EX-13 2 d33958exv13.htm ANNUAL REPORT TO UNIT HOLDERS

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EXHIBIT 13

2005 A NNUAL R EPORT & F ORM 10-K S AN J UAN B ASIN R OYALTY T RUST 05

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MESAV E R D E N nbsp; A T I O N A L P A R K Deep in the heart of the southwest lies the spirit of the ancient Anasazi people. Mesa Verde National Park is home to the cliff dwellings these people constructed almost 1,000 years ago, using only their hands and the natural resources available to them. Today, 24 Native American tribes in the southwest have an ancestral af.liation with the sites at Mesa Verde.

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DISTRIBUTIONS HIGH LOW PAID First Quarter $ 37.4000 $ 27.7000 $ .831092 Second Quarter 44.2000 34.1000 .740612 Third Quarter 51.4300 39.0000 .692829 Fourth Quarter 49.2500 38.3000 .987214 T O T A L F O R 2 0 0 5 $ 3.251747 First Quarter $ 22.9700 $ 17.7600 $ .443948 Second Quarter 25.3700 19.6500 .536204 Third Quarter 30.8100 23.8700 .738093 Fourth Quarter 33.6900 27.0000 .628753 T O T A L F O R 2 0 0 4 $ 2.346998 At March 6, 2006, there were 46,608,796 Units outstanding held by 1,795 Unit holders of record. The following table presents information relating to the distribution of record ownership of Units: NUMBER OF T Y P E O F U N I T H O L D E R S UNIT HOLDERS UNITS HELD Individuals, Joint Holders and Minors 1,577 2,032,306 Fiduciaries 171 500,083 Government Bodies 6 1,331 Clubs, Associations or Societies 6 13,117 Depositary (for all bene.cial holders) 1 43,712,465 Corporations 34 349,494 T O T A L 1,795 46,608,796 2005 2004 1 TH E T R U S T U N I T S O F B E N E F I C I A L I N T E R E S T The units of bene.cial interest of the Trust (the “Units”) are traded on the New York Stock Exchange under the symbol “SJT.” At March 6, 2006, the closing price of a Unit was $39.20. From January 1, 2004, to December 31, 2005, the quarterly high and low sales prices and the aggregate amount of monthly distributions per Unit paid each quarter were as follows: T H E P R I N C I P A L A S S E T o f the San Juan Basin Royalty Trust (the “Trust”) consists of a 75% net overriding royalty interest (the “Royalty”) carved out of certain oil and gas leasehold and royalty interests (the “Underlying Properties”) in properties located in the San Juan Basin of northwestern New Mexico.

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W E ARE PLEASED TO PRESENT THE 2005 A NNUAL R EPORT OF THE S AN J UAN B ASIN R OYALTY T RUST . The report includes a copy of the Trust’s Annual Report on Form 10-K filed with the Securities and Exchange Commission (the “Commission”) for the year ended December 31, 2005, without exhibits. The Form 10-K contains important information concerning the Underlying Properties, as defined below, including the oil and gas reserves attributable to the 75% net overriding royalty interest owned by the Trust. Production figures provided in this letter and in the Trustee’s Discussion and Analysis are based on information provided by Burlington Resources Oil & Gas Company LP (“BROG”), the current owner of the Underlying Properties and the successor, through a series of assignments and mergers, to Southland Royalty Company (“Southland Royalty”). The Trust was established in November 1980 by Southland Royalty. Pursuant to the Indenture that governs the operations of the Trust, Southland Royalty conveyed to the Trust a 75% net overriding royalty interest (equivalent to a net profits interest) (the “Royalty”), carved out of Southland Royalty’s oil and gas leasehold and royalty interests (the “Underlying Properties”) in properties in the San Juan Basin of northwestern New Mexico. On September 19, 2005, Compass Bancshares Inc. (“Compass”) announced the signing of a definitive agreement to acquire TexasBanc Holding Co. (“TexasBanc”), the parent company of the Trustee, in a combination that would create the fifth largest bank in Texas. The transaction, which is anticipated to be completed during the first half of 2006, is subject to all required regulatory approvals, approval by TexasBanc shareholders and other customary conditions. On December 12, 2005, ConocoPhillips and Burlington Resources, Inc., BROG’s parent (“Burlington”), announced that they signed a definitive agreement under which ConocoPhillips would acquire Burlington. That transaction is subject to shareholder and regulatory approval and other customary terms and conditions. It is anticipated that the transaction will be completed during the first half of 2006. Assuming that both of the subject transactions are completed, Compass Bank, a subsidiary of Compass, would succeed TexasBank as Trustee under the terms of the Indenture and ConocoPhillips (or a subsidiary) would succeed Burlington as BROG’s parent. The Royalty constitutes the principal asset of the Trust. Under the Indenture governing the Trust, the function of TexasBank, as Trustee, is to collect the net proceeds attributable to the Royalty (“Royalty Income”), to pay all expenses and charges of the Trust, and then distribute the remaining available income to the Unit holders. Income distributed to Unit holders in 2005 was $151,560,081 or $3.251747 per Unit. Distributable Income for 2005 consisted of Royalty Income of $153,858,264 plus interest income of $167,367, less administrative expenses of $2,465,550. Information about the Trust’s estimated pro ved reserves of gas, including coal seam gas, and of oil as well as the present value of net revenues discounted at 10% can be found in Item 2 of the accompanying Form 10-K. Independent petroleum engineers retained by the Trust have estimated the Underlying Properties could remain productive well beyond the stated production index of approximately 9.8 years and BROG has published information observing that the San Juan Basin will remain a major gas

resource for decades to come. In support of this observation, BROG cites the November 2002 U.S. Geological Survey study doubling its estimates of the gas reserves in the San Juan Basin to over 50 trillion cubic feet. Certain Royalty Income is generally considered portfolio income under the passive loss rules of the Internal Revenue Code. Therefore, Unit holders should generally not consider the taxable income from the Trust to be passive income in determining net passive income or loss. Unit holders should consult their tax advisors for further information. Unit holders of record will continue to receive an individualized tax information letter for each of the quarters ending March 31, June 30 and September 30, 2006, and for the year ending December 31, 2006. Unit holders owning Units in nominee name may obtain monthly tax information from the Trustee upon request. For the reader’s convenience, a glossary of definitions used in this report can be found on the inside back cover. Please visit our Web site at www.sjbrt.com to access news releases, reports, Commission filings and tax information. TexasBank, Trustee B Y : L E E A N N A N D E R S O N Vice President and Trust Officer T O U N I T H O L D E R S

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M ESA V ERDE N ATIONAL P ARK Look closely at the dwellings and it is clear the people who constructed them were small in stature compared to their modern day relatives. In fact, an average Ancestral Pueblan man was about 5 ´51/2 tall, while an average woman was 5 ´11/2. Life spans were short, as well. Most people lived an average of 32 to 34 years, while about 50 percent of the children died before they reached the age of .ve.

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D E S C R I P T I O N O F T H E P R O P E R T I E S T HE PRINCIPAL ASSET of the Trust is a 75% net overriding royalty interest (the “Royalty”) carved out of certain working, royalty and other leasehold interests (the “Underlying Properties”) owned by BROG in oil and gas properties located in the San Juan Basin, and more particularly in San Juan, Rio Arriba and Sandoval Counties of northwestern New Mexico. The Underlying Properties consist of working interests, royalty interests, overriding royalty interests and other contractual rights in 151,900 gross (119,000 net) producing acres and 4,429 gross (1,277 net) producing wells, including dual completions. The Underlying Properties have historically produced gas primarily from conventional wells drilled to three major formations: the Pictured Cliffs, the Mesaverde and the Dakota, ranging in depth from 1,500 to 8,000 feet. The characteristics of these reservoirs result in the wells having very long productive lives. A production index for oil and gas properties is derived by dividing remaining reserves by current production. Based upon the reserve report prepared by the Trust’s independent petroleum engineers as of December 31, 2005, the production index for the Underlying Properties is estimated to be approximately 9.8 years. The production index is subject to change from year-to-year based on reserve revisions and production levels and is not presented as an estimate of the life expectancy of the Trust. Among the factors considered by engineers in estimating remaining reserves of natural gas is the current sales price for gas. As the sales price increases, the producer can justify expending higher lifting costs and therefore reasonably expect to recover more of the known reserves. Accordingly, as gas prices rise, the production index increases and vice versa. In addition to gas from conventional wells, the Underlying Properties also produce gas from coal seam wells completed to the Fruitland Coal formation. The process of removing coal seam gas is often referred to as degasification or desorption. Millions of years ago, natural gas was generated in the process of coal formation and absorbed into the coal. Water later filled the natural fracture system. When the water is removed from the natural fracture system, reservoir pressure is lowered and the gas desorbs from the coal. The desorbed gas then flows through the fracture system and is produced at the well bore. The volume of formation water production typically declines with time and the gas production may increase for a period of time before starting to decline. In order to dispose of the formation water, surface facilities including pumping units are required, which results in the cost of a completed well being as much as $550,000. The price of coal seam gas is typically lower than the price of conventional gas. This is because the heating value of

coal seam gas is much lower than that of conventional gas due to (a) ever increasing percentages of carbon dioxide in coal seam gas (carbon dioxide has no heating value), and (b) the absence of heavier hydrocarbons such as ethanes, propanes, and butanes which are present in conventional gas. Furthermore, the processing fees for coal seam gas are typically higher than the processing fees for conventional gas due to the cost of extracting the carbon dioxide. The coal seam production from the Underlying Properties for the December 2005 production month was approximately 42.5% of the total gas production for that month. In February 2002, BROG informed the Trust that the New Mexico Oil Conservation Division (the “OCD”) had approved plans for 80-acre infill drilling of the Dakota formation in the San Juan Basin. In July 2003, the OCD approved 160-acre spacing in the Fruitland Coal formation. Eighty-acre spacing has been permitted in the Mesaverde formation since 1997. BROG reports that while there are currently no increased density proposals before the OCD, BROG continues to evaluate the merits of additional increased density for each formation in the San Juan Basin. The Federal Energy Regulatory Commission is primarily responsible for federal regulation of natural gas. For a further discussion of gas pricing, gas purchasers, gas production and regulatory matters affecting gas production see Item 2, “Properties,” in the accompanying Form 10-K.

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T R U S T E E ’ S D I S C U S S I O N & A N A L Y S I S 2005 2004 2003 2002 2001 Gas – Mcf 42,867,162 44,015,816 45,202,576 46,206,297 42,960,149 Mcf per Day 117,444 120,262 123,843 126,593 117,699 Oil – Bbls 69,558 77,341 74,727 93,659 92,413 Bbls per Day 191 211 205 257 253 Royalty Income for a calendar year is based on the actual gas and oil production during the period beginning with November of the preceding calendar year through October of the current calendar year. Gas and oil sales attributable to the Royalty for the past five years are summarized in the following table: 2005 2004 2003 2002 2001 Gas – Mcf 26,600,644 25,324,435 25,922,650 19,584,056 19,272,021 Average Price (per Mcf) $ 6.27 $ 4.68 $ 3.93 $ 2.32 $ 4.61 Oil – Bbls 43,142 44,832 43,123 40,215 42,056 Average Price (per Bbl) $ 49.62 $ 34.81 $ 26.11 $ 20.90 $ 24.99 G A S A N D O I L P R O D U C T I O N Total gas and oil production from the Underlying Properties for the five years ended December 31, 2005, were as follows: Sales volumes attributable to the Royalty are determined by dividing the net profits received by the Trust and attributable to oil and gas, respectively, by the prices received for sales volumes from the Underlying Properties, taking into consideration production taxes attributable to the Underlying Properties. Since the oil and gas sales attributable to the Royalty are based on an allocation formula dependent on such factors as price and cost, including capital expenditures, the aggregate sales amounts

from the Underlying Properties may not provide a meaningful comparison to sales attributable to the Royalty. The fluctuations in annual gas production that have occurred during these five years generally resulted from changes in the demand for gas during that time, marketing conditions, and increased capital spending to generate production from new and existing wells. Production from the Underlying Properties is influenced by the line pressure of the gas gathering systems in the San Juan Basin. As noted above, oil and gas sales attributable to the Royalty are based on an allocation formula dependent on many factors, including oil and gas prices and capital expenditures. BROG previously entered into two contracts for the sale of all volumes of gas produced from the Underlying Properties providing for (i) the sale of such gas to Duke Energy and Marketing L.L.C. and PNM Gas Services, respectively, (ii) the delivery of such gas at various delivery points through March 31, 2005, and from year-to-year thereafter until terminated by either party on 12 months’ notice, and (iii) the sale of such gas at prices which fluctuate in accordance with published indices for gas sold in the San Juan Basin of northwestern New Mexico. Effective January 1, 2004, the rights and obligations of Duke Energy and Marketing L.L.C. were assumed by ConocoPhillips Company (“ConocoPhillips”) pursuant to an Assignment and Novation Agreement. By correspondence dated March 25, 2004, BROG notified ConocoPhillips of BROG’s election to terminate such contract as of March 31, 2005. BROG then prepared a form of request for proposal and circulated it to a number of potential purchasers, including ConocoPhillips, inviting them to bid for the purchase of the gas currently sold under the contract expiring March 31, 2005. Effective as of April 1, 2005, BROG entered into two new contracts for the sale of all volumes of gas produced from the Underlying Properties and formerly sold to ConocoPhillips. These new contracts provide for (i) the sale of such gas to ChevronTexaco Natural Gas, a division of Chevron U.S.A. Inc. and Coral Energy Resources, L.P., respectively, (ii) the delivery of such gas at various delivery points through March 31, 2007, and from year-to-year thereafter until terminated by either party on 12 months’ notice, and (iii) 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. With respect to BROG’s contract with PNM Gas Services, BROG and PNM Gas Services have entered into a letter agreement dated January 31, 2005, pursuant to which the parties waive the right to terminate the underlying contract as of March 31, 2006, so that the term of that contract will continue until at least March 31, 2007, and from year-to-year thereafter until terminated by either party upon 12 months’ notice to the other. Confidentiality agreements with 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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T R U S T E E ’ S D I S C U S S I O N & A N A L Y S I S R O Y A L T Y I N C O M E Royalty Income consists of monthly Net Proceeds attributable to the Royalty. Royalty Income for the five years ended December 31, 2005, was determined as shown in the following table: 2005 2004 2003 2002 2001 Gas $ 267,895,460 $ 204,682,365 $ 175,653,183 $ 103,349,299 $ 169,052,231 Oil 3,451,115 2,670,763 1,938,972 1,863,827 2,233,071 Other 2,405,486 1 3,314,808 2 (1,202,368) 3 (5,110,589) 4 -0- T O T A L $ 273,752,061 $ 210,667,936 $ 176,389,787 $ 100,102,537 $ 171,285,302 Capital Expenditures $ 19,127,698 $ 22,338,684 $ 20,590,704 $ 21,470,777 $ 32,999,973 Severance Tax – Gas 26,717,315 19,766,231 17,281,986 9,752,508 16,687,074 Severance Tax – Oil 362,023 253,022 174,750 151,594 202,113 Other 273,766 42,763 41,850 18,037 55,000 Lease Operating Expenses and Property Taxes 22,126,907 20,210,213 15,637,481 15,701,740 15,109,139 T O T A L $ 68,607,709 $ 62,610,913 $ 53,726,771 $ 47,094,656 $ 65,053,299 Excess Production Costs -0- -0- -0- (2,259,628) 5 2,259,628 5 Interest on Excess Production Costs -0- -0- -0- (10,545) 5 -0- Net Profits $ 205,144,352 $ 148,057,023 $ 122,663,016 $ 50,737,708 $ 108,491,631 Net Overriding Royalty Interest 75% 75% 75% 75% 75% Royalty Income $ 153,858,264 $ 111,042,767 $ 91,997,262 $ 38,053,281 $ 81,368,723 (1) Represents funds allocated to the Trust as part of the ongoing negotiation of joint interest audit exceptions. (2) Represents funds allocated to the Trust as part of the ongoing negotiation of joint interest audit exceptions, interest received for resolved audit exceptions, and insurance proceeds for a business interruption claim. (3) Represents a settlement between BROG and the Mineral Management Service of the United States Department of the Interior (the “MMS”). (4) Represents deductions by BROG from the net proceeds otherwise payable to the Trust in connection with the portion of various settlement agreements with the MMS allocable to the Royalty (see Item 3 of Trust’s Annual Report on Form 10-K). (5) Represents excess production costs incurred in December 2001 and recovered by BROG in 2002, plus interest. G ROSS P ROCEEDS FROM THE U NDERLYING P ROPERTIES L ESS P RODUCTION C OSTS D I S T R I B U T A B L E I N C O M E Distributable Income consists of Royalty Income plus interest, less the general and administrative expenses of the Trust and any changes in cash reserves established by the Trustee. For the year ended December 31, 2005, Distributable Income was $151,560,081, representing a 38% increase from 2004. For the year ended December 31, 2004, Distributable Income was $109,390,735, representing a 21% increase from 2003. Distributable Income in 2003 was $90,357,837. The Trust received Royalty Income of $153,858,264 and interest income of $167,367 in 2005. After deducting administrative expenses of $2,465,550, Distributable Income for 2005 was $151,560,081 ($3.251747 per Unit). In 2004, Royalty Income was $111,042,767, interest income was $58,885, and administrative expenses were $1,710,917, resulting in Distributable Income of $109,390,735 ($2.346998 per Unit). The 38% increase in Distributable Income from 2004 to 2005 was primarily attributable to higher gas and oil prices which resulted in increased Royalty Income. In addition, interest earnings in 2005 were higher, as compared to 2004, primarily due to an increase in funds available for investment as well as an increase in interest rates. Administrative expenses were

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T R U S T E E ’ S D I S C U S S I O N & A N A L Y S I S higher in 2005, as compared to 2004, primarily as a result

of compliance with the new internal control, financial reporting and other requirements of the Sarbanes-Oxley Act of 2002 and costs incurred in resolving certain outstanding audit issues, including the costs of the arbitration referred to in Note 7 to the Financial Statements included herewith. In 2003, the Trust received Royalty Income of $91,997,262 and interest income of $43,882. After deducting administrative expenses of $1,683,307, Distributable Income for 2003 was $90,357,837 ($1.938644 per Unit). The 21% increase in Distributable Income from 2003 to 2004 was primarily attributable to higher gas and oil prices which resulted in increased Royalty Income. In addition, interest earnings in 2004 were higher, as compared to 2003, primarily due to an increase in funds available for investment as well as an increase in interest rates. Administrative expenses were slightly higher in 2004, as compared to 2003, primarily as a result of compliance with the new internal control, financial reporting and other requirements of the Sarbanes-Oxley Act of 2002. BROG has informed the Trustee that the New Mexico Oil and Gas Proceeds Withholding Tax Act (the “Withholding Tax Act”) requires remitters who pay certain oil and gas proceeds from production on New Mexico properties on or after October 1, 2003, to withhold income taxes from such proceeds in the case of certain nonresident recipients. The Trustee, on advice of New Mexico counsel, has observed that “net profits interests,” such as the Royalty, and other types of interests, the extent of which cannot be determined with respect to a specific share of the oil and gas production, are excluded from the withholding requirements of the Withholding Tax Act. Unit holders are reminded to consult with their tax advisors regarding the applicability of New Mexico income tax to distributions received from the Trust by a Unit holder. O P E R A T I N G E X P E N S E S Monthly operating expenses of the Underlying Properties, exclusive of property taxes, in 2005 averaged approximately $1,769,538, which is higher than the $1,639,670 average in 2004 and higher than the $1,250,600 average in 2003. Operating expenses were higher in 2005 than for 2004 primarily because increased activity strained the capacity of service vendors and resulted in increasing costs. Operating expenses were higher in 2004 than for 2003 primarily because in calculating Royalty Income for October 2004, BROG allocated approximately $1.3 million of costs incurred in the plugging and abandonment of wells from the periods 1999 through January 2003. Operating expenses for 2001 included the impact of the annual inclusion of $250,000 from BROG as an offset to lease operating expenses in connection with the settlement of the litigation described under “Settlements” below. The final $250,000 offset was made in December 2001. S ET T L E M E N T S As part of the September 4, 1996, settlement of the litigation filed by the Trustee on June 4, 1992 against BROG and Southland Royalty, the Trust was entitled to certain adjustments (the “Val Verde Credit”) that represented cost reductions favorable to the Trust in the charges for coal seam gas gathered and treated on BROG’s Val Verde system. Effective July 1, 2002, BROG sold the Val Verde facility. Accordingly, effective July 1, 2002, the calculation of net proceeds for gas gathered

and treated at the Val Verde facility no longer includes the Val Verde Credit. The total amount of the Val Verde Credit for the 12 months’ ended June 30, 2002, was estimated by the Trust’s joint interest auditors as approximately $1,880,000. The loss of the Val Verde Credit resulted in increased costs allocated to the Trust for coal seam gas gathered and treated on the Val Verde system and accordingly, decreased the Royalty Income received by the Trust. As a part of that same litigation settlement, the Trustee and BROG established a formal protocol pursuant to which joint interest auditors retained by the Trustee gained improved access to BROG’s books and records as applicable to the Underlying Properties. The audit process was initiated in 1996 and, since inception, has resulted in audit exceptions being granted by and payments received from BROG totaling approximately $15,500,000. C A P I TA L E X P E N D I T U R E S During 2005, in calculating Royalty Income, BROG deducted approximately $19.1 million of capital expenditures for projects, including drilling and completion of 38 gross (2.72 net) conventional wells, five gross (0.011 net) payadds, one gross (0.57 net) conventional restimulation, 25 gross (2.89 net) coal seam wells, one gross (0.99 net) coal seam recavitation, two gross (0.61 net) coal seam recompletions, and five gross (0.20 net) miscellaneous coal seam capital projects. The aggregate capital expenditures reported by BROG in calculating Royalty Income for 2005 include approximately $6 million attributable to the capital budgets for prior years. This occurs because projects within a given year’s budget may extend into subsequent years, with capital expenditures

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T R U S T E E ’ S D I S C U S S I O N & A N A L Y S I S attributable to those projects used in calculating Distributable Income to the Trust in those subsequent years. Further, BROG’s accounting period for capital expenditures runs through November 30 of each calendar year, such that capital expenditures incurred in December of each year are actually accounted for as part of the following year’s capital expenditures. In addition, with respect to wells not operated by BROG, BROG’s share of capital expenditures may not actually be paid by it until the year or years after those expenses were incurred by the operator. Capital expenditures of approximately $13.9 million for 2005 budgeted projects were used in calculating net proceeds payable to the Trust in calendar year 2005, and approximately $5.1 million in capital expenditures from the 2005 budget were used in calculating net proceeds payable to the Trust for January and February 2006. Therefore, an additional approximately $2.8 million in capital expenditures for budgeted 2005 projects remains to be spent. There were 110 gross (19.08 net) conventional wells, eight gross (1.73 net) payadds, six gross (3.30 net) conventional recompletions, seven gross (5.04 net) conventional restimulations, 59 gross (10.06 net) coal seam wells, five gross (2.32 net) coal seam recompletions, and one gross (0.04 net) miscellaneous coal seam capital project in progress as of December 31, 2005. During 2004, in calculating Royalty Income, BROG deducted approximately $22.3 million of capital expenditures for projects, including drilling and completion of 25 gross (6.49 net) conventional wells, recompletion of 11 gross (8.05 net) conventional wells, nine gross (5.95 net) restimulations, three gross (0.007 net) conventional payadds, 61 gross (6.10 net) coal seam wells, four gross (3.41 net) coal seam recompletions, and two gross (0.05 net) miscellaneous coal seam capital projects and facilities maintenance. There were 57 gross (6.94 net) new conventional wells, recompletion of three gross (0.89 net) conventional wells, four gross (2.24 net) conventional well restimulations, 13 gross (1.74 net) conventional payadds, 48 gross (4.74 net) coal seam wells, four gross (1.90 net) coal seam recompletions, and six gross (0.27 net) miscellaneous coal seam capital projects in progress as of December 31, 2004. During 2003, in calculating Royalty Income, BROG deducted approximately $20.6 million of capital expenditures for projects, including drilling and completion of 44 gross (15.36 net) conventional wells, recompletion of two gross (.07 net) conventional wells, three gross (.94 net) miscellaneous capital projects, 29 gross (21.55 net) restimulations, 49 gross (3.22 net) conventional payadds, 53 gross (16.98 net) coal seam wells, nine gross (1.6 net) coal seam recompletions, two gross (.92 net) coal seam recavitations, one gross (.04 net) coal seam restimulation, and two gross (.88 net) miscellaneous coal seam capital projects and facilities maintenance. There were 32 gross (7.0 net) new conventional wells, recompletion of 15 gross (3.72 net) conventional wells, 22 gross (9.11 net) conventional well restimulations, 14 gross (3.65 net) conventional payadds, 54 gross (14.43 net) coal seam wells, six gross (1.62 net) coal seam recompletions, one gross (.002 net) recavitation, and six gross (.20 net) miscellaneous coal seam capital projects in progress as of December 31, 2003.

BROG has informed the Trust that its budget for capital expenditures for the Underlying Properties in 2006 is estimated at $37.6 million. Approximately $33 million of that budget is allocable to 153 new wells, including 41 wells scheduled to be dually completed in the Mesaverde and Dakota formations at an aggregate projected cost of approximately $13.6 million. BROG indicates that 61 of the new wells, at an aggregate cost of approximately $16 million, are projected to be drilled to formations producing coal seam gas as distinguished from conventional gas, and $4.5 million is to be expended in working over existing wells and in the maintenance and improvement of production facilities. BROG reports that based on its actual capital requirements, the pace of regulatory approvals, and the mix of projects and swings in the price of natural gas, the actual capital expenditures for 2006 could range from $20 million to $45 million. BROG anticipates 451 projects, including the drilling of 103 new wells to be operated by BROG and 50 wells to be operated by third parties. Of the new BROG operated wells, 52 are projected to be conventional wells completed to the Pictured Cliffs, Mesaverde, and/or Dakota formations, and the remaining 51 are projected as coal seam gas wells to be completed in the Fruitland Coal formation. A total of 40 of the wells operated by third parties are projected to be conventional wells, and the remaining 10 are to be coal seam wells. BROG has announced that the budget for 2006 reflects the continuation of a shift toward increased development of conventional gas. C O N T R AC T UA L O B L I GAT I O N S 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

SAN JUAN BASIN GAS FIELDS OIL FIELDS LEASEHOLD ACREAGE Archuleta La Plata Montezuma Rio Arriba San Juan FARMINGTON DURANGO Sandoval McKinley COLORADO NEW MEXICO

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9 T R U S T E E ’ S D I S C U S S I O N & A N A L Y S I S 300 hours annually. As of January 1, 2003, 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). E F F E C T S O F S E C U R I T I E S

R E G U L AT I O N 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 as yet 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. C R I T I C A L A C C O U N T I N G P O L I C I E S In accordance with the Commission’s staff accounting bulletins and consistent with other royalty trusts, the Financial Statements of the Trust are prepared on the following basis: · Royalty Income recorded for a month is the amount computed and paid by BROG to the Trustee for the Trust. Royalty Income consists of the proceeds received by BROG from the sale of production from the Underlying Properties less accrued production costs, development and drilling costs, applicable taxes, operating charges, and other costs and deductions, multiplied by 75%. The calculation of net proceeds by BROG for any month includes adjustments to proceeds and costs for prior months and impacts the Royalty Income paid to the Trust and the distribution to Unit holders for that month. · Trust expenses recorded are based on liabilities paid and cash reserves established from Royalty Income for liabilities and contingencies. · Distributions to Unit holders are recorded when declared by the Trustee. · The conveyance which transferred the Royalty to the Trust provides that any excess of production costs applicable to the Underlying Properties over gross proceeds from such properties must be recovered from future net profits before Royalty Income is again paid to the Trust. The Financial Statements of the Trust differ from Financial Statements prepared in accordance with U.S. generally accepted accounting principles (“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 trust corpus instead of an expense.

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T R U S T E E ’ S D I S C U S S I O N & A N A L Y S I S R E S U L T S O F T H E 4 T H Q U A R T E R S O F 2 0 0 5 & 2 0 0 4 For the three months ended December 31, 2005, Distributable Income was $46,012,856 ($.987214 per Unit), which was more than the $29,305,430 ($.628753 per Unit) of income distributed during the same period in 2004. The increase in Distributable Income resulted primarily from higher average gas and oil prices. Royalty Income of the Trust for the fourth quarter is based on actual gas and oil production during August through October of each year. Gas and oil sales for the quarters ended December 31, 2005 and 2004 were as follows: 2005 2004 Gas – Mcf 10,248,571 11,295,783 Mcf per Day 111,398 122,780 Average Price (per Mcf) $ 7.77 $ 4.80 Oil – Bbls 16,477 17,686 Bbls per Day 179 192 Average Price (per Bbl) $ 59.06 $ 42.55 Gas – Mcf 6,516,096 6,566,249 Oil – Bbls 10,429 10,223 The average price of gas and oil increased in 2005 compared to the prior year. The price per barrel of oil during the fourth quarter of 2005 was $16.51 per Bbl higher than that received in the fourth quarter of 2004 due to increases in oil prices in world markets generally, including the posted price applicable to the Royalty. Gas production decreased because new production brought on line in 2005 failed to completely offset the natural decline in production from existing wells. In addition, production volumes were reduced in 2005 due to operational difficulties in the San Juan Basin, including: weather-related shut downs, pipeline maintenance work, compressor repairs and downtime at processing facilities. Capital costs for the fourth quarter of 2005 totaled $4,734,866 compared to $4,843,584 during the same period of 2004. Lease operating expenses and property taxes for the fourth quarter of 2005 averaged $1,939,447 per month compared to $2,168,935 per month in the fourth quarter of 2004. Operating expenses were lower in the fourth quarter of 2005 than for the fourth quarter of 2004 primarily because in calculating Royalty Income for October 2004, BROG allocated approximately $1.3 million of costs incurred in the plugging and abandonment of wells from the periods 1999 through January 2003. Based on 46,608,796 Units outstanding, the per Unit distributions during the fourth quarter of 2005 and 2004 were as follows: U NDERLYING P ROPERTIES A TTRIBUTABLE TO THE R OYALTY 2005 2004 October $ .243762 $ .214123 November .334553 .199538 December .408899 .215092 Q U A R T E R T O T A L $ .987214 $ .628753

N A V A J O N A T I O N A L M O N U M E N T In another area of the southwest, the Navajo National Monument preserves three of the most intact cliff dwellings of the Anasazi. These impressive multi-storied structures tell us much about the people, except why they completely abandoned the area by 1300 A.D. Whatever the reasons, the Anasazi people left behind a vast network of architecture that included irrigation systems, elaborate ceremonial chambers, ritualistic rock art images and ceramics.

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S A N J U A N B A S I N R O Y A L T Y T R U S T S T A T E M E N T S O F A S S E T S , L I A B I L I T I E S A N D T R U S T C O R P U S December 31, 2005 & 2004 A S S E T S 2005 2004 Cash and Short-Term Investments $ 19,173,162 $ 10,140,045 Net Overriding Royalty Interests in Producing Oil and Gas Properties – Net 23,881,494 26,674,821 T O T A L $ 43,054,656 $ 36,814,866 L I A B I L I T I E S & T R U S T C O R P U S 2005 2004 Distribution Payable to Unit holders $ 19,058,304 $ 10,025,187 Cash Reserves 114,858 114,858 Trust Corpus – 46,608,796 Units of Beneficial Interest Authorized and Outstanding 23,881,494 26,674,821 T O T A L $ 43,054,656 $ 36,814,866 S T A T E M E N T S O F D I S T R I B U T A B L E I N C O M E For the three years ended December 31, 2005 2005 2004 2003 Royalty Income $ 153,858,264 $ 111,042,767 $ 91,997,262 Interest Income 167,367 58,885 43,882 154,025,631 111,101,652 92,041,144 Expenditures – General and Administrative 2,465,550 1,710,917 1,683,307 Distributable Income $ 151,560,081 $ 109,390,735 $ 90,357,837 Distributable Income per Unit (46,608,796 Units) $ 3.251747 $ 2.346998 $ 1.938644 S T A T E M E N T S O F C H A N G E S I N T R U S T C O R P U S For the three years ended December 31, 2005 2005 2004 2003 Trust Corpus, Beginning of Period $ 26,674,821 $ 29,822,820 $ 33,697,906 Amortization of Net Overriding Royalty Interest (2,793,327) (3,147,999) (3,875,086) Distributable Income 151,560,081 109,390,735 90,357,837 Distributions Declared (151,560,081) (109,390,735) (90,357,837) Trust Corpus, End of Period $ 23,881,494 $ 26,674,821 $ 29,822,820 N O T E S T O F I N A N C I A L S T A T E M E N T S 1. T R U S T O R G A N I Z A T I O N A N D P R O V I S I O N S

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The San Juan Basin Royalty Trust (“Trust”) was established as of November 1, 1980. As of September 30, 2002, TexasBank (“Trustee”) replaced Bank One, N.A., as Trustee for the Trust. Southland Royalty Company (“Southland”)

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conveyed to the Trust a 75% net overriding royalty interest (“Royalty”) carved out of Southland’s working interests and royalty interests (the “Underlying Properties”) in the properties located in the San Juan Basin in northwestern New Mexico. On November 3, 1980, units of beneficial interest (“Units”) in the Trust were distributed to the Trustee for the benefit of Southland shareholders of record as of November 3, 1980, who received one Unit in the Trust for each share of Southland common stock held. The Units are traded on the New York Stock Exchange. The terms of the Trust Indenture provide, among other things, that: · The Trust shall not engage in any business or commercial activity of any kind or acquire any assets other than those initially conveyed to the Trust; · The Trustee may not sell all or any part of the Royalty unless approved by holders of 75% of all Units outstanding in which case the sale must be for cash and the proceeds promptly distributed; · The Trustee may establish a cash reserve for the payment of any liability which is contingent or uncertain in amount; · The Trustee is authorized to borrow funds to pay liabilities of the Trust; and · The Trustee will make monthly cash distributions to Unit holders (see Note 2).

2. Ne t Ove r r id in g Ro ya l t y In t e r e st a n d Dist r ibu t io n To Un it Ho l d e r s The amounts to be distributed to Unit holders (“Monthly Distribution Amounts”) are determined on a monthly basis by the Trustee. The Monthly Distribution Amount is an amount equal to the sum of cash received by the Trustee during a calendar month attributable to the Royalty, any reduction in cash reserves and any other cash receipts of the Trust, including interest, reduced by the sum of liabilities paid and any increase in cash reserves. If the Monthly Distribution Amount for any monthly period is a negative number, then the distribution will be zero for such month and such negative amount will be carried forward and deducted from future monthly distributions until the cumulative distribution calculation becomes a positive number, at which time a distribution will be made. Unit holders of record will be entitled to receive the calculated Monthly Distribution Amount for each month on or before 10 business days after the monthly record date, which is generally the last business day of each calendar month. The cash received by the Trustee consists of the proceeds received by the owner of the Underlying Properties from the sale of production less the sum of applicable taxes, accrued production costs, development and drilling costs, operating charges and other costs and deductions, multiplied by 75%. The initial carrying value of the Royalty ($133,275,528) represented Southland’s historical net book value at the date of the transfer of the Trust. Accumulated amortization as of December 31, 2005 and 2004 aggregated $109,394,034 and $106,600,707, respectively. 3. B A S I S O F A C C O U N T I N G The financial statements of the Trust are prepared on the following basis: · Royalty Income (as defined in the Glossary of Terms) recorded for a month is the amount computed and paid by the owner of the Underlying Properties, Burlington Resources Oil & Gas Company LP (“BROG”), the present owner of the Underlying Properties, to the Trustee for the Trust. Royalty Income consists of the proceeds received by BROG from the sale of production less accrued production costs, development and drilling costs, applicable taxes, operating charges, and other costs and deductions, multiplied by 75%. The calculation of net proceeds by BROG for any month includes adjustments to proceeds and costs for prior months and impacts the Royalty Income paid to the Trust and the distribution to Unit holders for that month. · Trust expenses recorded are based on liabilities paid and cash reserves established from Royalty Income for liabilities and contingencies. · Distributions to Unit holders are recorded when declared by the Trustee. · The conveyance which transferred the Royalty to the Trust provides that any excess of production costs applicable to the Underlying Properties over gross proceeds from such properties must be recovered from future net proceeds before Royalty Income is again paid to the Trust. The Financial Statements of the Trust differ from Financial Statements prepared in accordance with United States generally accepted accounting principles (“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 These Financial Statements should be read in conjunction with the accompanying Notes to Financial Statements included herein.

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N O T E S T O F I N A N C I A L S T A T E M E N T S a unit-of-production basis is charged directly to trust corpus instead of an expense. The basis of accounting used by the Trust is widely used by royalty trusts for financial purposes. 4. Fe d e r a l In c o me Ta xe s 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. The Royalty constitutes an “economic interest” in oil and gas properties for federal income tax purposes. Unit holders must report their share of the 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 coal seam wells drilled prior to January 1, 1993, qualified for federal income tax credits under Section 29 of the Internal Revenue Code of 1986, as amended, through 2002, but not thereafter. Accordingly, under present law, the Trust’s production of gas from coal seam wells does not qualify for the Section 29 tax credit. Congress has at various times since 2002 considered energy legislation, including provisions to reinstate the Section 29 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. Most recently, for example, on August 8, 2005, new energy tax legislation was enacted which, among other things, modifies the Section 29 credit in several respects, but does not extend the credit for production from coal seam wells. No prediction can be made as to what future tax legislation affecting Section 29 may be proposed or enacted or, if enacted, its impact, if any, on the Trust and the Unit holders. 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 and will not reduce passive losses. 5. C E R T A I N C O N T R A C T S BROG previously entered into two contracts for the sale of all volumes of gas produced from the Underlying Properties providing for (i) the sale of such gas to Duke Energy and Marketing L.L.C. and PNM Gas Services, respectively, (ii) the delivery of such gas at various delivery points through March 31, 2005, and from year-to-year thereafter until terminated by either party on 12 months’ notice, and (iii) the sale of such gas at prices which fluctuate in accordance with published indices for gas sold in the San Juan Basin of northwestern New Mexico. Effective January 1, 2004, the rights and obligations of Duke Energy and Marketing L.L.C. were assumed by ConocoPhillips Company (“ConocoPhillips”) pursuant to an Assignment and Novation Agreement. By correspondence dated March 25, 2004, BROG notified ConocoPhillips of BROG’s election to terminate such contract as of March 31, 2005. BROG then prepared a form of

request for proposal and circulated it to a number of potential purchasers, including ConocoPhillips, inviting them to bid for the purchase of the gas currently sold under the contract expiring March 31, 2005. Effective as of April 1, 2005, BROG entered into two new contracts for the sale of all volumes of gas produced from the Underlying Properties and formerly sold to ConocoPhillips. These new contracts provide for (i) the sale of such gas to ChevronTexaco Natural Gas, a division of Chevron U.S.A. Inc. and Coral Energy Resources, L.P., respectively, (ii) the delivery of such gas at various delivery points through March 31, 2007, and from year-to-year thereafter until terminated by either party on 12 months’ notice, and (iii) 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. With respect to BROG’s contract with PNM Gas Services, BROG and PNM Gas Services have entered into a letter agreement dated January 31, 2005, pursuant to which the parties waive the right to terminate the underlying contract as of March 31, 2006, so that the term of that contract will continue until at least March 31, 2007, and from year-to-year thereafter until terminated by either party upon 12 months’ notice to the other. Confidentiality agreements with 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. 6. S I G N I F I C A N T C U S T O M E R S Information as to significant purchasers of oil and gas production attributable to the Trust’s economic interests is

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N O T E S T O F I N A N C I A L S T A T E M E N T S included in Note 5 above and Item 2 of the Trust’s Annual Report on Form 10-K which is included in this report. 7. S E T T L E M E N T S A N D L I T I G A T I O N As part of a settlement between BROG and the Mineral Management Service of the United States Department of the Interior, $901,776 was deducted from the Trust’s April 2003 royalty payment. This represents the Trust’s 75% interest of the total settlement. The Trust reviewed the propriety of this deduction with its consultants and it became one of the issues submitted to the arbitration described below in this Note 7. During 2004, an aggregate of $3,314,808 was included in calculating net proceeds paid to the Trust by BROG as part of the ongoing negotiation of joint interest audit exceptions, interest for resolved audit exceptions, and insurance proceeds for a business interruption claim. In 2005, as part of the ongoing negotiations between the Trust and BROG concerning a number of revenue and expense audit issues, an aggregate of $2,405,486 was included in calculating net proceeds BROG paid to the Trust in settlement of certain of those audit issues. On November 11, 2005, an Arbitration Award was issued in favor of the Trust in the aggregate amount of $7,683,699 in arbitration styled San Juan Basin Royalty Trust vs. Burlington Resources Oil & Gas Company LP. The purpose of the arbitration was to resolve certain joint interest audit issues as between the parties to the arbitration. On November 21, 2005,

BROG filed its Original Petition to Vacate or to Modify or Correct Arbitration Award in the cause styled Burlington Resources Oil & Gas Company LP vs. San Juan Basin Royalty Trust, No. 2005-74370, in the District Court of Harris County, Texas, 281st Judicial District. In this litigation, BROG alleges that the award in favor of the Trust should be vacated or modified because one of the issues decided was beyond the scope of the matters agreed to be arbitrated, the award was issued in manifest disregard of applicable law, and a portion of the award is barred by limitations. BROG also seeks to recover its attorneys’ fees. The Trust has filed an answer and counterclaim in the litigation filed by BROG denying those allegations and asking that the arbitrator’s award be confirmed. 8. P R O V E D O I L A N D G A S R E S E R V E S ( U N A U D I T E D ) Proved oil and gas reserve information is included in Item 2 of the Trust’s Annual Report on Form 10-K which is included in this report. 9. Q U A R T E R L Y S C H E D U L E O F D I S T R I B U T A B L E I N C O M E ( U N A U D I T E D ) The following is a summary of the unaudited quarterly schedule of Distributable Income for the two years ended December 31, 2005 (in thousands, except unit amounts): DISTRIBUTABLE ROYALTY DISTRIBUTABLE INCOME AND INCOME INCOME DISTRIBUTION PER UNIT First Quarter $ 39,242 $ 38,736 $ .831092 Second Quarter 35,296 34,519 .740612 Third Quarter 32,833 32,292 .692829 Fourth Quarter 46,487 46,013 .987214 T O T A L $ 153,858 $ 151,560 $ 3.251747 First Quarter $ 21,196 $ 20,692 $ .443948 Second Quarter 25,509 24,992 .536204 Third Quarter 34,674 34,402 .738093 Fourth Quarter 29,663 29,305 .628753 T O T A L $ 111,042 $ 109,391 $ 2.346998 2005 2004

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W E H AV E AU DI TED TH E AC C OMPA N Y I NG STATEMEN TS of assets, liabilities and trust corpus of the San Juan Basin Royalty Trust as of December 31, 2005 and 2004 and the related statements of Distributable Income and changes in trust corpus for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As described in Note 3 to the financial statements, these financial statements were prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles. In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust corpus of the San Juan Basin Royalty Trust as of December 31, 2005 and 2004 and the Distributable Income and changes in trust corpus for each of the three years in the period ended December 31, 2005, on the basis of accounting described in Note 3 to the financial statements. We have also audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 10, 2006, expressed an unqualified opinion thereon. W EAVER AND T IDWELL , L.L.P. Fort Worth, Texas March 10, 2006

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R E P O R T O F I N D E P E N D E N T R E G I S T E R E D P U B L I C A C C O U N T I N G F I R M G L O S S A R Y O F T E R M S A GGREGATE M ONTHLY D ISTRIBUTION : An amount paid to Unit holders equal to the Royalty Income received by the Trustee during a calendar month plus interest, less the general and administrative expenses of the Trust, adjusted by any changes in cash reserves. BBL: Barrel, generally 42 U.S. gallons measured at 60°F. BCF: Billion cubic feet. BROG: Burlington Resources Oil & Gas Company LP. BTU: British thermal unit; the amount of heat necessary to raise the temperature of one pound of water one degree Fahrenheit. C OAL S EAM W ELL : A well completed to a coal deposit found to contain and emit natural gas. C OMMINGLED W ELL : A well which produces from two or more

formations through a common well casing and a single tubing string. C ONVENTIONAL W ELL : A well completed to a formation historically found to contain deposits of oil or gas (for example, in the San Juan Basin, the Pictured Cliffs, Dakota and Mesaverde formations) and operated in the conventional manner. D EPLETION : The exhaustion of a petroleum reservoir; the reduction in value of a wasting asset by removing minerals; for tax purposes, the removal and sale of minerals from a mineral deposit. D ISTRIBUTABLE I NCOME : An amount paid to Unit holders equal to the Royalty Income received by the Trustee during a given period plus interest, less the general and administrative expenses of the Trust, adjusted by any changes in cash reserves. D UAL C OMPLETION : The completion of a well into two separate producing formations at different depths, generally through one string of pipe producing from one of the formations, inside of which is a smaller string of pipe producing from the other formation. E STIMATED F UTURE N ET R EVENUES : An estimate computed by applying current prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements and allowed by Federal regulation) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, and assuming continuation of existing economic conditions; sometimes referred to as “estimated future net cash flows.” G RANTOR T RUST : A trust (or portion thereof) with respect to which the grantor or an assignee of the grantor, rather than the trust, is treated as the owner of the trust properties and is taxed directly on the trust income for federal income tax purposes under Sections 671 through 679 of the Internal Revenue Code. G ROSS A CRES O R W ELLS : The interests of all persons owning interests in such acres or wells. G ROSS P ROCEEDS : The amount received by BROG (or any subsequent owner of the Underlying Properties) from the sale of the production attributable to such interests. I NFILL D RILLING : The drilling of wells intended to be completed to proven reservoirs or formations, sometimes occurring in conjunction with regulatory approval for increased density in the spacing of wells. L EASE O PERATING E XPENSES : Expenses incurred in the operation of a producing property as apportioned among the several parties in interest. MCF: 1,000 cubic feet; the standard unit for measuring the volume of natural gas. MMBTU: One million British thermal units. M ULTIPLE C OMPLETION W ELL : A well which produces simultaneously through separate tubing strings from two or more producing horizons or alternatively from each. N ET A CRES OR W ELLS : The interests of BROG in such acres or wells. N ET O VERRIDING R OYALTY I NTEREST : A share of gross production from a property, measured by net profits from operation of the property and carved out of the working interest, i.e., a net profits interest. N ET P ROCEEDS : The excess of Gross Proceeds received by BROG during a particular period over Production Costs for such period. P AYADD : Completion in an existing well of additional productive zone(s) within a producing formation. P RESENT V ALUE O F E STIMATED F UTURE N ET R EVENUES : The present value of the Estimated Future Net Revenues computed using a discount rate of 10%. P RODUCTION C OSTS : Costs incurred on an accrual basis by BROG in operating the Underlying Properties, including both capital and noncapital costs and including, for example, development drilling, production and processing costs, applicable taxes and operating charges. P ROVED D EVELOPED R ESERVES : Those Proved Reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. P ROVED RESERVES : Those estimated quantities of crude oil, natural gas and natural gas liquids, which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions. P ROVED U NDEVELOPED R ESERVES : Those Proved Reserves which are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. R ECAVITATED W ELL : A coal seam well, the production from which has been enhanced or extended by the enlargement of the cavity within the coal deposit to which the well has been completed. R ECOMPLETED W ELL : A well completed by drilling a separate well bore from an existing casing in order to reach the same reservoir, or re-drilling the same well bore to reach a new reservoir after production from the original reservoir has been abandoned. R OYALTY : The principal asset of the Trust; the 75% net overriding royalty interest conveyed to the Trust on November 3, 1980, by Southland Royalty Company, the predecessor to BROG, which was carved out of the Underlying Properties. R OYALTY I NCOME : The monthly Net Proceeds attributable to the Royalty. S ECTION 29 T AX C REDIT : A federal income tax credit available under Section 29 of the Internal Revenue Code for producing coal seam gas (and other nonconventional fuels) from wells drilled prior to January 1, 1993, to a formation beneath a qualifying coal seam formation, and for production sold before 2003 from wells drilled after December 31, 1979, but prior to January 1, 1993, which are later completed into such a formation. S POT P RICE : The price paid for gas, oil or oil products sold under contracts for the purchase and sale of such minerals on a shortterm basis. U NDERLYING P ROPERTIES : The working, royalty and other interests owned by Southland Royalty Company, the predecessor to BROG, in properties located in the San Juan Basin of northwestern New Mexico, out of which the Royalty was carved. U NITS OF B ENEFICIAL I NTEREST : The units of ownership of the Trust, equal to the number of shares of common stock of Southland Royalty Company outstanding at the close of business on November 3, 1980. W ORKING I NTEREST : The operating interest under an oil and gas lease. S A N J U A N B A S I N R O Y A L T Y T R U S T TexasBank, Trustee 2525 Ridgmar Boulevard, Suite 100 Fort Worth, Texas 76116 Toll-free telephone: 866.809.4553 www.sjbrt.com sjt@texasbank.com A U D I T O R S Weaver and Tidwell, L.L.P. Fort Worth, Texas L E G A L C O U N S E L Vinson & Elkins L.L.P. Dallas, Texas T A X C O U N S E L Winstead, Sechrest & Minick, PC Houston, Texas T R A N S F E R A G E N T Computershare Investor Services Transfer Services P.O. Box A3480 Chicago, Illinois 60609-3480

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S A N J U A N B A S I N R O Y A L T Y T R U S T TexasBank, Trustee 2525 Ridgmar Boulevard, Suite 100 Fort Worth, Texas 76116 Toll-free telephone: 866.809.4553 www.sjbrt.com sjt@texasbank.com O N T H E C O V E R : Kiva interior, Mesa Verde National Park.