffs allege that XTO Energy has not properly accounted to the plaintiffs for the royalties to which they are entitled and seek an accounting regarding the natural gas and other products produced from their wells and the prices paid for the natural gas and other products produced, and for payment of the monies allegedly owed since June 2002, with a certain limited number of plaintiffs claiming monies owed for additional time. XTO Energy removed the case to federal district court in Oklahoma City. In April 2010, new counsel and representative parties, Fankhouser and Goddard, filed a motion to intervene and prosecute the Beer class, now styled Fankhouser v. XTO Energy Inc. This motion was granted on July 13, 2010. The new plaintiffs and counsel filed an amended complaint asserting new causes of action for breach of fiduciary duties and unjust enrichment. On December 16, 2010, the court certified the class. Cross motions for summary judgment were filed by the parties and ruled on by the court. XTO Energy has informed the trustee that after consideration of the rulings by the court in March and April of 2012, some benefiting XTO Energy and some benefiting the plaintiffs, and with due regard to the vagaries of litigation and their uncertain outcomes, XTO Energy and the plaintiffs entered into settlement negotiations prior to trial and reached a tentative settlement of $37 million on April 23, 2012. XTO has advised the trustee that $1.4 million of the settlement is attributable to Kansas claims which

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predate the Trust and therefore XTO Energy will not charge to the Trust. The settlement also includes a new royalty calculation for future royalty payments. The hearing for formal court approval of the settlement was conducted on June 21, 2012 and preliminarily approved by the court on June 29, 2012. A fairness hearing was conducted on October 10, 2012 and the settlement was given final approval by the court. The court’s order sets out the amount of attorneys’ fees and costs awarded to the plaintiffs’ counsel from the $37 million settlement. A third party administrator will make the distribution to the royalty owners as set out in the order approving the settlement.

XTO Energy has advised the trustee it believes that the terms of the conveyances covering the trust’s net profits interests require the trust to bear its 80% interest in the settlement, or approximately $28.5 million, of which $23.4 million will affect the net proceeds from Oklahoma and $5.1 million will affect the net proceeds from Kansas. If so, this will adversely affect the net proceeds of the trust from Oklahoma and Kansas and will result in costs exceeding revenues on these properties. XTO Energy began deducting the settlement amount with the September 2012 distribution. Based on the revised settlement allocation between Oklahoma and Kansas and recent revenue and expense levels, the deductions XTO Energy has made, and will resume making if the Tribunal (as defined below) ultimately rules in XTO Energy’s favor, will cause costs to exceed revenues for approximately 12 months on properties underlying the Oklahoma net profits interests and by approximately 7 years on properties underlying the Kansas net profits interests; however, changes in oil or natural gas prices or expenses could cause the time period to increase or decrease correspondingly. Excess costs must be recovered, with accrued interest, from the future net proceeds of that conveyance and cannot reduce net proceeds from other conveyances. The net profits interest from Wyoming is unaffected and payments will continue to be made from those properties to the extent revenues exceed costs on such properties. XTO Energy has advised the trustee that the settlement would decrease the amount of net profits going forward for the Oklahoma and Kansas properties due to changes in the way costs (such as gathering, compression and fuel) associated with operating the properties will be allocated, resulting in a net gain to the royalty interest owners. XTO Energy has advised the trustee that this expected net upward revision for the royalty interest owners would reduce applicable net profits to XTO Energy and, correspondingly, to the trust. As of September 30, 2013, the revision would have reduced trust net proceeds by approximately $686,000 (this amount would have been reflected in the June 2012 through September 2013 distributions).

The trustee has advised XTO Energy that all or a portion of the settlement amount should not be deducted from trust revenues. The trustee further advised XTO that, notwithstanding the Fankhouser settlement, XTO should make no change in the manner in which it calculates payments to the trust on a go-forward basis. XTO Energy does not agree with the trustee’s position, and to resolve this disagreement XTO Energy initiated binding arbitration on August 1, 2012 in accordance with the terms of the dispute resolution provisions of the Trust Indenture. On August 17, 2012 the trustee filed its response to XTO’s arbitration claim. All issues in the arbitration will be decided by a panel of three arbitrators (the “Tribunal”). Each side selected one arbitrator and the third arbitrator was selected by the other two appointed arbitrators. The arbitration will be administered by the American Arbitration Association under its commercial rules. The arbitration hearing is scheduled to begin November 12, 2013 in Fort Worth, Texas if not sooner disposed of by the parties by agreement or by the Tribunal on motion. Because XTO Energy advised the trustee that it began deducting the settlement in September 2012, the trustee reserved a total of $900,000 from trust distributions to help fund potential legal and other expenses relating to the arbitration. The trustee believed that without such a reserve, the trust was likely to be left without adequate resources to fund the costs of the arbitration out of monthly trust revenues. As of September 30, 2013, the reserve had been fully depleted in connection with such expenses. Any additional expenses related to this arbitration will be deducted as administrative expense when incurred, however a future reserve may be established to accommodate payment of these expenses as needed.

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The trustee requested that the Tribunal enjoin XTO Energy from continuing to deduct the Fankhouser settlement amount while the arbitration is pending. A hearing on the injunction was held on October 27, 2012. The Tribunal ordered that pending the issuance of a final award or further order of the Tribunal, XTO Energy should not treat any costs or expenses associated with the Fankhouser settlement as chargeable against the trust’s net profit interest under the conveyances. The Tribunal denied the trustee’s request for an interim order directing XTO Energy to pay the trust the amounts offset against the trust’s September and October 2012 distributions on the basis of the Fankhouser litigation. Based on this decision, deductions associated with the Fankhouser settlement were suspended starting in November 2012. XTO Energy has also informed the trustee that during the pendency of this action, no adjustment will be made to the net profits to the trust on a go-forward basis based on the changes in the way costs will be allocated to royalty owners in accordance with the Fankhouser settlement.

In September 2008, a class action lawsuit was filed against XTO Energy styled Wallace B. Roderick Revocable Living Trust, et al. v. XTO Energy Inc. in the District Court of Kearny County, Kansas. XTO Energy removed the case to federal court in Wichita, Kansas. The plaintiffs allege that XTO Energy has improperly taken post-production costs from royalties paid to the plaintiffs from wells located in Kansas, Oklahoma and Colorado. The plaintiffs have filed a motion to certify the class, including only Kansas and Oklahoma wells not part of the Fankhouser matter. After filing the motion to certify, but prior to the class certification hearing, the plaintiff filed a motion to sever the Oklahoma portion of the case so it could be transferred and consolidated with a newly filed class action in Oklahoma styled Chieftain Royalty Company v. XTO Energy Inc. This motion was granted. The Roderick case now comprises only Kansas wells not previously included in the Fankhouser matter. The case was certified as a class action in March 2012. XTO Energy filed an appeal of the class certification to the 10th Circuit Court of Appeals on April 11, 2012. The appeal was granted on June 26, 2012. The oral argument occurred May 8, 2013. The court reversed the certification of the class and remanded the case back to the trial court for further proceedings.

In December 2010, a 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 expressly excludes those claims and wells prosecuted in the Fankhouser case. The severed Roderick case claims related to the Oklahoma portion of the case were consolidated into Chieftain. The case was certified as a class action in April 2012. XTO Energy filed an appeal of the class certification to the 10th Circuit Court of Appeals on April 26, 2012. The appeal was granted on June 26, 2012. The oral argument occurred May 8, 2013. The court reversed the certification of the class and remanded the case back to the trial court for further proceedings.

XTO Energy has informed the trustee that it believes that XTO Energy has strong defenses to these lawsuits and intends to vigorously defend its position. However, XTO Energy is cognizant of other, similar litigation, such as Fankhouser, and other, unrelated entities. As these cases develop, XTO Energy will assess its legal position accordingly. If XTO Energy ultimately makes any settlement payments or receives a judgment against it in Chieftain or Roderick, XTO Energy has advised the trustee that it believes that the terms of the conveyances covering the trust’s net profits interests require the trust to bear its 80% share of such settlement or judgment related to production from the underlying properties. Additionally, if the judgment or settlement increases the amount of future payments to royalty owners,

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XTO Energy has informed the trustee that the trust would bear its proportionate share of the increased payments through reduced net proceeds. In the event of any such settlement or judgment, the trustee intends to review any claimed reductions in payment to the trust based on the facts and circumstances of such settlement or judgment. 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 profit interests of the cases named above, as applicable, for several monthly distributions, depending on the size of the judgment or 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 the costs for those net profit interests. If there is a settlement or judgment and should XTO Energy and the trustee disagree concerning the amount of the settlement or judgment to be charged against the trust’s net profits interests, the matter will be resolved by binding arbitration under the terms of the Indenture creating the trust through the American Arbitration Association.

On September 12, 2012, a lawsuit was filed against Bank of America as trustee and XTO Energy styled Harold Lamb v. Bank of America and XTO Energy Inc., in the U.S. District Court—Western District of Oklahoma. The plaintiff, Harold Lamb, is a unitholder in the trust and alleges that XTO Energy failed to properly pay and account to the trust under the terms of the net overriding royalty conveyance on certain Kansas and Oklahoma properties and that Bank of America, as trustee, failed to properly oversee such payment and accounting by XTO Energy. Additionally, the plaintiff alleges that Bank of America and XTO Energy have breached a fiduciary duty to the trust based on the allegations found in the Fankhouser class action discussed above. The plaintiffs are seeking unspecified amounts for actual/compensatory damages, punitive damages, disgorgement and injunctive relief. Subsequently, the plaintiff dismissed Bank of America from the lawsuit. The court granted XTO Energy’s motion to transfer venue and has transferred the case to the U.S. District Court for the Northern District of Texas. The Court granted XTO’s motion to dismiss and dismissed the case citing the plaintiff’s failure to make a sufficient pre-suit demand on the trustee. Subsequent to the dismissal, attorneys for Mr. Lamb sent a letter to the trustee demanding that the trustee initiate proceedings against XTO Energy.

On August 12, 2013, a demand for arbitration styled Sandra G. Goebel vs. XTO Energy, Inc., Timberland Gathering & Processing Company, Inc. and Bank of America, N.A. was filed with the American Arbitration Association. The claimant, Sandra Goebel, is a unitholder in the trust and alleges that XTO Energy breached the conveyances by misappropriating funds from the trust by failing to modify its existing sales contracts with its affiliate Timberland Gathering & Processing Company, Inc. (“Timberland”). Goebel alleges that these contracts do not currently reflect ‘market rate’ terms, and that XTO had a duty to renegotiate the contracts to obtain more favorable terms. The claimant further alleges that Bank of America breached its fiduciary duty by acquiescing to and facilitating XTO Energy’s alleged self-dealing and concealing information from unitholders that would have revealed XTO Energy’s breaches. The claim also alleges aiding and abetting breach of fiduciary duty by XTO Energy, and disgorgement and unjust enrichment by Timberland. The claimant seeks from the respondents’ damages of an estimated $59.6 million for alleged royalty underpayments, exemplary damages, an accounting by XTO Energy, a declaration, costs, reasonable attorneys’ fees, and pre-judgment and post-judgment interest. Goebel purports to sue on behalf of and for the benefit of the Hugoton Royalty Trust. The trustee filed a response to the arbitration demand denying any liability arising out of the claimant’s allegations. The terms of the Trust indenture provide that Bank of America shall be indemnified by the trust and shall have no liability, other than for fraud, gross negligence or acts or omissions in bad faith as adjudicated by final nonappealable judgment of a court of competent jurisdiction. The trustee intends to object to the arbitrability of Goebel’s claims against the trustee and to otherwise vigorously defend against the allegations. XTO Energy has informed the trustee that it believes that XTO Energy has strong defenses to the allegations in the arbitration. However, XTO Energy is cognizant that in litigation or arbitration, there is risk of receiving adverse rulings. As this matter develops, XTO Energy will continue to assess its legal position accordingly.

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The trustee anticipates that the trust will incur additional legal and other expenses in connection with the Goebel arbitration. As a result, the trustee intends to reserve an additional $1.6 million from trust distributions, which it currently anticipates taking over a period of four months. The September 2013 and October 2013 distributions each reflected a deduction of $400,000 in connection with such reserve. Because the potential expenses of arbitration are uncertain, especially at this stage of the process, it is possible that the reserve may not be sufficient to cover all of such expenses.

Certain of the underlying properties are involved in various other lawsuits and certain 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 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.

XTO advised the trustee that lower gas prices and increased production expenses related to the timing of cash disbursements caused costs to exceed revenues by $114,245 ($91,396 net to the trust) on properties underlying the Wyoming net profits interests in July 2012. However, these excess costs did not reduce net proceeds from the remaining conveyances. XTO advised the trustee that increased gas prices and decreased production expenses led to the full recovery of excess costs, plus accrued interest of $314 ($251 net to the trust) in August 2012.

XTO advised the trustee in September 2012 that it deducted $35,601,400 ($28,481,120 net to the trust) related to the Fankhouser settlement. The settlement deduction caused costs to exceed revenues by $27,235,464 ($21,788,371 net to the trust) on properties underlying the Oklahoma net profits interests and by $6,225,126 ($4,980,101 net to the trust) on properties underlying the Kansas net profits interests. However, these excess costs did not reduce net proceeds from the remaining conveyance. The excess costs claimed underlying the Kansas and Oklahoma net profits interests are the subject of pending arbitration described more fully under Note 5.

In accordance with the terms of the Hugoton Royalty Trust Indenture, XTO Energy advised the trustee that on April 24, 2013 it sold properties underlying the Oklahoma net profits interests for $1,188,430 ($950,744 net to the trust) pending any additional closing adjustments. This amount was included in the May 2013 distribution.

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The trust is required to join in a sale of up to 1% of the value of the net profits interests in any calendar year, pursuant to notice from XTO Energy of its desire to sell the related underlying properties.

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 2012 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.hugotontrust.com.

Distributable Income

Quarter

For the quarter ended September 30, 2013, net profits income was $10,581,606, as compared to $3,131,255 for third quarter 2012. This 238% increase in net profits income is primarily the result of higher oil and gas prices ($6.8 million) and the Fankhouser settlement deduction in September 2012 ($1.7 million), partially offset by decreased gas production ($0.9 million). See “Net Profits Income” on following page.

After adding interest income of $235 and deducting administration expense of $527,281, distributable income for the quarter ended September 30, 2013 was $10,054,560, or $0.251364 per unit of beneficial interest. Administration expense for the quarter decreased $454,741 as compared to the prior year quarter. Administration expense for third quarter 2013 included $400,000 which the trustee reserved for legal expenses regarding the Goebel arbitration and third quarter 2012 included $800,000 which the trustee reserved for legal expenses regarding the Fankhouser class action settlement. For third quarter 2012, distributable income was $2,149,320, or $0.053733 per unit. Distributions to unitholders for the quarter ended September 30, 2013 were:

Nine Months

For the nine months ended September 30, 2013, net profits income was $28,104,952 compared with $20,161,103 for the same 2012 period. This 39% increase in net profits income is primarily the result of higher gas prices ($9.4 million), the Fankhouser settlement deduction in September 2012 ($1.7 million) and proceeds from the property sale in May 2013 ($1.0 million), partially offset by decreased oil and gas production ($4.5 million). See “Net Profits Income” on following page.

After adding interest income of $555 and deducting administration expense of $1,027,147, distributable income for the nine months ended September 30, 2013 was $27,078,360, or $0.676959 per unit of beneficial interest. Administration expense for the nine months ended September 30, 2013 decreased $597,812 as compared with the same 2012 period. Administration expense for the first nine months of 2013 included $400,000 which the trustee reserved for legal expenses regarding the Goebel arbitration and the first nine months of 2012 included $900,000 which the trustee reserved for legal expenses regarding the Fankhouser class action settlement. For the nine months ended September 30, 2012, distributable income was $18,536,600, or $0.463415 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 third quarter 2012 to third quarter 2013 and from the first nine months of 2012 to the comparable period in 2013:

Sales Volumes

Gas

Gas sales volumes decreased 5% for third quarter and 7% for the nine-month period as compared with the same 2012 periods primarily because of natural production decline.

Oil

Oil sales volumes increased 3% for third quarter 2013 as compared with the same 2012 period primarily because of the timing of cash receipts, partially offset by natural production decline. Oil sales volumes decreased 7% for the first nine months of 2013 as compared with the same 2012 period primarily because of 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 2013 average gas price was $4.31 per Mcf, a 57% increase from the third quarter 2012 average gas price of $2.74 per Mcf. For the nine-month period, the average gas price increased 24% to $4.05 per Mcf in 2013 from $3.27 per Mcf in 2012. Natural gas prices are affected by the level of North American production, weather, crude oil and natural gas liquids prices, the U.S. economy, storage levels and import levels of liquefied natural gas. Natural gas prices are expected to remain volatile. The third quarter 2013 gas price is primarily related to production from May through July 2013, when the average NYMEX price was $4.00 per MMBtu. The average NYMEX price for August and September 2013 was $3.51 per MMBtu. At October 22, 2013, the average NYMEX futures price for the following twelve months was $3.78 per MMBtu.

Oil

The third quarter 2013 average oil price was $94.05 per Bbl, a 15% increase from the third quarter 2012 average oil price of $82.01 per Bbl. The year-to-date average oil price increased slightly to $92.76 per Bbl in 2013 from $92.71 per Bbl in 2012. Oil prices are expected to remain volatile. The third quarter 2013 oil price is primarily related to production from May through July 2013, when the average NYMEX price was $98.41 per Bbl. The average NYMEX price for August and September 2013 was $106.52 per Bbl. At October 22, 2013, the average NYMEX futures price for the following twelve months was $96.67 per Bbl.

Costs

Taxes, Transportation and Other

Taxes, transportation and other increased 14% for the quarter primarily because of increased oil and gas production taxes and other deductions related to higher oil and gas revenues, partially offset by decreased property taxes related to the timing of cash expenditures. Taxes, transportation and other increased 1% for the nine-month period primarily because of increased gas production taxes and other deductions related to higher gas revenues, partially offset by decreased property taxes related to the timing of cash expenditures and decreased oil production taxes related to lower oil revenues.

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Production Expense

Production expense decreased 5% for the quarter primarily because of decreased compressor rental and repairs and maintenance costs, partially offset by increased labor, fuel and field costs. Production expense decreased 7% for the nine-month period primarily because of decreased repairs and maintenance and compressor rental costs, partially offset by increased labor costs.

Development Costs

Development costs deducted in the calculation of net profits income are based on the development budget. These development costs increased 13% for the third quarter and 4% for the nine-month period primarily because of increased development activity.

As of December 31, 2012, cumulative actual costs exceeded cumulative budgeted costs by approximately $0.3 million. In calculating net profits income for the quarter ended September 30, 2013, XTO Energy deducted budgeted development costs of $1.7 million for the quarter and $4.7 million for the nine-month period. After considering actual development costs of $1.3 million for the quarter and $4.2 million for the nine-month period, budgeted costs deducted exceeded cumulative actual costs by approximately $0.2 million at September 30, 2013.

XTO Energy has advised the trustee that total 2013 budgeted development costs for the underlying properties are between $6 million and $8 million. The 2013 budget year generally coincides with the trust distribution months from April 2013 through March 2014. The monthly development cost deduction will be reevaluated by XTO Energy and revised as necessary, based on the 2013 budget and the timing and amount of actual expenditures. See Note 2 to Condensed Financial Statements.

Overhead

Overhead increased 7% for the quarter and 5% for the nine-month period primarily because of the annual rate adjustment based on an industry index.

Excess Costs

XTO advised the trustee that lower gas prices and increased production expenses related to the timing of cash disbursements caused costs to exceed revenues by $114,245 ($91,396 net to the trust) on properties underlying the Wyoming net profits interests in July 2012. However, these excess costs did not reduce net proceeds from the remaining conveyances. XTO advised the trustee that increased gas prices and decreased production expenses led to the full recovery of excess costs, plus accrued interest of $314 ($251 net to the trust) in August 2012.

XTO advised the trustee in September 2012 that it deducted $35,601,400 ($28,481,120 net to the trust) related to the Fankhouser settlement. The settlement deduction caused costs to exceed revenues by $27,235,464 ($21,788,371 net to the trust) on properties underlying the Oklahoma net profits interests and by $6,225,126 ($4,980,101 net to the trust) on properties underlying the Kansas net profits interests. However, these excess costs did not reduce net proceeds from the remaining conveyance. The excess costs claimed underlying the Kansas and Oklahoma net profits interests are the subject of pending arbitration described more fully under Note 5 to Condensed Financial Statements.

Other

In accordance with the terms of the Hugoton Royalty Trust Indenture, XTO Energy advised the trustee that on April 24, 2013 it sold properties underlying the Oklahoma net profits interests for $1,188,430 ($950,744 net to the trust) pending any additional closing adjustments. This amount was included in the May 2013 distribution.

The trust is required to join in a sale of up to 1% of the value of the net profits interests in any calendar year, pursuant to notice from XTO Energy of its desire to sell the related underlying properties.

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Contingencies

XTO Energy has entered into a settlement agreement in connection with certain litigation that may adversely affect the net proceeds of the trust from Oklahoma and Kansas, depending on the outcome of a pending arbitration proceeding between XTO Energy and the trust. Additionally, XTO Energy is a party to certain other litigation affecting the underlying properties and XTO Energy and the trustee are parties to other litigation relating to the trust. See Note 5 to Condensed Financial Statements.

Several states have enacted legislation requiring state income tax withholding from 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.

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 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, future drilling, workover and restimulation plans, the outcome of litigation and impact on trust proceeds, distributions to unitholders and industry and market conditions, are forward-looking statements that are subject to risks and uncertainties which are detailed in Part I, Item 1A of the trust’s Annual Report on Form 10-K for the year ended December 31, 2012, 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 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, 2012.

Item 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 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

Item 1. Legal Proceedings.

Refer to Note 5 of this Quarterly Report on Form 10-Q for information on legal proceedings.

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 Form 10-K for the year ended December 31, 2012.

Items 2 through 5.

Not applicable.

Item 6. Exhibits.

(a) Exhibits.

      Exhibit Number

      and Description

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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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