UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

or

Commission File No. 001-08032

San Juan Basin Royalty Trust

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

(866) 809-4553

(Registrant’s telephone number, including area code)

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

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

None

(Title of Class)

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

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

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  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☐    No  ☐

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ☐    No  ☒

Aggregate market value of the Units of Beneficial Interest held by non-affiliates of the registrant as of June 30, 2017: $317,269,701.

At March 16, 2018 there were 46,608,796 Units of Beneficial Interest of the registrant outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None.

Information Regarding Forward-Looking Statements

Certain information included in this Annual Report on Form 10-K contains, and other materials filed or to be filed by the San Juan Basin Royalty Trust (the “Trust”) with the Securities and Exchange Commission (the “SEC”) (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 within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and Section 27A of the Securities Act of 1933, as amended (the “Securities Act”). 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 are based on certain assumptions of Compass Bank, the trustee of the trust (the “Trustee”), and certain assumptions of information provided to the Trust by Hilcorp San Juan L.P. (“Hilcorp”), the owner of the Subject Interests (as defined herein); are based on an assessment of, and are subject to, a variety of factors deemed relevant by the Trustee and Hilcorp; and involve risks and uncertainties. However, whether actual results and developments will conform with such expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in Item 1A of Part I of this Annual Report, which could affect the future results of the energy industry in general, and the Trust and Hilcorp in particular, and could cause those results to differ materially from those expressed in such forward-looking statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on Hilcorp’s business and the Trust. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. The Trust undertakes no obligation to publicly update or revise any forward-looking statements, except as required by applicable law.

Hilcorp Information

As a holder of a net overriding royalty interest, the Trust relies on Hilcorp for information regarding Hilcorp and its affiliates; the Subject Interests, including the operations, acreage, well and completion count, working interests, production volumes, sales revenues, capital expenditures, operating expenses, reserves, drilling plans, drilling results and leasehold terms related to the Subject Interests; and factors and circumstances that have or may affect the foregoing. See Part II, Item 9A Controls and Procedures.

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following defined terms, certain of which have been adopted by the SEC and the Financial Accounting Standards Board are used within this Annual Report on Form 10-K:

Bbl: Barrel, generally 42 U.S. gallons measured at 60 degrees Fahrenheit.

Bbls/d: Barrels per day.

Bcf: Billion cubic feet.

Btu: British thermal unit; the amount of heat necessary to raise the temperature of one pound of water one degree Fahrenheit.

Coal Seam Well: A well completed to a coal deposit found to contain and emit natural gas.

Conventional Well: A well completed to a formation historically found to contain deposits of oil or natural gas (for example, in the San Juan Basin, the Pictured Cliffs, Dakota and Mesaverde formations) and operated in the conventional manner.

Developed Oil and Natural Gas Reserves: Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. See 17 CFR 210.4-10(a)(6).

Distributable Income: An amount paid to Unit Holders equal to the Royalty Income received by the Trustee during a given period plus interest, less the expenses and payment of liabilities of the Trust, adjusted by any changes in cash reserves.

Estimated future net revenues: Computed by applying current oil and natural gas prices (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 natural 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. See 17 CFR 210.4-10(c)(4)(A). “Estimated future net revenues” are sometimes referred to in this Annual Report on Form 10-K as “estimated future net cash flows.”

GAAP: United States generally accepted accounting principles.

Grantor Trust: 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 of 1986, as amended.

Henry Hub: Henry Hub index.

Horizontal Well: A well that begins as a vertical or inclined linear bore, which extends from the surface to a subsurface location just above the target oil or natural gas reservoir, then bears off to intersect the reservoir and, thereafter, continues at a near-horizontal altitude to substantially or entirely remain within the reservoir until the desired bottom hole location is reached.

Infill Drilling: 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.

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Lease Operating Expenses: Expenses incurred in the operation of a producing property as apportioned among the several parties in interest.

Mcf: Thousand cubic feet.

Mcf/d: Thousand cubic feet per day.

MMBtu: Million British thermal units.

MMcf: Million cubic feet.

Multiple Completion Well: A well which produces simultaneously, with or without separate tubing strings, from two or more producing horizons or alternatively from each.

Net Overriding Royalty Interest: 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.

Natural Gas Liquids (NGL): Those hydrocarbons that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants.

Present value of estimated future net revenues: Computed using the estimated future net revenues (as defined above) and a discount rate of 10%. See 17 CFR 210.4-10(c)(4)(A).

Proved developed reserves: Proved natural gas and oil reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

Proved natural gas and oil reserves: Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. See 17 CFR 210.4-10(a)(22).

Proved undeveloped reserves (PUDs): Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are schedule to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Reasonable certainty: (i) If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered or (ii) if probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased

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availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease. See 17 CFR 210.4-10(a)(24).

Reserves: Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project. See 17 CFR 210.4-10(a)(26).

Undeveloped oil and natural gas reserves: Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. See 17 CFR 210.4-10(a)(31).

Working Interest: The operating interest under an oil and natural gas lease.

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PART I

The Trust is an express trust created under the laws of the State of Texas by the San Juan Basin Royalty Trust Indenture entered into on November 1, 1980, between Southland Royalty Company (“Southland”) and The Fort Worth National Bank. Effective as of September 30, 2002, the original indenture was amended and restated and, effective as of December 12, 2007, the restated indenture was amended and restated, which we refer to as the “Indenture.” As a result of a series of mergers and other transactions, the current Trustee of the Trust is Compass Bank (the “Trustee”), which is a wholly-owned subsidiary of Banco Bilbao Vizcaya Argentaria, S.A.

The Conveyance and the Royalty

Pursuant to the Net Overriding Royalty Conveyance (the “Conveyance”) effective November 1, 1980, Southland conveyed to the Trust a 75% net overriding royalty interest (the “Royalty”) that burdens certain of Southland’s oil and natural gas interests (the “Subject Interests”) in properties located in the San Juan Basin of northwestern New Mexico. Subsequent to the Conveyance of the Royalty, through a series of sales, assignments and mergers, Southland’s successor became Hilcorp San Juan L.P. (“Hilcorp”), which acquired the Subject Interests from Burlington Resources Oil & Gas Company LP (“Burlington”), an indirect wholly-owned subsidiary of ConocoPhillips on July 31, 2017. The Royalty functions generally as a net profits interest. Under the terms of the Conveyance, the Trust receives 75% of net proceeds from the Subject Interests. The term “net proceeds,” as used in the Conveyance, means the excess of gross proceeds received by Hilcorp during a particular period over production costs for such period. “Gross proceeds” means the amount received by Hilcorp (or any subsequent owner of the Subject Interests) from the sale of the production attributable to the Subject Interests, subject to certain adjustments. “Production costs” generally means costs incurred on an accrual basis by Burlington/Hilcorp in operating the Subject Interests, including both capital and non-capital costs. For example, these costs include development drilling, production and processing costs, applicable taxes and operating charges. However, Hilcorp informed the Trust that, for wells operated by Hilcorp, it generally did not intend to accrue lease operating expenses to the Trust. If production costs exceed gross proceeds in any month, the excess is recovered out of future gross proceeds prior to the making of further payment to the Trust, but the Trust is not otherwise liable for any production costs or other costs or liabilities attributable to the Subject Interests or the minerals produced therefrom. If at any time the Trust receives more than the amount due under the Royalty, it is not obligated to return such overpayment, but the amounts payable to it for any subsequent period are reduced by such amount, plus interest, at a rate specified in the Conveyance.

The Royalty constitutes the principal asset of the Trust. The beneficial interest in the Royalty is divided into 46,608,796 units (the “Units”) representing undivided fractional interests in the beneficial interest of the Trust equal to the number of shares of the common stock of Southland outstanding as of the close of business on November 3, 1980. Each stockholder of Southland 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 then held. Holders of Units are referred to herein as “Unit Holders.”

As of December 31, 2017, 97% of the Trust’s estimated proved reserves consisted of natural gas reserves, and 86%⁽¹⁾ of the gross proceeds from the Subject Interests in 2017 were attributable to the production and sale of natural gas by Burlington and Hilcorp as well as other proceeds. Accordingly, the market price for natural gas produced and sold from the San Juan Basin heavily influences the amount of Trust income available for distribution to the Unit Holders by the Trust and, by extension, the price of the Units. Normally there is greater demand for natural gas used for heating or air conditioning purposes in the summer and winter months than during the rest of the year.

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The Trustee

The primary 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 to distribute the remaining available income to the Unit Holders. The Trust received approximately $33.2 million, $16.8 million and $19.4 million in Royalty Income from Hilcorp and Burlington in each of the fiscal years ended December 31, 2017, 2016 and 2015, respectively. After deducting administrative expenses and accounting for interest income and any change in cash reserves, the Trust distributed approximately $39.1 million, $13.9 million and $17.0 million to Unit Holders in each of the fiscal years ended December 31, 2017, 2016 and 2015, respectively. The Trust’s corpus was approximately $6.6 million, $7.8 million and $8.7 million as of December 31, 2017, 2016 and 2015, respectively.

Proceeds from production in the first month are generally received by Hilcorp in the second month, the net proceeds attributable to the Royalty are paid by Hilcorp to the Trustee in the third month, and distribution by the Trustee to the Unit Holders is made in the fourth month. Unit Holders of record as of the last business day of each month (the “monthly record date”) will be entitled to receive the calculated monthly distribution amount for such month on or before ten business days after the monthly record date. The amount of each monthly distribution will generally be determined and announced ten days before the monthly record date. The aggregate monthly distribution amount is the excess of (i) the net proceeds attributable to the Royalty paid to the Trustee, plus any decrease in cash reserves previously established for liabilities and contingencies of the Trust, over (ii) the expenses and payments of liabilities of the Trust, plus any net increase in cash reserves.

The Trustee may, in its sole discretion, establish a cash reserve for payment of Trust liabilities that are contingent or uncertain or otherwise not currently due and payable. As of December 31, 2017, the Trustee had established cash reserves of $1.0 million. The Trustee does not anticipate any further increases to the cash reserves in 2018.

Cash being held by the Trustee as cash reserves or pending distribution may be placed, in the Trustee’s discretion, in obligations issued by (or unconditionally guaranteed by) the United States or any agency thereof, repurchase agreements secured by obligations issued by the United States or any agency thereof, certificates of deposit of banks having capital, surplus and undivided profits in excess of $50 million or money market funds that have been rated at least AAm by Standard & Poor’s and at least Aa by Moody’s, subject, in each case, to certain other qualifying conditions. Currently, such funds are placed in interest-bearing negotiable order of withdrawal accounts whose funds are either insured by the Federal Deposit Insurance Corporation or secured by other assets of Compass Bank.

The other powers and duties of the Trustee are set forth in the Indenture and include the prosecution and defense of claims by and against the Trust, the engagement of consultants and professionals and the payment of Trust liabilities. If the Trustee determines that the Trust does not have sufficient funds to pay its liabilities, the Trustee may borrow funds on behalf of the Trust, in which case no distributions will be made to Unit Holders until such borrowings are repaid in full. The Trustee may not sell or dispose of any part of the assets of the trust without the affirmative vote from the Unit Holders of 75% of all of the Units outstanding; however, the Trustee may sell up to 1% of the value of the Royalty (as determined pursuant to the Indenture) during any 12-month period without the consent of the Unit Holders if it determines such a sale is in the best interest of the Unit Holders. The Trust does not operate the Subject Interests and 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.

Under the Indenture, the Trustee may act in its discretion in carrying out its powers and performing its duties and is liable only for fraud or for acts and omissions in bad faith. The Trustee is not liable for any act or omission of its agents or employees unless the Trustee acted in bad faith in its selection and retention of such agents or employees. The Indenture provides that the Trustee and its officers, agents and employees must be

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indemnified and receive reimbursement of expenses from the assets of the Trust for liabilities and claims incurred in the administration of the Trust, except for liabilities and claims arising from the Trustee’s fraud or bad faith.

Duration of the Trust

The Trust will terminate if (a) its gross revenue for each of two successive years is less than $1 million per year or, if earlier, (b) the Unit Holders of at least 75% of all of the Units outstanding vote in favor of termination. Upon termination of the Trust, the Trustee must sell the Royalty and distribute the proceeds to Unit Holders after satisfying or establishing reserves to satisfy the liabilities of the Trust.

Hilcorp

The sale of San Juan Basin assets from Burlington to Hilcorp closed on July 31, 2017. Hilcorp is the operator of the majority of the Subject Interests. As an operator, Hilcorp has the obligation under the Conveyance to conduct its operations in accordance with reasonable and prudent business judgment and good oil and natural gas field practices. Hilcorp has the right to abandon any well when, in its opinion, such well ceases to produce or is not capable of producing oil and natural gas in paying quantities. Hilcorp reserves the right to not participate in operations on the Subject Interests when it has a right to do so under the applicable operating or similar agreement. Hilcorp also is responsible, subject to the terms of an agreement with the Trust, for marketing the production from such properties, either under existing sales contracts or under future arrangements, at the best prices and on the best terms it shall deem reasonably obtainable in the circumstances. Additionally, Hilcorp is obligated under the Conveyance to maintain books and records sufficient to determine the amounts payable to the Trustee.

Additional Information

The principal office of the Trust is located at 300 West 7^th Street, Suite B, Fort Worth, Texas 76102 (toll-free telephone number (866) 809-4553). The Trust makes available (free of charge) its annual, quarterly and current reports (and any amendments thereto) filed with the SEC through its website at www.sjbrt.com as soon as reasonably practicable after electronically filing or furnishing such material with or to the SEC. The Trust’s materials filed with the SEC are also available at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549 or by calling the Public Reference Room of the SEC at 1-800-SEC-0330. The SEC also maintains the internet site of www.sec.gov. This site contains reports and, as applicable, proxy and information statements, and other information regarding the Trust and other issuers that file electronically with the SEC.

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, 300 West 7^th Street, Suite B, Fort Worth, Texas 76102 (toll-free telephone number (866) 809-4553, email address: sjt.us@bbva.com), 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 tax information is generally posted by the Trustee on the Trust’s website: www.sjbrt.com.

Described below are certain risks that we believe are associated with an investment in the Units of the Trust and the oil and natural gas industry. There may be additional risks that are not presently material or known to us. You should carefully consider each of the following risks and all other information set forth in this Annual Report on Form 10-K. If any of the events described below occur, our financial condition could be materially adversely affected.

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Oil and natural gas prices fluctuate due to a number of factors, and lower prices will reduce net proceeds to the Trust and distributions to Unit Holders.

The Trust’s monthly distributions are highly dependent upon the prices realized from the sale of natural gas and, to a lesser extent, oil. Oil and natural gas prices can fluctuate widely in response to a variety of factors that are beyond the control of the Trust and Hilcorp. Factors that contribute to price fluctuation include, among others:

Moreover, government regulations, such as regulation of natural gas transportation and price controls, can affect product prices in the long term. These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2017, the price of natural gas and oil for production from the Subject Interests increased 41.8% from an average price for natural gas of $1.89 per Mcf in 2016 to $2.68 per Mcf in 2017, and the price for oil increased 19.1% from an average price of $30.01 per Bbl in 2016 to $35.75 per Bbl in 2017. As a result of generally low oil and gas pricing, certain wells have become less economical and, as a result, Burlington and Hilcorp reduced production from the Subject Interests. Natural gas production from the Subject Interests decreased 7.9% from 28,003,159 Mcf in 2016 to 25,779,802 Mcf in 2017. See Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations.

Lower oil and natural gas prices will reduce proceeds to which the Trust is entitled and may ultimately reduce the amount of oil and natural gas that is economic to produce from the Subject Interests. As a result, Hilcorp or any third-party operator of any of the Subject Interests could determine during periods of low oil and natural gas prices to shut in or curtail production from wells on the Subject Interests. In addition, the operator of the Subject Interests could determine during periods of low oil and natural gas prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, Hilcorp or any third-party operator may abandon any well or property if it reasonably believes that the well or property can no longer produce oil and natural gas in commercially economic quantities. This could result in termination of the portion of the royalty interests relating to the abandoned well or property, and Hilcorp would have no obligation to drill a replacement well.

Hilcorp has informed us that it has not and does not intend to enter into derivative contracts or other hedging contracts with respect to the sale of production from the Subject Interests. Absent such arrangements, the revenue received from such production will be subject to market prices.

Hilcorp completed its acquisition of the Subject Interests from ConocoPhillips, which may result in certain administrative disruptions for the Trust, may increase costs and expenses or may adversely affect Distributable Income.

Burlington, a wholly-owned subsidiary of ConocoPhillips, was the principal operator of the Subject Interests until July 31, 2017, when Hilcorp announced that it completed its acquisition of the Subject Interests from

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ConocoPhillips. As a result of this acquisition, Hilcorp replaced Burlington as the principal operator of the Subject Interests. Although Hilcorp has assumed Burlington’s obligations with respect to the Subject Interests, the Hilcorp acquisition may not necessarily be in the best interests of the Trust and the Unit Holders. The Subject Interests remain to be subject to the Royalty following the Hilcorp transaction, but the Distributable Income will now be calculated and paid by Hilcorp. The Trust is in the process of transitioning certain reporting processes and procedures to Hilcorp, which could result in administrative disruptions for the Trust. Hilcorp may lack Burlington’s experience in the Subject Interests or its creditworthiness. Furthermore, the Hilcorp acquisition may increase the Trust’s general and administrative expenses in the form of increased accounting, audit, legal, and administrative costs. Hilcorp may also increase the budget for capital expenditures for the Subject Interests, which may adversely affect Distributable Income. Hilcorp’s reporting of revenue and expenses may differ from ConocoPhillips’ reporting.

Due to the transition from Burlington, Hilcorp has estimated certain revenue and expense numbers, which may adversely affect final Distributable Income.

The sale of San Juan Basin assets, including the Subject Interests, from Burlington to Hilcorp closed on July 31, 2017. Hilcorp assumed responsibility for monthly production beginning August 1, 2017. ConocoPhillips informed the Trust that the last production month for which ConocoPhillips was responsible was July 2017 and therefore the last monthly distribution report that the Trust received from ConocoPhillips was for September 2017. In October 2017, the Trust received the distribution report from Hilcorp.

Hilcorp informed the Trust that, due to the transition from Burlington, Hilcorp did not have all of the revenue and expense decks installed and did not have the appropriate detail to provide actual revenue and expense numbers. Therefore, Hilcorp estimated the October, November and December 2017 distributions based on the July 2017 production month (September 2017 distribution month) previously provided by Burlington and rounded to the nearest thousand. The October, November and December 2017 declarations of cash distribution each included an additional $1.0 million in estimated gross revenue based on Hilcorp’s knowledge that production volumes increased. Hilcorp has indicated that it may need to estimate revenue for subsequent distributions in 2018.

Distributions for November and December 2017 reflect actual expenses for the months of September and October 2017, although severance taxes continued to be estimated. The December 2017 declaration of cash distribution included a true-up of the actual versus previously estimated expense numbers for the August 2017 production month. Hilcorp will reconcile estimated versus actual revenue numbers once Hilcorp finalizes installation of its revenue decks, although Hilcorp has not indicated when such reconciliation may occur. Such estimations and reconciliations by Hilcorp will be credited or debited from future distributions to Unit Holders. The accounting reports used to prepare the financial information for January – September 2017 were provided by Burlington, and accounting reports for the months of October – December 2017 were provided by Hilcorp.

Increased costs of production and development will result in decreased Trust distributions.

Production and development costs attributable to the Subject Interests are deducted in the calculation of net proceeds. Accordingly, higher production and development costs, without concurrent increases in revenues, decrease the share of net proceeds paid to the Trust as Royalty Income.

If development and production costs of the Subject Interests exceed the proceeds of production from the Subject Interests, such excess costs are carried forward and the Trust will not receive a share of net proceeds for the Subject Interests until future net proceeds from production from such properties exceed the total of the excess costs. Development activities may not generate sufficient additional revenue to repay the costs; however, the Trust is not obligated to repay the excess costs except through future production.

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Trust reserve estimates depend on many assumptions that may prove to be inaccurate, which could cause both estimated reserves and estimated future revenues to be too high.

The value of the Units of the Trust depends upon, among other things, the amount of reserves attributable to the Royalty and the estimated future value of the reserves. Estimating reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the Subject Interests will vary from estimates and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating reserves. Those factors and assumptions may include:

Changes in these assumptions may materially change reserve estimates. Our estimate of proved natural gas reserves increased from 78,739 MMcf to 97,764 MMcf, as of December 31, 2016 and 2017, respectively, an increase of 19,025 MMcf, or approximately 24%. The discounted future net cash flows related to future Royalty Income from our proved reserves increased from $93.5 million to $137 million, as of December 31, 2016 and 2017, respectively, an increase of approximately $43.5 million, or 46.5%. For more information regarding our proved reserves, see Item 2. Properties – Oil and Natural Gas Reserves and Item 8. Financial Statements and Supplementary Data, Note 9.

The reserve data included herein are estimates only and are subject to many uncertainties. Actual quantities of oil and natural gas may differ considerably from the amounts set forth herein. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data.

The future financial condition of operators of the Subject Interests could impede the operation of wells.

The value of the Royalty and the Trust’s ultimate cash available for distribution is highly dependent on the financial condition of the operator of the wells. Neither Hilcorp nor any of the other operators of the Subject Interests has agreed with the Trust to maintain a certain net worth or to be restricted by other similar covenants.

The ability to operate the Subject Interests depends on all operators’ future financial condition and economic performance and access to capital, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of such operators.

In the event of the bankruptcy of any operator of the Subject Interests, the working interest owners in the affected properties, creditors or the debtor-in-possession would have to seek a new party to perform the operations of the affected wells. Hilcorp or the other working interest owners may not be able to find a replacement operator, and they may not be able to enter into a new agreement with such replacement party on favorable terms or within a reasonable period of time. As a result, such a bankruptcy may result in reduced production of reserves and decreased distributions to Unit Holders.

Production of oil and natural gas on the Subject Interests could be materially and adversely affected by severe or unseasonable weather.

Production of oil and natural gas on the Subject Interests could be materially and adversely affected by severe or unseasonable weather. Repercussions of severe weather conditions may include:

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Due to the Trust’s lack of industry and geographic diversification, adverse developments in the Trust’s existing area of operation could adversely impact its financial condition, results of operations and cash flows and reduce its ability to make distributions to the Unit Holders.

The Subject Interests are operated for oil and natural gas production and are focused exclusively in the San Juan Basin. This concentration could disproportionately expose the Trust’s interests to operational and regulatory risk in that area. Due to the lack of diversification in industry type and location of the Trust’s interests, adverse developments in the oil and natural gas markets or the area of the Subject Interests, including, for example, transportation or treatment capacity constraints, curtailment of production or treatment plant closures for scheduled maintenance, could have a significantly greater impact on the Trust’s financial condition, results of operations and cash flows than if the Royalty were more diversified.

The operators of the Subject Interests are subject to extensive governmental regulation that could affect the cost, manner and feasibility of conducting operations on the Subject Interests, which in turn could negatively impact Trust distributions, estimated and actual future net revenues to the Trust and estimates of reserves attributable to the Trust’s interests.

Oil and natural gas operations on the Subject Interests are subject to laws and regulations adopted or promulgated by federal, state and local authorities. From time to time, those requirements may require Hilcorp and other operators of the Subject Interests to incur substantial costs or restrict production. Changes in price controls, taxes and environmental laws relating to the crude oil and natural gas industry have the ability to significantly affect crude oil and natural gas production, operations and economics. We cannot always predict with certainty whether agencies or courts will change their interpretation of existing requirements, whether government authorities will adopt new requirements or the effect such changes may have on our business or financial condition.

Environmental laws, in particular, may change frequently and at times may force Hilcorp and other operators of the Subject Interests to incur additional costs as those changes are implemented, or in instances of possible non-compliance, to incur penalties. Additionally, the discharge of natural gas, crude oil, or other pollutants into the air, soil or water may give rise to substantial liabilities to government agencies and third parties, and may require Hilcorp and other operators of the Subject Interests to incur substantial costs of remediation.

Some of the complex environmental requirements to which operation of the Subject Interests may be subject include the Comprehensive Environmental Response, Compensation and Liability Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Clean Air Act, the Clean Water Act, the Endangered Species Act, the Safe Drinking Water Act, the Occupational Safety and Health Act and analogous state statutes along with regulations developed under these laws. See Item 2. Properties—Regulation.

The future course of U.S. environmental regulation is especially difficult to predict at the current time because of uncertainties about the policies of the Trump Administration. For example, the federal government may or may not continue developing regulations to reduce greenhouse gas emissions from the oil and gas industry. Even if federal environmental efforts slow, states may continue pursuing new regulations.

Any new requirements under environmental or other statutes could increase the cost to operate the Subject Interests, change the nature of such operations, delay operations or reduce the liquidity of, or otherwise negatively impact, the financial condition of Hilcorp and the other operators of the Subject Interests. Such costs, delays and changes in operations could have a material adverse effect on the operation of the Subject Interests, which in turn could negatively impact Trust distributions, estimated and actual future net revenues to the Trust and estimates of reserves attributable to the Trust’s interests.

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Operating risks for Hilcorp and other operators of the Subject Interests can adversely affect Trust distributions.

Royalty Income payable to the Trust is derived from the sale of natural gas and oil production following the gathering and processing of those minerals, which operations are subject to risk inherent in such activities. Such risks include the following, which may result in production operations being curtailed, delayed or canceled:

If anticipated production is lower due to any of the factors above or for any other reason, or if Hilcorp incurs additional operational or production costs as a result of these or other factors, the amount of Trust distributions may be significantly reduced.

None of the Trustee, the Trust nor the Unit Holders control the operation or development of the Subject Interests.

Neither the Trustee nor the Unit Holders can influence or control the operation or future development of the Subject Interests. The Subject Interests are owned by Hilcorp, which operates a majority of such properties and handles the calculation of the net proceeds attributable to the Royalty and the payment of Royalty Income to the Trust. The Subject Interests that are not operated by Hilcorp are operated by other operators, some of which may be affiliated with Hilcorp. The development of the Subject Interests is conducted pursuant to operating and similar agreements to which the Trust is not a party and under which the Trust has no control or other rights to determine the location, timing and other key aspects of development and maintenance that may materially impact results of operations.

The Royalty can be sold and the Trust can be terminated in certain circumstances.

The Trustee may sell or dispose of any part of the assets of the Trust with the affirmative vote of the Unit Holders of 75% of all of the Units outstanding, except that the Trustee may sell up to 1% of the value of the Royalty (as determined pursuant to the Indenture) during any 12-month period without the consent of the Unit Holders. The Trust does not operate the Subject Interests and is not empowered to carry on any business activity.

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The Trust will be terminated and the Trustee must sell the Royalty if holders of at least 75% of the Units approve the sale or vote to terminate the Trust, or if the Trust’s gross revenue for each of two successive years is less than $1 million per year. Any net proceeds of a sale following termination of the Trust will be distributed to the Unit Holders after satisfying or establishing reserves to satisfy the liabilities of the Trust, and Unit Holders will receive no further distributions from the Trust. We cannot assure you that any sale of Trust assets will be on terms acceptable to all Unit Holders.

Mineral properties, such as the Subject Interests, are depleting assets, and if Hilcorp or other operators of the Subject Interests do not perform additional development projects, the assets may deplete faster than expected.

The Royalty Income payable to the Trust is derived from the sale of depleting assets. The reduction in proved reserve quantities is a common measure of depletion. Future maintenance and development projects on the Subject Interests will affect the quantity of proved reserves. The timing and size of these projects will depend primarily on the market prices of natural gas. If Hilcorp does not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by the Trust. Hilcorp has no contractual obligation to the Trust to make capital expenditures on the Subject Interests in the future. Furthermore, for properties on which Hilcorp is not designated as the operator, Hilcorp has no control over the timing or amount of capital expenditures. Hilcorp has a right to not participate in the capital expenditures on properties for which it is not the operator, in which case Hilcorp and the Trust will not receive the proceeds from the sale of the production resulting from such capital expenditures. The Trust is not permitted to acquire other oil and natural gas properties or royalty interests to replace the depleting assets and production attributable to the Trust.

The amount of funds available for distribution to Unit Holders will be reduced by the amount of any cash reserves maintained by the Trustee in respect of anticipated future Trust expenses.

The Trustee is authorized to determine in its discretion the amount of cash reserves needed to pay liabilities and contingencies of the Trust. Total cash reserves were $1.0 million as of December 31, 2016 and 2017. The Trustee did not increase the cash reserves during 2017 and does not anticipate any further increases in 2018.

Unit Holders have limited voting rights.

Voting rights as a Unit Holder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Unit Holders or for an annual or other periodic re-election of the Trustee. Unlike corporations, which are generally governed by boards of directors elected by their equity holders, the Trust is administered by a corporate trustee in accordance with the Indenture and other organizational documents. The Trustee has extremely limited discretion in its administration of the Trust. If the Trustee does not take appropriate action to enforce provisions of the Conveyance, the recourse of the Unit Holders would likely be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. Unit Holders probably would not be able to sue Hilcorp or any other operator of the Subject Interests. The Indenture provides that the Trustee may only be removed and replaced by the holders of a majority of the outstanding Units, at a duly called meeting of Unit Holders. As a result, it may be difficult for public Unit Holders to remove or replace the Trustee without the cooperation of holders of a substantial percentage of the outstanding Units.

The limited liability of Unit Holders is uncertain.

The Unit Holders are not protected from the liabilities of the Trust to the same extent that a shareholder would be protected from a corporation’s liabilities. The structure of the Trust does not include the interposition of a limited liability entity such as a corporation or limited partnership which would provide further limited liability protection to Unit Holders. While the Trustee is liable for any excess liabilities incurred if the Trustee fails to

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ensure that such liabilities are to be satisfied only out of Trust assets, under the laws of Texas, which are unsettled on this point, a Unit Holder may be jointly and severally liable for any liability of the Trust if the satisfaction of such liability was not contractually limited to the assets of the Trust and the assets of the Trust and the Trustee are not adequate to satisfy such liability. As a result, Unit Holders may be exposed to personal liability. The Trust, however, is not liable for production costs or other liabilities of the Subject Interests.

Conflicts of interest could arise between Hilcorp and the Trust.

Hilcorp could have interests that conflict with the interests of the Trust and the Unit Holders. For example, Hilcorp’s interests may conflict with those of the Trust and the Unit Holders in situations involving the development, maintenance, operation or abandonment of the Subject Interests. Additionally, Hilcorp may abandon a well that is no longer producing in paying quantities even though such well is still generating revenue for the Unit Holders. Hilcorp may make decisions with respect to expenditures and decisions to allocate resources to projects in other areas that adversely affect the Subject Interests, including reducing expenditures on these properties, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future.

Hilcorp may not be adequately insured against operational hazards.

Hilcorp is not obligated to the Trust to maintain any particular types or amounts of insurance, and insurance may not be commercially available at adequate levels to cover its operational hazards at all times during the life of the Trust. If a well is damaged, Hilcorp would have no obligation to drill a replacement well or otherwise compensate the Trust for the loss. The Trust does not have insurance or indemnification to protect against losses or delays in receiving proceeds from such events.

Financial information of the Trust is not prepared in accordance with GAAP.

The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles, GAAP. Although this basis of accounting is permitted for royalty Trusts by the SEC, the financial statements of the Trust differ from GAAP financial statements because revenues are not accrued in the month of production; certain cash reserves may be established for liabilities and contingencies of the Trust 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 as an expense.

The Trust has not requested a ruling from the IRS regarding the tax treatment of the Trust. If the IRS were to determine (and be sustained in that determination) that the Trust is not a “grantor trust’’ for federal income tax purposes, the Trust could be subject to more complex and costly tax reporting requirements that could reduce the amount of cash available for distribution to Unit Holders.

If the Trust were not treated as a grantor trust for federal income tax purposes, the Trust may be properly classified as a partnership for such purposes. Although the Trust would not become subject to federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the Unit Holders, the Trust’s tax compliance requirements would be more complex and costly to implement and maintain, and its distributions to Unit Holders could be reduced as a result.

The Trustee has not requested a ruling from the U.S. Internal Revenue Service (“IRS”) regarding the tax status of the Trust, and the Trustee does not intend to request such a ruling or cannot assure you that such a ruling would be granted if requested or that the IRS will not challenge these positions on audit.

Unit Holders should be aware of the possible state tax implications of owning Units and should consult with their tax advisors.

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The recently passed comprehensive tax reform bill could adversely affect our business and financial condition.

On December 22, 2017, President Trump signed into law the budget reconciliation act commonly referred to as the “Tax Cuts and Jobs Act,” or the TCJA, that significantly changes the federal income taxation of business entities and their investors. The TCJA, among other things, reduces corporate and individual tax rates and makes a number of changes to the deductibility of certain items. In addition, many provisions in the TCJA require guidance from the Internal Revenue Service and the U.S. Treasury. Although the reduction in tax rates will benefit many shareholders, we are still evaluating the impact of the TCJA to us and our investors.

Unit Holders are required to pay taxes on their share of the Trust’s income even if they do not receive any cash distributions from the Trust.

Unit Holders are treated as if they own the Trust’s assets and receive the Trust’s income and are directly taxable thereon as if no Trust were in existence. Because the Trust generates taxable income that could be different in amount than the cash the Trust distributes, Unit Holders are required to pay any federal and applicable state income taxes and, in some cases, other state and local income taxes on their share of the Trust’s taxable income even if they receive no cash distributions from the Trust. A Unit Holder may not receive cash distributions from the Trust equal to such Unit Holder’s share of the Trust’s taxable income or even equal to the actual tax liability that results from that income.

A portion of any tax gain on the disposition of the Units could be taxed as ordinary income.

If a Unit Holder sells Units, the Unit Holder will recognize a gain or loss equal to the difference between the amount realized and the Unit Holder’s tax basis in those Units. A substantial portion of any gain recognized may be taxed as ordinary income due to potential recapture items, including depletion recapture. Potential investors should consult with their tax advisors prior to acquiring Units.

The Trust allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust Units each month based upon the ownership of the Units on the monthly record date, instead of on the basis of the date a particular Unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the Unit Holders.

The Trust generally allocates its items of income, gain, loss and deduction between transferors and transferees of the Units each month based upon the ownership of the Units on the monthly record date, instead of on the basis of the date a particular Unit is transferred. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the Trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the Unit Holders affected by the issue and result in an increase in the administrative expense of the Trust in subsequent periods.

None.

The Royalty conveyed to the Trust was carved out of Southland’s (now Hilcorp’s) working interests and royalty interests in certain properties situated in the San Juan Basin in northwestern New Mexico. See Item 1. Business, for information on the conveyance of the Royalty to the Trust. References below to “gross” wells and acres are to the interests of all persons owning interests therein, while references to “net” are to the interests of Hilcorp (from which the Royalty was carved) in such wells and acres.

Unless otherwise indicated, the following information in this Item 2 is based upon data and information furnished to the Trustee by Burlington and Hilcorp.

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The Subject Interests

The Subject Interests consist of working interests, royalty interests, overriding royalty interests and other contractual rights in 151,900 gross (119,000 net) producing acres in San Juan, Rio Arriba and Sandoval Counties of northwestern New Mexico. According to the information provided by Burlington and Hilcorp, there were, as of December 31, 2017, 4,376 gross (829.8 net) wells on the properties underlying the Subject Interests, calculated on a well bore basis and not including multiple completions as separate wells, of which approximately 980 gross (281.9 net) wells were multiple completion wells, resulting in a total of 5,430 gross (1,143.6) completions.

Hilcorp has informed the Trust that all of the subject acreage is held by production, and even though it has not been fully developed in every formation, Hilcorp has classified all of such acreage as developed. Production from conventional natural gas wells is primarily from the Pictured Cliffs, Mesaverde and Dakota formations, ranging in depth from 1,500 to 8,000 feet. Additional production is attributable to coal seam reserves in the Fruitland Coal formation.

Coal seam natural gas constituted approximately 30% of our total natural gas production during 2017 and approximately 23% of our proved natural gas reserves as of December 31, 2017. The process of removing coal seam natural 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 natural gas desorbs from the coal. The desorbed natural 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 natural gas production may increase for a period of time before starting to decline. Typically, the volumes of natural gas produced from a coal seam well decline more rapidly than those of conventional wells. In order to dispose of the formation water, surface facilities including pumping units are required. The price of coal seam natural gas is typically lower than the price of conventional natural gas. This is because the heating value of coal seam natural gas is much lower than that of conventional natural gas due to (a) ever increasing percentages of carbon dioxide in coal seam natural 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 natural gas. Furthermore, the production costs and processing fees for coal seam natural gas are typically higher than the processing fees for conventional natural gas due to the cost of extracting the carbon dioxide.

The Royalty conveyed to the Trust is limited to the base of the Dakota formation, which is currently the deepest significant producing formation under acreage affected by the Royalty. Rights to production, if any, from deeper formations are retained by Hilcorp.

2018 Capital Expenditure Budget

Hilcorp has informed the Trust that its 2018 budget for capital expenditures for the Subject Interests is estimated to be $0.54 million and that existing wells will continue to be operated.

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Oil and Natural Gas Production

Production of oil and natural gas and related average sales prices attributable to each of the Subject Interests and the Royalty for the three years ended December 31, 2017, were as follows:

Production costs for natural gas and oil attributable to the Subject Interests for the three years ended December 31, 2017 were as follows:

The Trust recognizes production during the month in which the related net proceeds attributable to the Royalty are paid to the Trust. Royalty Income for a calendar year is based on the actual natural gas and oil production during the period beginning with November of the preceding calendar year through October of the current calendar year. Sales volumes attributable to the Royalty are determined by dividing the net profits by the Trust from the sale of oil and natural gas, respectively, by the prices received for sales of such volumes from the Subject Interests, taking into consideration production taxes attributable to the Subject Interests. Because the oil and natural gas sales attributable to the Royalty are based upon an allocation formula dependent on such factors as price and cost, including capital expenditures, the aggregate sales amounts from the Subject Interests may not provide a meaningful comparison to sales attributable to the Royalty.

The fluctuations in annual natural gas production that have occurred during these three years generally resulted from changes in the demand for natural gas during that time, market conditions, and variances in capital spending to generate production from new and existing wells, as offset by the natural production decline curve. Also, production from the Subject Interests is influenced by the line pressure of the natural gas gathering systems in the San Juan Basin. As noted above, oil and natural gas sales attributable to the Royalty are based on an allocation formula dependent on many factors, including oil and natural gas prices and capital expenditures.

Marketing

Natural gas produced in the San Juan Basin is sold in both interstate and intrastate commerce. Reference is made to the discussion contained herein under “Regulation” for information as to federal regulation of prices of oil and natural gas. As part of the transition from Burlington to Hilcorp, Hilcorp has assumed, or been assigned, all the natural gas purchase, gathering and processing contracts affecting the Subject Interest. Natural gas produced from the Subject Interests is processed at the: Chaco, Val Verde, Milagro, Ignacio or Kutz plants, all located in the San Juan Basin. Hilcorp sells natural gas produced from the Subject Interests under various contracts.

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Hilcorp’s sales contracts with Shell Energy North America (US) LP (“Shell”) expires on March 31, 2018. Hilcorp and Chevron Natural Gas entered into certain replacement contracts covering those volumes beginning April 1, 2018. The replacement contracts with Chevron Natural Gas expire on March 31, 2019. Hilcorp’s sales contracts with EDF Trading North America LLC (“EDF”) automatically renewed for another year and now expires on March 31, 2019.

Hilcorp’s sales contracts with EDF, Shell and Chevron Natural Gas each provides for (i) the delivery of such natural gas at various delivery points through their respective termination dates and (ii) the sale of such natural gas at prices that fluctuate in accordance with published indices for natural gas sold in the San Juan Basin of northwestern New Mexico.

Hilcorp’s natural gas sales contract with New Mexico Gas Company, Inc. expires on March 31, 2019. The contract provides for the sale of certain winter-only natural gas supplies processed at the Kutz plant at prices that fluctuate in accordance with published indices for natural gas sold in the San Juan Basin of northwestern New Mexico.

Hilcorp contracts with Williams Four Corners, LLC (“WFC”) and Enterprise Field Services, LLC (“EFS”) for the gathering and processing of virtually all of the natural gas produced from the Subject Interests. Hilcorp’s predecessor entered into four contracts with WFC, each of which is effective for a term of 15 years commencing April 1, 2010. Hilcorp’s predecessor signed a similar agreement with EFS which was effective November 1, 2011 for a term of 15 years. Hilcorp’s predecessor has disclosed to the Trust a summary of that agreement which the Trust has reviewed with its consultants, subject to conditions of confidentiality.

The Trust is not a party to any of the purchase, gathering or processing contracts. As part of the 1996 settlement of litigation filed by the Trustee in 1992 against Burlington and Southland, the Trustee and Burlington established a formal protocol pursuant to which compliance auditors retained by the Trustee have access to Burlington and its successors’ books and records, which protocol has been adopted by Hilcorp.

Oil and Natural Gas Reserves

Proved Reserves

All of the Trust’s reserves are located in the San Juan Basin of northwestern New Mexico. Total proved developed and undeveloped oil and natural gas reserves as of December 31, 2017 were as follows:

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Estimated quantities of proved developed oil and natural gas reserves as of December 31, 2017, 2016 and 2015 were as follows:

Proved Undeveloped Reserves

Based on information provided by Burlington, Hilcorp, and analysis by our independent reserve engineer, there were no proved undeveloped reserves identified as of December 31, 2017, 2016 or 2015.

Internal Controls over Reserves Estimates

The process of estimating oil and natural gas reserves is complex and requires significant judgment. The Trust, however, does not have information that would be available to a company with oil and natural gas operations because detailed information is not generally available to owners of royalty interests. Given this, the Trustee accumulates information and data provided by Burlington and Hilcorp regarding the Royalty derived from the Subject Interests and provides such information to Cawley, Gillespie & Associates, Inc. (“CG&A”). CG&A extrapolates from such information estimates of the reserves attributable to the Subject Interests based on its expertise in the oil and natural gas fields where the Subject Interests are situated, as well as publicly available information. The Trust maintains internal controls and procedures applicable to reserve estimation which are reviewed annually and updated as required and reviews the reserve reports prepared by CG&A for reasonableness. The Trust’s internal controls and procedures regarding reserve estimates require proved reserves to be determined and disclosed in compliance with the SEC definitions and guidance.

Third-Party Reserves

The Trust does not maintain an internal petroleum engineering department and instead relies upon CG&A for a qualified, independent report of estimated reserves. The Trust verifies the qualifications and credentials of CG&A to prepare reserve estimates on behalf of the Trust. The independent petroleum engineers’ reports as to the proved oil and natural gas reserves as of December 31, 2014, 2015, 2016 and 2017 were prepared by CG&A. CG&A, whose firm registration number is F-693, was founded in 1961 and is nationally recognized in the evaluation of oil and natural gas properties. The technical person at CG&A primarily responsible for overseeing the reserve estimate with respect to the Trust is Zane Meekins. Mr. Meekins has been a practicing petroleum engineering consultant since 1989, with over 30 years of practice experience in petroleum engineering. He is a registered professional engineer in the State of Texas (License No. 71055). He graduated from Texas A&M University in 1987, summa cum laude, with a B.S. in Petroleum Engineering. CG&A and Mr. Meekins have indicated that they meet or exceed all requirements set forth in Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Regulation

General

Exploration for and production and sale of oil and natural gas are extensively regulated at the national, state, and local levels. These laws may govern a wide variety of matters, including allowable rates of production, transportation, marketing, pricing, well construction, water use, prevention of waste, waste disposal, pollution and protection of the environment. These laws, regulations and orders have in the past, and may again, restrict the rate of oil and natural gas production below the rate that would otherwise exist in the absence of such laws, regulations and orders.

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Laws affecting the oil and natural gas industry and the distribution of its products are under constant review for amendment or expansion, frequently increasing the regulatory burden on operations. Numerous governmental departments and agencies are authorized by statute to issue, and have issued, rules and regulations binding on the oil and natural gas industry. Compliance with applicable laws is often difficult and costly, while non-compliance may result in substantial penalties.

Natural Gas

The transportation and sale for resale of natural gas in interstate commerce, historically, have been regulated pursuant to several laws enacted by Congress and the regulations promulgated under these laws by the Federal Energy Regulatory Commission (“FERC”) and its predecessor. In the past, the federal government has regulated the prices at which natural gas could be sold in interstate commerce. Congress removed all price and non-price controls affecting wellhead sales of natural gas under the Natural Gas Wellhead Decontrol Act effective January 1, 1993. Congress could, however, reenact controls in the future.

Sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for pipeline transportation remain subject to extensive federal and state regulation. Several major regulatory changes have been implemented by Congress and FERC from 1985 to the present that affect the economics of natural gas production, transportation and sales. In addition, FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry.

Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts. The Trust cannot predict when or if any such proposals might become effective, or their effect, if any, on the Trust. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach to natural gas sales pursued since 1993 by FERC and Congress will continue.

Sales of crude oil, condensate and gas liquids are not currently regulated and are made at market prices. The ability to transport and sell petroleum products depends on pipelines that transport such products in interstate commerce and FERC regulates the rates, terms and conditions of service by such pipelines under the Interstate Commerce Act.

Environmental Regulation

General. Activities on the Subject Interests are subject to existing stringent and complex federal, state and local laws (including case law) and regulations governing health, safety, environmental quality and pollution control. Failure to comply with these laws, rules and regulations, however, may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the operations on the Subject Interests.

Cleanup. Under certain environmental laws and regulations, the operators of the Subject Interests could be subject to strict, joint and several liability for the removal or remediation of property contamination, whether at a drill site or a waste disposal facility, even when the operators did not cause the contamination or their activities were in compliance with all applicable laws at the time the actions were taken. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund” law, for example, imposes liability, regardless of fault or the legality of the original conduct, on certain classes of persons for releases into the environment of a “hazardous substance.” Liable persons may include the current or previous owner and operator of a site where a hazardous substance has been disposed and persons who arranged for the disposal of a hazardous substance at a site. Under CERCLA and similar statutes, government authorities or

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private parties may take actions in response to threats to the public health or the environment or sue responsible persons for the associated costs. In the course of operations, the working interest owner and/or the operator of Subject Interests may have generated and may generate materials that could trigger cleanup liabilities. In addition, the Subject Interests have produced oil and/or natural gas for many years, and previous operators may have disposed or released hydrocarbons, wastes or hazardous substances at the Subject Interests. The operator of the Subject Interests or the working interest owners may be responsible for all or part of the costs to clean up any such contamination. Although the Trust is not the operator of any Subject Interests, or the owner of any working interest, its ownership of the Royalty could cause it to be responsible for all or part of such costs to the extent CERCLA or any similar statute imposes responsibility on such parties as “owners.”

Climate Change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and certain other greenhouse gases (“GHGs”) endanger public health and the environment because emissions of such gases are contributing to warming of the Earth’s atmosphere and other climatic changes. Based on those findings, the EPA adopted and implemented various regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act (“CAA”). Among other things, these covered reductions in GHG emissions from motor vehicles, permits for certain large stationary sources of GHGs, monitoring and annual reporting of GHG emissions from specified GHG emission sources, including oil and natural gas exploration and production operations, and power plant performance standards that were intended to lead to the creation of additional state GHG control programs. In June 2013, moreover, President Obama unveiled a Presidential climate action plan designed to reduce emissions in the US of methane, carbon dioxide and other GHGs. In furtherance of that plan, the Obama Administration launched a number of initiatives, including a Strategy to Reduce Methane Emissions from the oil and natural gas industry. The Obama Administration’s goal was to reduce methane emissions from the oil and natural gas industry by 40-45% by 2025 as compared to 2012 levels. The EPA therefore issued regulations in 2016 that set additional standards for methane and volatile organic compound emissions from oil and natural gas production sources, including hydraulically fractured oil wells, and natural gas processing and transmission sources. As another prong of President Obama’s methane strategy, the Bureau of Land Management promulgated standards for reducing venting and flaring on public lands. The Trump Administration has tried to delay or revise a number of the Obama-era regulations; however, proponents of climate change regulations have been challenging those efforts in various courts with some success to date. The direction of future U.S. climate change regulation therefore is difficult to predict. Federal agencies may or may not continue developing regulations to reduce GHG emissions from the oil and gas industry. Even if federal efforts in this area slow, states may continue pursuing climate regulations. Various state governments and regional organizations comprising state governments already have enacted legislation and promulgated rules restricting GHG emissions or promoting the use of renewable energy, and additional such measures are frequently under consideration. Although it is not possible at this time to estimate how potential future requirements addressing GHG emissions would impact operations on the Subject Interests and Royalty Income, either directly or indirectly, any future federal, state or local laws or implementing regulations that may be adopted to address GHG emissions could require the operator of the Subject Interests to incur new or increased costs to obtain permits, operate and maintain equipment and facilities, install new emission controls, acquire allowances to authorize GHG emissions, pay taxes related to GHG emissions or administer a GHG emissions program. Regulation of GHGs could also result in a reduction in demand for and production of oil and natural gas. Additionally, to the extent that unfavorable weather conditions are exacerbated by global climate change or otherwise, the Subject Interests may be adversely affected to a greater degree than previously experienced.

Certain Tax Considerations

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.

The Trustee has been informed that the New Mexico Oil and Gas Proceeds and Pass-Through Entity Withholding Tax Act (the “Withholding Tax Act”) requires remitters who pay certain oil and natural gas

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proceeds from production on New Mexico wells 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 natural gas production, as well as amounts deducted from payments that are for expenses related to oil and natural 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.

As discussed herein under Part II, Item 9A (Controls and Procedures), due to the pass-through nature of the Trust, Burlington and Hilcorp are the primary sources of the information disclosed in this Annual Report on Form 10-K and the other periodic reports filed by the Trust with the SEC. Although the Trustee receives periodic updates from Hilcorp 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 Hilcorp’s timely delivery of the information to the Trust.

Burlington Matter

On September 13, 2017, the Trust and Burlington entered into a settlement (“Settlement Agreement”) of previously reported litigation styled Compass Bank, in its Capacity as Trustee of the San Juan Basin Royalty Trust v. Burlington Resources Oil & Gas Company LP and BROG GP LLC, No. D-101-CV-2014-01765 (the “2014 Litigation”). The lawsuit was filed in the 1^st Judicial District Court, Santa Fe County, New Mexico. The Settlement Agreement provides that Burlington pay the Trust $7.5 million to resolve the 2014 Litigation and all disputed and/or unresolved audit exceptions asserted by the Trust for the audit years January 1, 2007 through December 31, 2016. The Trust received the $7.5 million in September 2017 and the proceeds were paid to Unit Holders on October 16, 2017. The 2014 Litigation was dismissed with prejudice on September 14, 2017.

The Settlement Agreement also includes a mutual release of each party and its affiliates for any claims or damages arising out of or related to any acts, events or omissions occurring prior to January 1, 2017, including with respect to any claims asserted by the Office of Natural Resource Revenue (the “ONRR”) against Burlington and/or ConocoPhillips to pay additional royalties for production for periods prior to January 1, 2017. Pursuant to the Settlement Agreement, the Trust will be indemnified for any liability relating to the ONRR claims for periods prior to January 1, 2017 and Burlington has fully released the Trust from any such claims.

Jicarilla Matter

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

In 2007, Burlington obtained an Administrative Order from the Department of the Interior (the “DOI”) rejecting that portion of the MMS Order requiring Burlington to calculate and pay additional royalties based on

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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 (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, which 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 remanded the matter to the DOI for further proceedings. While a judgment or settlement in the DOI Case could impact the Royalty Income of the Trust, Burlington has informed the Trust that it does not have sufficient information to estimate a range of loss for the Trust because the DOI has not provided a major portion calculation for the January 1984 to February 1988 time period as required by the Court of Appeals ruling. Burlington indicates that the situation will not be alleviated until the DOI provides Burlington with a new Order to Perform or similar notice, but that it cannot predict when or if the DOI will provide such information or notice. The Trust’s consultants will continue to monitor development in this matter and analyze the appropriateness of the allocation, if any, by Burlington of any portion of any settlement or judgment in calculating the Royalty.

The Trust believes, based on advice of legal counsel, that although the Jicarilla matter was not specifically referenced in the Settlement Agreement, the clear intent of the Settlement Agreement was to completely sever the relationship between Burlington and the Trust and to release any and all claims “which existed or may have existed prior to January 1, 2017, or which Burlington held, may have held or may in the future hold arising out of or related to any acts, events or omissions occurring prior to January 1, 2017,” including “all claims accruing before or after January 1, 2017 relating to production prior to January 1, 2017 or Royalty on such production, regardless of whether they are known or unknown as of the Effective Date.”

Not applicable.

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PART II

Units of Beneficial Interest

The Units are traded on the New York Stock Exchange under the symbol “SJT.” The Trust makes monthly cash distributions to the Unit Holders. The aggregate monthly distribution amount is the excess of (i) the net proceeds attributable to the Royalty paid to the trustee of the Trust, plus any decrease in cash reserves previously established for liabilities and contingencies of the Trust, over (ii) the expenses and payments of liabilities of the Trust, plus any net increase in cash reserves. Future payments of cash distributions are dependent on such factors as prevailing natural gas and oil prices, expenses, increases in cash reserves and the actual production from the Subject Interests.

Unit Prices and Distributions by Quarters

From January 1, 2016 to December 31, 2017, the quarterly high and low sales prices and the aggregate amount of monthly distributions paid per Unit each quarter were as follows:

According to the records of our transfer agent, as of March 1, 2018, there were 46,608,796 Units outstanding held by 977 Unit Holders of record. The actual number of Unit Holders is greater than these numbers of Unit Holders of record and includes Unit Holders who are beneficial owners, but whose shares are held in street name by brokers and nominees. The number of Unit Holders of record also does not include Unit Holders whose Units may be held in trust by other entities.

Equity Compensation Plans

The Trust has no directors, executive officers or employees. Accordingly, the Trust does not maintain any equity compensation plans and there are no Units reserved for issuance under any such plans.

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The following table sets forth selected data for the Trust based on the audited statements of distributable income for the years indicated and the audited statements of assets, liabilities and trust corpus as of December 31 for the years indicated.

Overview

The principal asset of the Trust is the Royalty, which consists of a 75% net overriding royalty interest that burdens the Subject Interests located in the San Juan Basin of northwestern New Mexico. The primary function of the Trustee is to collect the Royalty Income, to pay all expenses and charges of the Trust and to distribute the remaining available income to the Unit Holders. The amount of income distributable to Unit Holders, which we refer to as “Distributable Income,” depends on the amount of Royalty Income and interest received by the Trust, as well as the amount of expenses paid by the Trust and any change in cash reserves.

Royalty Income. The Royalty functions generally as a net profits interest in the Subject Interests. The Royalty Income paid to the Trust is 75% of net proceeds from the Subject Interests. The term “net proceeds,” as used in the Conveyance, means the excess of gross proceeds received by Hilcorp during a particular period over production costs for such period. “Gross proceeds” means the amount received by Hilcorp (or any subsequent owner of the Subject Interests) from the sale of the production attributable to the Subject Interests, subject to certain adjustments.

The amount of gross proceeds attributable to the Subject Interests depends on prevailing natural gas prices and, to a lesser extent, crude oil prices. As a result, commodity prices affect the amount of Royalty Income available for distribution to the Unit Holders. During 2017, the price of natural gas and oil for production from the Subject Interests increased significantly from an average price for natural gas of $1.89 per Mcf in 2016 to $2.68 per Mcf in 2017, and the price for oil increased from an average price of $30.01 per Bbl in 2016 to $35.36 per Bbl in 2017.

The amount of gross proceeds also depends on the volumes of natural gas and oil produced from the Subject Interests. Under the terms of the Indenture, the Trust cannot acquire new natural gas and oil assets, and as a result, Royalty Income is dependent on the natural gas and oil volumes attributable to the Subject Interests. Although Hilcorp and other operators of the Subject Interests may conduct drilling operations or recompletions

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in the near term, the Subject Interests are depleting assets, and Hilcorp informs us it is unable to estimate the productive life of the Subject Interests. There were no new wells drilled on the Subject Interests by either Burlington or Hilcorp in 2016 or 2017. Hilcorp, however, recompleted one well in December, 2017, and has not budgeted any capital expenditures for new drilling in 2018. Lower commodity prices may also reduce the volume of natural gas and oil produced from the Subject Interests.

Under the terms of the Conveyance, production costs are deducted from gross proceeds in calculating Royalty Income. “Production costs” generally means costs incurred on an accrual basis by Burlington/Hilcorp in operating the Subject Interests, including both capital and non-capital costs. For example, these costs include development drilling, production and processing costs, applicable taxes and operating charges. However, Hilcorp informed the Trust that, for wells operated by Hilcorp, it generally did not intend to accrue lease operating expenses to the Trust. If production costs exceed gross proceeds in any month, the excess is recovered out of future gross proceeds prior to the making of further payment to the Trust, but the Trust is not otherwise liable for any production costs or other costs or liabilities attributable to the Subject Interests or the minerals produced therefrom. If at any time the Trust receives more than the amount due under the Royalty, it is not obligated to return such overpayment, but the amounts payable to it for any subsequent period are reduced by such amount, plus interest, at a rate specified in the Conveyance. The Trust and the Trustee has very limited authority to control the amount and timing of production costs.

Distributable Income. In addition to Royalty Income, the Trust receives interest income, typically from interest paid on cash deposits. General and administrative expenses constitute the Trust’s primary expense and include, among other items, the Trustee’s fees, audit, consulting and legal fees and reporting costs.

The Trustee is authorized to determine in its discretion the amount of cash reserves needed to pay liabilities and contingencies of the Trust. Total cash reserves were $1.0 million as of December 31, 2016 and 2017. The Trustee does not anticipate any further increases to the cash reserves in 2018.

Sale of Interest in the San Juan Basin from Burlington to Hilcorp

The sale of San Juan Basin assets, including the Subject Interests, from Burlington to Hilcorp closed on July 31, 2017. Hilcorp assumed responsibility for monthly production beginning August 1, 2017. ConocoPhillips informed the Trust that the last production month for which ConocoPhillips was responsible was July 2017 and therefore the last monthly distribution report that the Trust received from ConocoPhillips was for September 2017. In October 2017, the Trust received the distribution report from Hilcorp.

Hilcorp informed the Trust that, due to the transition from Burlington, Hilcorp did not have all of the revenue and expense decks installed and did not have the appropriate detail to provide actual revenue and expense numbers. Therefore, Hilcorp estimated the October, November and December 2017 distributions based on the July 2017 production month (September 2017 distribution month) previously provided by Burlington and rounded to the nearest thousand. The October, November and December 2017 declarations of cash distribution each included an additional $1.0 million in estimated gross revenue based on Hilcorp’s knowledge that production volumes increased. Hilcorp has indicated that it may need to estimate revenue for subsequent distributions in 2018.

Distributions for November and December 2017 reflect actual expenses for the months of September and October 2017, although severance taxes continued to be estimated. The December 2017 declaration of cash distribution included a true-up of the actual versus previously estimated expense numbers for the August 2017 production month. Hilcorp will reconcile estimated versus actual revenue numbers once Hilcorp finalizes installation of its revenue decks, although Hilcorp has not indicated when such reconciliation may occur. Such estimations and reconciliations by Hilcorp will be credited or debited from future distributions to Unit Holders. The accounting reports used to prepare the financial information for January – September 2017 were provided by Burlington, and accounting reports for the months of October – December 2017 were provided by Hilcorp.

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Results of Operations

Royalty Income

Royalty Income consists of monthly net proceeds attributable to the Royalty. Royalty Income for the three years ended December 31, 2017 was determined as shown in the following table:

Gross Proceeds from Subject Interests. Gross proceeds increased $29.1 million or 53% to $84.0 million for the year ended December 31, 2017 compared to $54.9 million for the year ended December 31, 2016. The increase was primarily attributable to higher natural gas and oil prices and the receipt of $10 million in gross revenue ($7.5 million net) from Burlington in settlement of the 2014 Litigation. Additional proceeds of $3.0 million were received based on Hilcorp’s increased revenue estimates along with a $1.0 million credit for reversal of accrued capital expenses. Due to the transition from Burlington, Hilcorp estimated the oil and natural gas revenue for the October, November and December 2017 distributions, based on information provided by Burlington.

Gross proceeds decreased $22 million or 29% to $54.9 million for the year ended December 31, 2016 compared to $76.9 million for the year ended December 31, 2015. The decrease was primarily attributable to lower natural gas and oil prices. An additional decrease to gross revenue was due to a $328,356 fuel and loss reporting revenue adjustment in May 2016 for the December 2014 to January 2016 production period.

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Capital Expenditures. The capital expenditures reported by Burlington for 2017 included amounts attributable to the capital budgets for prior years because capital expenditures are deducted in calculating Royalty Income in the month they accrue, and projects within a given year’s budget often extend into subsequent years. With respect to any wells operated by third parties other than Burlington or Hilcorp, Hilcorp’s share, if any, of capital expenditures for the year ended December 31, 2017 may not be paid until 2018 or later. For a summary of Hilcorp’s planned 2018 capital expenditures, see Liquidity and Capital Resources—2018 Capital Expenditure Budget.

Excluding a $1.0 million credit for reversal of accrued capital expenses, actual capital expenditures decreased $1 million or 71% from $1.4 million for the year ended December 31, 2016 compared to $0.4 million for the year ended December 31, 2017. Such decrease was primarily attributable to the challenging price environment for natural gas and natural gas liquids, fewer maintenance and facility projects, and the transition of the Subject Interests from Burlington to Hilcorp. Burlington issued the $1.0 million credit for the reversal of accrued capital expenses to zero out the accrued capital expense account prior to the sale to Hilcorp.

Capital expenditures decreased $11.4 million or 89% from $12.8 million for the year ended December 31, 2015 compared to $1.4 million for the year ended December 31, 2016. Approximately $0.7 million of capital expenditures for 2016 covered 20 projects budgeted for prior years, including 34 operated facilities projects. The approximately $0.7 million balance for 2016 expenditures was attributable to one well recompletion and eight projects for the maintenance and improvement of production facilities.

Severance Taxes. Aggregate severance taxes increased $1.7 million or 30% to $7.4 million for the year ended December 31, 2017 compared to $5.7 million for the year ended December 31, 2016. Due to the transition from Burlington, Hilcorp estimated the oil and natural gas severance tax for the October, November and December 2017 distributions. Aggregate severance taxes decreased $2.1 million or 27% to $5.7 million for the year ended December 31, 2016 compared to $7.8 million for the year ended December 31, 2015.

Lease Operating Expenses and Property Taxes. Lease operating expenses and property taxes decreased $3.5 million or 13% to $22.9 million for the year ended December 31, 2017 compared to $26.4 million for the year ended December 31, 2016. The decrease was primarily attributable to reductions in contracted maintenance, water hauling, chemical costs by switching vendors, optimizing treatments & reducing delivery charges, repair costs, efforts to reduce costs on compression equipment, and eliminating the outsourcing of PSV testing. Lease operating expenses and property taxes decreased $4.0 million or 13% to $26.4 million for the year ended December 31, 2016 compared to $30.4 million for the year ended December 31, 2015. The decrease was primarily attributable to Burlington’s efforts to reduce contracted maintenance and repair costs as a result of declining commodity prices, which began in 2014. Hilcorp informed the Trust that, for wells operated by Hilcorp, it generally did not intend to accrue lease operating expenses to the Trust.

Monthly operating expenses of the Subject Interests, including property taxes, in 2017 averaged approximately $1.9 million, compared to $2.2 million in 2016. Operating expenses averaged lower in 2017 primarily because of reduced maintenance and repair costs. Monthly operating expenses of the Subject Interests, including property taxes, in 2016 averaged approximately $2.2 million, as compared to $2.5 million in 2015. Operating expenses averaged lower in 2016 primarily because of reduced maintenance and repair labor.

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Distributable Income

Distributable Income increased $25.2 million or 181.3% to $39.1 million ($0.839547 per Unit) for the year ended December 31, 2017 from $13.9 million ($0.298851 per Unit) for the year ended December 31, 2016. The increase in Distributable Income from 2016 to 2017 was primarily attributable to higher natural gas prices, decreased general and administrative expenses related to audit and legal costs incurred in the 2014 Litigation, the $7.5 million received for settlement of the 2014 Litigation, and the receipt of a $1.0 million gross credit for the reversal of accrued capital expenses.

Distributable Income decreased $3.1 million or 18% to $13.9 million ($0.298851 per Unit) for the year ended December 31, 2016 from $17.0 million ($0.364745 per Unit) for the year ended December 31, 2015. The decrease in Distributable Income from 2015 to 2016 was primarily attributable to a decrease in Royalty Income over the same period as a result of lower natural gas pricing.

Interest Income. Interest Income in 2017 was lower as compared to 2016 primarily due to additional interest Burlington paid to the Trust in 2016 as a result of the granting of certain audit exceptions. Interest Income in 2016 included $731,606 of interest on the late payment of gross proceeds as a result of the negotiation of compliance audit issues.

General & Administrative Expenses. General and administrative expenses decreased $1.5 million or 48% to $1.6 million for the year ended December 31, 2017 compared to $3.1 million for the year ended December 31, 2016. The decrease was primarily attributable to decreased audit costs and legal costs incurred related to the 2014 Litigation, expenses incurred in 2016 responding to the Southwest Bank Campaign, and differences in timing in the receipt and payment of certain of these expenses. General and administrative expenses increased $0.9 million or 41% to $3.1 million for the year ended December 31, 2016 compared to $2.2 million for the year ended December 31, 2015. The increase was primarily attributable increased audit costs and legal costs incurred related to the 2014 litigation, expenses incurred in responding to the Southwest Bank Campaign, and differences in timing in the receipt and payment of certain of these expenses.

For more information about the Southwest Bank Campaign, see Part I, Item 7. Southwest Bank Proxy Campaign of our Annual Report on Form 10-K for the year ended December 31, 2016.

Cash Reserves. Total cash reserves were approximately $1.0 million, $1.0 million and $0.5 million as of December 31, 2017, 2016 and 2015, respectively. Cash reserves were increased by $463,687 during 2016 and by $350,071 during 2015 in order to cover litigation expenses and to have sufficient funds to cover monthly general and administrative expenses in the event that there is insufficient Royalty Income to cover such expenses. In April 2015, royalty income was insufficient to cover Trust expenses, and $97,648 in cash reserves were used.

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Cash available for distribution in May 2015 was first applied to pay Trust expenses and replenish the cash reserve, resulting in no Distributable Income for May 2015.

Liquidity and Capital Resources

The Trust’s principal source of liquidity and capital is Royalty Income. The Trust’s distribution of income to Unit Holders is funded by Royalty Income after payment of Trust expenses. The Trust is not liable for any production costs or liabilities attributable to the Royalty. If at any time the Trust receives more than the amount due under the Royalty, it is not obligated to return such overpayment, but the amounts payable to it for any subsequent period are reduced by such amount, plus interest, at a rate specified in the Conveyance. If the Trustee determines that the Trust does not have sufficient funds to pay its liabilities, the Trustee may borrow funds on behalf of the Trust, in which case no distributions will be made to Unit Holders until such borrowings are repaid in full. The Trustee may not sell or dispose of any part of the assets of the Trust without the affirmative vote the Unit Holders of 75% of all of the Units outstanding; however, the Trustee may sell up to 1% of the value of the Royalty (as determined pursuant to the Indenture) during any 12-month period without the consent of the Unit Holders.

2018 Capital Expenditure Budget

Hilcorp has informed the Trust that its 2018 budget for capital expenditures for the Subject Interests is estimated to be $0.54 million and that existing wells will continue to be operated.

Contractual Obligations

As of December 31, 2017, the Trust had no obligations or commitments to make future contractual payments other than the trustee fee payable to the Trustee. Under the Indenture, the Trustee is entitled to an administrative fee for its administrative services and the preparation of quarterly and annual statements, computed as (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. The minimum administrative fee due under items (i) and (ii) is $36,000 per year. Administrative fees paid to the Trustee were $288,739, $303,362 and $254,395 for the years ended December 31, 2017, 2016 and 2015, respectively.

Off-Balance Sheet Arrangements

None.

Critical Accounting Policies and Estimates

For a description of critical accounting policies and estimates, see Item 8. Financial Statements and Supplementary Data, Note 3.

Results of the 4th Quarters of 2017 and 2016

For the three months ended December 31, 2017, Distributable Income was $10,165,827 ($0.218110 per Unit) , which was more than the $7,680,850 ($0.164794 Per Unit) of income distributed during the same period in 2016. The increase in Distributable Income resulted primarily from higher average gas and oil prices in the fourth quarter of 2017.

Royalty Income of the Trust for the fourth quarter is customarily based on actual gas and oil production during August through October of each year. However, due to the transition from Burlington, Hilcorp did not have all of the revenue decks installed and used estimated oil and gas revenue numbers for the fourth quarter of

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2017 based on information previously provided by Burlington. Gas and oil sales for the quarters ended December 31, 2017 and 2016 were as follows:

The estimated average price of gas increased in the fourth quarter of 2017 compared to the same period of 2016. The estimated price per barrel of oil during the fourth quarter of 2017 was $2.06 lower than the price during the fourth quarter of 2016.

Capital costs for the fourth quarter of 2017 totaled $1,302 compared to $406,623 during the same period of 2016. Capital costs were dramatically lower in the fourth quarter of 2017 primarily due to the transition of operations from Burlington to Hilcorp and the continued suspension of Burlington’s drilling program in the San Juan Basin.

Lease operating expenses and property taxes for the fourth quarter of 2017 averaged $1,413,128 per month compared to $2,146,817 per month in the fourth quarter of 2016. Lease operating expenses and property taxes were $733,689 per month lower in the fourth quarter of 2017 than for the fourth quarter of 2016 primarily because of reduced maintenance, repair labor, reduced water hauling costs, reduced chemical costs by switching vendors, reduced delivery charges, optimizing treatments, and eliminating the outsourcing of PSV testing. Based on 46,608,796 Units outstanding, the per-Unit distributions during the fourth quarters of 2017 and 2016 were as follows:

Interest Rate and Foreign Currency Risk

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 any business or commercial activity of any kind whatsoever, including holding any derivative financial instruments or any borrowing transactions, other than the Trust’s ability to borrow money periodically as necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash reserves held by the Trust. The amount of any such borrowings is unlikely to be material to the Trust. The Trust periodically holds short-term investments acquired with funds held by the Trust pending distribution to Unit Holders and funds held in reserve for the payment of

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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 material interest rate risk. The Trust does not engage in transactions in foreign currencies which could expose the Trust or Unit Holders to any foreign currency related market risk.

Commodity Price Risk

The Trust’s most significant market risk relates to the prices received for natural gas and oil production. The revenues derived from the Subject Interests depend substantially on prevailing natural gas prices and, to a lesser extent, oil prices. As a result, commodity prices also affect the amount of distributable income to the Unit Holders. Lower prices may also reduce the amount of natural gas and oil that Burlington or the third-party operators can economically produce.

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Report of Independent Registered Public Accounting Firm

Compass Bank, Trustee

San Juan Basin Royalty Trust

Opinion on the Financial Statements

We have audited the accompanying statements of assets, liabilities and trust corpus of San Juan Basin Royalty Trust as of December 31, 2017 and 2016, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of San Juan Basin Royalty Trust as of December 31, 2017 and 2016, and its distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2017, on the basis of accounting described in Note 3 to the financial statements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), San Juan Basin Royalty Trust’s internal control over financial reporting as of December 31, 2017, based on the criteria established in 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 16, 2018 expressed an unqualified 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 generally accepted in the United States of America.

Basis for Opinion

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 are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to San Juan Basin Royalty Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

WEAVER AND TIDWELL, L.L.P.

We have served as San Juan Basin Royalty Trust’s auditor since 2001

Fort Worth, Texas

March 16, 2018

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FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Statements of Assets, Liabilities, and Trust Corpus

December 31, 2017 and 2016

Statements of Distributable Income

For each of the years ended December 31

These Financial Statements should be read in conjunction with the accompanying Notes to Financial Statements included herein.

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Statements of Changes in Trust Corpus

For each of the years ended December 31

These Financial Statements should be read in conjunction with the accompanying Notes to Financial Statements included herein.

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Notes to Financial Statements

1.    Trust Organization and Provisions

The San Juan Basin Royalty Trust (the “Trust”) was established on November 1, 1980. Southland Royalty Company (“Southland”) conveyed to the Trust a 75% net overriding royalty interest (the “Royalty”) which burdens certain of Southland’s oil and natural gas interests (the “Subject Interests”) in properties located in the San Juan Basin in northwestern New Mexico. Subsequent to the Conveyance of the Royalty, through a series of sales, assignments and mergers, Southland’s successor became Hilcorp San Juan L.P. (“Hilcorp”), which acquired the Subject Interests from Burlington Resources Oil & Gas Company LP (“Burlington”) on July 31, 2017. Burlington is an indirect wholly-owned subsidiary of ConocoPhillips. Through an acquisition completed on March 24, 2006, Compass Bank succeeded TexasBank as “Trustee” (herein so called) of the Trust. On September 7, 2007, Compass Bancshares, Inc. was acquired by Banco Bilbao Vizcaya Argentaria, S.A. (“BBVA”) and is now a wholly-owned subsidiary of BBVA.

On November 3, 1980, 46,608,796 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 Trust’s initial public offering was completed on 1980. The Units are traded on the New York Stock Exchange. Holders of Units are referred to herein as “Unit Holders.”

The terms of the Trust Indenture provide, among other things, that:

2.    Net Overriding Royalty Interest and Distribution to Unit Holders

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 Subject Interests 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%.

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Notes to Financial Statements — (Continued)

The initial carrying value of the Royalty of $133,275,528 represented Southland’s historical net book value at the date of the transfer of the Trust. Accumulated amortizations as of December 31, 2017 and 2016 were $126,698,148 and $125,491,149, respectively.

3.    Basis of Accounting

The financial statements of the Trust are prepared on the following basis and are not intended to present financial position and results of operations in conformity with U.S. generally accepted accounting principles:

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 liabilities and 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 as an expense. Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with U.S. generally accepted accounting principles, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues were received or expenses were paid. Because the trust’s financial statements are prepared on the modified cash basis, as described above, most accounting pronouncements are not applicable to the Trust’s financial statements. This comprehensive basis of accounting corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

The Trustee routinely reviews its royalty interests in oil and gas properties for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If an impairment event occurs and it is determined that the carrying value of the Trust’s royalty interests may not be recoverable, an impairment will be recognized as measured by the amount by which the carrying amount of the royalty interests exceeds the fair value of these assets, which would likely be measured by discounting projected cash flows. There was no impairment of the assets as of December 31, 2016 or 2017.

4.    Federal Income Taxes

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

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Notes to Financial Statements — (Continued)

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 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 natural 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 natural 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 natural 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 natural 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. 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.

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.

Tax positions taken by the Trust related to the Trust’s pass-through status and state tax positions have been reviewed, and the Trustee is of the opinion that material positions taken would more likely than not be sustained by examination. As of December 31, 2017, the Trust’s tax years 2014 and thereafter remain subject to examination.

5.    Certain Contracts

Natural gas produced in the San Juan Basin is sold in both interstate and intrastate commerce. Reference is made to the discussion contained herein under “Regulation” for information as to federal regulation of prices of oil and natural gas. As part of the transition from Burlington to Hilcorp, Hilcorp has assumed, or been assigned, all the natural gas purchase, gathering and processing contracts affecting the Subject Interest. Natural gas produced from the Subject Interests is processed at the: Chaco, Val Verde, Milagro, Ignacio or Kutz plants, all located in the San Juan Basin. Hilcorp sells natural gas produced from the Subject Interests under various contracts.

Hilcorp’s sales contracts with Shell Energy North America (US) LP (“Shell”) expires on March 31, 2018. Hilcorp and Chevron Natural Gas entered into certain replacement contracts covering those volumes beginning April 1, 2018. The replacement contracts with Chevron Natural Gas expire on March 31, 2019. Hilcorp’s sales contracts with EDF Trading North America LLC (“EDF”) automatically renewed for another year and now expires on March 31, 2019.

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Notes to Financial Statements — (Continued)

Hilcorp’s sales contracts with EDF, Shell and Chevron Natural Gas each provides for (i) the delivery of such natural gas at various delivery points through their respective termination dates and (ii) the sale of such natural gas at prices that fluctuate in accordance with published indices for natural gas sold in the San Juan Basin of northwestern New Mexico.

Hilcorp’s natural gas sales contract with New Mexico Gas Company, Inc. expires on March 31, 2019. The contract provides for the sale of certain winter-only natural gas supplies processed at the Kutz plant at prices that fluctuate in accordance with published indices for natural gas sold in the San Juan Basin of northwestern New Mexico.

Hilcorp contracts with Williams Four Corners, LLC (“WFC”) and Enterprise Field Services, LLC (“EFS”) for the gathering and processing of virtually all of the natural gas produced from the Subject Interests. Hilcorp’s predecessor entered into four contracts with WFC, each of which is effective for a term of 15 years commencing April 1, 2010. Hilcorp’s predecessor signed a similar agreement with EFS which was effective November 1, 2011 for a term of 15 years. Hilcorp’s predecessor has disclosed to the Trust a summary of that agreement which the Trust has reviewed with its consultants, subject to conditions of confidentiality.

The Trust is not a party to any of the purchase, gathering or processing contracts. As part of the 1996 settlement of litigation filed by the Trustee in 1992 against Burlington and Southland, the Trustee and Burlington established a formal protocol pursuant to which compliance auditors retained by the Trustee have access to Burlington and its successors’ books and records, which protocol has been adopted by Hilcorp.

6.    Hilcorp’s Estimation of Fourth Quarter Revenue

The sale of San Juan Basin assets, including the Subject Interests, from Burlington to Hilcorp closed on July 31, 2017. Hilcorp assumed responsibility for monthly production beginning August 1, 2017. ConocoPhillips informed the Trust that the last production month for which ConocoPhillips was responsible was July 2017 and therefore the last monthly distribution report that the Trust received from ConocoPhillips was for September 2017. In October 2017, the Trust received the distribution report from Hilcorp.

Hilcorp informed the Trust that, due to the transition from Burlington, Hilcorp did not have all of the revenue and expense decks installed and did not have the appropriate detail to provide actual revenue and expense numbers. Therefore, Hilcorp estimated the October, November and December 2017 distributions based on the July 2017 production month (September distribution month) previously provided by Burlington and rounded to the nearest thousand. The October, November and December 2017 declarations of cash distribution each included an additional $1.0 million in estimated gross revenue based on Hilcorp’s knowledge that production volumes increased. Hilcorp has indicated that it may need to estimate revenue for subsequent distributions in 2018.

Distributions for November and December 2017 reflect actual expenses for the months of September and October 2017, although severance taxes continued to be estimated. The December 2017 declaration of cash distribution included a true-up of the actual versus previously estimated expense numbers for the August 2017 production month. Hilcorp will reconcile estimated versus actual revenue numbers once Hilcorp finalizes installation of its revenue decks, although Hilcorp has not indicated when such reconciliation may occur. Such estimations and reconciliations by Hilcorp will be credited or debited from future distributions to Unit Holders and such adjustments could be material.

7.    Significant Customers

Information as to significant purchasers of oil and natural gas production attributable to the Trust’s economic interests is included in Note 5 above.

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Notes to Financial Statements — (Continued)

8.    Development Costs

Hilcorp’s capital budget plans for the Subject Interests are delivered to the Trustee at the beginning of each calendar year. The estimates are subject to change, based on, among other things, Hilcorp’s actual capital requirements, the pace of regulatory approvals, the mix of projects and swings in the price of natural gas.

Both the estimated annual capital expenditures and the actual expenses reported by Hilcorp include amounts attributable to capital budgets for prior years because capital expenditures are deducted in calculating Royalty Income in the month they accrue and projects within a given year’s budget often extend into subsequent years. Further, Hilcorp’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 accounted for as part of the following year’s capital expenditures. In addition, with respect to wells not operated by Hilcorp, Hilcorp’s share of capital expenditures may not be paid until the following year(s) after those expenses were incurred by the operator.

The budget for capital expenditures in 2017 for properties subject to the Trust’s royalty interest was estimated at $1.7 million, of which approximately $0.64 million was to be attributable to the capital budgets for 2016 and prior years. Actual capital expenditures of approximately $0.4 million were included in calculating royalty income paid to the Trust in calendar year 2017.

The 2016 capital expenditure budget was estimated at $4.8 million, of which approximately $1.4 million was to be attributable to the capital budgets for 2015 and prior years. Actual capital expenditures of approximately $1.4 million were included in calculating royalty income paid to the Trust in calendar year 2016, of which approximately $0.7 million related to projects budgeted for prior years.

The 2015 capital expenditure budget was estimated at $14.0 million, of which approximately $6.8 million was attributable to the capital budgets for 2014 and prior years. Actual capital expenses for 2015 were $12.8 million, of which approximately $5.2 million related to projects budgeted for prior years.

9.    Settlements and Litigation

Burlington Matter

On September 13, 2017, the Trust and Burlington entered into a settlement (“Settlement Agreement”) of previously reported litigation styled Compass Bank, in its Capacity as Trustee of the San Juan Basin Royalty Trust v. Burlington Resources Oil & Gas Company LP and BROG GP LLC, No. D-101-CV-2014-01765 (the “2014 Litigation”). The lawsuit was filed in the 1^st Judicial District Court, Santa Fe County, New Mexico. The Settlement Agreement provides that Burlington pay the Trust $7.5 million to resolve the 2014 Litigation and all disputed and/or unresolved audit exceptions asserted by the Trust for the audit years January 1, 2007 through December 31, 2016. The Trust received the $7.5 million in September 2017 and the proceeds were paid to Unit Holders on October 16, 2017. The 2014 Litigation was dismissed with prejudice on September 14, 2017.

The Settlement Agreement also includes a mutual release of each party and its affiliates for any claims or damages arising out of or related to any acts, events or omissions occurring prior to January 1, 2017, including with respect to any claims asserted by the Office of Natural Resource Revenue (the “ONRR”) against Burlington and/or ConocoPhillips to pay additional royalties for production for periods prior to January 1, 2017. Pursuant to the Settlement Agreement, the Trust will be indemnified for any liability relating to the ONRR claims for periods prior to January 1, 2017 and Burlington has fully released the Trust from any such claims.

Jicarilla Matter

Burlington has informed the Trust that pursuant to an Order to Perform issued by the Minerals Management Service, (“MMS”), dated June 10, 1998 (the “MMS Order”), the Jicarilla Apache Nation (the “Jicarilla”) alleged

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Notes to Financial Statements — (Continued)

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 natural 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 natural gas prior to processing or (b) the combined value of processed residue natural gas and plant products plus the value of any condensate recovered downstream without processing. The MMS Order alleged that Burlington’s dual accounting calculations on Native American leases were based on less than major portion prices. In 2000, Burlington and the Jicarilla entered into a settlement agreement resolving the issues associated with the dual accounting calculation. The major portion calculation issue remains outstanding. Burlington takes the position that a judgment or settlement could entitle Burlington to reimbursement from the Trust for past periods.

In 2007 Burlington obtained an Administrative Order from the Department of the Interior (the “DOI”) rejecting that portion of the MMS Order requiring Burlington to calculate and pay additional royalties based on the major portion price derived by the MMS. The Jicarilla filed suit solely against the DOI in the United States District Court for the District of Columbia (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, which 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 remanded the matter to the DOI for further proceedings. While a judgment or settlement in the DOI Case could impact the Royalty Income of the Trust, Burlington has informed the Trust that it does not have sufficient information to estimate a range of loss for the Trust because the DOI has not provided a major portion calculation for the January 1984 to February 1988 time period as required by the Court of Appeals ruling. Burlington indicates that the situation will not be alleviated until the DOI provides Burlington with a new Order to Perform or similar notice, but that it cannot predict when or if the DOI will provide such information or notice. The Trust’s consultants will continue to monitor development in this matter and analyze the appropriateness of the allocation, if any, by Burlington of any portion of any settlement or judgment in calculating the Royalty.

The Trust believes, based on advice of legal counsel, that although the Jicarilla matter was not specifically referenced in the Settlement Agreement, the clear intent of the Settlement Agreement was to completely sever the relationship between Burlington and the Trust and to release any and all claims “which existed or may have existed prior to January 1, 2017, or which Burlington held, may have held or may in the future hold arising out of or related to any acts, events or omissions occurring prior to January 1, 2017,” including “all claims accruing before or after January 1, 2017 relating to production prior to January 1, 2017 or Royalty on such production, regardless of whether they are known or unknown as of the Effective Date.”

10.    Supplemental Oil and Gas Reserve Information (Unaudited)

Proved Oil and Natural Gas Reserves

Proved oil and gas reserves have been estimated by independent petroleum engineers. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available. The reserves actually recovered and the

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Notes to Financial Statements — (Continued)

timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors.

The following table presents a reconciliation of proved reserve quantities attributable to the Royalty from December 31, 2014 to December 31, 2017:

Standardized Measure of Discounted Future Net Cash Flows

The following is a summary of a standardized measure of discounted future net cash flows related to the Trust’s total proved natural gas and oil reserve quantities. Information presented is based upon valuation of proved reserves by using discounted cash flows based upon average oil and gas prices during the 12-month period prior to the fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions and severance and ad valorem taxes, if any, and economic conditions, discounted at the required rate of 10%. As the Trust is not subject to taxation at the trust level, no provision for income taxes has been made in the following disclosure. Trust prices may differ from posted NYMEX prices due to differences in product quality and property location. The impact of changes in current prices on reserves could vary significantly from year to year. Accordingly, the information presented below should not be viewed as an estimate of the fair market value of the Trust’s oil and natural gas reserves or the costs that would be incurred to acquire equivalent reserves. A market value determination would require the analysis of additional parameters.

Estimates of proved oil and natural gas reserves are by their nature imprecise. Estimates of future net revenue attributable to proved reserves are sensitive to the unpredictable prices of oil and natural gas and other

38

Notes to Financial Statements — (Continued)

variables. Accordingly, under the allocation method used to derive the Trust’s quantity of proved reserves, changes in prices will result in changes in quantities of proved oil and natural gas reserves and estimated future net revenues.

The 2017, 2016 and 2015 changes in the standardized measure of discounted future net cash flows related to future Royalty Income from proved reserves are as follows:

Reserve quantities and revenues shown in the tables above for the Royalty were estimated from projections of reserves and revenues attributable to the combined Hilcorp and Trust interests. Reserve quantities attributable to the Royalty were derived from estimates by allocating to the Royalty a portion of the total net reserve quantities of the interests, based upon gross revenue less production taxes. Because the reserve quantities attributable to the Royalty are estimated using an allocation of the reserves, any changes in prices or costs will result in changes in the estimated reserve quantities allocated to the Royalty. Therefore, the reserve quantities estimated will vary if different future price and cost assumptions occur. The future net cash flows were determined without regard to future federal income tax credits, if any, available to production from coal seam wells.

For 2017, $2.62 per Mcf of natural gas and $37.67 per Bbl of oil were used in determining future net revenue. These prices were based on a 12-month unweighted average of the first-day-of-the-month pricing of $2.98 per MMBtu of Henry Hub natural gas and $51.34 per Bbl of West Texas Intermediate oil. The increase in reserve quantities for 2017 is due primarily to higher commodity prices.

For 2016, $2.07 per Mcf of natural gas and $29.59 per Bbl of oil were used in determining future net revenue. These prices were based on a 12-month unweighted average of the first-day-of-the-month pricing of $2.48 per MMBtu of Henry Hub natural gas and $42.75 per Bbl of West Texas Intermediate oil. The slight increase in reserve quantities for 2016 is due primarily to lower production costs and forecast adjustments.

For 2015, $2.29 per Mcf of natural gas and $36.48 per Bbl of oil were used in determining future net revenue. These prices were based on a 12-month unweighted average of the first-day-of-the-month pricing of $2.59 per MMBtu of Henry Hub natural gas and $50.28 per Bbl of West Texas Intermediate oil. The downward revision in reserve quantities for 2015 is due primarily to lower natural gas prices as well as a reduction in Burlington’s development plans, which results in an elimination of proved undeveloped reserves.

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Notes to Financial Statements — (Continued)

11.     Quarterly Schedule of Distributable Income (Unaudited)

The following is a summary of the unaudited quarterly schedule of distributable income for the two years ended December 31, 2017 and 2016 (in thousands, except per unit amounts):