HUGOTON ROYALTY TRUST - Annual Report: 2012 (Form 10-K)

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Hugoton Royalty Trust

(Exact name of registrant as specified in the Hugoton Royalty Trust Indenture)

U.S. Trust, Bank of America

Private Wealth Management

Trustee

P.O. Box 830650

Dallas, Texas 75283-0650

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number including area code:

(877) 228-5083

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  þ

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  þ    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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    þ

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  þ

The aggregate market value of the units of beneficial interest of the trust, based on the closing price on the New York Stock Exchange as of June 29, 2012 (the last business day of its most recently completed second fiscal quarter), held by non-affiliates of the registrant on that date was approximately $312 million.

At February 15, 2013, there were 40,000,000 units of beneficial interest of the trust outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Listed below is the only document parts of which are incorporated herein by reference and the parts of this report into which the document is incorporated:

None

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HUGOTON ROYALTY TRUST

2012 ANNUAL REPORT ON FORM 10-K

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HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

The following are definitions of significant terms used in this Annual Report on Form 10-K:

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PART I

Item 1. Business

Hugoton Royalty Trust is an express trust created under the laws of Texas pursuant to the Hugoton Royalty Trust Indenture entered into on December 1, 1998 between XTO Energy Inc. (formerly known as Cross Timbers Oil Company), as grantor, and NationsBank, N.A., as trustee. Bank of America, N.A., successor to NationsBank, N.A., is now the trustee of the trust. In 2007 the Bank of America private wealth management group officially became known as “U.S. Trust, Bank of America Private Wealth Management.” The legal entity that serves as the trustee of the trust did not change, and references in this Form 10-K to U.S. Trust, Bank of America Private Wealth Management shall describe the legal entity Bank of America, N.A. The principal office of the trust is located at 901 Main Street, Dallas, Texas 75202 (telephone number 877-228-5083).

The trust’s internet web site is www.hugotontrust.com. We make available free of charge, through our web site, our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. These reports are accessible through our internet web site as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

Effective December 1, 1998, XTO Energy conveyed to the trust 80% net profits interests in certain predominantly natural gas producing working interest properties in Kansas, Oklahoma and Wyoming under three separate conveyances. In exchange for these net profits interest conveyances to the trust, 40 million units of beneficial interest were issued to XTO Energy. In April and May 1999, XTO Energy sold a total of 17 million units in the trust’s initial public offering. In 1999 and 2000, XTO Energy also sold 1.3 million trust units to certain of its officers. The trust did not receive the proceeds from these sales of trust units. Units are listed and traded on the New York Stock Exchange under the symbol “HGT.” In May 2006, XTO Energy distributed all of its remaining 21.7 million trust units as a dividend to its common stockholders. XTO Energy currently is not a unitholder of the trust.

On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation.

The net profits interests entitle the trust to receive 80% of the net proceeds from the sale of oil and gas from the underlying properties. Each month XTO Energy determines the amount of cash received from the sale of production and deducts property and production taxes, production expense, development costs and overhead.

Net proceeds payable to the trust depend upon production quantities, sales prices of oil and gas and costs to develop and produce oil and gas in the prior month. If monthly costs exceed revenues for any of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming), such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net proceeds from other conveyances.

Costs exceeded revenues on properties underlying the Wyoming net profits interests in July 2012, on properties underlying the Kansas net profits interests in September 2012 and on properties underlying the Oklahoma net profits interests in September 2012. The excess costs claimed underlying the Kansas and Oklahoma net profits interests in September 2012 are the subject of pending arbitration described more fully under “Item 3 — Legal Proceedings.” For further information on excess costs, see Trustee’s Discussion and Analysis of Financial Condition and Results of Operations, under Item 7.

The trust is not liable for any production costs or liabilities attributable to the underlying properties. If at any time the trust receives net profits income in excess of the amount due, the trust is not obligated to return such overpayment, but net profits income payable to the trust for the next month will be reduced by the overpayment, plus interest at the prime rate.

As a working interest owner, XTO Energy can generally decline participation in any operation and allow consenting parties to conduct such operations, as provided under the operating agreements. XTO Energy also can assign, sell, or otherwise transfer its interest in the underlying properties, subject to the net profits interests, or can abandon an underlying property if it is incapable of producing in paying quantities, as determined by XTO Energy.

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To the extent allowed, XTO Energy is responsible for marketing its production from the underlying properties under existing sales contracts or new arrangements on the best terms reasonably obtainable in the circumstances. See “Pricing and Sales Information” under Item 2, Properties.

Net profits income received by the trust on or before the last business day of the month is related to net proceeds received by XTO Energy in the preceding month, and is generally attributable to oil and gas production two months prior. The amount to be distributed to unitholders each month by the trustee is determined by:

Adding –

(1) net profits income received,

(2) interest income and any other cash receipts and

(3) cash available as a result of reduction of cash reserves, then

Subtracting –

(1) liabilities paid and

(2) the reduction in cash available related to establishment of or increase in any cash reserve.

The monthly distribution amount is distributed to unitholders of record within ten business days after the monthly record date. The monthly record date is generally the last business day of the month. The trustee calculates the monthly distribution amount and announces the distribution per unit at least ten days prior to the monthly record date.

The trustee may establish cash reserves for contingencies. Cash held for such reserves, as well as for pending payment of the monthly distribution amount, may be invested in federal obligations or certificates of deposit of major banks.

The trustee’s function is to collect the net profits income from the net profits interests, to pay all trust expenses, and pay the monthly distribution amount to unitholders. The trustee’s powers are specified by the terms of the trust indenture. The trust cannot engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments. The trust has no employees since all administrative functions are performed by the trustee.

Approximately 74% of the net profits income received by the trust during 2012, as well as 76% of the estimated proved reserves of the net profits interests at December 31, 2012 (based on estimated future net cash flows using 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period), is attributable to natural gas. There has historically been a greater demand for gas during the winter months than the rest of the year. Otherwise, trust income generally is not subject to seasonal factors, nor dependent upon patents, licenses, franchises or concessions. The trust conducts no research activities.

The oil and gas industry is highly competitive in all its phases. Operators of the properties in which the trust holds interests encounter competition from other oil and gas companies and from individual producers and operators. Oil and natural gas are commodities, for which market prices are determined by external supply and demand factors.

Item 1A. Risk Factors

The following factors could cause actual results to differ materially from those contained in forward-looking statements made in this report and presented elsewhere by the trustee from time to time. Such factors may have a material adverse effect upon the trust’s financial condition, distributable income and changes in trust corpus.

The following discussion of risk factors should be read in conjunction with the financial statements and related notes included under Item 8, Financial Statements and Supplementary Data. Because of these and other factors, past financial performance should not be considered an indication of future performance.

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The market price for the trust units may not reflect the value of the net profits interests held by the trust.

The public trading price for the trust units tends to be tied to the recent and expected levels of cash distributions on the trust units. The amounts available for distribution by the trust vary in response to numerous factors outside the control of the trust or XTO Energy, including prevailing prices for oil and natural gas produced from the underlying properties. The market price of the trust units is not necessarily indicative of the value that the trust would realize if the net profits interests were sold to a third party buyer. In addition, such market price is not necessarily reflective of the fact that, since the assets of the trust are depleting assets, a portion of each cash distribution paid on the trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. There is no guarantee that distributions made to a unitholder over the life of these depleting assets will equal or exceed the purchase price paid by the unitholder.

Oil and natural gas prices fluctuate due to a number of uncontrollable factors, and any decline will adversely affect the net proceeds payable to the trust and trust distributions.

The trust’s monthly cash distributions are highly dependent upon the prices realized from the sale of natural gas and, to a lesser extent, oil. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the trust and XTO Energy. Factors that contribute to price fluctuations include instability in oil-producing regions, worldwide economic conditions, weather conditions, the supply and price of domestic and foreign oil, natural gas and natural gas liquids, consumer demand, the price and availability of alternative fuels, the proximity to, and capacity of, transportation facilities and the effect of worldwide energy conservation measures. Moreover, government regulations, such as regulation of natural gas transportation and price controls, can affect product prices in the long term. Lower oil and natural gas prices may reduce the amount of oil and natural gas that is economic to produce and will reduce net profits available to the trust. The volatility of energy prices reduces the predictability of future cash distributions to trust unitholders.

Higher production expense and/or development costs, without concurrent increases in revenue, will directly decrease the net proceeds payable to the trust. Certain claimed production expenses by XTO Energy may reduce or eliminate distributions to unitholders for extended periods of time.

Production expense and development costs are deducted in the calculation of the trust’s share of net proceeds. Accordingly, higher or lower production expense and development costs, without concurrent changes in revenue, will directly decrease or increase the amount received by the trust. If development costs and production expense for underlying properties in a particular state exceed the production proceeds from the properties (as was the case with respect to the properties underlying the Wyoming net profits interests in July 2012, the Kansas net profits interests in September 2012 and the Oklahoma net profits interests in September 2012), the trust will not receive net proceeds for those properties until future proceeds from production in that state exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs. The excess costs claimed by XTO Energy in September 2012 underlying the Kansas and Oklahoma net profits interests relate to settlement payments made by XTO Energy in the Fankhouser v. XTO Energy, Inc. case. Although the issue of whether XTO Energy may deduct all or a portion of the settlement payments from trust proceeds is the subject of a pending arbitration, if XTO Energy is ultimately successful in such arbitration, the deduction of the settlement payments would 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. See “Item 3 — Legal Proceedings” for additional information.

Proved reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions could cause the quantities and net present value of the reserves to be overstated.

Estimating proved oil and gas reserves is inherently uncertain. Petroleum engineers consider many factors and make assumptions in estimating reserves and future net cash flows. Those factors and assumptions include historical production from the area compared with production rates from similar producing areas, the effects of governmental regulation,

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assumptions about future commodity prices, production expense and development costs, taxes and capital expenditures, the availability of enhanced recovery techniques and relationships with landowners, working interest partners, pipeline companies and others. Lower oil and gas prices generally cause lower estimates of proved reserves. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variances could be material. Because the trust owns net profits interests, it does not own a specific percentage of the oil and gas reserves. Estimated proved reserves for the net profits interests are based on estimates of reserves for the underlying properties and an allocation method that considers estimated future net proceeds and oil and gas prices. Because trust reserve quantities are determined using an allocation formula, increases or decreases in oil and gas prices can significantly affect estimated reserves of the net profits interests.

Operational risks and hazards associated with the development of the underlying properties may decrease trust distributions.

There are operational risks and hazards associated with the production and transportation of oil and natural gas, including without limitation natural disasters, blowouts, explosions, fires, leakage of oil or natural gas, releases of other hazardous materials, mechanical failures, cratering, and pollution. Any of these or similar occurrences could result in the interruption or cessation of operations, personal injury or loss of life, property damage, damage to productive formations or equipment, damage to the environment or natural resources, or cleanup obligations. The operation of oil and gas properties is also subject to various laws and regulations. Non-compliance with such laws and regulations could subject the operator to additional costs, sanctions or liabilities. The uninsured costs resulting from any of the above or similar occurrences could be deducted as a production expense or development cost in calculating the net proceeds payable to the trust, and would therefore reduce trust distributions by the amount of such uninsured costs.

Cash held by the trustee is not fully insured by the Federal Deposit Insurance Corporation, and future royalty income may be subject to risks relating to the creditworthiness of third parties.

Currently, cash held by the trustee as a reserve for liabilities and for the payment of expenses and distributions to unitholders is invested in Bank of America, N.A. certificates of deposit which are backed by the good faith and credit of Bank of America, N.A., but are only insured by the Federal Deposit Insurance Corporation up to $250,000. Each unitholder should independently assess the creditworthiness of Bank of America, N.A. For more information about the credit rating of Bank of America, N.A., please refer to its periodic filings with the SEC. The trust does not lend money and has limited ability to borrow money, which the trustee believes limits the trust’s risk from the currently tight credit markets. The trust’s future royalty income, however, may be subject to risks relating to the creditworthiness of the operators of the underlying properties and other purchasers of crude oil and natural gas produced from the underlying properties, as well as risks associated with fluctuations in the price of crude oil and natural gas. Information contained in Bank of America N.A.’s periodic filings with the SEC is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report or any other filing that the trust makes with the SEC.

Trust unitholders and the trustee have no influence over the operations on, or future development of, the underlying properties.

Neither the trustee nor the trust unitholders can influence or control the operation or future development of the underlying properties. The failure of an operator to conduct its operations or discharge its obligations in a proper manner could have an adverse effect on the net proceeds payable to the trust. Although XTO Energy and other operators of the underlying properties must adhere to the standard of a prudent operator, they are under no obligation to continue operating the properties. Neither the trustee nor trust unitholders have the right to replace an operator.

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The assets of the trust represent interests in depleting assets and, if XTO Energy or any other operators developing the underlying properties do not perform additional successful development projects, the assets may deplete faster than expected. Eventually, the assets of the trust will cease to produce in commercial quantities and the trust will cease to receive proceeds from such assets.

The net proceeds payable to the trust are derived from the sale of hydrocarbons from depleting assets. The reduction in proved reserve quantities is a common measure of the depletion. Future maintenance and development projects on the underlying properties will affect the quantity of proved reserves and can offset the reduction in proved reserves. The timing and size of these projects will depend on the market prices of oil and natural gas. If the operator(s) of the properties do not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by the trust. Because the net proceeds payable to the trust are derived from the sale of hydrocarbons from depleting assets, the portion of distributions to unitholders attributable to depletion may be considered a return on capital as opposed to a return on investment. Distributions that are a return of capital will ultimately diminish the depletion tax benefits available to the unitholders, which could reduce the market value of the units over time. Eventually, the properties underlying the trust’s net profits interest will cease to produce in commercial quantities and the trust will, therefore, cease to receive any net proceeds therefrom.

Terrorism and continued geopolitical hostilities could adversely affect trust distributions or the market price of the trust units.

Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in response, cause instability in the global financial and energy markets. Terrorism and other geopolitical hostilities could adversely affect trust distributions or the market price of the trust units in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in oil and natural gas prices, or the possibility that the infrastructure on which the operators of the underlying properties rely could be a direct target or an indirect casualty of an act of terror.

XTO Energy may transfer its interest in the underlying properties without the consent of the trust or the trust unitholders.

XTO Energy may at any time transfer all or part of its interest in the underlying properties to another party. Neither the trust nor the trust unitholders are entitled to vote on any transfer of the properties underlying the trust’s net profits interests, and the trust will not receive any proceeds of any such transfer. Following any transfer, the transferred property will continue to be subject to the net profits interests of the trust, but the calculation, reporting and remitting of net proceeds to the trust will be the responsibility of the transferee.

XTO Energy or any other operator of any underlying property may abandon the property, thereby terminating the related net profits interest payable to the trust.

XTO Energy or any other operator of the underlying properties, or any transferee thereof, may abandon any well or property without the consent of the trust or the trust unitholders if they reasonably believe that the well or property can no longer produce in commercially economic quantities. This could result in the termination of the net profits interest relating to the abandoned well or property.

The net profits interests can be sold and the trust would be terminated.

The trust may sell the net profits interests if the holders of 80% or more of the trust units approve the sale or vote to terminate the trust. The trust will terminate if it fails to generate gross proceeds from the underlying properties of at least $1,000,000 per year over any consecutive two-year period. Sale of all of the net profits interests will terminate the trust. The net proceeds of any sale must be for cash with the proceeds promptly distributed to the trust unitholders.

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Trust unitholders have limited voting rights and have limited ability to enforce the trust’s rights against XTO Energy or any other operator of the underlying properties.

The voting rights of a trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for an annual or other periodic re-election of the trustee. Additionally, trust unitholders have no voting rights in XTO Energy or Exxon Mobil Corporation.

The trust indenture and related trust law permit the trustee and the trust to sue XTO Energy or any other operator of the underlying properties to compel them to fulfill the terms of the conveyance of the net profits interests. If the trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of the trust unitholders would likely be limited to bringing a lawsuit against the trustee to compel the trustee to take specified actions. Trust unitholders probably would not be able to sue XTO Energy or any other operator of the underlying properties.

Financial information of the trust is not prepared in accordance with U.S. GAAP.

The financial statements of the trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles, or U.S. GAAP. Although this basis of accounting is permitted for royalty trusts by the Securities and Exchange Commission, the financial statements of the trust differ from U.S. GAAP financial statements because net profits income is not accrued in the month of production, expenses are not recognized when incurred and cash reserves may be established for certain contingencies that would not be recorded in U.S. GAAP financial statements.

The limited liability of trust unitholders is uncertain.

The trust unitholders are not protected from the liabilities of the trust to the same extent that a shareholder would be protected from a corporation’s liabilities. The structure of the trust does not include the interposition of a limited liability entity such as a corporation or limited partnership which would provide further limited liability protection to trust unitholders. While the trustee is liable for any excess liabilities incurred if the trustee fails to ensure that such liabilities are to be satisfied only out of trust assets, under the laws of Texas, which are unsettled on this point, a unitholder may be jointly and severally liable for any liability of the trust if the satisfaction of such liability was not contractually limited to the assets of the trust and the assets of the trust and the trustee are not adequate to satisfy such liability. As a result, trust unitholders may be exposed to personal liability. The trust, however, is not liable for production costs or other liabilities of the underlying properties.

Drilling oil and natural gas wells is a high-risk activity and subjects the trust to a variety of factors that it cannot control.

Drilling oil and natural gas wells involves numerous risks, including the risk that commercially productive oil and natural gas reservoirs are not encountered. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause drilling activities to be unsuccessful. In addition, there is often uncertainty as to the future cost or timing of drilling, completing and operating wells. Further, development activities may be curtailed, delayed or canceled as a result of a variety of factors, including:

While these risks do not expose the trust to liabilities of the drilling contractor or operator of the well, they can reduce net proceeds payable to the trust and trust distributions by decreasing oil and gas revenues or increasing production

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expense or development costs from the underlying properties. Furthermore, these risks may cause the costs of development activities on the underlying properties to exceed the revenues therefrom, thereby reducing net proceeds payable to the trust and trust distributions.

The underlying properties are subject to complex federal, state and local laws and regulations that could adversely affect net proceeds payable to the trust and trust distributions.

Extensive federal, state and local regulation of the oil and natural gas industry significantly affects operations on the underlying properties. In particular, oil and natural gas development and production are subject to stringent environmental regulations. These regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning oil and natural gas wells and other related facilities, which costs could reduce net proceeds payable to the trust and trust distributions. These regulations may become more demanding in the future.

Item 1B. Unresolved Staff Comments

As of December 31, 2012, the trust did not have any unresolved Securities and Exchange Commission staff comments.

Item 2. Properties

The net profits interests are the principal asset of the trust. The trustee cannot acquire any other assets, with the exception of certain short-term investments as specified under Item 1, Business. The trustee may sell or otherwise dispose of all or any part of the net profits interests if approved by at least 80% of the unitholders, or upon termination of the trust. Otherwise, the trust may only sell up to 1% of the value of the net profits interests in any calendar year, pursuant to notice from XTO Energy of its desire to sell the related underlying properties. Any such sale must be for cash with the proceeds promptly distributed to the unitholders. All the underlying properties are currently owned by XTO Energy. XTO Energy may sell all or any portion of the underlying properties at any time, subject to and burdened by the net profits interests.

The underlying properties are predominantly gas-producing properties with established production histories in the Hugoton area of Oklahoma and Kansas, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. The average reserve-to-production index for the underlying properties as of December 31, 2012 is approximately 13 years. This index is calculated using total proved reserves and estimated 2013 production for the underlying properties. The projected 2013 production is from proved developed producing reserves as of December 31, 2012. Based on estimated future net cash flows at 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period, the proved reserves of the underlying properties are approximately 78% natural gas and 22% oil. XTO Energy operates approximately 95% of the underlying properties.

Because the underlying properties are working interests, production expense, development costs and overhead are deducted in calculating net profits income. As a result, net profits income is affected by the level of maintenance and development activity on the underlying properties. See Trustee’s Discussion and Analysis of Financial Condition and Results of Operations, under Item 7. Total 2012 development costs deducted for the underlying properties were $6 million, a decrease of 32% from the prior year. XTO Energy has informed the trustee that total 2013 budgeted development costs for the underlying properties are between $6 million and $8 million.

Significant Properties

Hugoton Area

Natural gas was discovered in the Hugoton area in 1922. With an estimated five million productive acres covering parts of Texas, Oklahoma and Kansas, the Hugoton area is one of the largest domestic natural gas producing areas. During 2012, daily sales volumes from the underlying properties in the Hugoton area averaged approximately 15,000 Mcf of gas and 58 Bbls of oil.

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Most of the production from the underlying properties in the Hugoton area is from the Chase formation. XTO Energy has informed the trustee that it has begun to develop other formations that underlie the 79,500 net acres held by production by the Chase formation wells, which include the Council Grove, Morrow, Chester and St. Louis formations. These formations are characterized by both oil and gas production from a variety of structural and stratigraphic traps. Since 2003, XTO Energy has drilled wells to these formations and plans to continue this development program in 2013.

Within this area, XTO Energy did not drill any wells or perform any workovers in 2012. XTO Energy has informed the trustee that it does not plan to drill any new wells but may perform up to 20 workovers during 2013.

XTO Energy’s future development plans for the underlying properties in the Hugoton area include:

XTO Energy delivers most of its Hugoton gas production to a gathering and processing system owned by a subsidiary. Most of the gas is sold under the terms of a contract that was entered into in March 1996, predating the existence of the trust. This system collects the majority of its throughput from underlying properties, which, in recent months, has been approximately 11,000 Mcf per day. The gathering subsidiary purchases the gas from XTO Energy at the wellhead, gathers and transports the gas to its plant, and treats and processes the gas at the plant. The gathering subsidiary has agreed to use its best efforts to purchase all gas produced by XTO Energy from the wells that are subject to the contract, but the gathering subsidiary is not obligated to purchase gas in excess of its market requirements. The gathering subsidiary has been taking all of the gas produced for over ten years. The gathering subsidiary pays XTO Energy for wellhead volumes at a price of 80% to 85% of the net residue price received by XTO Energy’s marketing affiliate, which amount is adjusted for the BTU content of the gas. This affiliate currently sells the residue to a pipeline at a price based on a monthly pipeline index less actual third party fees. The term of these contracts can vary by contract, but in general the contracts, after an initial stated period, renew on a monthly basis unless either party gives notice of termination. If either party to the contracts fails to perform under the contract, the contract may be terminated if written notice is given of the breach and the breaching party fails to cure the breach within a specified period. The March 1996 contract has an annual price renegotiation term under which either party can request that the price provided under the contract be renegotiated. Neither party has requested that the price be renegotiated. XTO Energy does not anticipate that the terms of the contracts will be renegotiated.

Other Hugoton gas production is sold under a third party contract that remains in effect for the life of the lease. Under the contract, XTO Energy receives 74.5% of the net proceeds received by the buyer from the sale of the residue gas and liquids produced from certain underlying properties. The residue gas net proceeds are based upon the weighted average price of the gas sold by the buyer at its facilities, and the liquids net proceeds are based upon an average daily index sales price, less transportation, processing and storage fees incurred by the buyer. The buyer agrees to use its best efforts to take all of the gas produced, subject to its market requirements. The buyer has been taking all of the gas produced for over ten years.

Anadarko Basin

Oil and gas accumulations were discovered in the Anadarko Basin of western Oklahoma in 1945. XTO Energy is one of the largest producers in the Ringwood, Northwest Okeene and Cheyenne Valley fields of Major County, the Northeast Cedardale field of Woodward County and the Elk City field of Beckham County, the principal producing regions of the underlying properties in the Anadarko Basin. Daily sales volumes from the underlying properties in the Anadarko Basin averaged 25,500 Mcf of gas and 539 Bbls of oil in 2012.

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The fields in the Major County area are characterized by oil and gas production from a variety of structural and stratigraphic traps. Productive zones include the Oswego, Red Fork, Inola, Chester, Manning, Mississippian, Hunton and Arbuckle formations. Within this area, XTO Energy drilled 1 gross (0.6 net) well and performed 46 workovers in 2012. XTO Energy has informed the trustee that does not plan to drill any new wells but may perform up to 14 workovers in Major County during 2013.

The fields within Woodward County are characterized primarily by gas production from a variety of structural and stratigraphic traps. Productive zones include the Cottage Grove, Oswego, Chester and Mississippian formations. Within this area, XTO Energy did not drill any wells but did perform 3 workovers in 2012. XTO Energy has informed the trustee that it does not plan to drill any new wells but may perform up to 3 workovers in Woodward County during 2013.

The Elk City field on the eastern edge of Beckham County produces oil and gas from a structural anticline with stratigraphic trapping features. Production zones include the Hoxbar, Atoka and Morrow formations. Within this area, XTO Energy did not drill any wells but did perform 9 workovers in 2012. XTO Energy has informed the trustee that does not plan to drill any new wells but may perform up to 6 workovers within the Elk City field during 2013.

XTO Energy plans to further develop the underlying properties in the Anadarko Basin primarily through:

A gathering subsidiary of XTO Energy operates a 300-mile gathering system and pipeline in the Major County area. The gathering subsidiary and a third-party processor purchase natural gas produced at the wellhead from XTO Energy and other producers in the area under various agreements, most of which were entered into in the 1960’s and 1970’s, and which include life-of-production terms such that the contracts will continue until there is no further production from the underlying properties, unless the production declines so that it is no longer economical to take the gas. The gathering subsidiary and the third-party processor are required to take certain minimum volumes of the gas produced but have been taking all of the volumes produced for over ten years. The gathering subsidiary gathers and transports the gas to a third-party processor, which processes the gas and pays XTO Energy and other producers for at least 50% of the liquids processed based upon a weighted average sales price less transportation charges, which price may vary in the event of inadequate markets. After the gas is processed, the gathering subsidiary transports the gas via a residue pipeline to a connection with an interstate pipeline. The gathering subsidiary sells the residue gas to the marketing subsidiary of XTO Energy based upon a weighted average price, which price will vary monthly based upon market conditions. The gathering subsidiary pays this price to XTO Energy less a compression and gathering fee of approximately $0.31 per Mcf of residue gas. This gathering fee was previously approved by the Federal Energy Regulatory Commission when the gathering subsidiary was regulated and is unlikely to change. During 2012, the gathering system collected approximately 9,000 Mcf per day, approximately 53% of which XTO Energy operates. Estimated capacity of the gathering system is 24,000 Mcf per day. The gathering subsidiary also provides contract operating services to properties in Woodward County, collecting approximately 6,000 Mcf per day, for an average fee of approximately $0.05 per Mcf. The fee is subject to an annual price renegotiation under which either party can request that the price provided under the contract be renegotiated. The contract continues on a yearly basis, and it is subject to termination upon written notice prior to its annual renewal or in the event the parties fail to agree upon a pricing renegotiation. XTO Energy also sells gas directly to its marketing subsidiary under a month-to-month contract, which then sells the gas to third parties. The price paid to XTO Energy is based upon the weighted average price of several published indices, which price varies upon market conditions but does not include a deduction for any marketing fees. The price paid by the marketing affiliate includes a deduction for any transportation fees charged by the third party. Neither party has a firm obligation to sell or purchase any specific minimum quantity of gas.

Green River Basin

The Green River Basin is located in southwestern Wyoming. Natural gas was discovered in the Fontenelle field of the Green River Basin in the early 1970’s. The producing reservoirs are the Frontier, Baxter and Dakota sandstones.

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Daily 2012 sales volumes from the underlying properties in the Fontenelle field averaged 15,200 Mcf of natural gas and 28 Bbls of oil. XTO Energy did not drill any wells or perform any workovers in the Green River Basin in 2012. XTO Energy has advised the trustee that it does not plan to drill any new wells but may perform up to 4 workovers in the Green River Basin during 2013. XTO Energy has advised the trustee that it is continuing its efforts to reduce pipeline pressure which has shown potential for increasing production and extending field life in the Fontenelle Field.

Potential development activities for the underlying properties in this area include:

XTO Energy markets the gas produced from the Fontenelle field and nearby properties under various marketing arrangements. Under the agreement covering the majority of the gas sold, XTO Energy compresses the gas on the lease, transports it off the lease and compresses the gas again prior to entry into the gas plant pipeline. The pipeline transports the gas to the gas plant, where the gas is processed, then redelivered to XTO Energy. The owner of the gas plant and related pipeline charges XTO Energy for operational fuel and processing and has agreed to accept certain volumes, which amounts can be adjusted by the owner. The owner may be able to cease taking volumes if it has valid unaddressed concerns regarding the creditworthiness of XTO Energy. In 2012, the fuel charge was 1.80% of the volumes produced and the processing fee was approximately $0.11 per MMBtu. These charges are adjusted annually based upon a published governmental economic index, and the contract renews on a year-to-year basis. XTO Energy transports and sells this gas directly to the markets based on a spot sales price on a month-to-month term, and the volumes to be sold are generally determined upon a monthly basis. These contracts may be terminated by either party if there are credit issues with the other party. The gas not sold under the above arrangement may be gathered and sold under a similar arrangement on a month-to-month term where the fee is approximately $0.18 per MMBtu and is adjusted annually. The amount of gas that the gatherer is required to gather is limited to certain maximum volumes, and the gatherer may be able to cease taking volumes if it has valid unaddressed concerns regarding the creditworthiness of XTO Energy. Alternatively, the gas may be sold under a contract where XTO Energy directly sells the gas to a third party on the lease at an adjusted index price, which price varies upon market conditions. The contract continues on a month-to-month basis, and the buyer is obligated to make a good faith effort to purchase a minimum 90% of the gas nominated by buyer for purchase. Condensate is sold to an independent third party at market rates on a month-to-month basis. The purchaser accepts all condensate delivered at the lease, but either party may suspend performance of the contract if there are credit issues with the other party.

Producing Acreage, Drilling and Well Counts

For the following data, “gross” refers to the total wells or acres on the underlying properties in which XTO Energy owns a working interest and “net” refers to gross wells or acres multiplied by the percentage working interest owned by XTO Energy. Although many of XTO Energy’s wells produce both oil and gas, a well is categorized as an oil well or a gas well based upon the ratio of oil to natural gas production. Operated wells are managed by XTO Energy, while nonoperated wells are managed by others.

The underlying properties are interests in developed properties located primarily in gas producing regions of Kansas, Oklahoma and Wyoming. The following is a summary of the approximate producing acreage of the underlying properties at December 31, 2012. Undeveloped acreage is not significant.

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The following is a summary of the producing wells on the underlying properties as of December 31, 2012:

The following is a summary of the number of wells drilled on the underlying properties during the years indicated. During 2012 and 2010 no exploratory wells were drilled on the underlying properties. During 2011, one exploratory dry hole (0.0 net) was drilled on the underlying properties. All other wells drilled were developmental. There were no wells in process of drilling at December 31, 2012.

Estimated Proved Reserves and Future Net Cash Flows

The following are proved reserves of the underlying properties, as estimated by independent engineers, and proved reserves and future net cash flows from proved reserves of the net profits interests, based on an allocation of these reserves, at December 31, 2012:

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Proved reserves consist of the following:

Approximately 85% of the underlying proved reserves are proved developed reserves.

The process of estimating oil and gas reserves is complex and requires significant judgment as discussed in Item 1A, Risk Factors, and is performed by XTO Energy. As a result, XTO Energy has developed internal policies and controls for estimating and recording reserves. XTO Energy’s policies regarding booking reserves require proved reserves to be in compliance with the SEC definitions and guidance. XTO Energy’s policies assign responsibilities for compliance in reserves bookings to its reserve engineering group and require that reserve estimates be made by qualified reserves estimators, as defined by the Society of Petroleum Engineers’ standards. All qualified reserves estimators are required to receive education covering the fundamentals of SEC proved reserves assignments.

The XTO Energy reserve engineering group reviews reserve estimates with our third-party petroleum consultants, Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents, Ltd. estimated oil and gas reserves attributable to the underlying properties as of December 31, 2012, 2011, 2010 and 2009. Miller and Lents’ primary technical person responsible for calculating the trust’s reserves has more than 30 years of experience as a reserve engineer. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net profits interests. Numerous uncertainties are inherent in estimating reserve volumes and values, and such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimates.

Reserve quantities and revenues for the net profits interests were estimated from projections of reserves and revenues attributable to the combined interests of the trust and XTO Energy in the subject properties. Since the trust has defined net profits interests, the trust does not own a specific percentage of the oil and gas reserve quantities. Accordingly, reserves allocated to the trust pertaining to its 80% net profits interests in the properties have effectively been reduced to reflect recovery of the trust’s 80% portion of applicable production and development costs. Because trust reserve quantities are determined using an allocation formula, any fluctuations in actual or assumed prices or costs will result in revisions to the estimated reserve quantities allocated to the net profits interests.

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Oil and Natural Gas Production

Trust production is recognized in the period net profits income is received, which is the month following receipt by XTO Energy, and generally two months after the time of production. Oil and gas production and average sales prices attributable to the underlying properties and the net profits interests for each of the three years ended December 31 were as follows:

Oil and gas production by conveyance attributable to the underlying properties for each of the three years ended December 31 were as follows:

Pricing and Sales Information

A subsidiary of XTO Energy purchases most of XTO Energy’s natural gas production based on a weighted average sales price, then sells the gas to third parties for the best available price. Oil production is generally marketed at the wellhead to third parties at the best available price. XTO Energy arranges for some of its natural gas to be processed by unaffiliated third parties and markets the natural gas liquids. Most of the natural gas attributable to the underlying properties is marketed under contracts existing at trust inception. Contracts covering production from the Ringwood area of the Major County area are generally for the life of the lease, and the contract for the majority of production from the Hugoton area was extended through 2013. If new contracts are entered with unaffiliated third parties, the proceeds from sales under those new contracts will be included in gross proceeds from the underlying properties. If new contracts are entered with XTO Energy’s marketing subsidiary, it may charge XTO Energy a fee that may not exceed 2% of the sales price of the oil and natural gas received from unaffiliated parties. The sales price is net of any deductions for transportation from the wellhead to the unaffiliated parties and any gravity or quality adjustments. For further information on these arrangements see Significant Properties above.

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Regulation

Natural Gas Regulation

The interstate transportation and sale for resale of natural gas is subject to federal regulation, including transportation and storage rates charged, tariffs, and various other matters, by the Federal Energy Regulatory Commission. Federal price controls on wellhead sales of domestic natural gas terminated on January 1, 1993. While natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act, including enforcement rules and new annual reporting requirements for certain sellers of natural gas. It is impossible to predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, such proposals might have on the operations of the underlying properties.

Federal Regulation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The net price received from the sale of these products is affected by market transportation costs. Under rules adopted by FERC effective January 1995, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances.

On December 19, 2007, the President signed into law the Energy Independence & Security Act of 2007 (PL 110-140). The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations, and establishes penalties for violations thereunder. XTO Energy has advised the trustee that it cannot predict the impact of future government regulation on any crude oil, condensate or natural gas liquids facilities, sales or transportation transactions.

Environmental Regulation

Companies that are engaged in the oil and gas industry are affected by federal, state and local laws regulating the discharge of materials into the environment. Those laws may impact operations of the underlying properties. No material expenses have been incurred on the underlying properties in complying with environmental laws and regulations. XTO Energy does not expect that future compliance will have a material adverse effect on the trust.

There is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change. Several states have adopted climate change legislation and regulations, and various other regulatory bodies have announced their intent to regulate GHG emissions or adopt climate change regulations. As these regulations are under development, XTO Energy is unable to predict the total impact of the potential regulations upon the operators of the underlying properties, and it is possible that operators of the underlying properties could face increases in operating costs in order to comply with climate change or GHG emissions legislation, which costs could reduce net proceeds payable to the trust and trust distributions.

State Regulation

The various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rates of production may be regulated and the maximum daily production allowables from both oil and gas wells may be established on a market demand or conservation basis, or both.

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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 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 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 Part I, Item 3, Legal Proceedings). 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

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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 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.

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 taxes the income of nonresidents from real property located within the state, and the trust has been advised by counsel that Oklahoma will tax nonresidents on income from the net profits interest located within the state. Kansas also taxes the income of nonresidents from property located within the state. However, for tax years beginning after December 31, 2012, Kansas allows individuals to deduct certain amounts, including net income from royalties reported on schedule E of their Form 1040 federal individual income tax return, from their federal adjusted gross income when calculating their Kansas taxable income. This deduction applies to amounts reported as royalty income that are received from grantor trusts, such as the trust. Kansas and Oklahoma also impose a corporate income tax that may apply to unitholders organized as corporations (subject to certain exceptions for S corporations and limited liability companies, depending on their treatment for federal tax purposes).

Wyoming does not have a state income tax.

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

State Tax Withholding

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

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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.

Other Regulation

The Minerals Management Service of the United States Department of the Interior amended the crude oil valuation regulations in July 2004 and the natural gas valuation regulations in June 2005 for oil and natural gas produced from federal oil and natural gas leases. The principal effect of the oil regulations pertains to which published market prices are most appropriate to value crude oil not sold in an arm’s-length transaction and what transportation deductions should be allowed. The principal effect of the natural gas valuation regulations pertains to the calculation of transportation deductions and changes necessitated by judicial decisions since the regulations were last amended. Seven percent of the net acres of the underlying properties, primarily located in Wyoming, involve federal leases. Neither of these changes have had a significant effect on trust distributions.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws, including, but not limited to, regulations and laws relating to environmental protection, occupational safety, resource conservation and equal employment opportunity. XTO Energy has advised the trustee that it does not believe that compliance with these laws will have any material adverse effect upon the unitholders.

Item 3. Legal Proceedings

An amended petition for a class action lawsuit, Beer, et al. v. XTO Energy Inc., was filed in January 2006 in the District Court of Texas County, Oklahoma by certain royalty owners of natural gas wells in Oklahoma and Kansas. The plaintiffs allege that XTO Energy has not properly accounted to the plaintiffs for the royalties to which they are entitled and seek an accounting regarding the natural gas and other products produced from their wells and the prices paid for the natural gas and other products produced, and for payment of the monies allegedly owed since June 2002, with a certain limited number of plaintiffs claiming monies owed for additional time. XTO Energy removed the case to federal district court in Oklahoma City. In April 2010, new counsel and representative parties, Fankhouser and Goddard, filed a motion to intervene and prosecute the Beer class, now styled Fankhouser v. XTO Energy Inc. This motion was granted on July 13, 2010. The new plaintiffs and counsel filed an amended complaint asserting new causes of action for breach of fiduciary duties and unjust enrichment. On December 16, 2010, the court certified the class. Cross motions for summary judgment were filed by the parties and ruled on by the court. XTO Energy has informed the trustee that after consideration of the rulings by the court in March and April of 2012, some benefiting XTO Energy and some benefiting the plaintiffs, and with due regard to the vagaries of litigation and their uncertain outcomes, XTO Energy and the plaintiffs entered into settlement negotiations prior to trial and reached a tentative settlement of $37 million on April 23, 2012. XTO has advised the trustee that $1.4 million of the settlement is attributable to Kansas claims which predate the Trust and therefore XTO Energy will not charge to the Trust. The settlement also includes a new royalty calculation for future royalty payments. The hearing for formal court approval was conducted on June 21, 2012 and preliminarily approved by the court on June 29, 2012. A fairness hearing was conducted on October 10, 2012 and the settlement was given final approval by the court. The court’s order sets out the amount of attorneys’ fees and costs awarded to the plaintiffs’ counsel from the $37 million settlement. A third party administrator will make the distribution to the royalty owners as set out in the order approving the settlement.

XTO Energy has advised the trustee it believes that the terms of the conveyances covering the trust’s net profits interests require the trust to bear its 80% interest in the settlement, or approximately $28.5 million, of which $23.4 million will affect the net proceeds from Oklahoma and $5.1 million will affect the net proceeds from Kansas. If so, this will adversely affect the net proceeds of the trust from Oklahoma and Kansas and will result in costs exceeding revenues on these properties. XTO Energy began deducting the settlement amount with the September 2012 distribution. Based on the revised settlement allocation between Oklahoma and Kansas and recent revenue and expense levels, the deductions XTO Energy has made, and will resume making if the Tribunal 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

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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 would decrease the amount of net profits going forward for the Oklahoma and Kansas properties due to changes in the way costs (such as gathering, compression and fuel) associated with operating the properties will be allocated, resulting in a net gain to the royalty interest owners. XTO Energy has advised the trustee that this expected net upward revision for the royalty interest owners would reduce applicable net profits to XTO Energy and, correspondingly, to the trust. For 2012 the revision would have reduced trust net proceeds by approximately $272,000 (which amount would have been reflected in the June 2012 through December 2012 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 October 7, 2013 in Fort Worth, Texas if not sooner disposed of by the parties by agreement or by the Tribunal on motion. Because XTO Energy advised the trustee that it began deducting the settlement in September, the trustee reserved a total of $900,000 from trust distributions to help fund potential legal and other expenses relating to the arbitration. The trustee believed that without such a reserve, the trust was likely to be left without adequate resources to fund the costs of the arbitration out of monthly trust revenues. 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 were suspended starting in November 2012. XTO Energy has also informed the trustee that during the pendency of this action, no adjustment will be made to the net profits to the trust on a go-forward basis based on the changes in the way costs will be allocated to royalty owners in accordance with the Fankhouser settlement.

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

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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 10th Circuit Court of Appeals on April 26, 2012, believing the class certification was not proper. The appeal was granted on June 26, 2012. The matter has been fully briefed, and oral argument is scheduled for 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 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.

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

Item 4. Mine Safety Disclosures

Not Applicable.

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PART II

Item 5. Market for Units of the Trust, Related Untiholder Matters and Trust Purchases of Units

Units of Beneficial Interest

The units of beneficial interest in the trust began trading on the New York Stock Exchange on April 9, 1999 under the symbol “HGT.” The following are the high and low unit sales prices and total cash distributions per unit paid by the trust during each quarter of 2012 and 2011:

At December 31, 2012, there were 40,000,000 units outstanding and approximately 873 unitholders of record; 37,775,743 of these units were held by depository institutions.

The trust has no equity compensation plans, nor has it purchased any units during the period covered by this report.

Item 6. Selected Financial Data

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Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations

Calculation of Net Profits Income

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

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Results of Operations

Years Ended December 31, 2012, 2011 and 2010

Net profits income for 2012 was $25,132,038, as compared with $56,565,368 for 2011 and $62,883,206 for 2010. The 56% decrease in net profits income from 2011 to 2012 is primarily the result of lower gas prices ($25.2 million), decreased oil and gas production ($5.0 million) and the portion of the Fankhouser settlement deducted in September and October of 2012 ($4.4 million), partially offset by lower development costs ($2.2 million). The 10% decrease in net profits income from 2010 to 2011 is primarily the result of decreased oil and gas production ($10.3 million), partially offset by higher oil prices ($3.5 million). Approximately 74% in 2012, 81% in 2011 and 85% in 2010 of net profits income was derived from natural gas sales.

Trust administration expense was $1,859,626 in 2012 as compared to $801,563 in 2011 and $856,314 in 2010. Included in 2012 administration expense is $900,000 which the trustee has reserved for legal expenses regarding the Fankhouser class action settlement. Interest income was $508 in 2012, $1,155 in 2011 and $1,108 in 2010. Changes in interest income are attributable to fluctuations in net profits income and interest rates. Distributable income was $23,272,920 or $0.581823 per unit in 2012, $55,764,960 or $1.394124 per unit in 2011 and $62,028,000 or $1.550700 per unit in 2010.

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:

Volumes

From 2011 to 2012, underlying gas sales volumes decreased 6% and underlying oil sales volumes decreased 8% primarily due to natural production decline. From 2010 to 2011, underlying gas sales volumes decreased 10% primarily due to natural production decline. Underlying oil sales volumes decreased 7% 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.

Prices

Gas.    The 2012 average gas price was $3.28 per Mcf, a 31% decrease from the 2011 average gas price of $4.73 per Mcf, which was relatively flat from the 2010 average gas price of $4.72 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 average NYMEX price for November 2012 through January 2013 was $3.51 per MMBtu. At February 11, 2013, the average NYMEX gas price for the following 12 months was $3.63 per MMBtu.

Oil.    The average oil price for 2012 was $91.30 per Bbl, 1% higher than the average oil price for 2011 of $90.07 per Bbl, which was 22% higher than the average oil price for 2010 of $73.77 per Bbl. Oil prices are expected to remain volatile. The average NYMEX price for November 2012 through January 2013 was $89.87 per Bbl. At February 11, 2013, the average NYMEX oil price for the following 12 months was $98.17 per Bbl.

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Costs

The calculation of net profits income includes deductions for production expense, development costs and overhead since the related underlying properties are working interests. If monthly costs exceed revenues for any state, these excess costs must be recovered, with accrued interest, from future net proceeds of that state and cannot reduce net profits income from another state. See “Excess costs” below.

Taxes, transportation and other.    Taxes, transportation and other generally fluctuates with changes in total revenues. Taxes, transportation and other decreased 19% from 2011 to 2012 primarily because of decreased gas production taxes and other deductions related to lower gas revenues, partially offset by increased property taxes related to increased valuations. Taxes, transportation and other decreased 11% from 2010 to 2011 primarily because of decreased property taxes related to the timing of expenditures and decreased gas production taxes and other deductions related to lower gas revenues, partially offset by increased oil production taxes related to higher oil revenues.

Production expense.    Production expense increased 7% from 2011 to 2012 primarily because increased labor, repairs and maintenance costs and mechanical and marketing rebates included in 2011, partially offset by decreased fuel costs. Production expense remained relatively flat from 2010 to 2011 primarily because increased labor, field, fuel and compressor rental costs were offset by mechanical and marketing rebates received in 2011, decreased insurance, plugging and abandonment and repairs and maintenance costs.

Development costs.    Development costs deducted were $6.0 million in 2012, $8.8 million in 2011 and $7.3 million in 2010. In 2012, actual development costs were $8.7 million. At December 31, 2012, cumulative actual costs exceeded cumulative budgeted costs by approximately $0.3 million. The monthly development cost deduction was $500,000 from the September 2009 distribution through the July 2010 distribution. As a result of increased development activity, the development cost deduction was increased to $600,000 beginning with the August 2010 distribution and to $850,000 beginning with the October 2010 distribution and was maintained at that level 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 end of 2012. For further information on 2013 budgeted development costs, see Properties, under Item 2. 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.

Overhead.    Overhead is charged by XTO Energy for administrative expenses incurred to support operations of the underlying properties. Overhead fluctuates based on changes in the active well count and drilling activity on the underlying properties, as well as an annual cost level adjustment.

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

XTO advised the trustee in September 2012 that it deducted $35,601,400 ($28,481,120 net to the trust) related to the Fankhouser settlement. The settlement deduction caused costs to exceed revenues by $27,235,464 ($21,788,371 net to the trust) on properties underlying the Oklahoma net profits interests and by $6,225,126 ($4,980,101 net to the trust) on properties underlying the Kansas net profits interests. However, these excess costs did not reduce net proceeds from the remaining conveyance. XTO advised the trustee in October 2012 that it partially recovered $3,342,186 ($2,673,749 net to the trust) of excess costs. Remaining excess costs at December 31, 2012 were $24,027,648 ($19,222,118 net to the trust) on properties underlying the Oklahoma net profits interests and $6,090,756 ($4,872,605 net to the trust) on properties underlying the Kansas net profits interests. The excess costs claimed underlying the Kansas and Oklahoma net

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profits interests are the subject of pending arbitration described more fully under “Item 3 — Legal Proceedings.” See Note 9 to Financial Statements under Item 8, Financial Statements and Supplementary Data.

Costs exceeded revenues by $513,475 ($410,780 net to the trust) on properties underlying the Kansas net profits interests in October and November 2009. Lower gas prices caused costs to exceed revenues on properties underlying the Kansas net profits interests. However, these excess costs did not reduce net proceeds from the remaining conveyances. XTO Energy advised the trustee that increased gas prices led to the partial recovery of excess costs of $410,957 ($328,766 net to the trust), plus accrued interest of $1,958 ($1,566 net to the trust) in December 2009 and the full recovery of excess costs of $102,518 ($82,014 net to the trust), plus accrued interest of $282 ($226 net to the trust) in January 2010.

Fourth Quarter 2012 and 2011

During fourth quarter 2012 the trust received net profits income totaling $4,970,935 compared with fourth quarter 2011 net profits income of $13,206,026. This 62% decrease in net profits income was primarily due to lower gas prices ($6.0 million) and the portion of the Fankhouser settlement deducted in October of 2012 ($2.7 million), partially offset by decreased taxes transportation and other costs ($0.4 million).

Administration expense was $234,667 and interest income was $52, resulting in fourth quarter 2012 distributable income of $4,736,320 or $0.118408 per unit. Distributable income for fourth quarter 2011 was $13,088,840 or $0.327221 per unit.

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

Volumes

Fourth quarter underlying gas sales volumes remained relatively flat and underlying oil sales volumes decreased 4% from 2011 to 2012. Gas sales volumes remained relatively flat as increased production resulting from 2011 scheduled maintenance on a gathering and processing system in the Hugoton area and the timing of cash receipts were offset by natural production decline. Oil sales volumes decreased primarily because of natural production decline.

Prices

The average fourth quarter 2012 gas price was $3.28 per Mcf, or 30% lower than the fourth quarter 2011 average price of $4.70 per Mcf. The average fourth quarter 2012 oil price was $86.92 per Bbl, or 5% higher than the fourth quarter 2011 average price of $83.12 per Bbl. For further information about product prices, see “Years Ended December 31, 2012, 2011 and 2010 – Prices” above.

Costs

Taxes, transportation and other. Taxes, transportation and other decreased 13% from fourth quarter 2011 to 2012 primarily because of decreased gas production taxes and other deductions related to lower gas revenues, partially offset by increased property taxes related to increased valuations.

Production expense. Fourth quarter production expense decreased 4% from 2011 to 2012 primarily because of decreased fuel, repairs and maintenance and outside operated costs, partially offset by increased labor and location costs.

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Development costs. Development costs, which were deducted based on budgeted development costs, remained flat from fourth quarter 2011 to 2012.

Overhead. Overhead is charged by XTO Energy for administrative expenses incurred to support operations of the underlying properties. Overhead fluctuates based on changes in the active well count and drilling activity on the underlying properties, as well as an annual cost level adjustment.

Excess costs. XTO advised the trustee in September 2012 that it deducted $35,601,400 ($28,481,120 net to the trust) related to the Fankhouser settlement. The settlement deduction caused costs to exceed revenues by $27,235,464 ($21,788,371 net to the trust) on properties underlying the Oklahoma net profits interests and by $6,225,126 ($4,980,101 net to the trust) on properties underlying the Kansas net profits interests. However, these excess costs did not reduce net proceeds from the remaining conveyance. XTO advised the trustee in October 2012 that it partially recovered $3,342,186 ($2,673,749 net to the trust) of excess costs. Remaining excess costs at December 31, 2012 were $24,027,648 ($19,222,118 net to the trust) on properties underlying the Oklahoma net profits interests and $6,090,756 ($4,872,605 net to the trust) on properties underlying the Kansas net profits interests. The excess costs claimed underlying the Kansas and Oklahoma net profits interests are the subject of pending arbitration described more fully under “Item 3 – Legal Proceedings.” See Note 9 to Financial Statements under Item 8, Financial Statements and Supplementary Data.

Liquidity and Capital Resources

The trust’s only cash requirement is the monthly distribution of its income to unitholders, which is funded by the monthly receipt of net profits income after payment of trust administration expenses. The trust is not liable for any production costs or liabilities attributable to the net profits interests. If at any time the trust receives net profits income in excess of the amount due, the trust is not obligated to return such overpayment, but future net profits income payable to the trust will be reduced by the overpayment, plus interest at the prime rate. The trust may borrow funds required to pay trust liabilities if fully repaid prior to further distributions to unitholders.

The trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the trust’s liquidity or the availability of capital resources.

Greenhouse Gas Emissions and Climate Change Regulation

There is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change. Several states have adopted climate change legislation and regulations, and various other regulatory bodies have announced their intent to regulate GHG emissions or adopt climate change regulations. As these regulations are under development, XTO Energy is unable to predict the total impact of the potential regulations upon the operators of the underlying properties, and it is possible that the operators of the underlying properties could face increases in operating costs in order to comply with climate change or GHG emissions legislation, which costs could reduce net proceeds payable to the trust and trust distributions.

Off-Balance Sheet Arrangements

The trust has no off-balance sheet financing arrangements. The trust has not guaranteed the debt of any other party, nor does the trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.

Contractual Obligations

As shown below, the trust had no obligations and commitments to make future contractual payments as of December 31, 2012, other than the December distribution payable to unitholders in January 2013, as reflected in the statement of assets, liabilities and trust corpus.

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Related Party Transactions

The underlying properties from which the net profits interests were carved are currently owned by XTO Energy, which operates approximately 95% of the underlying properties. In computing net proceeds, XTO Energy deducts a monthly overhead charge for reimbursement of administrative expenses on the underlying properties it operates. As of December 31, 2012, the monthly overhead charge, based on the number of operated wells, was approximately $967,000 ($773,600 net to the trust) and is subject to annual adjustment based on an oil and gas industry index.

XTO Energy sells a significant portion of natural gas production from the underlying properties to certain of XTO Energy’s wholly owned subsidiaries under contracts in existence when the trust was created, generally at amounts approximating monthly published market prices. For further information regarding natural gas sales from the underlying properties to affiliates of XTO Energy, see Significant Properties, under Item 2, Properties and Note 8 to Financial Statements under Item 8, Financial Statements and Supplementary Data. Total gas sales from the underlying properties to XTO Energy’s wholly owned subsidiaries were $22.3 million for 2012, or 34% of total gas sales, $35.6 million for 2011, or 35% of total gas sales and $48.5 million for 2010, or 43% of total gas sales.

On June 25, 2010, XTO Energy became a wholly owned subsidiary of Exxon Mobil Corporation.

Critical Accounting Policies

The financial statements of the trust are significantly affected by its basis of accounting and estimates related to its oil and gas properties and proved reserves, as summarized below.

Basis of Accounting

The trust’s financial statements are prepared on a modified cash basis, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles. This method of accounting is consistent with reporting of taxable income to trust unitholders. The most significant differences between the trust’s financial statements and those prepared in accordance with U.S. generally accepted accounting principles are:

This comprehensive basis of accounting other than U.S. generally accepted accounting principles 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. For further information regarding the trust’s basis of accounting, see Note 2 to Financial Statements under Item 8, Financial Statements and Supplementary Data.

All amounts included in the trust’s financial statements are based on cash amounts received or disbursed, or on the carrying value of the net profits interests, which was derived from the historical cost of the interests at the date of their transfer from XTO Energy, less accumulated amortization to date. Accordingly, there are no fair value estimates included in the financial statements based on either exchange or nonexchange trade values.

Oil and Gas Reserves

The proved oil and gas reserves for the underlying properties are estimated by independent petroleum engineers. The estimated reserves for the underlying properties are then used by XTO Energy to calculate the estimated oil and gas reserves attributable to the net profits interests. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as

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well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using 12-month average prices, based on the first-day-of-the-month price for each month in the period, estimated reserve quantities can be significantly impacted by changes in product prices. Accordingly, oil and gas quantities ultimately recovered and the timing of production may be substantially different from original estimates.

The standardized measure of discounted future net cash flows and changes in such cash flows, as reported in Note 10 to Financial Statements under Item 8, Financial Statements and Supplementary Data, is prepared using assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission. Such assumptions include using 12-month average oil and gas prices, based on the first-day-of-the-month price for each month in the period, and year end costs for estimated future development and production expenditures. Discounted future net cash flows are calculated using a 10% rate. Changes in any of these assumptions, including consideration of other factors, could have a significant impact on the standardized measure. Accordingly, the standardized measure does not represent XTO Energy’s or the trustee’s estimated current market value of proved reserves.

Forward-Looking Statements

Certain information included in this annual report and other materials filed, or to be filed, by the trust with the Securities and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by XTO Energy or the trustee) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended, relating to the trust, operations of the underlying properties and the oil and gas industry. Such forward-looking statements may concern, among other things, reserve-to-production ratios, future production, development activities, future development plans by area, increased density drilling, maintenance projects, development, production and other costs, oil and gas prices, pricing differentials, proved reserves, future net cash flows, production levels, litigation, regulatory matters and competition. Such forward-looking statements are based on XTO Energy’s current plans, expectations, assumptions, projections and estimates and are identified by words such as “expects,” “intends,” “plans,” “projects,” “anticipates,” “predicts,” “believes,” “goals,” “estimates,” “should,” “could”, and similar words that convey the uncertainty of future events. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict. Therefore, actual results may differ materially from expectations, estimates or assumptions expressed in, implied in, or forecasted in such forward-looking statements. Some of the risk factors that could cause actual results to differ materially are explained in Item 1A, Risk Factors.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

The only assets of and sources of income to the trust are the net profits interests, which generally entitle the trust to receive a share of the net profits from oil and gas production from the underlying properties. Consequently, the trust is exposed to market risk from fluctuations in oil and gas prices. The trust is a passive entity and, other than the trust’s ability to periodically borrow money as necessary to pay expenses, liabilities and obligations of the trust that cannot be paid out of cash held by the trust, the trust is prohibited from engaging in borrowing transactions. The amount of any such borrowings is unlikely to be material to the trust. In addition, the trustee is prohibited by the trust indenture from engaging in any business activity or causing the trust to enter into any investments other than investing cash on hand in specific short-term cash investments. Therefore, the trust cannot hold any derivative financial instruments. As a result of the limited nature of its borrowing and investing activities, the trust is not subject to any material interest rate market risk. Additionally, any gains or losses from any hedging activities conducted by XTO Energy are specifically excluded from the calculation of net proceeds due the trust under the forms of the conveyances. The trust does not engage in transactions in foreign currencies which could expose the trust to any foreign currency related market risk.

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Item 8. Financial Statements and Supplementary Data

All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto.

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HUGOTON ROYALTY TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

STATEMENTS OF DISTRIBUTABLE INCOME

STATEMENTS OF CHANGES IN TRUST CORPUS