Annual Report (10-k)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

☒	Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2018

☐	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

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)


Texas		75-6279898
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Compass Bank 300 W. 7 ^th Street, Suite B Fort Worth, Texas		76102
(Address of principal executive offices)		(Zip Code)

(866) 809-4553

(Registrant’s telephone number, including area code)

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


Title of Each Class		Name of Each Exchange on Which Registered
Units of Beneficial Interest		New York Stock Exchange

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.


Large accelerated filer ☐	Accelerated filer ☑	Non-accelerated filer ☐	Smaller reporting company ☑
Emerging growth company ☐

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, 2018: $269,720,179

At March 18, 2019 there were 46,608,796 Units of Beneficial Interest of the registrant outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None.


GLOSSARY OF OIL AND NATURAL GAS TERMS			i
PART I			1
	ITEM 1.	BUSINESS	1
	ITEM 1A.	RISK FACTORS	4
	ITEM 1B.	UNRESOLVED STAFF COMMENTS	4
	ITEM 2.	PROPERTIES	4
	ITEM 3.	LEGAL PROCEEDINGS	10
	ITEM 4.	MINE SAFETY DISCLOSURES	10
PART II			11
	ITEM 5.	MARKET FOR REGISTRANT’S UNITS, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASES OF UNITS	11
	ITEM 6.	SELECTED FINANCIAL DATA	11
	ITEM 7.	TRUSTEE’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION S	11
	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	18
	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	28
	ITEM 9A.	CONTROLS AND PROCEDURES	28
	ITEM 9B.	OTHER INFORMATION	32
PART III			32
	ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT	32
	ITEM 11.	EXECUTIVE COMPENSATION	32
	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY HOLDER MATTERS	32
	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	33
	ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	33
PART IV			34
	ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	34

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,” “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). Such statements also are based on an assessment of, and are subject to, a variety of factors deemed relevant by the Trustee and Hilcorp that 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 that 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.

Hilcorp’s reporting of natural gas volumes differs from the reporting of gas volumes from Burlington Resources Oil & Gas Company LP (“Burlington”), an indirect wholly-owned subsidiary of ConocoPhillips, from which Hilcorp acquired the Subject Interests on July 31, 2017. The natural gas volumes reported to the Trust by Hilcorp are based on plant residue gas volumes plus equivalent volumes for natural gas liquids. Hilcorp converts one barrel of natural gas liquids to six Mcf of natural gas using industry standards. Historically, ConocoPhillips reported natural gas production to the Trust based on wellhead volumes. Such differences in reporting methodology could significantly affect the comparison of reported natural gas volumes and average pricing in 2018 to those from prior periods.

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.

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.

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

Mcf : Thousand cubic feet.

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.

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 well 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 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).

Recompleted Well : A well completed by drilling a separate well bore from an existing casing in order to reach the same reservoir, or redrilling the same well bore to reach a new reservoir.

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 well recompletion. See 17 CFR 210.4-10(a)(31).

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


GLOSSARY OF OIL AND NATURAL GAS TERMS			i
PART I			1
	ITEM 1.	BUSINESS	1
	ITEM 1A.	RISK FACTORS	4
	ITEM 1B.	UNRESOLVED STAFF COMMENTS	4
	ITEM 2.	PROPERTIES	4
	ITEM 3.	LEGAL PROCEEDINGS	10
	ITEM 4.	MINE SAFETY DISCLOSURES	10
PART II			11
	ITEM 5.	MARKET FOR REGISTRANT’S UNITS, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASES OF UNITS	11
	ITEM 6.	SELECTED FINANCIAL DATA	11
	ITEM 7.	TRUSTEE’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION S	11
	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	18
	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	28
	ITEM 9A.	CONTROLS AND PROCEDURES	28
	ITEM 9B.	OTHER INFORMATION	32
PART III			32
	ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT	32
	ITEM 11.	EXECUTIVE COMPENSATION	32
	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY HOLDER MATTERS	32
	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	33
	ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	33
PART IV			34
	ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	34

PART I

ITEM 1.

BUSINESS

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 (the “San Juan Basin”). 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 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 Trust’s 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, 2018, 98% of the Trust’s estimated proved reserves consisted of natural gas reserves, and 96% of the gross proceeds from the Subject Interests in 2018 were attributable to the production and sale of natural gas by 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.

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 $19.4 million and $33.2 million in Royalty Income from Hilcorp and Burlington in each of the fiscal years ended December 31, 2018 and 2017, respectively. After deducting administrative expenses and accounting for interest income and any change in cash reserves, the Trust distributed approximately $18.0 million and $39.1 million to Unit Holders in each of the fiscal years ended December 31, 2018 and 2017, respectively. The Trust’s corpus was approximately $5.8 million and $6.6 million as of December 31, 2018 and 2017, 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, 2018, the Trustee had established cash reserves of $1.0 million. In September 2018 the Trust utilized cash reserves of $97,909 to pay Trust administrative expenses, and the Trust replenished its cash reserves by $97,909 in October 2018. The Trustee does not anticipate any increase to the cash reserves in 2019.

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 the Trustee.

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 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, and as a result, Hilcorp’s actions could have a material impact on the results of operations and could have interests that conflict with the interests of the Trust and the Unit Holders. The Subject Interests that are not operated by Hilcorp are operated by other operators, some of which may be affiliated with Hilcorp. 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. 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. Neither the Trustee nor the Unit Holders can influence or control the operation or future development of the Subject Interests.

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. 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, even though such well is still generating revenue for the Unit Holders. 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 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. In addition, 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.

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 available at the SEC’s internet site, 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.

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 .

ITEM 1A.

RISK FACTORS

Not required.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

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. 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.

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 Hilcorp, there were, as of December 31, 2018, 4,322 gross (828.1 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 988 gross (274.7 net) wells were Multiple Completion Wells, resulting in a total of 5,382 gross (1,134.7 net) 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 15% of our proved natural gas reserves as of December 31, 2018. 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.

2019 Capital Expenditure Budget

On March 1, 2019, Hilcorp has informed the Trust that for 2019, it currently has budgeted approximately $2.6 million in capital expenditures, which includes approximately $0.7 million towards five well recompletions and approximately $1.9 million towards drilling one new horizontal well.

Oil and Natural Gas Production

Hilcorp’s reporting of natural gas volumes differs from the reporting of gas volumes by Burlington and ConocoPhillips. The natural gas volumes reported to the Trust by Hilcorp are based on plant residue gas volumes plus equivalent volumes for natural gas liquids. Hilcorp converts one barrel of natural gas liquids to six Mcf of natural gas using industry standards. Historically, ConocoPhillips reported natural gas production to the Trust based on wellhead volumes. Such differences in reporting methodology could significantly affect the comparison of reported natural gas volumes and average pricing in 2018 to those from prior periods.

Production of oil and natural gas and related average sales prices attributable to each of the Subject Interests and the Royalty for the two years ended December 31, 2018, were as follows:


	For the year ended December 31,
	2018				2017
	Natural Gas (Mcf)		Oil and Condensate (Bbls)		Natural Gas (Mcf)		Oil and Condensate (Bbls)
Production
Subject Interests		32,501,962		52,944		25,779,802		55,225
Royalty		10,406,632		32,191		12,122,810		25,128
Average Price (per Mcf/Bbl)	$	1.89	$	52.23	$	2.68	$	35.75

Production costs for natural gas and oil attributable to the Subject Interests for the two years ended December 31, 2018 were as follows:


	2018		2017
Total Production Costs (including capital expenses)	$	38,488,437	$	29,682,492
Average Production Costs per unit of Production	$	1.1842	$	1.1514
Lease Operating Expenses	$	27,757,091	$	22,691,965
Average Lifting Cost per unit of Production	$	0.8540	$	0.8802

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 two 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. Please refer 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 Interests. Natural gas produced from the Subject Interests is processed at the following sites: 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 Chevron Natural Gas (“Chevron) and EDF Trading North America LLC (“EDF”) automatically renewed for an additional one-year term and now expire on March 31, 2020. Each of Hilcorp’s sales contracts with EDF and Chevron 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. Hilcorp’s natural gas sales contract with New Mexico Gas Company, Inc. automatically renewed for an additional one-year term and now expires on March 31, 2020. 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.

Hilcorp contracts with Enterprise Field Services, LLC (“EFS”) for the gathering and processing of certain natural gas produced from the Subject Interests. Hilcorp’s predecessor signed an 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.

Hilcorp’s predecessor entered into four contracts with Williams Four Corners, LLC (“WFC”), each of which is effective for a term of 15 years commencing April 1, 2010. The EFS and WFC contracts covered the gathering and processing of virtually all of the natural gas produced from the Subject Interests. On October 1, 2018, Harvest Midstream I, L.P., an affiliated midstream company of Hilcorp, completed the acquisition of WFC’s gas pipeline and processing facilities in the San Juan Basin. The Conveyance sets forth the processing costs that Hilcorp can charge for both non-affiliates and affiliates.

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. Total proved Developed and Undeveloped Oil and Natural Gas Reserves attributable to the Royalty as of December 31, 2018 were as follows:


	Proved Reserves ⁽¹⁾⁽²⁾
Reserves Category	Natural Gas (MMcf)		Crude Oil and Condensate (MBbls)
Developed		75,844		203
Undeveloped		-		-

Total Proved		75,844		203

(1)

Proved reserves were calculated using prices equal to the twelve-month unweighted arithmetic average of the first-day-of-the-month commodity prices for each of the preceding twelve months, which were $3.10 per MMBtu (Henry Hub) of natural gas and $65.56 per Bbl (West Texas Intermediate) of oil. The adjusted volume-weighted average prices over the life of the properties were $2.55 per Mcf of gas and $54.06 per Bbl of oil.

(2)

The Trust does not own a specific percentage of the oil and gas reserves because the Conveyance has defined the Trust’s interest as a net overriding royalty interest. Because the Trust’s reserve quantities are determined using an allocation formula, any fluctuations in actual or assumed prices or costs will result in revisions to the estimated reserve quantities allocated to the net overriding royalty interest.

Estimated quantities of proved Developed Oil and Natural Gas Reserves attributable to the Royalty as of December 31, 2018 and 2017 were as follows:


	2018		2017
Natural Gas (MMcf)		75,844		97,764
Crude Oil and Condensate (MBbls)		203		257

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, 2018 or 2017.

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 the same level of information that generally would be available to a company with oil and natural gas operations because detailed information generally is not available to owners of royalty interests. Thus, the Trustee relies upon accumulated information and data solely provided by Hilcorp regarding the Royalty derived from the Subject Interests and provides such information for the Trust’s auditing purposes to Cawley, Gillespie & Associates, Inc. (“CG&A”). CG&A extrapolates from such Hilcorp-provided 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 other publicly available information, and provides the results to the Trust.

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 has verified 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, 2017 and 2018 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, and is a registered professional engineer in the State of Texas (License No. 71055). Mr. Meekins graduated from Texas A&M University in 1987, summa cum laude , with a B.S. in Petroleum Engineering. Both 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.

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. Such costs and penalties may affect the amount of net proceeds attributable to the Royalty that are paid to the Trust by Hilcorp or by subsequent operators of the Subject Interests.

Natural Gas

The transportation and 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.

Any such price or non-price control regulations may affect the amount of net proceeds attributable to the Royalty that are paid to the Trust by Hilcorp or subsequent operators of the Subject Interests.

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 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. The current 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, and the outcomes of future elections may result in a return to President Obama’s regulatory scheme or other policy agendas that seek to curb the U.S. production and usage of fossil fuels. The direction of future U.S. climate change regulation therefore is difficult to predict, as well as the impact such regulation may have on the amount of net proceeds attributable to the Royalty that are paid to the Trust by Hilcorp or subsequent operators of the Subject Interests. In addition, 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 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 should consult with their individual tax advisors regarding the applicability of the Withholding Tax Act and other tax matters to distributions received from the Trust by a Unit Holder.

ITEM 3.

LEGAL PROCEEDINGS

Jicarilla Matter and Burlington Settlement

For information about the Jicarilla Matter and the Trust’s prior settlement with Burlington (“2014 Litigation”), see Part I, Item 3. Legal Proceedings in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2017.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5.

MARKET FOR REGISTRANT ’ S UNITS, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASES OF UNITS

Units of Beneficial Interest

The Units are traded on the New York Stock Exchange under the symbol “SJT.”

Dividend Policy

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 Holders

According to the records of our transfer agent, as of March 1, 2019, there were 46,608,796 Units outstanding held by 912 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.

ITEM 6.

SELECTED FINANCIAL DATA

Not Required.

ITEM 7.

TRUSTEE ’ S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As discussed herein under Part II, Item 9A (Controls and Procedures), due to the pass-through nature of the Trust, Hilcorp is the primary source 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.

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. 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 2018, the price of natural gas for production from the Subject Interests decreased significantly from an average price for natural gas of $2.68 per Mcf in 2017 to $1.89 per Mcf in 2018. The price for oil increased from an average price of $35.75 per Bbl in 2017 to $52.23 per Bbl in 2018.

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 well recompletions 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 2017 or 2018. Hilcorp recompleted one well in 2017 and 15 wells in 2018. As of March 1, 2019, Hilcorp has informed the Trust that for 2019, it has budgeted approximately $2.6 million in capital expenditures for 2019, which includes approximately $0.7 million towards five well recompletions and approximately $1.9 million towards drilling one new horizontal well. 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, 2017 and 2018. In September 2018 the Trust utilized cash reserves of $97,909 to pay Trust administrative expenses. The Trust replenished its cash reserves by $97,909 in October 2018. The Trustee does not anticipate any increase to the cash reserves in 2019.

Sale of Burlington’s Interest in the San Juan Basin Hilcorp

The sale of San Juan Basin assets, including the Subject Interests, from Burlington to Hilcorp closed on July 31, 2017. 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 Burlington’s reporting.

Gross Proceeds and Severance Tax Estimates. The Trust has been advised by Hilcorp that during the transition period since its acquisition of the Subject Interests that there has been a delay in the transfer of historical information and knowledge from Burlington to Hilcorp. During this transition, the Trust has been advised by Hilcorp that for certain months it has recorded estimates of cash revenues and expenses, based on the best information available. Hilcorp has informed the Trust that it believes that its estimates have been prepared in accordance with the Conveyance.

Hilcorp’s process of reconciling actual revenue and severance tax numbers versus previously reported estimated numbers (which the Trust refers to as “true-ups”) from prior periods during fiscal 2017 and 2018 are still occurring and being reported in 2019. Thus, distributions to the Trust from Hilcorp in any given month may be subject to adjustment based upon prior months’ true-ups, plus interest due to the Trust. Generally, there is a two or three month lag in Hilcorp truing-up previously reported estimated or accrued financial information; however, Hilcorp has notified the Trustee that as of the date of this Annual Report, it will still need to true-up the previously reported natural gas production (and for the trust distribution months of January 2018 and October through December 2018, oil production) and financial information for the trust distribution months of January 2018 and June through December 2018 and, therefore, possibly adjust future distributions of net proceeds to reflect such true-ups plus interest on such amounts (as required by the Conveyance) to the extent an underpayment has occurred.

The Trust has been advised by Hilcorp that as a result of its continued transitioning of historic information and knowledge from Burlington, Hilcorp included an additional $1.0 million in “Other” revenue in the gross proceeds estimates for each of the October, November and December 2017 and January 2018 distribution months based on Hilcorp’s estimated increased natural gas production. However, such “Other” proceeds were subsequently offset due to lower natural gas pricing. The additional $1.0 million in “Other” gross proceeds received in both the October and November 2017 distributions months were reversed by Hilcorp and charged back to the Trust in the May and June 2018 distributions months, respectively. Hilcorp has not yet trued-up the $1.0 million in “Other” gross proceeds included in both the December 2017 and January 2018 distributions.

Gross Proceeds and Severance Tax True-ups. Hilcorp has reconciled actual revenue and severance tax numbers versus the previously reported numbers (referred to as “true-ups”) and adjusted the distributions for certain months. More specifically, the May 2018 distribution included a true-up of the oil and gas production and “Other” revenue used in the October 2017 distribution, resulting in a net decrease of approximately $0.6 million. The June 2018 distribution included a true-up of the oil and gas production and “Other” revenue used in the November 2017 distribution and the gas production used in the May 2018 distribution, which totaled a net reduction of approximately $1.2 million. In addition, the July 2018 distribution included a true-up of oil production used in the December 2017 and June 2018 distributions which totaled a net reduction of $60,000. The August 2018 distribution included a true-up of oil production used in the July 2018 distribution resulting in a net increase of $41,000. The September 2018 distribution included a true-up of natural gas production used in the December 2017 distribution which resulted in a net decrease of $92,000.

Results of Operations

Royalty Income

Royalty Income consists of monthly net proceeds attributable to the Royalty. Royalty Income for the two years ended December 31, 2018 was determined as shown in the following table:


	For the years ended December 31,
	2018			2017
Gross Proceeds From the Subject Interests:
Natural Gas	$	61,476,079		$	69,006,242	⁽¹⁾
Oil		2,765,035			1,974,296	⁽¹⁾
Other		13,107	⁽⁴⁾		12,998,201	⁽²⁾

Total		64,254,221			83,978,739

Capital Expenditures		2,397,175			399,236
Severance Tax – Natural Gas		7,954,108			7,178,515	⁽¹⁾
Severance Tax – Oil		242,825			189,041	⁽¹⁾
Other		(3,734	)		(1,000,000	) ⁽³⁾
Lease Operating Expenses and Property Taxes		27,757,283			22,915,700

Total		38,347,657			29,682,492

Net Profits		25,906,564			54,296,247

Net Overriding Royalty Interest		75%			75%

Royalty Income	$	19,429,923		$	40,722,185

(1)	Due to the transition from Burlington, Hilcorp estimated the oil and natural gas revenue and severance taxes for the October, November and December 2017 distributions based on information provided by Burlington.

(2)

Includes $7.5 million ($10.0 million gross up) received for settlement of the 2014 Litigation plus $3.0 million of additional revenue estimated by Hilcorp, offset by $1,799 for Burlington’s revenue adjustment for gas imbalance settlements. Please refer to Item 3 of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2017, for a discussion of the 2014 Litigation.

(3)	Credit for reversal of accrued capital expenses.

(4)	Consists primarily of approximately $1.0 million in estimated revenue from non-operated properties offset by true-ups by Hilcorp.

Gross Proceeds from Subject Interests. Gross proceeds decreased $19.7 million or 24% to $64.3 million for the year ended December 31, 2018 compared to $84 million for the year ended December 31, 2017. The decrease was primarily attributable to lower natural gas prices and the receipt in 2017 of $10 million in gross revenue ($7.5 million net) from Burlington in settlement of the 2014 Litigation. Please refer to Item 3 of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2017, for a discussion of the 2014 Litigation. Additional “Other” proceeds of $3.0 million were received in 2017 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.

Capital Expenditures . The capital expenditures reported by Hilcorp for 2018 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 Hilcorp, Hilcorp’s share, if any, of capital expenditures for the year ended December 31, 2018 may not be paid until 2019 or later. For a summary of Hilcorp’s planned 2019 capital expenditures, see Liquidity and Capital Resources— 2019 Capital Expenditure Budget .

Capital expenditures increased $2.0 million or 500% from $0.4 million for the year ended December 31, 2017 compared to $2.4 million for the year ended December 31, 2018. Hilcorp’s total 2018 capital expenditures for the Trust’s Subject Interests were $2.4 million, which includes approximately $2.0 million for 15 well recompletions and $0.4 million for six facility projects.

Severance Taxes. Aggregate severance taxes increased $0.8 million or 11% to $8.2 million for the year ended December 31, 2018 compared to $7.4 million for the year ended December 31, 2017. The increase was primarily attributable to Hilcorp’s continued efforts to apply available tax exemptions, but has not yet applied all such exemptions. 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.

Lease Operating Expenses and Property Taxes. Lease operating expenses and property taxes increased $4.8 million or 21% to $27.8 million for the year ended December 31, 2018 compared to $22.9 million for the year ended December 31, 2017. Monthly operating expenses of the Subject Interests, including property taxes, in 2018 averaged approximately $2.3 million, compared to $1.9 million in 2017. Operating expenses were higher in 2018 primarily because of increased activity in the San Juan Basin.

Distributable Income


	For the years ended December 31,
	2018		2017
Royalty Income	$	19,429,923	$	33,222,185	⁽¹⁾
Other Revenue – Settlement Proceeds		-		7,500,000
Interest Income		37,343		15,082

Total Income		19,467,266		40,737,267
Expenditures – General and Administrative		1,491,298		1,607,011
Increase in Cash Reserves		-		-

Distributable Income	$	17,975,968	$	39,130,256

Distributable Income per Unit (46,608,796 Units)	$	0.385678	$	0.839547

(1)	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.

Distributable Income decreased $21.1 million or 54% to $18.0 million ($0.385678 per Unit) for the year ended December 31, 2018 from $39.1 million ($0.8395471 per Unit) for the year ended December 31, 2017. The decrease in Distributable Income from 2017 to 2018 was primarily attributable to lower natural gas prices and the receipt in 2017 of $10 million in gross revenue ($7.5 million net) from Burlington in settlement of the 2014 Litigation. Please refer to Item 3 of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2017, for a discussion of the 2014 Litigation. Additional “Other” proceeds of $3.0 million were received in 2017 based on Hilcorp’s increased revenue estimates along with a $1.0 million credit for reversal of accrued capital expenses.

Interest Income. Interest Income in 2018 was higher as compared to 2017 primarily due to additional interest Hilcorp paid to the Trust in 2018 as a result of capital expenditures charged to the Trust in error.

General & Administrative Expenses. General and administrative expenses decreased $0.1 million or 7% to $1.5 million for the year ended December 31, 2018 compared to $1.6 million for the year ended December 31, 2017. The decrease was primarily attributable to differences in timing in the receipt and payment of certain of these expenses.

Cash Reserves. Total cash reserves were $1.0 million as of December 31, 2017 and 2018.

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.

2019 Capital Expenditure Budget

Hilcorp has informed the Trust that its 2019 budget for capital expenditures for the Subject Interest is estimated to be approximately $2.6 million and that existing wells will continue to be operated. Hilcorp also has informed the Trust that its current 2019 budget includes approximately $0.7 million towards five well recompletions scheduled to be completed in the Mesaverde and Fruitland Coal formations, and an additional approximately $1.9 million towards one horizontal well to be drilled in the Mancos formation.

Contractual Obligations

As of December 31, 2018, 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 $267,951 and $288,739 for the years ended December 31, 2018 and 2017, 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 2018 and 2017

For the three months ended December 31, 2018, Distributable Income was $6,386,706 ($0.137028 per Unit), which was less than the $10,165,827 ($0.218110 per Unit) of income distributed during the same period in 2017. The decrease in Distributable Income resulted primarily from higher revenue in the fourth quarter of 2017 as a result of higher prices.

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 2017 based on information previously provided by Burlington. Gas and oil sales for the quarters ended December 31, 2018 and 2017 were as follows:


	Three months ended December 31,
	2018		2017
			(Estimates)
Subject Interests
Gas — Mcf		7,543,326		6,465,000
Mcf per Day		81,993		70,272
Average Price (per Mcf)	$	2.18	$	2.60
Oil — Bbls		10,287		8,700
Bbls per Day		112		95
Average Price (per Bbl)	$	57.65	$	32.41
Attributable to the Royalty
Gas — Mcf		3,233,548		3,451,569
Oil — Bbls		6,307		4,674

The average price of gas decreased in the fourth quarter of 2018 compared to the same period of 2017. The average price per barrel of oil during the fourth quarter of 2018 was $25.24 higher than the price during the fourth quarter of 2017.

Capital costs for the fourth quarter of 2018 totaled approximately $(0.9 million) due to a reversal of approximately $2.4 million in capital costs overcharged to the Trust by Hilcorp in the September 2018 distribution month, as compared to $1,302 during the same period of 2017.

Lease operating expenses and property taxes for the fourth quarter of 2018 averaged $2,337,983 per month compared to $1,413,128 per month in the fourth quarter of 2017. Lease operating expenses and property taxes were $924,855 per month higher in the fourth quarter of 2018 than for the fourth quarter of 2017 primarily because of increased activity in the San Juan Basin.

Based on 46,608,796 Units outstanding, the per-Unit distributions during the fourth quarters of 2018 and 2017 were as follows:


	Three months ended December 31,
	2018		2017
October		0.075488		0.072741
November		0.037385		0.072081
December		0.024155		0.073288

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not Applicable.

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 Hilcorp or the third-party operators can economically produce.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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, 2018 and 2017, and the related statements of distributable income and changes in trust corpus for the years then ended, 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, 2018 and 2017, and its distributable income and changes in trust corpus for the years then ended, 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, 2018, 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 18, 2019 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 18, 2019

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Statements of Assets, Liabilities, and Trust Corpus

December 31, 2018 and 2017


	2018		2017
ASSETS
Cash and Short-Term Investments	$	2,125,838	$	4,415,851
Net Overriding Royalty Interests in Producing Oil and Gas Properties – Net		5,844,727		6,577,380

TOTAL	$	7,970,565	$	10,993,231


	2018		2017
LIABILITIES & TRUST CORPUS
Distribution Payable to Unit holders	$	1,125,838	$	3,415,851
Cash Reserves		1,000,000		1,000,000
Trust Corpus – 46,608,796 Units of Beneficial Interest Authorized and Outstanding		5,844,727		6,577,380

TOTAL	$	7,970,565	$	10,993,231

Statements of Distributable Income

December 31, 2018 and 2017


	2018		2017
Royalty Income	$	19,429,923	$	33,222,185
Other Revenue – Settlement Proceeds		-		7,500,000
Interest Income		37,343		15,082

Total Revenue		19,467,266		40,737,267
Expenditures – General and Administrative		1,491,298		1,607,011
Increase in Cash Reserves		-		-
Distributable Income	$	17,975,968	$	39,130,256

Distributable Income per Unit (46,608,796 Units)	$	0.385678	$	0.839547

Statements of Changes in Trust Corpus

December 31, 2018 and 2017


	2018			2017
Trust Corpus, Beginning of Period	$	6,577,380		$	7,784,379
Amortization of Net Overriding Royalty Interest		(732,653	)		(1,206,999	)
Distributable Income		17,975,968			39,130,256
Distributions Declared		(17,975,968	)		(39,130,256	)

Trust Corpus, End of Period	$	5,844,727		$	6,577,380

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

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:

•

The Trust shall not engage in any business or commercial activity of any kind or acquire any assets other than those initially conveyed to the Trust;

•

The Trustee may sell up to one percent (1%) of the value (based on prior year engineering reports) of the Royalty in any 12- month period, but otherwise may not sell all or any part of the Royalty unless approved by holders of 75% of all Units outstanding. In either case, the sale must be for cash and the proceeds promptly distributed;

•

The Trustee may establish a cash reserve for the payment of any liability which is contingent or uncertain in amount;

•

The Trustee is authorized to borrow funds to pay liabilities of the Trust;

•

The Trustee will make monthly cash distributions to Unit Holders (see Note 2); and

•

The Trust will generally terminate upon the first to occur of the following events: (a) at such time as the Trust’s gross revenue for each of two successive years is less than $1.0 million per year or (b) the Unit Holders of at least 75% of all of the Units outstanding vote in favor of termination.

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%.

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 amortization as of December 31, 2018 and 2017 were $127,430,801 and $126,698,148, 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 net proceeds attributable to the Royalty (the “Royalty Income”) recorded for a month is the amount computed and paid by the owner of the Subject Interests, Hilcorp San Juan L.P. (“Hilcorp”), the present owner of the Subject Interests, to the Trustee for the Trust. Royalty Income consists of the proceeds received by Hilcorp from the sale of production less accrued production costs, development and drilling costs, applicable taxes, operating charges, and other costs and deductions, multiplied by 75%. The calculation of net proceeds by Hilcorp for any month includes adjustments to proceeds and costs for prior months and impacts the Royalty Income paid to the Trust and the distribution to Unit Holders for that month.

•

Although permitted under the Conveyance, Hilcorp has informed the Trust that, for wells operated by Hilcorp, it generally did not intend to accrue lease operating expenses to the Trust.

•

Hilcorp has informed the Trust that oil revenue is typically reported to the Trust based on actual volumes and pricing and that due to timing, Hilcorp reports accrued natural gas revenues to the Trust based on actual production volumes from the meters. Generally, Hilcorp reconciles the natural gas revenue accruals with the plant processing statements the month following the previously reported financial information.

•

Trust expenses recorded are based on liabilities paid and cash reserves established from Royalty Income for liabilities and contingencies.

•

Distributions to Unit Holders are recorded when declared by the Trustee.

•

The conveyance which transferred the Royalty to the Trust provides that any excess of production costs applicable to the Subject Interests over gross proceeds from such properties must be recovered from future net proceeds before Royalty Income is again paid to the Trust.

The financial statements of the Trust differ from financial statements prepared in accordance with 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, which include the provisions of the new revenue recognition standard in ASU 2014-09. In addition, the disclosures required by ASU 2014-09 did not impact the disclosures over revenue by the Trust. 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 Trust has evaluated the impact of ASC 842, Leases , and determined that this standard has no impact on the Trust’s financial statements.

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

Notes to Financial Statements — (Continued)

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 and recorded as a reduction of trust corpus. There was no impairment of the assets as of December 31, 2018 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 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.

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, 2018, the Trust’s tax years 2015 and thereafter remain subject to examination.

5. Certain Contracts

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 Interests. Natural gas produced from the Subject Interests is processed at the following sites: 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.

Notes to Financial Statements — (Continued)

Hilcorp’s sales contracts with Chevron Natural Gas (“Chevron) and EDF Trading North America LLC (“EDF”) automatically renewed for an additional one-year term and now expire on March 31, 2020. Each of Hilcorp’s sales contracts with EDF and Chevron 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. automatically renewed for another year and now expires on March 31, 2020. 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 Enterprise Field Services, LLC (“EFS”) for the gathering and processing of certain natural gas produced from the Subject Interests. Hilcorp’s predecessor signed an agreement with EFS which was effective November 1, 2011 for a term of 15 years, and the contract was assumed by or assigned to Hilcorp. 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.

Hilcorp’s predecessor entered into four contracts with Williams Four Corners, LLC (“WFC”), each of which is effective for a term of 15 years commencing April 1, 2010, and which were assigned to Hilcorp. The EFS and WFC contracts cover the gathering and processing of virtually all of the natural gas produced from the Subject Interests. On October 1, 2018, Harvest Midstream I, L.P., an affiliated midstream company of Hilcorp, completed the acquisition of WFC’s gas pipeline and processing facilities in the San Juan Basin.

6. 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.

7. 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 October 31 of each calendar year, such that capital expenditures incurred in November 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.

Hilcorp’s original 2018 capital expenditures plan delivered to the Trust in February 2018 reported estimated capital expenditures of $547,800 for properties subject to the Trust’s royalty interests. In September 2018, the Trustee did not declare a monthly cash distribution to Unit holders primarily because of excess capital expenditures in the July 2018 production month. Following the excess production costs Hilcorp charged to the

Notes to Financial Statements — (Continued)

Trust in the July 2018 production month that resulted in no distribution being paid by the Trust to Unit holders in September 2018, at the Trustee’s request, the Trust’s external compliance auditors investigated the increased capital expenditures for additional well recompletions charged to the Trust. Upon review of the information Hilcorp provided to the Trust, they discovered, and subsequently informed Hilcorp that the Trust’s 75% net overriding royalty interest did not burden Hilcorp’s working interest in certain wells for which the Trust was charged well recompletion capital expenditures. As a result, such expenditures should not have been charged to the Trust. Hilcorp’s royalty payment calculation in its October 2018 report to the Trust included an approximately $2.4 million reversal of such gross capital expenditures, plus interest, along with the recoupment by Hilcorp of $140,780 in gross excess production costs from the September 2018 distribution month.

In November 2018, Hilcorp further updated its Revised Plan that the Trust disclosed to its Unit Holders in September 2018, and provided the Trust with its Second Revised 2018 Capital Expenditures Plan (“Second Revised Plan”). Hilcorp’s Second Revised Plan estimated total 2018 capital spending for the Trust’s subject interests to be approximately $2.3 million. Actual capital expenditures of approximately $2.4 million were included in calculating royalty income paid to the Trust in calendar year 2018.

Hilcorp’s estimated its 2017 capital expenditure budget 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.

8. 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 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

Notes to Financial Statements — (Continued)

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.

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.”

9. 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 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.

Notes to Financial Statements — (Continued)

The following table presents a reconciliation of proved reserve quantities attributable to the Royalty from December 31, 2015 to December 31, 2018:


	Crude Oil and Condensate (MBbls)			Natural Gas (MMcf)
Reserves as of December 31, 2015		170			75,573
Revisions of previous estimates		41			11,507
Extensions, discoveries and other additions		1			302
Production		(24	)		(8,643	)

Reserves as of December 31, 2016		188			78,739
Revisions of previous estimates		94			31,090
Extensions, discoveries and other additions		-			58
Production		(25	)		(12,123	)

Reserves as of December 31, 2017		257			97,764
Revisions of previous estimates		(24	)		(12,150	)
Extensions, discoveries and other additions		2			637
Production		(32	)		(10,407	)

Reserves as of December 31, 2018		203			75,844

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.


	December 31,
	2018			2017
	(in thousands)
Future cash inflows	$	211,064		$	267,568
Future costs		23,430			27,492

Future net cash flows	$	187,634		$	240,076
Discount of future net cash flows at 10%		(79,724	)		(103,086	)

Standardized measure of discounted future net cash flows	$	107,910		$	136,990

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 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.

Notes to Financial Statements — (Continued)

The 2018 and 2017 changes in the standardized measure of discounted future net cash flows related to future Royalty Income from proved reserves are as follows:


	2018			2017
	(in thousands)
Balance, January 1	$	136,990		$	93,479
Revisions of prior-year estimates, change in prices and other		(24,290	)		67,345
Extensions, discoveries and other additions		941			40
Accretion of discount		13,699			9,348
Royalty Income		(19,430	)		(33,222	)

Balance, December 31	$	107,910		$	136,990

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 2018, $2.55 per Mcf of natural gas and $54.06 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 $3.10 per MMBtu of Henry Hub natural gas and $65.56 per Bbl of West Texas Intermediate oil. The decrease in reserve quantities for 2018 is due primarily to lower natural gas prices and higher lease operating expenses.

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.

Notes to Financial Statements — (Continued)

10. 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, 2018 and 2017 (in thousands, except per unit amounts):


2018	Royalty Income			Distributable Income		Distributable Income Per Unit
First Quarter	$	6,647		$	6,227	$	0.133610
Second Quarter		2,991			2,532		0.054322
Third Quarter		3,001			2,830		0.060718
Fourth Quarter		6,791			6,387		0.137028

Total	$	19,430		$	17,976	$	0.385678


2017	Royalty Income			Distributable Income		Distributable Income Per Unit
First Quarter	$	8,608		$	8,147	$	0.174796
Second Quarter		6,451			5,981		0.128333
Third Quarter		15,120	*		14,836		0.318308
Fourth Quarter		10,543			10,166		0.218110

Total	$	40,722		$	39,130	$	0.839547

*	Includes settlement proceeds of $7.5 million

11. Commitments and Contingencies

Contingencies related to the Subject Interests that are unfavorably resolved would generally be reflected by the Trust as reductions to future Royalty Income payments to the Trust with corresponding reductions to cash distributions to Unit holders.

12. Subsequent Events

The Trustee has evaluated subsequent events for potential disclosure through the date that these financial statements were issued, and none were identified.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

The Trust maintains a system of internal disclosure controls and procedures that is designed to ensure that the information required to be disclosed in the Trust’s filings under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms. In its evaluation of its disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on information provided by Hilcorp, the owner of the properties, and, prior to September 2017, Burlington, as the prior owner of the properties. Consequently, the Trust’s ability to timely and accurately disclose relevant information in its periodic reports is dependent upon Hilcorp’s timely delivery of accurate oil and gas revenue and production cost information and, therefore, the net proceeds owed to the Trust.

Notes to Financial Statements — (Continued)

The Conveyance that transferred the royalty to the Trust obligates Hilcorp to provide the Trust with certain financial and operational information, including information concerning calculations of net proceeds owed to the Trust. Pursuant to the settlement of litigation in 1996 between the Trust and Burlington, Burlington agreed to newer, more formal financial reporting and audit procedures as compared to those required to be provided by the Conveyance. As it did with Burlington, once the Trust receives the financial information from Hilcorp, the Trust engages independent public accountants, compliance auditors, attorneys and petroleum engineers in order to assist the Trustee to ensure the accuracy and completeness of the information required to be disclosed in the Trust’s periodic reports. These outside professionals advise the Trustee in its review and compilation of this information for inclusion in this Annual Report on Form 10-K and the other periodic reports provided by the Trust to the SEC.

The Trust has been advised by Hilcorp that during the transition period since its acquisition of the Subject Interests that there has been a delay in the transfer of historical information and knowledge from Burlington to Hilcorp. During this transition, the Trust has been advised by Hilcorp that it has recorded estimates of cash revenues and expenses based on the best information available. Hilcorp has informed the Trust that it believes that its estimates have been prepared in accordance with the Conveyance. As a result, AMS-PAR, the Trust’s compliance auditors, have had to audit vast amounts of new data in a largely unfamiliar format. This new data format has necessitated AMS-PAR to develop its own internal systems, processes, and tools to organize and interpret the vast amount of raw data so that it can make a meaningful analysis. Hilcorp is aware that the Trustee and AMS-PAR have had to implement additional processes. As a result, Hilcorp has informed the Trustee that Hilcorp has hired third-party consultants to help it through this transition. The Trustee and its third party compliance auditors have been coordinating with Hilcorp to ensure that Hilcorp can provide the required level of detail on a timely and accurate basis.

Despite the Trust’s internal controls and procedures ensuring the accuracy of the Trust’s reporting based upon the financial information received from Hilcorp, Hilcorp’s process of reconciling actual revenue and severance tax numbers versus previously reported estimated numbers (which the Trust refers to as “true-ups”) from prior periods during fiscal 2017 and 2018 are still occurring and being reported in 2019. Thus, distributions to the Trust from Hilcorp in any given month may be subject to adjustment based upon prior months’ true-ups, plus interest due to the Trust. Generally, there is a two or three-month lag in Hilcorp reconciling previously reported estimated or accrued financial information; however, Hilcorp has notified the Trustee that as of the date of this Annual Report, it will still need to true-up the previously reported estimated natural gas and oil production and financial information for certain of the Trust’s 2017 and 2018 distribution months. Furthermore, Hilcorp possibly may adjust future distributions of net proceeds to reflect such true-ups plus interest on such amounts (as required by the Conveyance) to the extent an underpayment has occurred. Hilcorp has agreed to waive the interest on any overpayments (as required by the Conveyance) that are determined following such true-ups until June of 2019.

The Trustee has evaluated the Trust’s internal disclosure controls and procedures as of December 31, 2018, and has concluded that such disclosure controls and procedures are effective, at the “reasonable assurance” level (as such term is used in Rule 13a-15(f) of the Exchange Act), to ensure that material information received from Hilcorp is gathered on a timely basis to be included in the Trust’s periodic reports and recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Additionally, during the quarter ended December 31, 2018, there were no changes in the Trust’s internal control over financial reporting (as such term is used in Rule 13a-15(f) of the Exchange Act) that materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting. Because the Trust does not have, nor does the Indenture provide for, officers, a board of directors or an independent audit committee, the Trustee has reviewed neither the Trust’s disclosure controls and procedures nor the Trust’s internal control over financial reporting in concert with management, a board of directors or an independent audit committee.

Notes to Financial Statements — (Continued)

Trustee’s Report on Internal Control over Financial Reporting

Compass Bank, in its capacity as trustee of the Trust, is responsible for establishing and maintaining adequate internal control over financial reporting. The Trust’s internal control over financial reporting is a process designed under the supervision of the Trustee to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Trust’s financial statements for external purposes in accordance with a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles.

As of December 31, 2018, the Trustee assessed the effectiveness of the Trust’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “ Internal Control – Integrated Framework ”, issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework). Based on the assessment, the Trustee determined that the Trust maintained effective internal control over financial reporting as of December 31, 2018, based on those criteria.

Weaver and Tidwell, L.L.P., the independent registered public accounting firm that audited the financial statements of the Trust included in this Annual Report on Form 10-K, has issued an attestation report on the Trust’s internal control over financial reporting as of December 31, 2018. The report, which expresses an unqualified opinion on the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2018, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting.”

Report of Independent Registered Public

Accounting Firm on Internal Control over Financial Reporting

Compass Bank, Trustee

San Juan Basin Royalty Trust

Opinion on Internal Control Over Financial Reporting

We have audited San Juan Basin Royalty Trust’s (the “Trust”) internal control over financial reporting as of December 31, 2018, based on criteria established in 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, San Juan Basin Royalty Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the statements of assets, liabilities, and trust corpus of San Juan Basin Royalty Trust as of December 31, 2018 and 2017 and the related statements of distributable income and changes in trust corpus for the years then ended December 31, 2018 and our report dated March 18, 2019 expressed an unqualified opinion thereon.

Basis for Opinion

The Trustee is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Trustee’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the entity’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

An entity’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the modified cash basis of accounting described in Note 3 to the financial statements. An entity’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the modified cash basis accounting described in Note 3 to the financial statements, and that receipts and expenditures of the entity are being made only in accordance with authorizations of the Trustee; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

WEAVER AND TIDWELL, L.L.P.

Fort Worth, Texas

March 18, 2019

ITEM 9B.

OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The Trust is managed by a corporate trustee and has no directors, executive officers or employees. Accordingly, the Trust does not have an audit committee, audit committee financial expert, nominating committee or a code of ethics applicable to executive officers. The Trustee has adopted a policy regarding standards of conduct and conflicts of interest applicable to all directors, officers and employees of the Trustee. The Trustee is a corporate trustee which may be removed, with or without cause, at a meeting of the Unit Holders, by the affirmative vote of the holders of a majority of all the Units then outstanding.

Section 16(a) Beneficial Ownership Reporting Compliance

The Trust has no directors or officers. Accordingly, only holders of more than 10% of the Trust’s Units are required to file with the SEC initial reports of ownership of Units and reports of changes in such ownership. Based solely on a review of these reports, the Trust believes that the applicable reporting requirements of Section 16(a) of the Exchange Act were complied with for all transactions which occurred in 2018.

ITEM 11.

EXECUTIVE COMPENSATION

The Trust has no directors, executive officers or employees to whom it pays compensation. The Trust is administered by employees of the Trustee in the ordinary course of their employment who receive no compensation specifically related to their services to the Trust. Accordingly, the Trust does not have a compensation committee or maintain any equity compensation plans, and there are no Units reserved for issuance under any such plans.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY HOLDER MATTERS

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.

Security Ownership of Certain Beneficial Owners

The following table sets forth as of February 12, 2019 information with respect to the Unit Holders who were known to the Trustee to be the beneficial owners of more than 5 percent of the outstanding Units.

Name and Address of Beneficial Owner

Number of Units
Beneficially Owned

Percent

First Eagle Investment Management, LLC

1345 Avenue of the Americas

New York, NY 10105 ⁽¹⁾

5,065,927

10.87%

(1)

This information was provided in a Schedule 13G/A filed with the SEC on February 12, 2019 by First Eagle Investment Management, LLC, and which stated First Eagle Investment Management, LLC beneficially holds such Units on behalf of its investment advisory clients and is deemed to have sole voting power with respect to 4,949,408 of the Units and sole power to dispose or to direct the disposition of 5,065,927 of the Units. The First Eagle Global Fund, a registered investment Company for which First Eagle Investment Management, LLC acts as investment adviser, may be deemed to beneficially own 3,908,035of these 5,065,927 units, or 8.38% of the outstanding Units.

Security Ownership of Trustee

Compass Bank serves as agent and custodian for certain customer accounts. As of February 6, 2019, Compass Bank could be deemed to beneficially own 50,400 Units related to these accounts, or less than one percent of the outstanding Units. Compass Bank has sole voting power over 400 of these Units and no voting power over the remaining 50,000, and has sole power to dispose of 400 of such Units. Compass Bank does not have a pecuniary interest in any of these Units.

Changes in Control

The Trustee knows of no arrangement, including any pledge by any person of Units of the Trust, the operation of which may at a subsequent date result in a change of control of the Trust.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The Trust has no directors or executive officers, therefore no determination been made relative to director independence. See Item 11 for the remuneration received by the Trustee during the year ended December 31, 2018 and Item 12 for information concerning Units owned by the Trustee.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table presents fees for professional audit services rendered by Weaver and Tidwell, L.L.P., the Trust’s principal accountants, for the audit of the Trust’s annual financial statements for the fiscal years ended December 31, 2018 and 2017 and fees billed for other services rendered to the Trust by Weaver and Tidwell, L.L.P. during those periods.


	2018		2017
Audit Fees	$	93,195	$	91,250
Audit-Related Fees		-0-		-0-
Tax Fees		2,805		4,750
All Other Fees		-0-		-0-

Total	$	96,000	$	96,000

Audit Fees consist of fees billed for professional services rendered for the audit of the Trust’s annual financial statements and internal control over financial reporting, review of the interim financial statements included in the Trust’s quarterly reports and services that are normally provided by Weaver and Tidwell, L.L.P. in connection with statutory and regulatory filings or engagements.

Audit-Related Fees consist of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of the Trust’s financial statements. This category includes fees related to audit and attest services not required by statute or regulations and consultations concerning financial accounting and reporting standards.

Tax Fees consist of fees for professional services billed for tax compliance, tax advice and tax planning. These services include assistance regarding federal and state tax compliance.

All Other Fees consist of fees billed for products and services other than the services reported above.

The Trust has no directors or executive officers. Accordingly, the Trust does not have an audit committee and there are no audit committee pre-approval policies or procedures relating to services provided by the Trust’s independent accountants. Pursuant to the terms of the Indenture, the Trustee engages and approves all services rendered by the Trust’s independent accountants.

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents are filed as a part of this Annual Report on Form 10-K:

Financial Statements

Included in Part II of this Annual Report on Form 10-K:

Report of Independent Registered Public Accounting Firm

Statements of Assets, Liabilities and Trust Corpus

Statements of Distributable Income

Statements of Changes in Trust Corpus

Notes to Financial Statements

Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting

Financial Statement Schedules

Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.

Exhibits


Exhibit Number		Description

4(a)		San Juan Basin Amended and Restated Royalty Trust Indenture, dated December 12, 2007, filed as Exhibit 99.2 to the Trust’s Current Report on Form 8-K filed with the SEC on December 14, 2007, and incorporated herein by reference.*

4(b)		Net Overriding Royalty Conveyance from Southland Royalty Company to The Fort Worth National Bank, as Trustee, dated November 3, 1980 (without Schedules), filed as Exhibit 4(b) to the Trust’s Annual Report on Form 10-K filed with the SEC for the year ended December 31, 2006, incorporated herein by reference.*

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

10		Indemnification Agreement, dated May 13, 2003, with effectiveness as of July 30, 2002, by and between Lee Ann Anderson and San Juan Basin Royalty Trust, heretofore filed as Exhibit 10(a) to the Trust’s Quarterly Report on Form 10-Q filed with the SEC for the quarter ended March 31, 2003, is incorporated herein by reference.*

23		Consent of Cawley, Gillespie & Associates, Inc., reservoir engineer.**

31		Certification required by Rule 13a-14(a), dated March 18, 2019, by Joshua R. Peterson, Senior Vice President and Trust Officer of Compass Bank, the Trustee of the Trust.**

32		Certification required by Rule 13a-14(b), dated March 18, 2019, by Joshua R. Peterson, Senior Vice President and Trust Officer of Compass Bank, on behalf of Compass Bank, the Trustee of the Trust.***

99.1		Independent Petroleum Engineers’ Report prepared by Cawley, Gillespie & Associates, Inc., dated March 5, 2019.**

*	A copy of this Exhibit is available to any Unit Holder (free of charge) upon written request to the Trustee, Compass Bank, 300 W. 7 ^th St., Suite B, Fort Worth, Texas 76102.

**	Filed herewith.

***	Furnished herewith.

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


SAN JUAN BASIN ROYALTY TRUST

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

	/s/ Joshua R. Peterson
	By:	Joshua R. Peterson
		Senior Vice President and Trust Officer