SAN JUAN BASIN ROYALTY TRUST - Quarter Report: 2013 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the Quarterly Period Ended June 30, 2013

or

For the transition period from                      to                     

Commission File No. 1-8032

SAN JUAN BASIN ROYALTY TRUST

(Exact name of registrant as specified in the Amended and Restated San Juan Basin Royalty Trust Indenture)

Compass Bank

300 W. 7^th Street, Suite B

Fort Worth, Texas 76102

(Address of principal executive offices) (Zip Code)

(866) 809-4553

(Registrant’s telephone number, including area code)

N/A

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, or a smaller reporting company. See 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 Rule 12b-2 of the Act).    Yes  ¨    No  x

Number of Units of beneficial interest outstanding at August 9, 2013: 46,608,796

SAN JUAN BASIN ROYALTY TRUST

PART I

FINANCIAL INFORMATION

The condensed financial statements included herein have been prepared without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. The financial statements of the San Juan Basin Royalty Trust (the “Trust”) continue to be prepared in a manner that differs from generally accepted accounting principles in the United States of America (“GAAP”); this form of presentation is customary to other royalty trusts. Certain information and footnote disclosures normally included in annual financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. Nonetheless, Compass Bank, the trustee of the Trust (the “Trustee”), believes that the disclosures are adequate to make the information presented not misleading. These condensed financial statements should be read in conjunction with the financial statements and the notes thereto included in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2012. In the opinion of the Trustee, all adjustments, consisting only of normal recurring adjustments, have been included that are necessary to fairly present the assets, liabilities and trust corpus of the Trust at June 30, 2013 and the distributable income and changes in trust corpus for the six-month periods ended June 30, 2013 and 2012. The distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

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SAN JUAN BASIN ROYALTY TRUST

CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (UNAUDITED)

CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS (UNAUDITED)

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

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SAN JUAN BASIN ROYALTY TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED)

The San Juan Basin Royalty Trust (the “Trust”) was established as of November 1, 1980. The financial statements of the Trust are prepared on the following basis:

The financial statements of the Trust differ from financial statements prepared in accordance with GAAP because revenues are not accrued in the month of production; certain cash reserves may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP; expenses are recorded when paid instead of when incurred; and amortization of the Royalty calculated on a unit-of-production basis is charged directly to the Trust corpus instead of as an expense. The basis of accounting used by the Trust is widely used by royalty trusts for financial reporting purposes.

For federal income tax purposes, the Trust constitutes a fixed investment trust which is taxed as a grantor trust. A grantor trust is not subject to tax at the trust level. The Unit Holders 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 Unit Holder at the time such income is received or accrued by the Trust rather than when distributed by the Trust.

Additionally, the Trust is a widely held fixed investment trust (“WHFIT”) classified as a non-mortgage widely held fixed investment trust (“NMWHFIT”) for federal income tax purposes. The Trustee is the representative of the Trust that will provide tax information in accordance with the applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT and a NMWHFIT.

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The Royalty constitutes an “economic interest” in oil and gas properties for federal income tax purposes. Unit Holders must report their share of the production revenues of the Trust as ordinary income from oil and gas royalties and are entitled to claim depletion with respect to such income. The Royalty is treated as a single property for depletion purposes. The Trust has on file technical advice memoranda confirming such tax treatment.

Sales of gas production from certain coal seam wells drilled prior to January 1, 1993, qualified for federal income tax credits under Section 29 (now Section 45K) of the Internal Revenue Code of 1986 (as amended, the “Code”) through 2002 but not thereafter. Accordingly, under present law, the Trust’s production and sale of gas from coal seam wells does not qualify for tax credit under Section 45K of the Code (the “Section 45 Tax Credit”). Congress has at various times since 2002 considered energy legislation, including provisions to reinstate the Section 45 Tax Credit in various ways and to various extents, but no legislation that would qualify the Trust’s current production for such credit has been enacted. For example, in December 2010, new energy tax legislation was enacted which, among other things, modified the Section 45 Tax Credit in several respects, but did not extend the credit for production from coal seam wells. No prediction can be made as to what future tax legislation affecting Section 45K of the Code may be proposed or enacted or, if enacted, its impact, if any, on the Trust and the Unit Holders. Each Unit Holder should consult his or her own tax advisor regarding tax compliance matters related to such Unit Holder’s interest in the Trust.

The classification of the Trust’s income for purposes of the passive loss rules may be important to a Unit Holder. As a result of the Tax Reform Act of 1986, royalty income such as that derived through the Trust will generally be treated as portfolio income that may not be offset or reduced by passive losses.

See Part II, Item 1 – Legal Proceedings, concerning the status of litigation matters.

On March 14, 2008, Burlington notified the Trust that the distribution for March would be reduced by $4,921,578. Burlington described this amount as the Trust’s portion of what Burlington had paid to settle claims for the underpayment of royalties in the case styled United States of America ex rel. Harrold E. (“Gene”) Wright v. AGIP Petroleum Co. et al., Civil Action No. 5:03CV264 (formerly 9:98-CV-30) (E.D. Tex.). The Trust’s consultants continue to analyze this settlement as it may apply to the Trust.

Burlington has informed the Trust that pursuant to an Order to Perform issued by the Minerals Management Service (“MMS”) dated June 10, 1998 (the “MMS Order”), the Jicarilla Apache Nation (the “Jicarilla”) alleged that in valuing production for royalty purposes one must perform (i) a major portion analysis, which calculates value on the highest price paid or offered for a major portion of the gas produced from the field where the leased lands are situated; and (ii) a dual accounting calculation, which computes royalties on the greater of (a) the value of gas prior to processing or (b) the combined value of processed residue gas and plant products plus the value of any condensate recovered downstream without processing. The MMS Order alleged that Burlington’s dual accounting calculations on Native American leases were based on less than major portion prices. In 2000, Burlington and the Jicarilla entered into a settlement agreement resolving the issues associated with the dual accounting calculation. The major portion calculation issue remains outstanding. Burlington takes the position that a judgment or settlement could entitle Burlington to reimbursement from the Trust for past periods.

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In 2007 Burlington obtained an Administrative Order from the Department of the Interior (the “DOI”) rejecting that portion of the MMS Order requiring Burlington to calculate and pay additional royalties based on the major portion price derived by the MMS. The Jicarilla filed suit solely against the DOI in the United States District Court for the District of Columbia in an action entitled 1:07-CV-00803-RJL, Jicarilla Apache Nation v. Department of Interior (the “DOI Case”) seeking a declaration that the Administrative Order is unlawful and of no force and effect, as well as an injunction requiring enforcement of the underlying major portion orders that were rejected by the Assistant Secretary. In 2009, a summary judgment was entered by the district court in the DOI Case upholding the Administrative Order and dismissing the Jicarilla’s claims. The Jicarilla appealed to the U.S. Court of Appeals for the D.C. Circuit. On July 16, 2010, the U.S. Court of Appeals held that the 2007 Administrative Order dismissing the Jicarilla claims was arbitrary and capricious with respect to January 1984 through February 1988 production periods and by Memorandum Order dated October 7, 2011, remanded the matter to the DOI for further proceedings. While a judgment or settlement in the DOI Case could impact the Royalty Income of the Trust, Burlington has informed the Trust that it does not have sufficient information to estimate a range of loss for the Trust because the DOI has not provided a major portion calculation for the January 1984 to February 1988 time period as required by the July 16, 2010 Court of Appeals ruling described above. Burlington indicates that the situation will not be alleviated until the DOI provides Burlington with a new Order to Perform or similar notice, but that it cannot predict when or if the DOI will provide such information or notice. The Trust’s consultants will continue to monitor development in this matter and analyze the appropriateness of the allocation, if any, by Burlington of any portion of any settlement or judgment in calculating the Royalty.

In May 2011, a verdict was entered in the case styled Abraham et al. v. BP America Production Company, Case No. 6:09-cv-00961, in the U.S. District Court for the District of New Mexico, awarding the plaintiffs approximately $9.74 million in damages and $3.5 million in pre-judgment interest and costs based upon a jury finding that the defendant had failed to pay royalties consistent with market value for gas produced in the San Juan Basin. The defendant appealed and the Tenth Circuit reversed the judgment of the District Court and remanded the case for a new trial. On March 20, 2013, the Court entered a judgment and order approving a settlement reached by the parties on December 20, 2012 pursuant to which BP will pay $10 million plus interest to the plaintiffs, net of attorneys’ fees and certain other expenses, including the cost of settlement administration. The order is final and non-appealable, and the settlement administrator is working with BP to prepare a distribution to the class. The Trust is a member of the plaintiff class. However, it is uncertain whether any amount distributed to the Trust will be material. The Trustee will continue to monitor these proceedings.

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Forward-Looking Information

Certain information included in this Quarterly Report on Form 10-Q contains, 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 the Trust) may contain or include, forward-looking statements. Such forward-looking statements may be or may concern, among other things, capital expenditures, drilling activity, development activities, production efforts and volumes, hydrocarbon prices, estimated future net revenues, estimates of reserves, the results of the Trust’s activities, and regulatory matters. Such forward-looking statements generally are accompanied by words such as “may,” “will,” “estimate,” “expect,” “predict,” “project,” “anticipate,” “goal,” “should,” “assume,” “believe,” “plan,” “intend,” or other words that convey the uncertainty of future events or outcomes. Such statements reflect the current view of Burlington Resources Oil & Gas Company LP (“Burlington”), the working interest owner, with respect to future events; are based on an assessment of, and are subject to, a variety of factors deemed relevant by the Trustee and Burlington; and involve risks and uncertainties. These risks and uncertainties include volatility of oil and gas prices, product supply and demand, competition, regulation or government action, litigation and uncertainties about estimates of reserves. Should one or more of these risks or uncertainties occur, actual results may vary materially and adversely from those anticipated.

Business Overview

The Trust is an express trust created under the laws of the state of Texas by the San Juan Basin Royalty Trust Indenture (the “Original Indenture”) entered into on November 3, 1980 between Southland Royalty Company (“Southland Royalty”) and The Fort Worth National Bank. Effective as of September 30, 2002, the Original Indenture was amended and restated (the Original Indenture, as amended and restated, the “First Restated Indenture”) and, effective as of December 12, 2007 the First Restated Indenture was amended and restated (the First Restated Indenture, as amended and restated, the “Indenture”). The Trustee of the Trust is Compass Bank.

On October 23, 1980, the stockholders of Southland Royalty approved and authorized that company’s conveyance of a 75% net overriding royalty interest (equivalent to a net profits interest) to the Trust for the benefit of the stockholders of Southland Royalty of record at the close of business on the date of the conveyance (the “Royalty”) carved out of that company’s oil and gas leasehold and royalty interests (the “Underlying Properties”) in properties located in the San Juan Basin of northwestern New Mexico. Pursuant to the Net Overriding Royalty Conveyance (the “Conveyance”) the Royalty was transferred to the Trust on November 3, 1980 effective as to production from and after November 1, 1980.

The Royalty constitutes the principal asset of the Trust. The beneficial interests in the Royalty are divided into that number of Units of Beneficial Interest (the “Units”) of the Trust equal to the number of shares of the common stock of Southland Royalty outstanding as of the close of business on November 3, 1980. Each stockholder of Southland Royalty of record at the close of business on November 3, 1980 received one freely tradable Unit for each share of the common stock of Southland Royalty then held. Holders of Units are referred to herein as “Unit Holders.” Subsequent to the Conveyance of the Royalty, through a series of assignments and mergers, Southland Royalty’s successor became Burlington. On March 31, 2006, a subsidiary of ConocoPhillips completed its acquisition of Burlington Resources, Inc., Burlington’s parent. As a result, ConocoPhillips became the parent of Burlington Resources, Inc., which in turn, is the parent of Burlington. On May 1, 2012, ConocoPhillips announced that it had completed the spinoff to Phillips 66 of the company’s refining and marketing business from its exploration and production business. According to ConocoPhillips, both businesses are now stand-alone, publicly traded corporations. The Trustee will continue to monitor this situation’s effect on the Trust, if any.

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The function of the Trustee is to collect the net proceeds attributable to the Royalty (“Royalty Income”), to pay all expenses and charges of the Trust and distribute the remaining available income to the Unit Holders. The Trust does not operate the Underlying Properties and, in fact, is not empowered to carry on any business activity. The Trust has no employees, officers or directors. All administrative functions of the Trust are performed by the Trustee.

Burlington is the principal operator of the Underlying Properties. A very high percentage of the Royalty Income is attributable to the production and sale by Burlington of natural gas from the Underlying Properties. Accordingly, the market price for natural gas produced and sold from the San Juan Basin heavily influences the amount of Royalty Income distributed by the Trust and, by extension, the price of the Units.

Three Months Ended June 30, 2013 and 2012

The Trust received Royalty Income of $6,237,669 and interest income of $198 during the second quarter of 2013. No distributions were made in March or April 2013. In March, production costs exceeded revenues, and there was a $156,724 decrease in cash reserves as funds were withdrawn to pay administrative expenses. The cash available for distribution in April was applied first to pay certain deferred administrative costs and to replenish the reserve maintained by the Trustee for liabilities and contingencies. After deducting administrative expenses of $514,941 and establishing a cash reserve of $186,243, distributable income for the quarter was $5,536,683 ($0.118790 per Unit). In the second quarter of 2012, Royalty Income was $10,582,704, interest income was $210,041, administrative expenses were $414,016 and distributable income was $10,378,729 ($0.222678 per Unit). Based on 46,608,796 Units outstanding, the per-Unit distributions during the second quarter of 2013 were as follows:

The Royalty Income distributed in the second quarter of 2013 was lower than that distributed in the second quarter of 2012 primarily because both capital expenditures and lease operating expenses in the second quarter of 2013 were materially higher than those for the second quarter of 2012 and those increases in cost more than offset the increase in the gross proceeds of sales of gas and oil during the second quarter of 2013 as compared with the second quarter of 2012. Interest income was lower for the quarter ended June 30, 2013 as compared to the quarter ended June 30, 2012, due to the receipt in 2012 of $209,347 in interest on the late payment of net proceeds as a result of the ongoing negotiation of compliance audit issues. Administrative expenses were higher in 2013 primarily as a result of differences in timing in the receipt and payment of certain of these expenses.

The capital costs attributable to the Underlying Properties for the second quarter of 2013 and deducted by Burlington in calculating Royalty Income were approximately $6.8 million as compared to approximately $3.9 million of capital costs in the second quarter of 2012. Burlington indicates the increase in capital expenditures in the second quarter of 2013 is due to Burlington’s understatement of capital costs in the second quarter of 2012 and to an increase in expenses attributable to budgets for prior years.

Burlington informed the Trust that its amended budget for capital expenditures for the Underlying Properties in 2013 is estimated at $18.5 million ($10 million less than the capital budget announced by Burlington in January 2013). Of the $18.5 million, approximately $5 million will be attributable to the capital budgets for 2012 and prior years. Burlington reports that based on its actual capital requirements, the pace of regulatory approvals, the mix of projects and swings in the price of natural gas, the actual capital expenditures for 2013 could range from $15 million to $45 million. Although the reported $19.3 million of capital expenditures for the six months ended June 30, 2013 already exceed the estimated budget, on March 27, 2013 Burlington announced the temporary suspension of its drilling program in the San Juan Basin, indicating that it plans to monitor natural gas prices and restart the program at some point in the future, dependent upon such gas prices. Existing wells will continue to be operated.

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Burlington anticipates 397 projects in 2013. Approximately $8.2 million of the $18.5 million budget is allocable to nine new wells, including seven wells scheduled to be dually completed in the Mesaverde and Dakota formations and one well to be completed in all three of the Mesaverde, Mancos Shale and Dakota formations. Approximately $5.4 million will be spent on recompletions and miscellaneous facilities projects. In light of the challenged price environment for natural gas and natural gas liquids, Burlington will increase its recompletion activity in 2013, noting that such activity is intended to open a new zone of production at a substantially lower cost than drilling a new well. Of the $5 million attributable to the budgets for prior years, approximately $3 million is allocable to 30 new wells and the $2 million balance will be applied to miscellaneous capital projects such as workovers and operated facility projects.

Lease operating expenses and property taxes were $10,020,364 and $168,858, respectively, for the second quarter of 2013, as compared to $6,874,859 and $139,489, respectively, for the second quarter of 2012. Burlington indicates the increase in operating expenses in the second quarter of 2013 is due to Burlington’s understatement of capital and lease operating expenses during the second quarter of 2012 and to increased maintenance and repair costs in the second quarter of 2013. Taxes for the second quarter of 2013 were higher primarily because of increases in the production volume and average price of natural gas.

As previously reported, and as related to the 2012 results reported herein, Burlington has reported that as a result of a miscalculation by Burlington (the “2012 Calculation Error”), lease operating expenses and capital expenditures were understated by approximately 25% during the months of April through July 2012, which caused the Royalty Income due the Trust to be overpaid by approximately $3,386,861. As permitted by the Royalty Conveyance document, Burlington offset the overpayment against Royalty Income payable to the Trust over four consecutive months commencing with August 2012.

Burlington has reported to the Trustee that during the second quarter of 2013, nine gross (4.22 net) conventional wells were completed on the Underlying Properties. There were no wells in progress at June 30, 2013.

There were eight gross (1.53 net) conventional wells completed on the Underlying Properties during the second quarter of 2012. Three gross (0.32 net) conventional wells were in progress at June 30, 2012.

There were 4,015 gross (1,158.50 net) producing wells being operated subject to the Royalty as of December 31, 2012, calculated on a well bore basis and not including multiple completions as separate wells. Of those wells, seven gross (5.00 net) are oil wells and the balance are gas wells. Burlington reports that approximately 839 gross (319.60 net) of the wells are multiple completion wells resulting in a total of 4,854 gross (1,478.10 net) completions.

“Gross” acres or wells, for purposes of this discussion, means the entire ownership interest of all parties in such properties, and Burlington’s interest therein is referred to as the “net” acres or wells. In calculating the number of net wells, where a well is completed to multiple formations, Burlington indicates it (a) multiplies the working interest for each zone by a fraction equal to one divided by the total number of completions in that well bore, and (b) adds the interests so calculated for each zone to obtain the net ownership interest in that well. A “payadd” is the completion of an additional productive interval in an existing completed zone in a well.

Royalty Income for the quarter ended June 30, 2013 is associated with actual gas and oil production during February 2013 through April 2013 from the Underlying Properties. Gas and oil sales from the Underlying Properties for the three months ended June 30, 2013 and 2012 were as follows:

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During the second quarter of 2013, average gas prices were $0.11 per Mcf higher than the average prices reported during the second quarter of 2012. The average price per barrel of oil during the second quarter of 2013 was $8.85 per barrel lower than that received for the second quarter of 2012.

Gas produced from the Underlying Properties is processed at one of the following five plants: Chaco, Val Verde, Milagro, Ignacio, and Kutz, all located in the San Juan Basin. All of such gas other than that processed at Kutz is being sold to Chevron USA, Inc. (“Chevron”) under a contract with Burlington dated April 1, 2011 which provides for the delivery of gas through March 31, 2013 and from year to year thereafter. Because neither party gave notice of termination, the term of the Chevron contract has automatically been extended through at least March 31, 2014.

Gas produced from the Underlying Properties and processed at Kutz was being sold under three separate contracts with Pacific Gas and Electric Company (“PG&E”), Shell Energy North America (US), LP (“Shell”) and New Mexico Gas Company, Inc. (“NMGC”). The NMGC contract for the sale of certain winter-only supplies of the Kutz gas is for a five-year term expiring March 31, 2017. Both PG&E and Shell gave notice of the termination of their respective contracts effective March 31, 2013. Burlington circulated requests for proposal soliciting bids for the purchase of those volumes commencing April 1, 2013 and Burlington has entered into two new contracts effective April 1, 2013 with Shell and EDF Trading North America, LLC for the purchase of those volumes through March 31, 2014.

All four of the current contracts provide for (i) the delivery of such gas at various delivery points through their respective termination dates and from year-to-year thereafter, until terminated by either party upon notice of between six and twelve months; and (ii) the sale of such gas at prices which fluctuate in accordance with the published indices for gas sold in the San Juan Basin of northwestern New Mexico.

Burlington contracts with Williams Four Corners, LLC (“WFC”) and Enterprise Field Services, LLC (“EFS”) for the gathering and processing of virtually all of the gas produced from the Underlying Properties. Four contracts were entered into with WFC to be effective for terms of 15 years commencing April 1, 2010. Burlington has also signed an agreement with EFS effective November 1, 2011 for a term of 15 years. Burlington has disclosed to the Trust a summary of that agreement which the Trust has reviewed with its consultants, subject to conditions of confidentiality.

Confidentiality agreements with gatherers and purchasers of gas produced from the Underlying Properties prohibit public disclosure of certain terms and conditions of gas sales contracts with those entities, including specific pricing terms and gas receipt points. Such disclosure could compromise the ability to compete effectively in the marketplace for the sale of gas produced from the Underlying Properties.

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Six Months Ended June 30, 2013 and 2012

For the six months ended June 30, 2013, the Trust received Royalty income of $9,909,897 and interest income of $664. There was a $29,518 net increase in cash reserves. After deducting administrative expenses of $948,067 and the cash reserve increase, distributable income was $8,932,976 ($0.191658 per Unit) for the six months ended June 30, 2013. For the six months ended June 30, 2012, the Trust received Royalty income of $25,433,196 and interest income of $557,736. There was no change in cash reserves. After deducting administrative expenses of $987,507, distributable income was $25,003,425 ($0.536454 per Unit) for the six months ended June 30, 2012.

The decrease in distributable income from 2012 to 2013 resulted primarily from increased capital expenditures and lease operating costs and decreased gross proceeds from the sale of natural gas during the first half of 2013. Interest earnings for the six months ended June 30, 2013, as compared to the six months ended June 30, 2012 were lower due to the receipt in 2012 of $555,177 in interest on the late payment of net proceeds as a result of the ongoing negotiation of compliance audit issues. General and administrative expenses were higher for the six months ended June 30, 2013, as compared to the same period in 2012 primarily as a result of differences in timing in the receipt and payment of the expenses.

Capital expenditures incurred by Burlington, attributable to the Underlying Properties, for the first six months of 2013 amounted to approximately $19.3 million. Capital expenditures were approximately $9.8 million for the first six months of 2012. Lease operating expenses and property taxes totaled $18,830,090 and $408,755, respectively, as compared to $15,166,928 and $6,406, respectively, for the first six months of 2012. Both capital expenditures and lease operating expenses for the first six months of 2012 were understated as a result of the 2012 Calculation Error.

Burlington has reported to the Trustee that during the six months ended June 30, 2013, 17 gross (9.51 net) conventional wells were completed on the Underlying Properties. There were 16 gross (4.44 net) conventional wells completed on the Underlying Properties in the six months ending June 30, 2012.

Royalty income for the six months ended June 30, 2013 is associated with actual gas and oil production during November 2012 through April 2013 from the Underlying Properties. Gas and oil sales from the Underlying Properties for the six months ended June 30, 2013 and 2012 were as follows:

Royalty Income received by the Trust for the three months and six months ended June 30, 2013 and 2012, respectively, was computed as shown in the following table:

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CALCULATION OF ROYALTY INCOME

Contractual Obligations

Under the Indenture governing the Trust, the Trustee is entitled to an administrative fee for its administrative services and the preparation of quarterly and annual statements of: (i) 1/20 of 1% of the first $100 million of the annual gross revenue of the Trust, and 1/30 of 1% of the annual gross revenue of the Trust in excess of $100 million and (ii) the Trustee’s standard hourly rates for time in excess of 300 hours annually, provided that the administrative fee due under items (i) and (ii) above will not be less than $36,000 per year (as adjusted annually to reflect the increase (if any) in the Producers Price Index as published by the U.S. Department of Labor, Bureau of Labor Statistics, since December 31, 2003).

Effects of Securities Regulation

As a publicly-traded trust listed on the New York Stock Exchange (the “NYSE”), the Trust is and will continue to be subject to extensive regulation under, among others, the Securities Act of 1933, the Securities Exchange Act of 1934 (which contains many of the provisions of the Sarbanes-Oxley Act of 2002), and the rules and regulations of the NYSE. Issuers failing to comply with such authorities risk serious consequences, including criminal as well as civil and administrative penalties. In most instances, these laws, rules, and regulations do not specifically address their applicability to publicly-traded trusts, such as the Trust. In particular, the Sarbanes-Oxley Act of 2002 provides for the adoption by the Securities and Exchange Commission (the “Commission”) and NYSE of certain rules and regulations that may be impossible for the Trust to literally satisfy because of its nature as a pass-through trust. It is the Trustee’s intention to follow the Commission’s and NYSE’s rulemaking closely, attempt to comply with such rules and regulations and, where appropriate, request relief from these rules and regulations. However, if the Trust is unable to comply with such rules and regulations or to obtain appropriate relief, the Trust may be required to expend presently unknown but potentially material costs to amend the Indenture that governs the Trust to allow for compliance with such rules and regulations. To date, the rules implementing the Sarbanes-Oxley Act of 2002 have generally made appropriate accommodation for passive entities such as the Trust.

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Critical Accounting Policies

In accordance with the Commission’s rules and regulations and consistent with other royalty trusts, the financial statements of the Trust are prepared on the following basis:

The financial statements of the Trust differ from financial statements prepared in accordance with GAAP because revenues are not accrued in the month of production; certain cash reserves may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP; expenses are recorded when paid instead of when incurred; and amortization of the Royalty calculated on a unit-of-production basis is charged directly to the Trust corpus instead of as an expense.

The Trust invests in no derivative financial instruments, and has no foreign operations or long-term debt instruments. The Trust is a passive entity and is prohibited from engaging in a trade or business, including borrowing transactions, other than as periodically necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust. The amount of any such borrowings is unlikely to be material to the Trust. The Trust is also permitted to hold short-term investments acquired with funds held by the Trust pending distribution to Unit Holders and funds held in reserve for the payment of Trust expenses and liabilities. Because of the short-term nature of these borrowings and investments and certain limitations upon the types of such investments which may be held by the Trust, the Trustee believes that the Trust is not subject to any material interest rate risk. The Trust is not permitted to engage in transactions in foreign currencies which could expose the Trust or Unit Holders to any foreign currency related market risk. The Trust is not permitted to market the gas, oil or natural gas liquids from the Underlying Properties; Burlington is responsible for such marketing.

The Trust maintains a system of disclosure controls and procedures that is designed to ensure that information required to be disclosed in the Trust’s filings under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the Commission’s rules and forms. Due to the pass-through nature of the Trust, Burlington provides much of the information

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disclosed in this Form 10-Q and the other periodic reports filed by the Trust with the Commission. Consequently, the Trust’s ability to timely disclose relevant information in its periodic reports is dependent upon Burlington’s delivery of such information. Accordingly, the Trust maintains disclosure controls and procedures designed to ensure that Burlington accurately and timely accumulates and delivers such relevant information to the Trustee and those who participate in the preparation of the Trust’s periodic reports to allow for the preparation of such periodic reports and any decisions regarding disclosure.

The Indenture does not require Burlington to update or provide information to the Trust. However, the Conveyance transferring the Royalty to the Trust obligates Burlington to provide the Trust with certain information, including information concerning calculations of net proceeds owed to the Trust. Pursuant to the settlement of litigation in 1996 between the Trust and Burlington, Burlington agreed to newer, more formal financial reporting and audit procedures as compared to those provided in the Conveyance.

In order to help ensure the accuracy and completeness of the information required to be disclosed in the Trust’s periodic reports, the Trust engages independent public accountants, compliance auditors, marketing consultants, attorneys and petroleum engineers. These outside professionals advise the Trustee in its review and compilation of this information for inclusion in this Form 10-Q and the other periodic reports provided by the Trust to the Commission.

The Trustee has evaluated the Trust’s disclosure controls and procedures as of June 30, 2013 and has concluded that such disclosure controls and procedures are effective, at the “reasonable assurance” level, to ensure that material information related to the Trust is gathered on a timely basis to be included in the Trust’s periodic reports and recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms. In reaching its conclusion, the Trustee has considered the Trust’s dependence on Burlington to deliver timely and accurate information to the Trust. Additionally, during the quarter ended June 30, 2013 there were no changes in the Trust’s internal control over financial reporting that materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting. The Trustee has reviewed neither the Trust’s disclosure controls and procedures nor the Trust’s internal control over financial reporting in concert with management, a board of directors or an independent audit committee. The Trust does not have, nor does the Indenture provide for, officers, a board of directors or an independent audit committee.

PART II

OTHER INFORMATION

As discussed above under Part I, Item 4 – Controls and Procedures, due to the pass-through nature of the Trust, Burlington provides much of the information disclosed in this Form 10-Q and the other periodic reports filed by the Trust with the Commission. Although the Trustee receives periodic updates from Burlington regarding activities which may relate to the Trust, the Trust’s ability to timely report certain information required to be disclosed in the Trust’s periodic reports is dependent on Burlington’s timely delivery of the information to the Trust.

On March 14, 2008, Burlington notified the Trust that the distribution for March would be reduced by $4,921,578. Burlington described this amount as the Trust’s portion of what Burlington had paid to settle claims for the underpayment of royalties in the case styled United States of America ex rel. Harrold E. (“Gene”) Wright v. AGIP Petroleum Co. et al., Civil Action No. 5:03CV264 (formerly 9:98-CV-30) (E.D. Tex.). The Trust’s consultants continue to analyze this settlement as it may apply to the Trust.

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Burlington has informed the Trust that pursuant to an Order to Perform issued by the Minerals Management Service (“MMS”) dated June 10, 1998 (the “MMS Order”), the Jicarilla Apache Nation (the “Jicarilla”) alleged that in valuing production for royalty purposes one must perform (i) a major portion analysis, which calculates value on the highest price paid or offered for a major portion of the gas produced from the field where the leased lands are situated; and (ii) a dual accounting calculation, which computes royalties on the greater of (a) the value of gas prior to processing or (b) the combined value of processed residue gas and plant products plus the value of any condensate recovered downstream without processing. The MMS Order alleged that Burlington’s dual accounting calculations on Native American leases were based on less than major portion prices. In 2000, Burlington and the Jicarilla entered into a settlement agreement resolving the issues associated with the dual accounting calculation. The major portion calculation issue remains outstanding. Burlington takes the position that a judgment or settlement could entitle Burlington to reimbursement from the Trust for past periods.

In 2007 Burlington obtained an Administrative Order from the Department of the Interior (the “DOI”) rejecting that portion of the MMS Order requiring Burlington to calculate and pay additional royalties based on the major portion price derived by the MMS. The Jicarilla filed suit solely against the DOI in the United States District Court for the District of Columbia in an action entitled 1:07-CV-00803-RJL, Jicarilla Apache Nation v. Department of Interior (the “DOI Case”) seeking a declaration that the Administrative Order is unlawful and of no force and effect, as well as an injunction requiring enforcement of the underlying major portion orders that were rejected by the Assistant Secretary. In 2009, a summary judgment was entered by the district court in the DOI Case upholding the Administrative Order and dismissing the Jicarilla’s claims. The Jicarilla appealed to the U.S. Court of Appeals for the D.C. Circuit. On July 16, 2010, the U.S. Court of Appeals held that the 2007 Administrative Order dismissing the Jicarilla claims was arbitrary and capricious with respect to January 1984 through February 1988 production periods and by Memorandum Order dated October 7, 2011, remanded the matter to the DOI for further proceedings. While a judgment or settlement in the DOI Case could impact the Royalty Income of the Trust, Burlington has informed the Trust that it does not have sufficient information to estimate a range of loss for the Trust because the DOI has not provided a major portion calculation for the January 1984 to February 1988 time period as required by the July 16, 2010 Court of Appeals ruling described above. Burlington indicates that the situation will not be alleviated until the DOI provides Burlington with a new Order to Perform or similar notice, but that it cannot predict when or if the DOI will provide such information or notice. The Trust’s consultants will continue to monitor development in this matter and analyze the appropriateness of the allocation, if any, by Burlington of any portion of any settlement or judgment in calculating the Royalty.

In May 2011, a verdict was entered in the case styled Abraham et al. v. BP America Production Company, Case No. 6:09-cv-00961, in the U.S. District Court for the District of New Mexico, awarding the plaintiffs approximately $9.74 million in damages and $3.5 million in pre-judgment interest and costs based upon a jury finding that the defendant had failed to pay royalties consistent with market value for gas produced in the San Juan Basin. The defendant appealed and the Tenth Circuit reversed the judgment of the District Court and remanded the case for a new trial. On March 20, 2013, the Court entered a judgment and order approving a settlement reached by the parties on December 20, 2012 pursuant to which BP will pay $10 million plus interest to the plaintiffs, net of attorneys’ fees and certain other expenses, including the cost of settlement administration. The order is final and non-appealable, and the settlement administrator is working with BP to prepare a distribution to the class. The Trust is a member of the plaintiff class. However, it is uncertain whether any amount distributed to the Trust will be material. The Trustee will continue to monitor these proceedings.

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SIGNATURES

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

Date: August 9, 2013

(The Trust has no directors or executive officers.)

INDEX TO EXHIBITS