UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

For the quarterly period ended September 30, 2012March 31, 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 OctoberApril 1, 20122013

40,000,000

HUGOTON ROYALTY TRUST

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED September 30, 2012MARCH 31, 2013

TABLE OF CONTENTS

HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

The following are definitions of significant terms used in this Form 10-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 trust’s 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, 2012March 31, 2013 and the distributable income and changes in trust corpus for the three- and nine-monththree-month periods ended September 30,March 31, 2013 and 2012 and 2011 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, 2012, and for the three-month and nine-month periods ended September 30, 2012 and 2011 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

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, 2012,March 31, 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, 2012March 31, 2013 and 2011.2012. 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, 2011,2012, 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 February 29, 2012,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, 20112012 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 5, 2012May 9, 2013

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.

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

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)

1. Basis of Accounting

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.

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 $135,962,610$139,703,930 as of September 30, 2012March 31, 2013 and $131,698,955$137,173,974 as of December 31, 2011.2012.

2. Development Costs

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 $850,000$500,000 from the January 20112012 distribution through the August 2011 distribution. Due to lower than anticipated actual costs as a result of reduced activity, the development cost deduction was decreased to $500,000 beginning with the September 2011 distribution and was maintained at that level through the September 2012March 2013 distribution. XTO Energy has advised the trustee that revised total 20122013 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 (over) under previous deductions. XTO Energy has advised the trustee that this monthly deduction will continue to be evaluated and revised as necessary.

3. Federal Income Taxes

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 monthsquarter of 2012,2013, 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.

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.

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. 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.

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 trustee@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 atwww.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.

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

4. State Income Taxes

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 Oklahoma and Kansas 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 and Kansas taxtaxes the income of nonresidents from real property located within those states,the state, and the trust has been advised by counsel that those statesOklahoma will each tax nonresidents on income from the net profits interestsinterest located in those states. Wyoming does not have a statewithin the state. Kansas also taxes the income tax.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.

5. Contingencies

An amended petition for a class action lawsuit,Beer, et al. v. XTO Energy IncInc.,., 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 theBeer class, now styledFankhouser 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. AfterXTO 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. This includesXTO has advised the trustee that $1.4 million of athe settlement is attributable to Kansas portionclaims which predatespredate the Trust and therefore has been excluded from Kansas net profits interest.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, it is expected that the deductions XTO Energy has stated it has made, and will continue to make,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. 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 is expected towould 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 willwould reduce applicable net profits to XTO Energy and, correspondingly, to the trust. TheAs of March 31, 2013, the revision is expected to be calculatedwould have reduced trust net proceeds by approximately $358,000 (this amount would have been reflected in earlythe June 2012 through March 2013 and at this time the impact is not fully determinable. 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 tentatively scheduled for May 13,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 has advised the trustee that it began deducting the settlement in September, the trustee has reserved a total of $900,000 from trust distributions to help fund potential legal and other expenses relating to the arbitration. The trustee believesbelieved that without such a reserve, the trust iswas likely to be left without adequate resources to fund the costs of the arbitration out of monthly trust revenues. Because the potential expenses of arbitration are uncertain, especially at this early stage of the arbitration, it is possible that the reserve may not be sufficient to cover all of such expenses.

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 trust’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 will bewere 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 styledWallace 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 styledChieftain 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 has filed an appeal of the class certification to the 10^th10th Circuit Court of Appeals on April 11, 2012, believing the class certification was not proper. The appeal was granted on June 26, 2012. It is expected that theThe matter will behas been fully briefed, in early 2013 and the Courtoral argument occurred May 8, 2013. The court will rule at a time of its discretion.

In December 2010, a 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 demand an accounting to determine whether they have been fully and fairly paid gas royalty interests. The case expressly excludes those claims and wells being prosecuted in the Fankhouser case. The severed Roderick case claims related to the Oklahoma portion of the case were consolidated intoChieftain. The case was certified as a class action in April 2012. XTO Energy has filed an appeal of the class certification to the 10^th10th Circuit Court of Appeals on April 26, 2012, believing the class certification was not proper. The appeal was granted on June 26, 2012. It is expected that theThe matter will behas been fully briefed, in early 2013 and the Courtoral argument occurred May 8, 2013. The court will rule at a time of its discretion.

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 involving it, such asFankhouser, 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 inChieftain orRoderick, 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, 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 styledHarold Lamb v. Bank of America and XTO Energy Inc.,in the U.S. District Court - 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 theFankhouserclass 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 has filed aEnergy’s motion to transfer venue in an effort to moveand has transferred the case from Oklahoma to the U.S. District Court for the Northern District of Texas. XTO has also filed two motions to dismiss. XTO Energy has informed the trustee that it believes it has strong defenses to this lawsuit and intends to vigorously defend its position. However, XTO Energy is cognizant of other, similar litigation involving it, such asFankhouser, and other, unrelated entities. As this case develops XTO Energy will assess its legal position accordingly.

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.

6. Excess CostsOther

In accordance with the terms of the Hugoton Royalty Trust Indenture, XTO Energy has 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 thatApril 24, 2013 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) onsold properties underlying the Oklahoma net profits interests and by $6,225,126for approximately $1,188,430 ($4,980,101950,744 net to the trust) pending any additional closing adjustments. This amount will be included in the May 2013 distribution which will be paid on properties underlyingJune 14, 2013.

The trust is required to join in a sale of up to 1% of the Kansasvalue of the net profits interests. However, these excess costs did not reduce net proceedsinterests in any calendar year, pursuant to notice from XTO Energy of its desire to sell the remaining conveyance. See Note  5.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 20112012 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.www.hugotontrust.com.

Distributable Income

Quarter

For the quarter ended September 30, 2012,March 31, 2013, net profits income was $3,131,255,$8,065,774, as compared to $15,477,314$10,073,319 for thirdfirst quarter 2011. This 80% decrease in2012. Decreased net profits income is primarily the result of decreased gas production ($1.4 million) and lower gasoil and oilgas prices ($10.41.0 million) and the Fankhouser settlement deduction in September 2012, partially offset by increased oil production ($1.70.3 million). See “Net Profits Income” on following page.

After adding interest income of $87$154 and deducting administration expense of $982,022,$247,808, distributable income for the quarter ended September 30, 2012March 31, 2013 was $2,149,320,$7,818,120, or $0.053733$0.195453 per unit of beneficial interest. Changes in interest income are attributable to fluctuations in net profits income and interest rates. Administration expense for the quarter increased $837,713 as compared todecreased $291 from the prior year quarter. For first quarter $800,000 of which the trustee has reserved for legal expenses regarding the Fankhouser class action settlement. For third quarter 2011,2012, distributable income was $15,333,360,$9,825,440 or $0.383334$0.245636 per unit.

Distributions to unitholders for the quarter ended September 30, 2012March 31, 2013 were:

Nine Months

Record Date		Payment Date		Distribution per Unit
January 31, 2013		February 14, 2013		$	0.065536
February 28, 2013		March 14, 2013			0.068665
March 28, 2013		April 12, 2013			0.061252
				$	0.195453

For the nine months ended September 30, 2012, net profits income was $20,161,103 compared with $43,359,342 for the same 2011 period. This 54% decrease in net profits income is primarily the result of lower gas prices ($19.3 million), decreased oil and gas production ($4.8 million) and the Fankhouser settlement deduction in September 2012 ($1.7 million), partially offset by lower development costs ($2.2 million). See “Net Profits Income” below.

After adding interest income of $456 and deducting administration expense of $1,624,959, distributable income for the nine months ended September 30, 2012 was $18,536,600, or $0.463415 per unit of beneficial interest. Administration expense for the nine months ended September 30, 2012 increased $940,926 as compared with the same 2011 period, $900,000 of which the trustee has reserved for legal expenses regarding the Fankhouser class action settlement. For the nine months ended September 30, 2011, distributable income was $42,676,120, or $1.066903 per unit.

Net Profits Income

Net profits income is recorded when received by the trust, which is the month following receipt by XTO Energy, and generally two months after oil and gas production. Net profits income is generally affected by three major factors:

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

The following are explanations of significant variances on the underlying properties from third quarter 2011 to thirdfirst quarter 2012 and from theto first nine months of 2011 to the comparable period in 2012:quarter 2013:

Sales Volumes

Gas

Gas sales volumes decreased 9% for third quarter and 8% for the nine-month period as compared with the same 2011 periods primarily because of natural production decline.

Oil

Oiloil sales volumes increased 1% for third8% from first quarter 2012 as compared withto first quarter 2013. Decreased gas sales volumes are primarily due to natural production decline and the same 2011 periodtiming of cash receipts. Increased oil sales volumes are primarily because ofdue to the timing of cash receipts, partially offset by natural production decline. Oil sales volumes decreased 9% for the first nine months of 2012 as compared with the same 2011 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 thirdfirst quarter 2013 average gas price was $3.87 per Mcf, a 3% decrease from the first quarter 2012 average gas price was $2.74of $4.00 per Mcf, a 45% decrease from the third quarter 2011 average gas price of $4.96 per Mcf. For the nine-month period, the average gas price decreased 31% to $3.27 per Mcf in 2012 from $4.74 per Mcf in 2011. 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 thirdfirst quarter 20122013 gas price is primarily related to production from MayNovember 2012 through July 2012,January 2013, when the average NYMEX price was $2.41$3.51 per MMBtu. The average NYMEX price for AugustFebruary and September 2012March 2013 was $2.82$3.33 per MMBtu. At October 12, 2012,April 18, 2013, the average NYMEX futures price for the following twelve months was $3.94$4.52 per MMBtu.

Oil

The thirdfirst quarter 2013 average oil price was $83.95 per Bbl, a 12% decrease from the first quarter 2012 average oil price was $82.01of $95.36 per Bbl, a 14% decrease from the third quarter 2011 average oil price of $95.00 per Bbl. The year-to-date average oil price increased 1% to $92.71 per Bbl in 2012 from $92.19 per Bbl in 2011. Oil prices are expected to remain volatile. The thirdfirst quarter 20122013 oil price is primarily related to production from MayNovember 2012 through July 2012,January 2013, when the average NYMEX price was $88.33$89.87 per Bbl. The average NYMEX price for AugustFebruary and September 2012March 2013 was $94.52$94.33 per Bbl. At October 12, 2012,April 18, 2013, the average NYMEX futures price for the following twelve months was $93.64$87.36 per Bbl.

Costs

Taxes, Transportation and Other

Taxes, transportation and other decreased 30%5% for the first quarter and 21% for the nine-month period primarily because of decreased oil and gas production taxes and other deductions related to lower oil and gas revenues, partially offset by increased property tax valuations.taxes related to the timing of cash expenditures.

Production Expense

Production expense increased 11%decreased 4% for the first quarter primarily because of increased labordecreased repairs and maintenance, fuel, and compressor costs, and marketing and economic rebates included in 2011, partially offset by decreased fuelincreased water disposal and labor costs. Production expense

Overhead

Overhead increased 11%5% for the nine-month periodfirst quarter primarily because of increased labor and maintenance costs and marketing and economic rebates included in 2011, partially offset by decreased insurance costs.the annual rate adjustment based on an industry index.

Development Costs

Development costs deducted in the calculation of net profits income are based primarily on the current level of development expenditures and the development budget. These developmentDevelopment costs decreased 32% for first quarter 2013 were flat from the third quarter and 38% for the nine-month period primarily because of decreased development activity.prior year quarter.

As ofAt December 31, 2011,2012, cumulative actual costs exceeded cumulative budgeted costs exceeded cumulative actual costsdeducted by approximately $2.4$0.3 million. In calculating net profits income for the quarter ended September 30, 2012,March 31, 2013, XTO Energy deducted budgeted development costs of $1.5 million for the quarter and $4.5 million for the nine-month period.million. After considering actual development costs of $2.0$1.4 million for the quarter, and $7.9 million for the nine-month period, cumulative actual costs exceeded cumulative budgeted costs deducted by approximately $1.0 million at September 30,$0.2 million. First quarter actual development costs primarily relate to disbursements for development activity in fourth quarter 2012.

XTO Energy has advised the trustee that revised total 20122013 budgeted development costs for the underlying properties are between $6 million and $8 million. The 20122013 budget year generally coincides with the trust distribution months from April 20122013 through March 2013.2014. The monthly development cost deduction will be reevaluated by XTO Energy and revised as necessary, based on the 20122013 budget and the timing and amount of actual expenditures. See Note 2 to Condensed Financial Statements.

Excess CostsOther

In accordance with the terms of the Hugoton Royalty Trust Indenture, XTO Energy has 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 thatApril 24, 2013 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) onsold properties underlying the Oklahoma net profits interests and by $6,225,126for approximately $1,188,430 ($4,980,101950,744 net to the trust) pending any additional closing adjustments. This amount will be included in the May 2013 distribution which will be paid on properties underlyingJune 14, 2013.

The trust is required to join in a sale of up to 1% of the Kansasvalue of the net profits interests. However, these excess costs did not reduce net proceedsinterests in any calendar year, pursuant to notice from XTO Energy of its desire to sell the remaining conveyance. See Note 5 to Condensed Financial Statements.related underlying properties.

Contingencies

XTO Energy has entered into a tentative settlement agreement in connection with certain litigation that is anticipated tomay adversely affect the net proceeds of the trust from Oklahoma and Kansas.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. 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, 2011,2012, 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, 2011.2012.

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.

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, 2011.2012.

Items 2 through 4.5.

Not applicable.

Item 5. Other Information.

Item 6. Exhibits.

SIGNATURES

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

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