HUGOTON ROYALTY TRUST - Quarter Report: 2012 March (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 March 31, 2012

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 April 1, 2012

40,000,000

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HUGOTON ROYALTY TRUST

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

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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 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 March 31, 2012 and the distributable income and changes in trust corpus for the three-month periods ended March 31, 2012 and 2011 have been included. Distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

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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)

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 $133,695,975 as of March 31, 2012 and $131,698,955 as of December 31, 2011.

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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 from the January 2011 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 March 2012 distribution. XTO Energy has advised the trustee that total 2012 budgeted development costs for the underlying properties are between $8 million and $9 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.

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 quarter of 2012, 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 if the adjusted basis of such property includes adjustments for deductions for depletion under Section 611 of the Internal Revenue 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

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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.

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 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.

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

4. State Income Taxes

All revenues from the trust are from sources within either Kansas, Oklahoma or Wyoming. Because it distributes all of its net income to unitholders, the trust has not been taxed at the trust level in Kansas or Oklahoma. While the trust has not owed tax, the Trustee is 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 tax the income of nonresidents from real property located within those states, and the trust has been advised by counsel that those states will each tax nonresidents on income from the net profits interests located in those states. Wyoming does not have a state income tax. 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).

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 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

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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. 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, the parties entered settlement negotiations leading up to trial and reached a tentative settlement of $37 million on April 23, 2012, which requires court approval. The hearing for formal court approval is scheduled for May 23, 2012. Assuming the court approves the settlement, a fairness hearing will be scheduled at a later date. The trust will bear its 80% interest in the settlement, or approximately $29.6 million. This will adversely affect the net proceeds of the trust from Oklahoma and Kansas and will result in costs exceeding revenues on these properties. Based on recent revenue and expense levels, it is expected that costs will exceed revenues for approximately 18 months; 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. The settlement is expected to 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. This expected net upward revision for the royalty interest owners will reduce applicable net profits to XTO Energy and, correspondingly, to the trust.

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 has filed an appeal to the 10^th Circuit Court of Appeals concerning the certification.

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 being 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 has filed an appeal to the 10^th Circuit Court of Appeals concerning the certification.

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 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, the trust will bear its 80% share of such settlement or judgment related to production from the underlying properties. Additionally, if the judgment

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or settlement increases the amount of future payments to royalty owners, the trust would bear its proportionate share of the increased payments through reduced net proceeds. 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, it 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.

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.

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 2011 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

For the quarter ended March 31, 2012, net profits income was $10,073,319, as compared to $13,214,098 for first quarter 2011. Decreased net profits income is primarily the result of decreased oil and gas production ($2.7 million) and lower gas prices ($1.8 million), partially offset by lower development costs ($0.8 million) and higher oil prices ($0.5 million). See “Net Profits Income” below.

After adding interest income of $220 and deducting administration expense of $248,099, distributable income for the quarter ended March 31, 2012 was $9,825,440, or $0.245636 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 decreased $26,284 from the prior year quarter. For first quarter 2011, distributable income was $12,940,000 or $0.323500 per unit.

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

Net Profits Income

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

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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 first quarter 2011 to first quarter 2012:

Sales Volumes

Gas sales volumes decreased 8% and oil sales volumes decreased 24% from first quarter 2011 to first quarter 2012. Decreased gas sales volumes are primarily due to natural production decline. Decreased oil sales volumes are primarily due to natural production decline and the timing of cash receipts.

The estimated rate of natural production decline on the underlying oil and gas properties is approximately 6% to 8% a year.

Sales Prices

Gas

The first quarter 2012 average gas price was $4.00 per Mcf, a 9% decrease from the first quarter 2011 average gas price of $4.41 per Mcf. 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 first quarter 2012 gas price is primarily related to production from November 2011 through January 2012, when the average NYMEX price was $3.32 per MMBtu. The average NYMEX price for February and March 2012 was $2.56 per MMBtu. At April 18, 2012, the average NYMEX futures price for the following twelve months was $2.61 per MMBtu.

Oil

The first quarter 2012 average oil price was $95.36 per Bbl, a 12% increase from the first quarter 2011 average oil price of $85.34 per Bbl. Oil prices are expected to remain volatile. The first quarter 2012 oil price is primarily related to production from November 2011 through January 2012, when the average NYMEX price was $98.53 per Bbl. The average NYMEX price for February and March 2012 was $104.32 per Bbl. At April 18, 2012, the average NYMEX futures price for the following twelve months was $104.13 per Bbl.

Costs

Taxes, Transportation and Other

Taxes, transportation and other decreased 11% for the first quarter primarily because of decreased oil and gas production taxes and other deductions related to lower oil and gas revenues.

Production

Production expense increased 7% for the first quarter primarily because of increased labor, fuel, compressor and repairs and maintenance costs, partially offset by decreased insurance costs.

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Development

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 development costs for first quarter 2012 decreased 41% from the prior year quarter primarily because of decreased development activity.

As of December 31, 2011, cumulative budgeted costs exceeded cumulative actual costs by approximately $2.4 million. In calculating net profits income for the quarter ended March 31, 2012, XTO Energy deducted budgeted development costs of $1.5 million. After considering actual development costs of $1.8 million for the quarter, cumulative budgeted costs deducted exceeded actual costs by $2.1 million. First quarter actual development costs primarily relate to disbursements for development activity in fourth quarter 2011.

XTO Energy has advised the trustee that total 2012 budgeted development costs for the underlying properties are between $8 million and $9 million. The 2012 budget year generally coincides with the trust distribution months from April 2012 through March 2013. The monthly development cost deduction will be reevaluated by XTO Energy and revised as necessary, based on the 2012 budget and the timing and amount of actual expenditures. See Note 2 to Condensed Financial Statements.

Contingencies

XTO Energy has entered into a tentative settlement agreement in connection with certain litigation that is anticipated to adversely affect the net proceeds of the trust from Oklahoma and Kansas. 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, which is incorporated by this reference as though fully set forth herein. XTO Energy and the trustee assume no duty to update these statements as of any future date.

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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.

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, 2011.

Items 2 through 4.

Not applicable.

Item 5. Other Information.

Item 6. Exhibits.

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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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