HUGOTON ROYALTY TRUST - Quarter Report: 2012 June (Form 10-Q)

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

For the quarterly period ended June 30, 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 July 1, 2012

40,000,000

Table of Contents

HUGOTON ROYALTY TRUST

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2012

TABLE OF CONTENTS

2

Table of Contents

HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

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

3

Table of Contents

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 June 30, 2012 and the distributable income and changes in trust corpus for the three- and six-month periods ended June 30, 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 June 30, 2012, and for the three-month and six-month periods ended June 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.

4

Table of Contents

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 June 30, 2012, and the related condensed statements of distributable income and changes in trust corpus for the three-month and six-month periods ended June 30, 2012 and 2011. 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, 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, 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, 2011 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

August 8, 2012

5

Table of Contents

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.

6

Table of Contents

HUGOTON ROYALTY TRUST

Condensed Statements of Distributable Income (Unaudited)

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

7

Table of Contents

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.

8

Table of Contents

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.

9

Table of Contents

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 $135,177,531 as of June 30, 2012 and $131,698,955 as of December 31, 2011.

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 June 2012 distribution. XTO Energy has advised the trustee that revised total 2012 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 six months 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.

10

Table of Contents

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 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.

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 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

11

Table of Contents

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 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, XTO Energy and the plaintiffs entered into settlement negotiations prior to trial and reached a tentative settlement of $37 million on April 23, 2012. The hearing for formal court approval was conducted on June 21, 2012 and preliminarily approved by the court on June 29, 2012. A fairness hearing has been scheduled for October 10, 2012. 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 $29.6 million. 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 has stated that it will begin deducting the settlement amount in the third quarter. Based on recent revenue and expense levels, it is expected that the deductions XTO Energy has stated it will make will cause costs to 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 to the extent revenues exceed costs on such properties. XTO Energy has advised the trustee that 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. XTO Energy has advised the trustee that this expected net upward revision for the royalty interest owners will reduce applicable net profits to XTO Energy and, correspondingly, to the trust. The trustee has advised XTO Energy that all or a portion of the settlement amount should not be deducted from trust revenues. XTO Energy does not agree with the trustee’s position and to resolve this disagreement XTO Energy initiated arbitration on August 1, 2012 in accordance with the terms of the dispute resolution provisions of the Trust Indenture. The trustee intends to prepare a response to XTO Energy’s arbitration claim within the required time frame. The binding arbitration will be heard by a panel of three arbitrators in Fort Worth, Texas, with each side selecting one arbitrator and the third arbitrator selected by the two appointed arbitrators. The arbitration will be administered by the American Arbitration Association under its commercial rules.

12

Table of Contents

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 of the class certification to the 10^th Circuit Court of Appeals on April 11, 2012. The appeal was granted on June 26, 2012.

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 of the class certification to the 10^th Circuit Court of Appeals on April 26, 2012. The appeal was granted on June 26, 2012.

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, 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.

13

Table of Contents

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. Subsequent Events

XTO Energy advised the trustee that lower gas prices and increased production expenses related to the timing of cash expenditures 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.

The trustee has advised XTO Energy it withheld $100,000 in July 2012, bringing the total reserved to $200,000, for potential legal expenses regarding investigating the Fankhouser class action settlement. The trustee may withhold additional amounts from future distributions, which amounts may exceed the amounts withheld to date.

See Note 5 for a discussion of arbitration initiated on August 1, 2012 between XTO Energy and the trustee.

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

Quarter

For the quarter ended June 30, 2012, net profits income was $6,956,529, as compared to $14,667,930 for second quarter 2011. This 53% decrease in net profits income is primarily the result of lower gas prices ($7.7 million). See “Net Profits Income” on the following page.

After adding interest income of $149 and deducting administration expense of $394,838, distributable income for the quarter ended June 30, 2012 was $6,561,840, or $0.164046 per unit of beneficial interest. Administration expense for the quarter increased $129,497 as compared to the prior year quarter, $100,000 of which the trustee has reserved for legal expenses regarding investigating the Fankhouser class action settlement. For second quarter 2011, distributable income was $14,402,760, or $0.360069 per unit.

14

Table of Contents

Distributions to unitholders for the quarter ended June 30, 2012 were:

Six Months

For the six months ended June 30, 2012, net profits income was $17,029,848 compared with $27,882,028 for the same 2011 period. This 39% decrease in net profits income is primarily the result of lower gas prices ($9.5 million) and decreased oil and gas production ($3.8 million), partially offset by decreased development costs ($1.7 million). See “Net Profits Income” below.

After adding interest income of $369 and deducting administration expense of $642,937, distributable income for the six months ended June 30, 2012 was $16,387,280, or $0.409682 per unit of beneficial interest. Administration expense for the six months ended June 30, 2012 increased $103,213 as compared with the same 2011 period, $100,000 of which the trustee has reserved for legal expenses regarding investigating the Fankhouser class action settlement. For the six months ended June 30, 2011, distributable income was $27,342,760, or $0.683569 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:

15

Table of Contents

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

16

Table of Contents

The following are explanations of significant variances on the underlying properties from second quarter 2011 to second quarter 2012 and from the first six months of 2011 to the comparable period in 2012:

Sales Volumes

Gas

Gas sales volumes decreased 7% for second quarter and 8% for the six-month period as compared with the same 2011 periods primarily because of natural production decline.

Oil

Oil sales volumes decreased 3% for second quarter 2012 as compared with the same 2011 period primarily because of natural production decline. Oil sales volumes decreased 14% for the first six months of 2012 as compared with the same 2011 period primarily because of natural production decline and the timing of cash receipts.

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

Sales Prices

Gas

The second quarter 2012 average gas price was $3.05 per Mcf, a 37% decrease from the second quarter 2011 average gas price of $4.86 per Mcf. For the six-month period, the average gas price decreased 24% to $3.54 per Mcf in 2012 from $4.63 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 second quarter 2012 gas price is primarily related to production from February through April 2012, when the average NYMEX price was $2.44 per MMBtu. The average NYMEX price for May and June 2012 was $2.23 per MMBtu. At July 16, 2012, the average NYMEX futures price for the following twelve months was $3.26 per MMBtu.

Oil

The second quarter 2012 average oil price was $100.63 per Bbl, a 4% increase from the second quarter 2011 average oil price of $96.92 per Bbl. The year-to-date average oil price increased 8% to $98.24 per Bbl in 2012 from $90.95 per Bbl in 2011. Oil prices are expected to remain volatile. The second quarter 2012 oil price is primarily related to production from February through April 2012, when the average NYMEX price was $104.01 per Bbl. The average NYMEX price for May and June 2012 was $88.53 per Bbl. At July 16, 2012, the average NYMEX futures price for the following twelve months was $90.41 per Bbl.

Costs

Taxes, Transportation and Other

Taxes, transportation and other decreased 23% for the quarter and 17% for the six-month period primarily because of decreased gas production taxes and other deductions related to lower gas revenues, partially offset by increased property tax valuations.

17

Table of Contents

Production

Production expense increased 15% for the quarter primarily because of increased maintenance, water disposal and other operating costs, partially offset by decreased compressor rental costs. Production expense increased 11% for the six-month period primarily because of increased maintenance, chemical and treating, water disposal and other operating costs, partially offset by decreased insurance costs.

Development

Development costs deducted in the calculation of net profits income are based on the development budget. These development costs decreased 41% for the second quarter and for the six-month period 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 June 30, 2012, XTO Energy deducted budgeted development costs of $1.5 million for the quarter and $3.0 million for the six-month period. After considering actual development costs of $4.0 million for the quarter and $5.9 million for the six-month period, cumulative actual costs exceeded budgeted costs deducted by approximately $0.5 million at June 30, 2012.

XTO Energy has advised the trustee that revised total 2012 budgeted development costs for the underlying properties are between $6 million and $8 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.

18

Table of Contents

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.

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.

19

Table of Contents

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 5.

Not applicable.

Item 6. Exhibits.

20

Table of Contents

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.

21