Form 10-Q

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

(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 November 9, 2012: 46,608,796

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, 2011. 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 September 30, 2012 and the distributable income and changes in trust corpus for the three-month periods and nine-month periods ended September 30, 2012 and 2011. The distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

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

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.

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, BROG notified the Trust that the distribution for March would be reduced by $4,921,578. BROG described this amount as the Trust’s portion of what BROG 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.

Following mediation conducted on April 8 and 23, 2010, BROG and the Trust entered into a settlement of previously reported litigation styled San Juan Basin Royalty Trust vs. Burlington Resources Oil & Gas Company, L.P., No. D1329-CV-08-751, in the District Court of Sandoval County, New Mexico, 13th Judicial District. The dispute subject to the mediation arose out of an arbitrator’s award in 2005 in favor of the Trust. That award effectively resolved five compliance audit issues, but BROG argued in subsequent litigation that one of those issues was beyond the scope of the matters agreed to be submitted to arbitration. Pursuant to the settlement, the litigation was dismissed, BROG paid $2,600,000 to the Trust in May 2010, and released its claims for attorneys’ fees.

BROG 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 BROG’s dual accounting calculations on Native American leases were based on less than major portion prices. In 2000, BROG and the Jicarilla entered into a settlement agreement resolving the issues associated with the dual accounting calculation. The major portion calculation issue remains outstanding. BROG takes the position that a judgment or settlement could entitle BROG to reimbursement from the Trust for past periods.

In 2007 BROG obtained an Administrative Order from the Department of the Interior (the “DOI”) rejecting that portion of the MMS Order requiring BROG 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, BROG 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. BROG indicates that the situation will not be alleviated until the DOI provides BROG 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 BROG 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 to the Tenth Circuit, and the plaintiffs filed a cross-appeal on several grounds, including that the trial court should have submitted the punitive damage issue to the jury. On July 18, 2012 the Tenth Circuit reversed the judgment of the District Court and remanded the case for a new trial. The Trust is a member of the plaintiff class. If there is ultimately a distribution to the plaintiff class, it is uncertain whether any amount distributed to the Trust will be material. The Trustee will continue to monitor these proceedings.

Noting a material decline in expenses in the second quarter of 2012, the Trustee asked BROG for an explanation. BROG has informed the Trust that the principal reason for the decrease in capital costs and lease operating expenses in the second quarter of 2012 was a miscalculation by BROG for the

months of April through July 2012 which caused lease operating expenses and capital expenditures to be understated by approximately 25% (the “2012 Calculation Error”). As a result of the 2012 Calculation Error, the Royalty income due the Trust for those four months was overpaid by approximately $3,386,861. BROG has communicated to the Trust that, as permitted under the terms of the Royalty conveyance document, it intends to offset the overpayment against Royalty income payable to the Trust over four consecutive months beginning with August 2012. Based upon the additional monthly lease operating expenses and capital expenditures BROG has reported it will use in order to recover the overpayment, the Royalty income distributions to the Trust were reduced by $742,779 in August, $1,090,583 in September, $767,122 in October and an estimated reduction of $786,377 is anticipated in November 2012. See Part I, Item 2. - Trustee’s Discussion and Analysis of Financial Condition and Results of Operations, for more information.

Item 2. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations.

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 (“BROG”), 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 BROG; 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.

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 BROG. On March 31, 2006, a subsidiary of ConocoPhillips completed its acquisition of Burlington Resources, Inc., BROG’s parent. As a result, ConocoPhillips became the parent of Burlington Resources, Inc., which in turn, is the parent of BROG. 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.

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.

BROG is the principal operator of the Underlying Properties. A very high percentage of the Royalty Income is attributable to the production and sale by BROG 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.

The Trust received Royalty income of $4,926,020 and interest income of $11,950 during the third quarter of 2012. There was no change in cash reserves. After deducting administrative expenses of $320,679, distributable income for the quarter was $4,617,291 ($0.099066 per Unit). In the third quarter of 2011, Royalty income was $17,886,286, interest income was $1,329, administrative expenses were $227,539 and distributable income was $17,660,076 ($0.378900 per Unit). Based on 46,608,796 Units outstanding, the per-Unit distributions during the third quarter of 2012 were as follows:

The Royalty income distributed in the third quarter of 2012 was lower than that distributed in the third quarter of 2011 primarily due to a decrease in the average gas price from $4.94 per Mcf for the third quarter of 2011 to $2.44 per Mcf for the third quarter of 2012. Interest income was higher for the quarter ended September 30, 2012 as compared to the quarter ended September 30, 2011, due to additional interest received in September from granted audit exceptions. Administrative expenses were higher in 2012 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 third quarter of 2012 and deducted by BROG in calculating Royalty income were approximately $4.1 million as compared to approximately $6.5 million of capital costs in the third quarter of 2011. However, BROG indicates that actual drilling costs were approximately $3.1 million higher in the third quarter of 2011. A miscalculation by BROG for the months of April through July 2012 caused lease operating expenses and capital expenditures to be understated by approximately 25% (the “2012 Calculation Error”). The 2012 Calculation Error caused capital costs to be understated by $333,644 in July 2012 and to be overstated by a total of $985,356 in August and September 2012 as that error was corrected.

As a result of the 2012 Calculation Error, the Royalty income due the Trust for the four months of April through July 2012 was overpaid by approximately $3,386,861. BROG has communicated to the Trust that, as permitted under the terms of the Royalty conveyance document, it intends to offset the overpayment against Royalty income payable to the Trust over four consecutive months beginning with August 2012. Based upon the additional monthly lease operating expenses and capital expenditures BROG has reported it will use in order to recover the overpayment, the Royalty income distributions to the Trust were reduced by $742,779 in August, $1,090,583 in September, $767,122 in October and an estimated reduction of $786,377 is anticipated in November 2012.

BROG has informed the Trust that its budget for capital expenditures for the Underlying Properties in 2012 is estimated at $20.8 million. Of the $20.8 million, approximately $5 million will be attributable to the capital budgets for 2011 and prior years. BROG reported in February 2012 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 2012 could range from $5 million to $35 million.

BROG anticipates 383 projects in 2012. Approximately $12.4 million of the $20.8 million budget is allocable to 21 new wells, including nine wells scheduled to be dually completed in the Mesaverde and Dakota formations and 12 wells to be completed in all three of the Mesaverde, Mancos Shale and Dakota formations. BROG indicates that evaluation of the Mancos Shale formation is in the very early stages. There are plans for a horizontal Mancos well beginning in the fourth quarter of 2012. Approximately $3.4 million will be spent on workovers and facilities projects. Of the $5 million attributable to the budgets for prior years, approximately $3 million is allocable to 20 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 $9,017,423 and $139,489, respectively, for the third quarter of 2012, as compared to $8,938,611 and $150,406, respectively, for the third quarter of 2011. The 2012 Calculation Error resulted in lease operating expenses being understated by $214,859 in July 2012 and overstated in August and September 2012 by a total of $1,459,127 as that error was corrected. Adjusting lease operating expenses for the third quarter of 2012 for the 2012 Calculation Error indicates actual lease operating expenses of $8,273,155, an amount which is $665,456 lower than lease operating expenses in the third quarter of 2011. But BROG also reports the figure for 2011 included a non-recurring audit adjustment which added $612,964 in lease operating expenses from a prior period, such that actual lease operating expenses for the third quarter of 2012 were only nominally lower than for the third quarter of the prior year. Taxes for the third quarter of 2012 were lower because in April 2012, BROG reduced its accrual for taxes from $50,135 per month to $46,496 per month. BROG adjusts its accruals for taxes based upon actual property taxes paid in the prior year.

BROG has reported to the Trustee that during the third quarter of 2012, four gross (0.69 net) conventional wells were completed on the Underlying Properties. Seven gross (2.98 net) conventional wells were in progress at September 30, 2012.

There were 14 gross (1.61 net) conventional wells and one gross (0.22 net) coal seam well completed on the Underlying Properties during the third quarter of 2011. Six gross (0.08 net) conventional wells and one gross (0.66 net) coal seam well were in progress at September 30, 2011.

There were 4,049 gross (1,180.50 net) producing wells being operated subject to the Royalty as of December 31, 2011, calculated on a well bore basis and not including multiple completions as separate wells. Of those wells, seven gross (5.50 net) are oil wells and the balance are gas wells. BROG reports that approximately 828 gross (324.5 net) of the wells are multiple completion wells resulting in a total of 4,877 gross (1,505 net) completions.

“Gross” acres or wells, for purposes of this discussion, means the entire ownership interest of all parties in such properties, and BROG’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, BROG 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 September 30, 2012 is associated with actual gas and oil production during May 2012 through July 2012 from the Underlying Properties. Gas and oil sales from the Underlying Properties for the three months ended September 30, 2012 and 2011 were as follows:

During the third quarter of 2012, average gas prices were $2.50 per Mcf lower than the average prices reported during the third quarter of 2011. The average price per barrel of oil during the third quarter of 2012 was $8.37 per barrel lower than that received for the third quarter of 2011.

BROG previously entered into four contracts effective April 1, 2009, for the sale of all gas produced from the Underlying Properties other than the gas covered by a pre-existing contract with New Mexico Gas Company, Inc. (“NMGC”). The then current purchasers were Chevron Natural Gas, a division of Chevron USA, Inc. (“Chevron”), Pacific Gas and Electric Company (“PG&E”), BP Energy Company, Macquarie Cook Energy LLC, and NMGC. In March 2010, notice of termination of each of the Chevron, BP Energy Company and Macquarie Cook Energy LLC contracts was given such that they terminated effective March 31, 2011. Requests for proposal were circulated to potential purchasers of those packages of gas covered by the expiring contracts with a view toward obtaining new contracts to be effective April 1, 2011. Because none of BROG, PG&E, or NMGC gave notice of termination of their contracts, the terms of those two contracts have been automatically extended through at least March 31, 2013.

BROG entered into three new contracts effective April 1, 2011, for the sale of the gas produced from the Underlying Properties but not sold under the two pre-existing contracts. The purchasers under such new contracts are Chevron, PG&E and Salt River Project Agricultural Improvement and Power District (“SRP”). All five of the current contracts provide for (i) the delivery of such gas at various delivery points through March 31, 2013 and from year-to-year thereafter, until terminated by either party upon notice of between six and twelve months (except for the SRP contract which terminated March 31, 2012); 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. Requests for proposals were circulated soliciting bids for the purchase of those volumes sold under the SRP contract which expired March 31, 2012. Contracts are now in place for the sale of those volumes to PG&E, Shell Energy North America (US), LP and SRP on delivery and pricing terms substantially the same as the other contracts described in this paragraph and also for terms expiring March 31, 2013.

On or about January 4, 2012, the operator of the Lybrook gas processing plant took that facility out of service and rerouted gas formerly treated there to its Ignacio plant. Because the NMGC system is not interconnected with the Ignacio plant, it became impossible for BROG to sell gas to NMGC under the contract described above such that BROG declared a force majeure event and terminated the NMGC contract. BROG negotiated a contract to sell the NMGC volumes to Chevron at prices and terms acceptable to the Trust’s consultants for the period through the March 31, 2013 termination date of the prior NMGC contract.

BROG 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 new contracts were entered into with WFC to be effective for terms of 15 years commencing April 1, 2010. BROG has also signed a new agreement with EFS effective November 1, 2011 for a term of 15 years. BROG has disclosed to the Trust a summary of that agreement which the Trust has reviewed with its consultants, subject to conditions of confidentiality. The Trustee will continue to monitor this matter as it may relate to the Trust.

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.

For the nine months ended September 30, 2012, the Trust received Royalty income of $30,359,217 and interest income of $569,686. There was no change in cash reserves. After deducting administrative expenses of $1,308,187, distributable income was $29,620,716 ($0.635520 per Unit) for the nine months ended September 30, 2012. For the nine months ended September 30, 2011, the Trust received Royalty income of $48,843,626 and interest income of $685,855. There was no change in cash reserves. After deducting administrative expenses of $1,276,041, distributable income was $48,253,440 ($1.035285 per Unit) for the nine months ended September 30, 2011.

The decrease in distributable income from 2011 to 2012 resulted primarily from lower gas prices during the first nine months of 2012. Interest earnings were lower for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011, due primarily to a decrease in funds available for investment and a reduction in the amount of interest due as the result of late payment of gross proceeds.

General and administrative expenses were higher for the nine months ended September 30, 2012, as compared to the same period in 2011, primarily as a result of differences in timing in the receipt and payment of certain of the expenses.

Capital expenditures incurred by BROG, attributable to the Underlying Properties, for the first nine months of 2012 amounted to approximately $13.9 million. Capital expenditures were approximately $15.8 million for the first nine months of 2011. Lease operating expenses and property taxes for the first nine months of 2012 totaled $24,184,351 and $145,896, respectively, as compared to $26,149,294 and $571,025, respectively, for 2011. In April 2012, BROG reduced its accrual for taxes from $50,135 per month to $46,496 per month.

BROG has reported to the Trustee that during the nine months ended September 30, 2012, 20 gross (5.13 net) conventional wells were completed on the Underlying Properties.

There were 42 gross (6.64 net) conventional wells and five gross (1.04 net) coal seam wells completed on the Underlying Properties during the nine months ended September 30, 2011.

Royalty income for the nine months ended September 30, 2012 is associated with actual gas and oil production during November 2011 through July 2012 from the Underlying Properties. Gas and oil sales from the Underlying Properties for the nine months ended September 30, 2012 and 2011 were as follows:

Royalty income received by the Trust for the three months and nine months ended September 30, 2012 and 2011, respectively, was computed as shown in the following table:

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).

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.

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; BROG 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, BROG provides much of the information 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 BROG’s delivery of such information. Accordingly, the Trust maintains disclosure controls and procedures designed to ensure that BROG 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 BROG to update or provide information to the Trust. However, the Conveyance transferring the Royalty to the Trust obligates BROG 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 BROG, BROG 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 September 30, 2012 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 BROG to deliver timely and accurate information to the Trust. Additionally, during the quarter ended September 30, 2012 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.

As discussed above under Part I, Item 4 – Controls and Procedures, due to the pass-through nature of the Trust, BROG 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 BROG 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 BROG’s timely delivery of the information to the Trust.

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, BROG 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. BROG indicates that the situation will not be alleviated until the DOI provides BROG 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 BROG of any portion of any settlement or judgment in calculating the Royalty.

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.


COMPASS BANK, AS TRUSTEE OF THE SAN JUAN BASIN ROYALTY TRUST

By:		/s/ Lee Ann Anderson
		Lee Ann Anderson
		Vice President and Senior Trust Officer


Large accelerated filer x	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company ¨
		(Do not check if a smaller reporting company)


CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

ASSETS	September 30, 2012		December 31, 2011
	(Unaudited)

Cash and short-term investments	$	658,629	$	7,101,319
Net overriding royalty interest in producing oil and gas properties (net of accumulated amortization of $120,998,010 and $120,130,470 at September 30, 2012 and December 31, 2011, respectively)		12,277,518		13,145,058

	$	12,936,147	$	20,246,377

LIABILITIES AND TRUST CORPUS

Distribution payable to Unit holders	$	502,840	$	6,945,530
Cash reserves		155,789		155,789
Trust corpus – 46,608,796 Units of beneficial interest authorized and outstanding		12,277,518		13,145,058

	$	12,936,147	$	20,246,377


CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS (UNAUDITED)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Trust corpus, beginning of period	$	12,475,033	$	13,986,056	$	13,145,058	$	14,745,884
Amortization of net overriding royalty interest		(197,515)		(403,228)		(867,540)		(1,163,056)
Distributable income		4,617,291		17,660,076		29,620,716		48,253,440
Distributions declared		(4,617,291)		(17,660,076)		(29,620,716)		(48,253,440)


Trust corpus, end of period	$	12,277,518	$	13,582,828	$	12,277,518	$	13,582,828


July . . .. . . . . . . . . . . .	$	.052155
August . . . . . . . . . . . .		.036122
September. . . . . . . . . . .		.010789

Quarter Total . . . . .	$	.099066


	Three Months Ended September 30,
	2012		2011
Gas:
Total sales (Mcf)		8,503,327		8,565,498
Mcf per day		92,427		93,103
Average price (per Mcf)	$	2.44	$	4.94

Oil:
Total sales (Bbls)		14,290		14,701
Bbls per day		155		160
Average price (per Bbl)	$	76.52	$	84.89


CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (UNAUDITED)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Royalty income	$	4,926,020	$	17,886,286	$	30,359,217	$	48,843,626
Interest income		11,950⁽¹⁾		1,329		569,686⁽²⁾		685,855⁽³⁾

Total revenue		4,937,970		17,887,615		30,928,903		49,529,481
General and administrative expenditures		320,679		227,539		1,308,187		1,276,041


Distributable income	$	4,617,291	$	17,660,076	$	29,620,716	$	48,253,440


Distributable income per Unit (46,608,796 Units)	$	0.099066	$	0.378900	$	0.635520	$	1.035285


	Nine Months Ended September 30,
	2012		2011
Gas:
Total sales (Mcf)		24,846,092		24,388,870
Mcf per day		90,679		89,337
Average price (per Mcf)	$	3.35	$	4.72

Oil:
Total Sales (Bbls)		38,330		43,318
Bbls per day		140		159
Average price (per Bbl)	$	83.54	$	83.12


CALCULATION OF ROYALTY INCOME

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Gross proceeds of sales from the Underlying Properties
Gas proceeds	$	20,716,421	$	42,209,984	$	83,538,936	$	114,961,156
Oil proceeds		1,093,450		1,248,036		3,202,212		3,600,453
Other		------		------		(246,332)⁽¹⁾		------

Total		21,809,871		43,458,020		86,494,816		118,561,609

Less production costs:
Severance tax – gas		1,909,830		3,872,807		7,487,678		10,559,177
Severance tax – oil		109,232		115,679		310,920		359,139
Lease operating expense and property tax		9,156,912		9,089,017		24,330,247		26,720,319
Capital expenditures		4,065,870		6,532,136		13,887,015		15,798,139


Total		15,241,844		19,609,639		46,015,860		53,436,774


Net profits		6,568,027		23,848,381		40,478,956		65,124,835
Net overriding royalty interest		75%		75%		75%		75%


Royalty Income	$	4,926,020	$	17,886,286	$	30,359,217	$	48,843,626



(4)(a)		Amended and Restated Royalty Trust Indenture, dated September 30, 2002 (the original Royalty Trust Indenture, dated November 1, 1980, having been entered into between Southland Royalty Company and The Fort Worth National Bank, as Trustee), heretofore filed as Exhibit 99.2 to the Trust’s Current Report on Form 8-K filed with the Commission on October 1, 2002, is incorporated herein by reference.*

(4)(b)		Net Overriding Royalty Conveyance from Southland Royalty Company to The Fort Worth National Bank, as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit 4(b) to the Trust’s Annual Report on Form 10-K filed with the Commission for the fiscal year ended December 31, 2007, is incorporated herein by reference.*

(4)(c)		Assignment of Net Overriding Interest (San Juan Basin Royalty Trust), dated September 30, 2002, between Bank One, N.A. and TexasBank, heretofore filed as Exhibit 4(c) to the Trust’s Quarterly Report on Form 10-Q filed with the Commission for the quarter ended September 30, 2002, is incorporated herein by reference.*

31		Certification required by Rule 13a-14(a), dated November 9, 2012, by Lee Ann Anderson, Vice President and Senior Trust Officer of Compass Bank, the Trustee of the Trust.**

32		Certification required by Rule 13a-14(b), dated November 9, 2012, by Lee Ann Anderson, Vice President and Senior Trust Officer of Compass Bank, on behalf of Compass Bank, the Trustee of the Trust.***


Exhibit Number		Description

(4)(a)		Amended and Restated Royalty Trust Indenture, dated September 30, 2002 (the original Royalty Trust Indenture, dated November 1, 1980, having been entered into between Southland Royalty Company and The Fort Worth National Bank, as Trustee), heretofore filed as Exhibit 99.2 to the Trust’s Current Report on Form 8-K filed with the Commission on October 1, 2002, is incorporated herein by reference.*

(4)(b)		Net Overriding Royalty Conveyance from Southland Royalty Company to The Fort Worth National Bank, as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit 4(b) to the Trust’s Annual Report on Form 10-K filed with the Commission for the fiscal year ended December 31, 2007, is incorporated herein by reference.*

(4)(c)		Assignment of Net Overriding Interest (San Juan Basin Royalty Trust), dated September 30, 2002, between Bank One, N.A. and TexasBank, heretofore filed as Exhibit 4(c) to the Trust’s Quarterly Report on Form 10-Q with the Commission for the quarter ended September 30, 2002, is incorporated herein by reference.*

31		Certification required by Rule 13a-14(a), dated November 9, 2012, by Lee Ann Anderson, Vice President and Senior Trust Officer of Compass Bank, the Trustee of the Trust.**

32		Certification required by Rule 13a-14(b), dated November 9, 2012, by Lee Ann Anderson, Vice President and Senior Trust Officer of Compass Bank, on behalf of Compass Bank, the Trustee of the Trust.***