UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM10-K

(Mark One)

For the fiscal year ended December 31, 20192020

OR

Commission file number1-8033

PERMIAN BASIN ROYALTY TRUST

(Exact Name of Registrant as Specified in the Permian Basin Royalty Trust Indenture)

Royalty Trust Management

Simmons Bank

2911 Turtle Creek Boulevard

Suite 850

Dallas, Texas 75219

(Address of Principal Executive Offices; Zip Code)

(855)588-7839

(Registrant’s Telephone Number, Including Area Code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:

None

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 every Interactive Data File required to be submitted pursuant to Rule 405 of RegulationS-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☐        No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, a 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 Rule12b-2 of the Exchange Act.:

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 USC. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule12b-2 of the Act).    Yes  ☐        No  ☑

The aggregate market value of the voting andnon-voting common equity held bynon-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter was $283,847,567.64.

At March 1, 2020,2021, there were 46,608,796 Units of Beneficial Interest of the Trust outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None.

FORWARD LOOKING INFORMATION

Certain information included in this report contains, and other materials filed or to be filed by the Trust with the Securities and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by the Trust) may contain or include, forward looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Such forward looking statements may be or may concern, among other things, capital expenditures, drilling activity, development activities, production efforts and volumes, hydrocarbon prices and the results thereof, and regulatory matters. Although the Trustee believes that the expectations reflected in such forward-looking statements are reasonable, such expectations are subject to numerous risks and uncertainties and the Trustee can give no assurance that they will prove correct. There are many factors, none of which are within the Trustee’s control, that may cause such expectations not to be realized, including, among other things, factors such as actual oil and gas prices and the recoverability of reserves, capital expenditures, general economic conditions, actions and policies of petroleum-producing nations and other changes in the domestic and international energy markets and the factors identified under Item 1A, “Risk Factors.” Such forward looking statements generally are accompanied by words such as “estimate,” “expect,” “predict,” “anticipate,” “goal,” “should,” “assume,” “believe,” or other words that convey the uncertainty of future events or outcomes.

i

TABLE OF CONTENTS

ii

PART I

The Permian Basin Royalty Trust (the “Trust”) is an express trust created under the laws of the state of Texas by the Permian Basin Royalty Trust Indenture (the “Trust Indenture”) entered into on November 3, 1980, between Southland Royalty Company (“Southland Royalty”) and The First National Bank of Fort Worth, as Trustee. Simmons Bank, an Arkansas state-chartered bank (“Simmons Bank”), is now the Trustee of the Trust. The principal office of the Trust (sometimes referred to herein as the “Registrant”) is located at 2911 Turtle Creek Boulevard, Suite 850, Dallas, Texas (telephone number (855)588-7839).

On January 9, 2014, Bank of America N.A. (as successor to The First National Bank of Fort Worth) gave notice to Unit holders that it would be resigning as trustee of the Trust subject to certain conditions that included the appointment of Southwest Bank as successor trustee. At a Special Meeting of Trust Unit holders, the Unit holders approved the appointment of Southwest Bank as successor trustee of the Trust once the resignation of Bank of America N.A. took effect and also approved certain amendments to the Trust Indenture. The effective date of Bank of America N.A.’s resignation and the effective date of Southwest Bank’s appointment as successor trustee was August 29, 2014.

Effective October 19, 2017, Simmons First National Corporation (“SFNC”) completed its acquisition of First Texas BHC, Inc., the parent company of Southwest Bank. SFNC is the parent company of Simmons Bank. SFNC merged Southwest Bank with Simmons Bank effective February 20, 2018. The defined term “Trustee” as used herein shall refer to Bank of America N.A. for periods prior to August 29, 2014, and shall refer to Southwest Bank for periods from August 29, 2014 through February 19, 2018 and shall refer to Simmons Bank for periods on and after February 20, 2018.

On October 23, 1980, the stockholders of Southland Royalty approved and authorized that company’s conveyance of net overriding royalty interests (equivalent to net profits interests) to the Trust for the benefit of the stockholders of Southland Royalty of record at the close of business on the date of the conveyance consisting of a 75% net overriding royalty interest carved out of that company’s fee mineral interests in the Waddell Ranch properties in Crane County, Texas and a 95% net overriding royalty interest carved out of that company’s major producing royalty properties in Texas. The conveyance of these interests (the “Royalties”) was made on November 3, 1980, effective as to production from and after November 1, 1980 at 7:00 a.m. The properties and interests from which the Royalties were carved and which the Royalties now burden are collectively referred to herein as the “Underlying Properties.” The Underlying Properties are more particularly described under “Item 2. Properties” herein.

The function of the Trustee is to collect the income attributable to the Royalties, to pay all expenses and charges of the Trust, and then to distribute the remaining available income to the Unit holders. The Trust is not empowered to carry on any business activity and has no employees, all administrative functions being performed by the Trustee.

The Royalties constitute the principal asset of the Trust and the beneficial interests in the Royalties are divided into that number of Units of Beneficial Interest (the “Units”) of the Trust equal to the number of shares of the common stock of Southland Royalty outstanding as of the close of business on November 3, 1980. Each stockholder of Southland Royalty of record at the close of business on November 3, 1980, received one Unit for each share of the common stock of Southland Royalty then held.

In 1985, Southland Royalty became a wholly-owned subsidiary of Burlington Northern Inc. (“BNI”). In 1988, BNI transferred its natural resource operations to Burlington Resources Inc. (“BRI”) as a result of which Southland Royalty became a wholly-owned indirect subsidiary of BRI. As a result of this transfer, Meridian Oil Inc., a Delaware corporation (“MOI”), which was the parent company of Southland Royalty, became a wholly owned direct subsidiary of BRI. Effective January 1, 1996, Southland Royalty was merged with and into MOI. As a result of this merger, the separate corporate existence of Southland Royalty ceased and MOI survived and succeeded to the ownership of all of the assets of Southland Royalty and assumed all of its rights, powers, privileges, liabilities and obligations. Effective July 11, 1996,

MOI changed its name to Burlington Resources Oil & Gas Company, now Burlington Oil & Gas Company LP (“BROG”). Any reference to BROG hereafter for periods prior to the occurrence of the aforementioned name change or merger should, as applicable, be construed to be a reference to MOI or Southland Royalty. Further, BROG notified the Trust that, on February 14, 1997, the Texas Royalty properties (as defined herein on page 8)10) that are subject to the Net Overriding Royalty Conveyance dated November 1, 1980 (the “Texas Royalty Conveyance”), were sold to Riverhill Energy Corporation (“Riverhill Energy”) of Midland, Texas. Effective March 31, 2006, ConocoPhillips acquired BRI pursuant to a merger between BRI and a wholly-owned subsidiary of ConocoPhillips. As a result of this acquisition, BRI and BROG are both wholly-owned subsidiaries of ConocoPhillips.

BROG notified the Trust, that on November 1, 2019, the Waddell Ranch properties (as defined herein on page 8)10) that are subject to the Net Overriding Royalty Conveyance (Permian Basin Royalty Trust — Waddell Ranch) dated November 1, 1980 (the ‘‘Waddell“Waddell Ranch Conveyance”), were sold to Blackbeard Operating, LLC (“Blackbeard”) of Fort Worth, Texas. Blackbeard will becomebecame the operator effective as of April 1, 2020.

The term “net proceeds” is used in the above described conveyance and means the excess of “gross proceeds” received by the owner of the Underlying Properties during a particular period over “production costs” for such period. “Gross proceeds” means the amount received by the owner of the Underlying Properties from the sale of the production attributable to the Underlying Properties, subject to certain adjustments. “Production costs” means, generally, costs incurred on an accrual basis in operating the Underlying Properties, including both capital andnon-capital costs; for example, development drilling, production and processing costs, applicable taxes, and operating charges. 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 liable for any production costs or liabilities attributable to these properties and interests or the minerals produced therefrom. If at any time the Trust receives more than the amount due from the Royalties, it shall not be obligated to return such overpayment, but the amounts payable to it for any subsequent period shall be reduced by such overpaid amount, plus interest, at a rate specified in the conveyance.

To the extent it has the legal right to do so, the owner of the Underlying Properties is responsible for marketing the production from such properties and interests, 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. The owner of the Underlying Properties also has the obligation to maintain books and records sufficient to determine the amounts payable to the Trustee. The owner of the Underlying Properties, however, can sell its interests in the Underlying Properties.

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

Cash held by the Trustee as a reserve for liabilities or contingencies (which reserves may be established by the Trustee in its discretion) or pending distribution is placed, at 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 a capital surplus and undivided profits in excess of $50,000,000, or other interest bearing accounts in FDIC-insured state or national banks, including the Trustee, so long as the entire amount in such account is at all times fully insured by the FDIC, subject, in each case, to certain other qualifying conditions.

The income to the Trust attributable to the Royalties is not subject in material respects to seasonal factors nor in any manner related to or dependent upon patents, licenses, franchises or concessions. The Trust conducts no research activities. The Trust has no employees since all administrative functions are performed by the Trustee.

BROG,Blackbeard, as the current operator, has advised the Trustee that it believes that comparable revenues could be obtained in the event of a change in purchasers of production.

the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production levels;

Changes in any of these factors and assumptions can materially change reserve and future net revenue estimates. The Trust’s estimate of reserves and future net revenues is further complicated because the Trust holds an interest in net overriding royalties and does not own a specific percentage of the crude oil or natural gas reserves. Ultimately, actual production, revenues and expenditures for the Underlying Properties, and therefore actual net proceeds payable to the Trust, will vary from estimates and those variations could be material. Results of drilling, testing and production after the date of those estimates may require substantial downward revisions or write-downs of reserves.

Operational risks and hazards associated with the development of the Underlying Properties may decrease Trust distributions.

There are operational risks and hazards associated with the production and transportation of crude oil and natural gas, including without limitation natural disasters, blowouts, explosions, fires, leakage of crude oil or natural gas, releases of other hazardous materials, mechanical failures, cratering, and pollution. Any of these or similar occurrences could result in the interruption or cessation of operations, personal injury or loss of life, property damage, damage to productive formations or equipment, or damage to the environment or natural resources, or cleanup obligations. The operation of oil and gas properties is also subject to various laws and regulations.Non-compliance with such laws and regulations could subject the operator to additional costs, sanctions or liabilities. The uninsured costs resulting from any of these or similar occurrences could be deducted as a cost of production in calculating the net proceeds payable to the Trust and would therefore reduce Trust distributions by the amount of such uninsured costs.

As of December 31, 2019,2020, oil and gas production from the Waddell Ranch properties is processed through a single facility, future distributions from those properties may be particularly susceptible to such risks. A partial or complete shut down of operations at that facility could disrupt the flow of royalty payments to the Trust and, accordingly, the

Terrorism and continued hostilities in the Middle East could decrease Trust distributions or the market price of the Units.

Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as the military or other actions taken in response, cause instability in the global financial and energy markets. Terrorism and sustained military campaigns could adversely affect Trust distributions or the market price of the Units in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in crude oil and natural gas prices, or the possibility that the infrastructure on which the operators developing the Underlying Properties rely could be a direct target or an indirect casualty of an act of terror.

Unit holders and the Trustee have no influence over the operations on, or future development of, the Underlying Properties.

Neither the Trustee nor the Unit holders can influence or control the operations on, or future development of, the Underlying Properties. The failure of an operator to conduct its operations, discharge its obligations, deal with regulatory agencies or comply with laws, rules and regulations, including environmental laws and regulations, in a proper manner could have an adverse effect on the net proceeds payable to the Trust. The current operators developing the Underlying Properties are under no obligation to continue operations on the Underlying Properties. Neither the Trustee nor the Unit holders have the right to replace an operator.

The operators developing the Texas Royalty properties have no duty to protect the interests of the Unit holders and do not have sole discretion regarding development activities on the Underlying Properties.

Under the terms of a typical operating agreement relating to oil and gas properties, the operator owes a duty to working interest owners to conduct its operations on the properties in a good and workmanlike manner and in accordance with its best judgment of what a prudent operator would do under the same or similar circumstances. BROGBlackbeard is currently the operator of record of the Waddell Ranch overriding royalty interests and in such capacity owes the Trust a contractual duty under the conveyance agreement for that overriding royalty interest to operate the Waddell Ranch properties in good faith and in accordance with a prudent operator standard. The operators of the properties burdened by the Texas Royalty properties’ overriding royalty interests, however, have no contractual or fiduciary duty to protect the interests of the Trust or the Unit holders other than indirectly through its duty of prudent operations to the unaffiliated owners of the working interests in those properties.

In addition, even if an operator, including BROGBlackbeard in the current case of the Waddell Ranch properties (as defined herein on page 8)10), concludes that a particular development operation is prudent on a property, it may be unable to undertake such activity unless it is approved by the requisite approval of the working interest owners of such properties (typically the owners of at least a majority of the working interests). Even if the Trust concludes that such activities in respect of any of its overriding royalty interests would be in its best interests, it has no right to cause those activities to be undertaken.

The operator developing any Underlying Property may transfer its interest in the property without the consent of the Trust or the Unit holders.

Any operator developing any of the Underlying Properties may at any time transfer all or part of its interest in the Underlying Properties to another party. Neither the Trust nor the Unit holders are entitled to vote on any transfer of the

The operator developing any Underlying Property may abandon the property, thereby terminating the Royalties payable to the Trust.

The operators developing the Underlying Properties, or any transferee thereof, may abandon any well or property without the consent of the Trust or the Unit holders if they reasonably believe that the well or property can no longer produce in commercially economic quantities. This could result in the termination of the Royalties relating to the abandoned well or property.

The Royalties can be sold and the Trust would be terminated.

The Trustee must sell the Royalties if the holders of 75% or more of the Units approve the sale or vote to terminate the Trust. The Trustee must also sell the Royalties if they fail to generate net revenue for the Trust of at least $1,000,000 per year over any consecutivetwo-year period. Sale of all of the Royalties will terminate the Trust. The net proceeds of any sale will be distributed to the Unit holders. The sale of the remaining Royalties and the termination of the Trust will be taxable events to the Unit holders. Generally, a Unit holder will realize gain or loss equal to the difference between the amount realized on the sale and termination of the Trust and his adjusted basis in such Units. Gain or loss realized by a Unit holder who is not a dealer with respect to such Units and who has a holding period for the Units of more than one year will be treated as long-term capital gain or loss except to the extent of any depletion recapture amount, which must be treated as ordinary income. Other federal and state tax issues concerning the Trust are discussed under Note 4 and Note 7 to the Trust’s financial statements, which are included herein. Each Unit holder should consult his own tax advisor regarding Trust tax compliance matters, including federal and state tax implications concerning the sale of the Royalties and the termination of the Trust.

Unit holders have limited voting rights and have limited ability to enforce the Trust’s rights against the current or future operators developing the Underlying Properties.

The voting rights of a Unit holder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Unit holders or for an annual or other periodicre-election of the Trustee.

The Trust indenture and related trust law permit the Trustee and the Trust to sue BROG,Blackbeard, Riverhill Energy Corporation or any other future operators developing the Underlying Properties to compel them to fulfill the terms of the conveyance of the Royalties. If the Trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of the Unit holders would likely be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. Unit holders probably would not be able to sue BROG,Blackbeard, Riverhill Energy Corporation or any other future operators developing the Underlying Properties.

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

The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States (“GAAP”). Although this basis of accounting is permitted for royalty trusts by the U.S. Securities and Exchange Commission the (“SEC”), the financial statements of the Trust differ from GAAP financial statements mainly because revenues are not accrued in the month of production and cash reserves may be established which would not be accrued in GAAP financial statements. Further, Trust expenses are recorded when paid and not in the month they were incurred.

to be satisfied only out of Trust assets, under the laws of Texas, which are unsettled on this point, a holder of Units may be jointly and severally liable for any liability of the Trust if the satisfaction of such liability was not contractually limited to the assets of the Trust and the assets of the Trust and the Trustee are not adequate to satisfy such liability. As a result, Unit holders may be exposed to personal liability.

The tax treatment of an investment in Trust Units could be affected by recent and potential legislative changes, possibly on a retroactive basis.

U.S. federal tax reform legislation informally known as the Tax Cuts and Jobs Act (the “TCJA”) was enacted December 22, 2017, and makes significant changes to the federal income tax rules applicable to both individuals and entities, including changes to the effective tax rate on a Unit holder’s allocable share of certain income from the Trust. The TCJA is complex and lacks administrative guidance, thus, Unit holders should consult their tax advisor regarding the TCJA and its effect on an investment in Trust Units. In addition, President Biden’s administration has generally proposed repealing fossil fuel tax subsidies, which could impact certain tax benefits available to Trust Unit holders.

For taxable years beginning after 2017, the highest marginal U.S. federal income tax rates applicable to ordinary income and long-term capital gains of individuals are 37% and 20%, respectively. Any modification to the U.S. federal income tax laws or interpretations thereof (including administrative guidance relating to the TCJA) may be applied retroactively and could adversely affect the Trust’s business, financial condition or results of operations. The Trust is unable to predict whether any changes or other proposals will ultimately be enacted, or whether any adverse interpretations will be issued. Any such changes or interpretations could negatively impact the value of an investment in the Trust Units.

The recent spread of COVID-19, or the novel coronavirus, and the measures taken to mitigate the impact of the COVID-19 pandemic, are likely adversely affecting the business and operations of the operators of the Waddell Ranch properties and the Texas royalty properties, which in turn could have an adverse effect on trust distributions.

The business of the operators of the Waddell Ranch properties and the Texas Royalty properties is likely being adversely affected by the COVID-19 pandemic and measures being taken to mitigate its impact. As the coronavirus pandemic and government responses are rapidly evolving, the extent of the impact on domestic sales of crude oil and natural gas remains unknown and is constantly evolving. The oil and gas industry experienced a sharp and rapid decline in the demand for crude oil and natural gas as the U.S. and global economy, and commodity prices, were negatively impacted as economic activity is curtailed in response to the COVID-19 pandemic. Prices have rebounded somewhat but continue to fluctuate. Official restrictions on non-essential activities, including “shelter in place” and “stay at home” orders, have been introduced and re-introduced throughout the U.S. and the world, and the length of time for which they will remain continues to be unknown, which may impact production activities by the operators of the Underlying Properties, and the length of time such measures are in place may further adversely affect the income the Trust receives from the Royalties. Fewer businesses than normal are open and fewer people are going to work which has reduced the demand for oil and natural gas, plus reliance by the operators of the Underlying Properties on third-party suppliers, contractors, and service providers exposes them to possibility of delay or interruption of operations. At this time, the full extent to which COVID-19 will negatively impact the global economy and the oil and gas industry is uncertain, but pandemics or other significant public health events will most likely have a material adverse effect on the operators’ business and financial condition which would likely have an adverse effect on trust distributions.

The Trust has not received any written comments from the Securities and Exchange Commission staff regarding its periodic or current reports under the Act not less than 180 days before December 31, 2019, 2020,

which comments remain unresolved.

The net overriding royalties conveyed to the Trust (the “Royalties”) include: (1) a 75% net overriding royalty carved out of Southland Royalty’s fee mineral interests in the Waddell Ranch in Crane County, Texas (the “Waddell

Ranch properties”); and (2) a 95% net overriding royalty carved out of Southland Royalty’s major producing royalty interests in Texas (the “Texas Royalty properties”). The interests out of which the Trust’s net overriding royalty interests were carved were in all cases less than 100%. The Trust’s net overriding royalty interests represent burdens against the properties in favor of the Trust without regard to ownership of the properties from which the overriding royalty interests were carved. The net overriding royalty for the Texas Royalty properties is subject to the provisions of the lease agreements under which such royalties were created. References below to “net” wells and acres are to the interests of the owner of the Underlying Properties (from which the Royalties were carved) in the “gross” wells and acres.

A production index for oil and gas properties is the number of years derived by dividing remaining reserves by current production. The production index for the Trust properties based on the reserve report prepared by independent petroleum engineers as of December 31, 2019,2020, is approximately 9.810.1 years.

Blackbeard has advised the Trustee that the total amount of capital expenditures for 20192020 with regard to the Waddell Ranch properties totaled $6.6$10.4 million (gross). Capital expenditures include the cost of remedial and maintenance activities. The amount spent on remedial and maintenance activities iswas approximately $3.3 million$71,000 of the budgeted amount projectedexpended by BROG for 2019.Blackbeard in 2020.

BROGBlackbeard has advised the Trustee that the capital expenditures budget for 20202021 totals approximately $1.35$86.6 million (gross) ($0.632.5 million net to the Trust), of which approximately $1.35$1.5 million (gross) is attributable to facilities. Accordingly, there is a 88% decreasein$76.2 million increasein capital expenditures for 20202021 as compared with the 20192020 capital expenditures. The major reason for the variance is the decreased prices. There will be no91 new drill wells and no24 recompletions in 20202021 as compared to 216 new drill wells and 03 recompletion in 2019. The foregoing capital expenditures budget may be subject to revision after Blackbeard assumes the role of operator of the Waddell Ranch properties on April 1, 2020.

OIL AND GAS PRODUCTION

The Trust recognizes production during the month in which the related distribution is received. Production of oil and gas attributable to the Royalties and the Underlying Properties, the related average sales prices and the average production cost per unit of production attributable to the Underlying Properties for the three years ended December 31, 2019,2020, excluding portions attributable to the adjustments discussed below, were as follows:

Since the oil and gas sales attributable to the Royalties are based on an allocation formula that is dependent on such factors as price and cost (including capital expenditures), production amounts do not necessarily provide a meaningful comparison.

Waddell Ranch properties lease operating expense for 20192020 was $23.4$19.6 million (gross). The lease operating expense increaseddecreased from $23.1$23.4 in 20182019 primarily because of increasingdecreasing activity and facilities maintenance. Waddell Ranch lifting cost on a barrel of oil equivalent (BOE) basis was $25.19/$32.92/bbl as compared to $25.19 in 20182019 and $13.38$20.30 in 2017.2018.

PRICING INFORMATION

Reference is made to the caption entitled “Regulation” for information as to federal regulation of prices of natural gas. The following paragraphs provide information regarding sales of oil and gas from the Waddell Ranch properties. As a royalty owner, Riverhill Energy is not furnished detailed information regarding sales of oil and gas from the Texas Royalty properties.

Oil.    The Trustee has been advised by the operator that since June 2006, the oil from the Waddell Ranch has been marketed by the operator by soliciting bids from third parties on an outright sale basis of production listed in bid packages.

Gas.    The gas produced from the Waddell Ranch properties is processed through a natural gas processing plant and sold at the tailgate of the plant. Plant products are marketed by Burlington Resources Trading Inc., an indirect subsidiary of BRI. The processor of the gas (Warren Petroleum Company, L.P.) receives 15% of the liquids and residue gas as a fee for gathering, compression, treating and processing the gas.

OIL AND GAS RESERVES

The following are definitions adopted by the SEC and the Financial Accounting Standards Board which are applicable to terms used within this Item:

“Proved oil and gas reserves” are those quantities of oil and 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of thefirst-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“Developed oil and gas reserves” are 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.

“Estimated future net revenues” are computed by applying average prices during the12-month period prior to fiscalyear-end determined as an unweighted arithmetic average of thefirst-day-of-the-month benchmark price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, and assuming continuation of existing economic conditions. “Estimated future net revenues” are sometimes referred to herein as estimated future net cash flows.

“Present value of estimated future net revenues” is computed using the estimated future net revenues and a discount factor of 10%.

“Reserves” are estimated remaining quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.

“Undeveloped oil and gas reserves” are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) 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.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for 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, as defined in 17 CFR210.4-10(a)(2), or by other evidence using reliable technology establishing reasonable certainty.

The process of estimating oil and gas reserves is complex and requires significant judgment. As a result, the Trustee has developed internal policies and controls for estimating reserves. As described above, the Trust does not have information that would be available to a company with oil and gas operations because detailed information is not generally available to owners of royalty interests. The Trustee gathers production information (which information is net to the Trust’s interests in the Underlying Properties) and provides such information to Cawley, Gillespie & Associates, Inc., who extrapolates from such information estimates of the reserves attributable to the Underlying Properties based on its expertise in the oil and gas fields where the Underlying Properties are situated, as well as publicly available information. The Trust’s policies regarding reserve estimates require proved reserves to be in compliance with the SEC definitions and guidance.

The independent petroleum engineers’ reports as to the proved oil and gas reserves attributable to the Royalties conveyed to the Trust were obtained from Cawley, Gillespie & Associates, Inc. Cawley, Gillespie & Associates, Inc. has been in business since 1973 when the petroleum consulting firm Keller & Augustson merged with the petroleum consulting firm Cawley, Harrington & Gillespie. The primary business of Cawley, Gillespie & Associates, Inc. is the estimation and evaluation of petroleum reserves. Kenneth J. Mueller, has been employed by Cawley, Gillespie & Associates, Inc. since 1996. Mr. Mueller attended Texas A&M University from 1975 to 1979, graduating with a Bachelor of Science degree, Summa Cum Laude, in Petroleum Engineering in 1979, and has in excess of twenty yearsyears’ experience in oil and gas reserves studies and evaluations. Mr. Mueller is a licensed professional engineer with the Texas Board of Professional Engineers and a member of the Texas Society of Professional Engineers.

Cawley, Gillespie & Associates, Inc.’s reports are attached as exhibits to this Form10-K. The following table presents a reconciliation of proved reserve quantities from January 1, 20172018 through December 31, 20192020 (in thousands):

Estimated quantities of proved reserves and net cash flow as of December 31, 20192020 are as follows:

Average oil and gas prices of $55.69 per barrel and $2.58 per Mcf were used to determine the estimated future net revenues from the Waddell Ranch properties and the Texas Royalty properties, respectively, at December 31, 2019. The downward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties are primarily due to weaker pricing for oil and by weaker gas pricing. The Texas Royalty Propertiesproperties are revised downward due to weaker pricing for oil.

Exploration and production operations are subject to various types of regulation at the federal, tribal, state and local levels. Such regulation includes requiring permits for the drilling and production of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, controlling and remediating pollution from exploration and production activities, proper handling and disposal of waste generated from exploration and production operations, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. Natural gas and oil operations are also subject to various conservation laws and regulations that regulate the size of drilling and spacing units or proration units and the density of wells which may be drilled and unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum allowable production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of natural gas and oil that can be produced, potentially to raise prices, and to limit the number of wells or the locations which can be drilled.

Federal Natural Gas Regulation

The Federal Energy Regulatory Commission (the “FERC”) is primarily responsible for federal regulation of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal governmental regulation, including regulation of transportation and storage tariffs and various other matters, by the FERC. On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or the FERC rules, regulations or orders thereunder. Wellhead sales of domestic natural gas are not subject to regulation. Consequently, sales of natural gas may be made at market prices, subject to applicable contract provisions.

Sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. Several major regulatory changes have been implemented by Congress and the FERC from 1985 to the present that affect the economics of natural gas production, transportation, and sales. In addition, the 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 the 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 and these initiatives generally reflect more light-handed regulation of the natural gas industry. The ultimate impact of the rules and regulations issued by the FERC since 1985 cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial decisions and final decisions by the FERC.

New proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the 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 recently pursued by the FERC and Congress will continue.

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. Crude oil prices are affected by a variety of factors. Since domestic crude price controls were lifted in 1981, the principal factors influencing the prices received by producers of domestic crude oil have been the pricing and production of the members of the Organization of Petroleum Export Countries (OPEC).

On December 19, 2007, President Bush signed into law the Energy Independence & Security Act of 2007 (PL 110 140). The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations, and establishes penalties for violations thereunder.

State Regulation

The various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rates of production may be regulated and the maximum daily production allowables from both oil and gas wells may be established on a market demand or conservation basis, or both.

Local Regulation

Drilling for and production and transportation of crude oil and natural gas are also regulated by local authorities. Local laws may include land use regulations, permitting requirements, and noise and traffic ordinances. Such regulation could increase drilling and production costs or create delays in development and production of the Underlying Properties.

Environmental Regulation

Companies in the oil and gas industry are subject to stringent and complex federal, tribal, state and local laws and regulations governing the health and safety aspects of oil and gas operations, the management and discharge of materials into the environment, or otherwise relating to environmental protection. Those laws and regulations may impose numerous obligations that are applicable to the operations of the Underlying Properties, including the acquisition of a permit before conducting drilling, production or underground injection activities; the restriction on the types, quantities and concentrations of materials that can be emitted or released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, endangered or threatened species habitat, and other protected areas; the installation of emission monitoring and/or pollution control equipment; the reporting of the types and quantities of various substances that are stored, processed, or released in connection with operation of the Underlying Properties; the remediation of pollution from current or former operations, such as cleanup of releases, pit closure, removal of surface equipment and plugging of abandoned wells; the planning and preparedness for spill and emergency response activities; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from operations including waste generation, air emissions, water discharges and current and historical waste disposal practices. Failure to comply with these laws and regulations 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. Under certain environmental laws and regulations, the operators of the Underlying Properties could also be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination, in either case, whether at a drill site or a waste disposal facility, regardless of whether the operators were responsible for the release or contamination or if the operations were in compliance with all applicable laws at the time those actions were taken.

In addition, climate change is the subject of an important public policy debate and the basis for new legislation proposed by the United States Congress and certain states. Some states have adopted climate change statutes and regulations. The United States Environmental Protection Agency (the “EPA”) has promulgated greenhouse gas monitoring and reporting regulations that, since 2011, have required annual reporting of carbon dioxide, methane and nitrous oxide emissions from certain sources in the oil and natural gas industry sector, including in the onshore oil and natural gas production segment.

Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under Section 202(a) of the Clean Air Act, concluding that greenhouse gas pollution threatens the public health and welfare of future generations. The EPA indicated that it will use data collected through the reporting rules to decide whether to promulgate future greenhouse gas emission limits. On August 16, 2012, the EPA issued a final rule, known as New Source Performance Standards (“NSPS”) Subpart OOOO, that established new source performance standards for volatile organic compounds (“VOC(s)”) and sulfur dioxide, an air toxics standard for major sources of oil and natural gas production, and an air toxics standard for major sources of natural gas transmission and storage. The rule required that, starting January 1,

January 1, 2015, all hydraulically fractured or refractured natural gas wells be completed using reduced emission (“green”) completion technology, which significantly reduces VOC emissions. Limiting emissions of VOCs will have theco-benefit of also limiting methane, a greenhouse gas. These regulations also include requirements applicable to storage tanks and other equipment in the affected oil and natural gas industry segments. On May 12, 2016, the EPA issued a final rule, known as NSPS Subpart OOOOa, establishing additional standards for the reduction of methane, VOCs, and other emissions from new and existing sources in the oil and gas sector. Among other requirements, these new standards require green completion technology for new hydraulically fractured or refractured oil wells. And rulemaking concerning regulation of greenhouse gas and other emissions from the oil and natural gas industry continues: in October 2018, the EPA released proposed revisions to some of the 2016 requirements, including reducing the required frequency of fugitive emissions monitoring at well sites and compressor stations. AsMost recently, as August 2019, EPA has proposed modifications to the NSPS Subpart OOOOpublished two new rules on September 14 and OOOOa rules — for example, proposing to15, 2020 that remove sources in the transmission and storage segmentsectors of the oil and natural gas industry from regulation under the NSPS Subpart OOOO/OOOOa and to rescind methane requirementsmethane-specific standards for allthe production and processing sourcessegments of the industry. However, states and environmental groups brought suit challenging the new rules almost immediately. Although the bulk of the 2012 and 2016 standards are currently in effect, future implementation and the oilultimate scope of the 2012 and natural gas industry or, alternatively, rescind all methane requirements2016 standards are uncertain at this time as a result of these challenges and current uncertainty regarding how the standards may be altered under the rules without removing any sources from the oil and natural gas source category.administration of recently elected U.S. President Biden. Accordingly, the ultimate scope of these regulations remains uncertain.

Congress and various states, including Texas, have proposed or adopted legislation regulating or requiring disclosure of the chemicals in the hydraulic fracturing fluid that is used in the drilling operation. Texas requires oil and gas operators to disclose the chemicals on the Frac Focus website. Hydraulic fracturing has historically been regulated by state oil and natural gas commissions. The EPA, however, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act (the “SDWA”). The EPA has issued permitting guidance for oil and natural gas hydraulic fracturing activities using diesel fuels. Under the guidance, EPA defined the term “diesel” to include five categories of oils, including some such as kerosene, that are not traditionally considered to be diesel.

The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state agency. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. In May 2015, EPA and the U.S. Army Corps of Engineers jointly announced a final rule defining the “Waters of the United States” (“WOTUS”) which are protected under the CWA. The rule, which would have made additional waters expressly Waters of the United States and therefore subject to the jurisdiction of the Clean Water Act, rather than subject to a case-specific evaluation, was stayed by the U.S. Court of Appeals for the Sixth Circuit before it took effect. On February 1, 2018, EPA officially delayed implementation of the 2015 rule until early 2020, and in July 2018, the EPA proposed repeal of the 2015 WOTUS rule. Later that year, EPA’s decision was challenged in court, which resulted in a decision by the U.S. District Court for the District of South Carolina to enjoin EPA’s February 2018 delay rule. Several states then acted to halt reinstatement of the 2015 WOTUS rule, the effect of all of which was that the 2015 WOTUS definition was in effect in 22 states. In September 2019, EPA finalized the repeal of the 2015 WOTUS rule, and the repeal became effective in December 2019, reinstating thepre-2015 standards. Litigation of the repeal quickly ensued. Meanwhile, in December 2018, the EPA and the U.S. Army Corps of Engineers issued a proposed rule to revise the definition of “Waters of the United States.” The rule was finalized in January 2020, and will becomebecame effective 60 days after publication in the Federal Register.on June 22, 2020. The rule narrows the WOTUS definition, excluding, for example, streams that flow only after precipitation and wetlands without a direct surface connection to traditional navigable waters. TheLitigation by parties opposing the rule again quickly followed, including a challenge in the U.S. District Court for the District of Colorado, which resulted in a statewide stay of the rule on June 19, 2020. This ruling is expected to be heavily litigated, which could delay its implementation.currently being appealed in the Tenth Circuit. Regardless, the applicable WOTUS definition affects what CWA permitting or other regulatory obligations may be triggered during development and operation of the Underlying Properties, and changes to the WOTUS definition could cause delays in development and/or increase the cost of development and operation of the Underlying Properties.

Spill prevention, control, and countermeasure (“SPCC”) regulations promulgated under the CWA and later amended by the Oil Pollution Act of 1990 impose obligations and liabilities related to the prevention of oil spills and damages resulting from such spills into or threatening waters of the United States or adjoining shorelines. For example,

In addition, several cases have recently put a spotlight on the issue of whether injection wells may be regulated under the CWA if a direct hydrological connection to a jurisdictional surface water can be established. The split among

There are no material pending legal proceedings to which the Trust is a party or of which any of its property is the subject.

This Item is not applicable to the Trust.

PART II

Units of Beneficial Interest

Units of Beneficial Interest (“Units”) of the Trust are traded on the New York Stock Exchange with the symbol PBT.

Approximately 861Unit828Unit holders of record held the 46,608,796 Units of the Trust at March 2, 2020.9, 2021.

The Trust has no equity compensation plans and has not repurchased any Units during the period covered by this report.

REMOVED AND RESERVED.

Computation of Royalty Income Received by the Trust

The Trust’s royalty income is computed as a percentage of the net profit from the operation of the properties in which the Trust owns net overriding royalty interests. The percentages of net profits are 75% and 95% in the cases of the Waddell Ranch properties and the Texas Royalty properties, respectively. Royalty income received by the Trust for the five years ended December 31, 2019,2020, was computed as shown in the table on the next page.

Trustee’s Discussion and Analysis for the Three-Year Period Ended December 31, 20192020

Liquidity and Capital Resources

As stipulated in the Trust Agreement, the Trust is intended to be passive in nature and the Trustee does not have any control over or any responsibility relating to the operation of the Underlying Properties. The Trustee has powers to collect and distribute proceeds received by the Trust and pay Trust liabilities and expenses and its actions have been limited to those activities. The Trust is a passive entity and other than the Trust’s ability to periodically borrow money as necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited from engaging in borrowing transactions. As a result, other than such borrowings, if any, the Trust has no source of liquidity or capital resources other than the Royalties.

Results of Operations

Royalty income received by the Trust for the three-year period ended December 31, 2019,2020, is reported in the following table:

Royalty income of the Trust for the calendar year is associated with actual oil and gas production for the period November of the prior year through October of the current year. Oil and gas production for 2020, 2019 2018 and 20172018 generated by the Royalties and the Underlying Properties, excluding portions attributable to the adjustments discussed hereafter, are presented in the following table:

The average price of oil decreased to $39.51 per barrel in 2020, down from $51.74 per barrel in 2019, down from $58.11 per barrel in 2018.2019. The average price of oil in 20172018 was $45.88$58.11 per barrel. In addition, the average price of gas decreased from $3.55 per Mcf in 2018 to $2.64 per Mcf in 2019.2019 to $1.47 per Mcf in 2020. The average price of gas in 20172018 was $3.28$3.55 per Mcf. Oil prices have decreased primarily because of world market conditions.conditions and the negative impact of the COVID-19 pandemic on economic activity. Oil prices are expected to remain volatile. Gas liquids values remain weaker and keep the prices of gas weaker.weaker in addition to not receiving revenue from Blackbeard on the Waddell NPI due to excess costs of new drilling.

Subsequent to December 31, 2019,2020, the price of both oil and gas continued to fluctuate, giving rise to a correlating adjustment of the respective standardized measure of discounted future net cash flows. As of March 6, 2020,10, 2021, NYMEX posted oil prices were approximately $41.14$64.75 per barrel, which compared to the posted price of $55.68$39.57 per barrel, used to calculate the worth of future net revenue of the Trust’s proved developed reserves, would result in a smaller standardized measure of discounted future net cash flows for oil. As of March 6, 2020,10, 2021, NYMEX posted gas prices were $1.89$2.69 per million British thermal units. The use of such price, as compared to the posted price of $2.58$2.00 per million British thermal units, used to calculate the future net revenue of the Trust’s proved developed reserves would result in a smaller standardized measure of discounted future net cash flows for gas.

Since the oil and gas sales attributable to the Royalties are based on an allocation formula that is dependent on such factors as price and cost (including capital expenditures), production amounts do not necessarily provide a meaningful comparison. For the underlying properties total oil production decreased by approximately 2.6%5% from 20182019 to 20192020 primarily due to the natural decline of production. For the underlying properties total gas production decreasedincreased approximately 15.4%5% from 20182019 to 20192020 primarily due to the natural decline of production.

On May 2, 2011, ConocoPhillips, as the parent company of BROG, the then-operator of theadditional production on Waddell Ranch properties, notified the Trustee that as a result of inaccuracies in ConocoPhillips’ accounting and record keeping relatingdue to the Trust’s interest in proceeds from the gas plant production since January 2007, ConocoPhillips overpaid the Trust approximately $5.9 million initially. ConocoPhillips withheld $4.5 million from the proceeds for 2011 pending completions to the corrections of the accounting procedures. Beginning with the October 2012 distribution, previously withheld proceeds of $4.5 million were reimbursed by ConocoPhillips to the Trust ($4.0 million and $0.5 million in 2013 and 2012, respectively). ConocoPhillips has adjusted the monthly royalty payments to the Trust since October 2012 by the related reimbursed amounts to reflect ConocoPhillips’ ongoing correction of past and current production and royalty allocations and the payment of the previously withheld proceeds. These adjustments were completed in the first quarter of 2015. The Trust’s reported royalty income for the years ended December 31, 2019, 2018 and 2017 was not significantly impacted by these offsetting amounts. At this time, the Trustee considers all such corrections and adjustment to be accurate and fairly performed.new drilling.

Total capital expenditures in 20192020 used in the net overriding royalty calculation were approximately $3.3$10.3 million (gross) compared to $3.3 million (gross) in 2019 and $730,000 (gross) in 2018 and $1.9 million (gross) in 2017.2018. The operator of the Waddell Ranch properties has informed the Trustee that, in order to halt the production decline curve and to exploit the remaining potential of the Trust’s assets more fully, a more aggressive, robust capital expenditure budget will be necessary in the future and is being pursued.

In 2018,2019, there were 0 recompletion wells completed and 190 wells permanently plugged on the Waddell Ranch properties. Actual costs for this program in 20182019 approximated $1.01$3.3 million (gross). This cost is for the development program and base facilities. The recompletions, on average, provided a total of an additional 0 BOEPD to the exit rate annualized average. In 2019,2020, there were 216 new drill wells and 03 recompletion.

Texas law requires all temporarily abandoned wells to be either worked over and recompleted to functional status or permanently plugged and abandoned within a five year time frame. The Waddell Ranch properties contain over 700 such temporarily abandoned wells. In 2019,2020, there were 0recompletion3recompletion wells completed and 021 wells permanently plugged on the Waddell Ranch properties.

There were 2gross (1net)20 gross (10 net) drill wells completed on the Waddell Ranch properties during 2019.2020. At December 31, 2018,2019, there was 0 2drill wellwells and 0 workover in progress on the Waddell Ranch properties.

BROGBlackbeard has advised the Trustee that the proposed budget for 20202021 will be $1.4$86.7 million (gross) and $600,000$32.5 (net). The 20202021 budget will not include amounts to be spent onverticalonvertical wells, or wells to be worked over and completed, but will be spent on additional facilities and infrastructure improvements and the completion of projects begun in 2019. The foregoing capital expenditures budget may be subject to revision after Blackbeard assumes the role of operator of2020.

In 2020, lease operating expense and property taxes on the Waddell Ranch properties on April 1, 2020.

administrative expenses for any potentially extraordinary events and/or expenses was $1,050,000$1,100,000 as of December 31, 2019.2020. Total reserves for expenses for the years ended December 31, 2020, 2019 and 2018 and 2017 was $0,$50,000, $0 and $0, respectively.

Distributable income for 2020 was $10,958,618 or $0.24 per Unit.

Distributable income for 2019 was $19,421,131 or $0.42 per Unit.

Distributable income for 2018 was $30,789,460 or $.66 per Unit.

Distributable income for 2017 was $29,325,236 or $.63 per Unit.

Results of the Fourth Quarters of 20192020 and 20182019

Royalty income received by the Trust for the fourth quarter of 20192020 amounted to $5,129,649$1,980,417 or $0.11$0.04 per Unit. For the fourth quarter of 2018,2019, the Trust received royalty income of $7,509,505or $0.16per$5,129,649 or $0.11per Unit. Interest income for the fourth quarter of 20192020 amounted to $4,826$1,539 compared to $6,782$4,826 for the fourth quarter of 2018.2019. The decrease in interest income can be attributed primarily to a decrease of funds available. Total general and administrative expenses was $135,434 for the fourth quarter of 2020 compared to $213,203 for the fourth quarter of 2019 compared to $143,389 for the fourth quarter of 2018.2019. The increasedecrease in expenses primarily related to timing of payments of legal and auditor expenses.

Royalty income for the Trust for the fourth quarter is associated with actual oil and gas production during August through October from the Underlying Properties. Oil and gas production attributable to the Underlying Properties for the quarter and the comparable period for 20182019 are as follows: