☒ ☒ ☐ ☐ ☒ ☐ ☒ $9,597,489. PART II PART III PART IV assumptions made by the Trust in light of its experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. The Trustee (as defined herein) relies on the Working Interest Owners for information regarding the Subject Interests (as defined in mtr.q4web.com/home/default.aspx. Information contained on, or that can be accessed through the Trust’s website, is not incorporated by reference into this Annual Report on Form 10-K, and you should not consider information on the Trust’s website to be part of this Annual Report on Form 10-K. The SEC maintains a website at www.sec.gov that contains reports and other information regarding SEC registrants, including the Trust. As used in this report, Scout refers to the current operator of the Hugoton Royalty Properties, Hilcorp refers to the current operator of the San Juan ” (e) the Trust will terminate upon the first to occur of the following events: (i) at such time as the 31, 2021. adjusted for changes during such month in any cash reserves established for the payment of contingent or future obligations of the Trust made by the Trustee. The Monthly Distribution Amount for each month is payable to unitholders of record on the monthly record date, which is the close of business on the last business day of such month or such other date as the Trustee determines is required to comply with legal or stock exchange requirements. However, pursuant to the Trust Indenture and in order to reduce the administrative expenses of the Trust, the Trustee does not distribute cash monthly. Instead, the Trustee makes distributions, if any, during January, April, July and October of each year. While distributions are Liability of Unitholders Regulations reporting requirements for WHFITs and the dissemination of Trust tax reporting information, the Trustee provides a tax information reporting booklet which is intended to be used only to assist Trust unitholders in the preparation of their federal income tax returns. This tax information booklet can be obtained at http:// mtr.q4web.com/home/default.aspx. their net investment income. Grantor trusts such as Mesa Royalty Trust are not subject to the NIIT; however, the unitholders may be subject to the tax. For these purposes, investment income would generally include 2018. Production of the Reserve Report was supervised by a Vice President at Miller and Lents, Ltd. who is a professionally qualified and licensed Professional Engineer in the State of Texas with Proved Developed Oil and Condensate Natural Gas Liquids Gas Proved Undeveloped Oil and Condensate Natural Gas Liquids Gas Total, Proved Oil and Condensate Natural Gas Liquids Gas Future Royalty income(1) (1) Standardized Measure of Future Net Royalty Income, discounted at 10% per annum(1) The Reserve Report was delivered to the Trustee on March Income, Production and Production Prices and Production Costs Year ended December 31, 2019: Average Sales Price Average Production Costs(1) Net production volumes attributable to the Royalty paid(2) Year ended December 31, 2018: Average Sales Price Average Production Costs(1) Net production volumes attributable to the Royalty paid(2) Year ended December 31, 2017: Average Sales Price Average Production Costs(1) Net production volumes attributable to the Royalty paid(2) State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take and common purchaser requirements, as well as complaint-based rate regulation. the environment, for damages to natural resources and for the costs of health studies. In addition, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Hydraulic Fracturing. It is customary to recover oil and natural gas from deep shale, tight sand and coal bed formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Conventional hydraulic fracturing techniques are used to increase production in vertical wells. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions of the federal Safe Drinking Water Act to exclude certain hydraulic fracturing activities from the definition of distributions. Natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and the Working Interest Owners. Factors that contribute to price fluctuation include, among others: reserves and reduce therefrom. increased volatility in 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. Please read “Business — Regulation and Prices” under Item 1 of this Form 10-K. that climate change could have global, regional or local effects on the severity of weather (including hurricanes, floods and droughts), sea levels, arability of farmland, and water availability and quality, including predicted effects on areas in which the Royalty Properties are located. If such effects were to occur, exploration and production operations of the Royalty Properties have the potential to be adversely affected. Potential adverse effects could include damages to the facilities of the Working Interest Owners or disruption of production activities associated with weather related events, scale-backs in operations on the Royalty Properties due to the threat of such climatic effects, and increases in costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climatic effects or increased costs for insurance coverage. The Working Interest Owners may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change and can adversely affect Trust distributions as a result. production. Some states have adopted and others are considering legislation to restrict hydraulic fracturing. Several states including those where Royalty properties are located have adopted legislation requiring the public disclosure of hydraulic fracturing chemicals, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, hydraulic fracturing requires large amounts of water. This water, along with any produced water, is often sent to injection wells for disposal. This activity has been associated with earthquakes and some states, particularly Oklahoma, have limited injection well activity. Any additional level of regulation could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business and required disclosure without protection for trade secret or proprietary products could discourage service companies from using such products and as a result impact the degree to which some oil and gas wells may be efficiently and economically completed or brought into production. Unitholders have limited voting rights. Financial information of the Trust is not prepared in accordance with U.S. GAAP. paid. Trust’s Royalty income is net of capital expenditures, these capital expenditures are controlled and paid by the Working Interests Owners, and the Trust receives Royalty income net of these expenses. In addition, the Trust does not have any off-balance sheet arrangements or other contingent obligations. Year ended December 31, 2019: The Trust's proportionate share of—Gross Proceeds(1) Less the Trust's proportionate share of—Capital costs Operating costs Net Proceeds(2) Royalty Income(2) Average Sales Price Average Production Costs(3) Net production volumes attributable to the Royalty paid(4) Year ended December 31, 2018: The Trust's proportionate share of—Gross Proceeds(1) Less the Trust's proportionate share of—Capital costs Operating costs Net Proceeds(2) Royalty Income(2) Average Sales Price Average Production Costs(3) Net production volumes attributable to the Royalty paid(4) San Juan of Net Proceeds reported for the San Juan paid. Royalty income Interest income General and administrative expenses Distributable income Distributable income per unit Average sales price Actual production volumes attributable to the Royalty paid for Hugoton Royalty Properties Net production volumes attributable to the Royalty paid for Hugoton Royalty Properties Average sales price Actual production volumes attributable to the Royalty paid for San Juan Basin—Colorado Properties Net production volumes attributable to the Royalty paid for San Juan Basin—Colorado Properties Average sales price Actual production volumes attributable to the Royalty paid for San Juan Basin—New Mexico Properties Net production volumes attributable to the Royalty paid for San Juan Basin—New Mexico Properties Off-Balance Sheet Arrangements Royalty income Interest income General and administrative expenses Distributable income Distributable income per unit ASSETS Cash and short-term investments Net overriding royalty interests in oil and gas properties Accumulated amortization Total assets LIABILITIES AND TRUST CORPUS Distributions payable Trust corpus (1,863,590 units of beneficial interest, issued and outstanding) Total liabilities and trust corpus Trust corpus, beginning of year Distributable income Distributions to unitholders Amortization of net overriding royalty interests Trust corpus, end of year monthly amounts received by the Trust from September 2017 to March 2019 are fully reconciled and adjusted, Net Proceeds from the San paid. ” whose purposes are limited to: (1) converting the Royalties to cash, either by retaining them and collecting the proceeds of production (until production has ceased or the Royalties are otherwise terminated) or by selling or otherwise disposing of the Royalties; and (2) distributing such cash, net of amounts for payments of liabilities to the Trust, to the unitholders. The Trust has no sources of liquidity or capital resources other than the revenues, if any, attributable to the Royalties and interest on cash held by the Trustee as a reserve for liabilities or for distribution. The terms of the Trust Indenture provide, among other things, that: 2019. The net overriding royalty interest is reviewed for impairment whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. If circumstances require the net overriding royalty interest to be tested for possible impairment, the Trust first compares undiscounted cash flows expected to be generated by the net overriding royalty interest to its carrying value. If the carrying value of the net overriding royalty interest is not recoverable on an undiscounted cash flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. The fair value of the net overriding royalty interest is measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. modified cash basis of accounting: Note San Juan Basin—Colorado Properties—Red Willow San Juan Basin—New Mexico Properties—Hilcorp Total Excess production costs result when costs, charges, and expenses attributable to a working interest property exceed the revenue received from the sale of oil, gas, and other hydrocarbons produced from such property. The excess production costs must be recovered by the Working Interest Owners before any distribution of Royalty income from the Royalty Properties which are operated by such Working Interest Owners will be made to the Trust. Note The effect on distributable income per unit of adjustments to the Contingent Reserve for the years ended December 31 are as follows: Distributable Income Increase in the Contingent Reserve Withdrawal from the Contingent Reserve Distributable Income Available for Distribution Distributable Income Available for Distribution per unit Units outstanding Note determined as an unweighted average of the first-of-the-month price for each month, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Operating costs, production and ad valorem taxes and future development and abandonment costs were based on current costs as of each year end, with no escalation. Proved Reserves: December 31, 2015 Revisions to previous estimates Extensions, discoveries and other additions Production December 31, 2016 Revisions to previous estimates Extensions, discoveries and other additions Production December 31, 2017 Revisions to previous estimates Extensions, discoveries and other additions Production December 31, 2018 Revisions to previous estimates Extensions, discoveries and other additions Production December 31, 2019 Proved Developed Reserves: December 31, 2015 December 31, 2016 December 31, 2017 December 31, 2018 December 31, 2019 Proved Undeveloped Reserves: December 31, 2014 December 31, 2015 December 31, 2016 December 31, 2017 December 31, 2018 The Trust's proportionate share of future Gross Proceeds The Trust's proportionate share of future operating costs Future capital costs Future Royalty income Discount at 10% per annum Standardized measure of future Royalty income from proved oil and gas reserves Standardized measure of future Royalty income from proved oil and gas reserves at beginning of year Revisions of previous estimates Net changes in price and production costs Royalty income Accretion of discount Net changes in standardized measure Standardized measure of future Royalty income from proved oil and gas reserves at end of year 2019: Royalty income Distributable income Distributable income per unit 2018: Royalty income Distributable income Distributable income per unit The Trustee does not expect that the Audit fees(1) Audit-related fees Tax fees(2) All other fees Total fees 31, 2021Use these links to rapidly review the documentPART IV
SECURITIES AND EXCHANGE COMMISSION
(Mark One) (Mark One)☒ ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
20192020
Or Oro
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
Global Corporate Trust
601 Travis Street, Floor 16
Houston, Texas
(Address of principal executive offices)
(Zip Code) Registrant'sRegistrant’s telephone number, including area code:713-483-6020 Title of each class Trading Symbol(s) Name of each exchange on which registered Units of Beneficial Interest MTR New York Stock Exchange o☐ No ýo☐ No ýý☒ No oo☐ No o"large“large accelerated filer," "accelerated” “accelerated filer," "smaller” “smaller reporting company,"” and "emerging“emerging growth company"company” in Rule 12b-2 of the Exchange Act. Large accelerated filer o☐ Accelerated filer o☐ Non-accelerated filer ý☒ Smaller reporting company ý Emerging growth company o☐ oo☐ Noý28, 201930, 2020 of $11.49$5.15 was approximately $21,412,649.30, 2020,31, 2021, 1,863,590 Units of Beneficial Interest were outstanding in Mesa Royalty Trust. Page PagePART I PART I Business 1 1715 2723 Properties 2723 2723 2723 2824 2824 2824 3026 3633 3836 5449 5449 5651 5651 5651 5651 5651 5853 SIGNATURES 59 54 "forward-looking statements"“forward-looking statements” about Mesa Royalty Trust (the "Trust"“Trust”) and other matters discussed herein that are subject to risks and uncertainties that are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"“Exchange Act”). All statements other than statements of historical fact included in this document, including, without limitation, statements under "Trustee's“Trustee’s Discussion and Analysis of Financial Condition and Results of Operations,"” including the Trust'sTrust’s or any Working Interest Owner'sOwner’s (as defined in "“Item 1—Description of the Trust"”) future financial position, status in any insolvency proceeding, business strategy, budgets, projected costs, statements regarding the COVID-19 pandemic and related containment measures, expected market conditions and commodity pricing, plans and objectives, for future operations, information regarding targetfuture distributions, statements regarding reconciliation and adjustment of estimated versus actual revenue and expense amounts, statements pertaining to future exploration and development activities and costs, estimates regarding production costs and expenses, estimates of cash flows, statements regarding the number of development wells estimated to be completeddrilled and producing in future periods, and informationestimates regarding production and reserve growth,reserves, are forward-looking statements. Actual outcomes and results, which are substantially all outside of the Trust’s control, may differ materially from those projected. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "potential," "possibly," "could," "may," "can," "foresee," "plan," "goal," "assume," "target," "should," "intend"“estimate,”i"Description“Description of the Trust"Trust” under Item 1), the Royalty (as defined in "Description“Description of the Trust"Trust” under Item 1), and the Working Interest Owners themselves. Although the Working Interest Owners have advised the Trust that they believe that the expectations reflected in the forward-looking statements contained herein are reasonable, nosuch expectations reflected in these forward-looking statements will prove to be correct. However, whetherWhether actual results and developments will conform with such expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in this Form 10-K, and those set forth from time to time in the Trust'sTrust’s filings with the Securities and Exchange Commission (the "SEC"“SEC”), which could affect the future results of the energy industry in general, and the Trust and Working Interest Owners in particular, and could cause those results to differ materially from those expressed in suchthese 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 the Working Interest Owners'Owners’ businesses 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."Trustee"“Trustee”), 601 Travis Street, Floor 16, Houston, Texas 77002. The telephone number of the Trust is 713-483-6020. The Bank of New York Mellon Trust Company, N.A., is the successor Trustee from JPMorgan Chase Bank, N.A., which is the successor by mergers to the originally named Trustee, Texas Commerce Bank National Association. The Trust has no employees. Administrative functions of the Trust are performed by the Trustee. The Trustee maintains a website for the Trust that makes available, free of charge, filings by the Trust with the SEC and other information. Any reports filed with the SEC are accessible free of charge through our website as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The Trust'sTrust’s website is http://mtr.investorhq.businesswire.com/."Trust"“Trust”) was created on November 1, 1979, and is now governed by the Mesa Royalty Trust Indenture (as amended, the "Trust Indenture"“Trust Indenture”). Through a series of conveyances, assignments, and acquisitions, the Trust currently owns an overriding royalty interest (the "Royalty"“Royalty”) equal to 11.44% of 90% of the Net Proceeds (as defined in the Conveyance and described below) attributable to the specified interest in certain producing oil and gas properties located in the:"Hugoton“Hugoton Royalty Properties"Properties”);•"San“San Juan Basin—Basin — New Mexico Properties"Properties”); and•"San“San Juan Basin—Basin — Colorado Properties"Properties”, and together with the "San“San Juan Basin—Basin — New Mexico Properties, the "San“San Juan Basin Royalty Properties"Properties”, and together with the Hugoton Royalty Properties, the "Royalty Properties"“Royalty Properties”).("MLP"(“MLP”), which was the predecessor to MESA Inc., conveyed to the Trust the Royalty equal to 90% of the Net Proceeds (as defined in the Conveyance and described below) attributable to the specified interests in properties conveyed by the assignor on that date (the "Subject Interests"“Subject Interests”). The Subject Interests consisted of interests in the Royalty Properties described above. The Royalty is evidenced by counterparts of an Overriding Royalty Conveyance, dated as of November 1, 1979 (the "Conveyance"“Conveyance”). In 1985, the Trust Indenture was amended and the Trust conveyed to an affiliate of Mesa Petroleum Co. 88.5571% of the original Royalty (such transfer, the "1985 Assignment"“1985 Assignment”). The effect of the 1985 Assignment was an overall reduction of approximately 88.56% in the size of the Trust. As a result, the Trust is now entitled to receive 11.44% of 90% of the Net Proceeds attributable to each month. Until August 7, 1997, MESA Inc. operated the Hugoton Royalty Properties through Mesa Operating Co., a wholly owned subsidiary of MESA Inc. On August 7, 1997, MESA Inc. merged with and into Pioneer Natural Resources Company ("Pioneer"), formerly a wholly owned subsidiary of MESA Inc., and Parker & Parsley Petroleum Company merged with and into Pioneer Natural Resources USA, Inc. (successor to Mesa Operating Co.), a wholly owned subsidiary of Pioneer ("PNR") (collectively, the mergers are referred to herein as the "Merger"). Subsequent to the Merger, the Hugoton Royalty Properties were operated by PNR until December 31, 2014, at which point Linn Energy Holdings, LLC, a subsidiary of Linn Energy, LLC ("Old Linn") took over as operator. Pursuant to the bankruptcy proceedings and court-approved plans of reorganization involving Old Linn, which are described in detail below, Linn Energy, Inc. (together with its subsidiaries, "Linn") became the operator of the Hugoton Royalty Properties on February 28, 2017. On April 18, 2018, Linnannounced its Board of Directors' decision to separate Linn into two stand-alone public companies. On August 7, 2018 Linn completed the spin-off of Riviera Resources, Inc. ("Riviera") through the pro rata distribution of all of the shares of Riviera's outstanding common stock to Linn's stockholders. In connection with such distribution, Linn ceased to be the operator of the Hugoton Royalty Properties, and since August 7, 2018, Riviera operated the Hugoton Royalty Properties. On November 22, 2019, Riviera Resources, Inc. (“Riviera”) completed the sale of its interest in its remaining properties located in the Hugoton Basin under the Purchase and Sale Agreement, dated August 28, 2019 (the "Purchase Agreement"“Purchase Agreement”), by and between the Riviera Upstream, LLC, Riviera Operating, LLC and Scout Energy Group V, LP ("Scout"(“Scout”). Pursuant to the Purchase Agreement, Riviera divested all of its interest in oil and gas assets and contracts in the Hugoton Royalty Properties. Since November 23, 2019, Scout has operated the Hugoton Royalty Properties.Basin—Basin — Colorado Properties. On April 30, 1991, MLP sold to Conoco, Inc. ("ConocoPhillips"(“ConocoPhillips”) its interests in the San Juan Basin Royalty Properties (the "San“San Juan Basin Sale"Sale”). The Trust'sTrust’s interest in the San Juan Basin Royalty Properties was conveyed from PNR'sPNR’s working interest in 31,328 net producing acres in northwestern New Mexico and southwestern Colorado. ConocoPhillips sold the portion of its interests in the San Juan Basin—Basin — Colorado Properties to MarkWest Energy Partners, Ltd. (effective("(“Red Willow"Willow”) (effective April 1, 1992). On October 26, 1994, MarkWest Energy Partners, Ltd. sold substantially all of its interest in the San Juan Basin—Basin — Colorado Properties to BP Amoco Company ("BP"(“BP”), a subsidiary of BP p.l.c. On February 28, 2020, BP completed the sale of all of its interest in the San Juan Basin — Colorado Properties to IKAV Energy Inc. (“IKAV”). BP, under a transition services agreement with IKAV, operated the properties until December 1, 2020. IKAV and Red Willow currently operate the San Juan Basin—Basin — Colorado Properties.Basin—Basin — New Mexico Properties. Starting from the date of the San Juan Basin Sale and ending on July 31, 2017, ConocoPhillips operated substantially all of the San Juan Basin—Basin — New Mexico Properties, except an immaterial number of properties assigned to XTO Energy, Inc. ("XTO"(“XTO”) effective January 1, 2005. On July 31, 2017, ConocoPhillips sold its San Juan Basin assets to Hilcorp San Juan LP ("Hilcorp"(“Hilcorp”), an affiliate of Hilcorp Energy Company. On March 29, 2018, XTO sold to Hilcorp an immaterial number of properties, which comprise certain portions of the San Juan Basin—Basin — New Mexico Properties. Hilcorp currently operates all of the San Juan Basin—Basin — New Mexico Properties. Following Hilcorp's acquisition of ConocoPhillips' and XTO's interests in the San Juan Basin—New Mexico Properties, there was a transition period to transfer historical information, knowledge and processes from one owner to the other. During this transition period, Hilcorp recorded estimates of revenues and expenses and made payments to the Trust based on historical amounts previously paid by ConocoPhillips, and the Trust recognized such amounts in accordance with its modified cash basis of accounting. Accordingly, Hilcorp made an estimated monthly payment of $97,150 in Net Proceeds to the Trust from September 2017 to March 2019 based upon the July 2017 production month previously paid by ConocoPhillips. In April 2019, Hilcorp began to generate actual (instead of estimated) Net Proceeds due to the Trust on a monthly basis. Hilcorp has informed the Trust that it will utilize actual revenue and expense amounts and either add or subtract reconciled historical amounts on a month by month basis, which will be recognized over time by the Trust in accordance with the Trust's modified cash basis of accounting. In December 2019, Hilcorp made the first payment to the Trust reconciling historical amounts, which was in the amount of $29,698 for the accounting month of September 2017 and was the only reconciliation payment made by Hilcorp during 2019. Until all estimated historical monthly amounts received by the Trust from September 2017 to March 2019 are fully reconciled and adjusted, Net Proceeds from the San Juan—New Mexico Properties will reflect adjustments to actual current production and costs to account for historical monthly reconciliations as they are completed. Because of anticipated future adjustments, the amounts of Net Proceeds reported for the San Juan Basin—New Mexico Properties during the year ended December 31, 2019 may not be representative of Net Proceeds that will be received in future years. Hilcorp has informed the Trust that significant incremental costs of approximately $1.1 million attributable to the Trust were incurred in 2018 with respect to a newly drilled well in the San Juan Basin—New Mexico Properties. Incremental costs attributable to the Trust will reduce the Trust's future Net Proceeds over a period of time as adjustments are made by Hilcorp after taking into account actual revenues as well as costs for these properties during the applicable time period. The potential impact to Net Proceeds depends upon the results of all of the reconciliation work currently being conducted by Hilcorp and is therefore uncertain. The Trust will undertake a review of the reconciliation calculations by Hilcorp and the amount of Net Proceeds calculated and paid and intends to engage third party consultants when appropriate to assist in the Trust's review. Pursuant to the Trust Indenture, the Trust is not required to pay to Hilcorp any amounts that could be owed if the estimated revenue exceeded actual revenue amounts or estimated expenses were less than actual expense amounts in past periods. However, Hilcorp may recover such amounts by withholding a portion or all of the Net Proceeds that would otherwise be payable to the Trust in subsequent periods. This could result in a decrease in Net Proceeds paid to the Trust and could result in future material reductions in distributions to the Trust's unitholders. Net Proceeds from the San Juan Basin—New Mexico Properties for years ended December 31, 2019 and 2018 were $871,096 and $1,165,797, respectively, which revenue accounted for approximately 48% and 50%, respectively, of the total Royalty income reported by the Trust during those periods.Basin—Basin — New Mexico Properties, and BPIKAV and Red Willow refersrefer to the current co-operators of certain tracts of land included in the San Juan Basin—Basin — Colorado Properties, unless otherwise indicated. Scout, BP,IKAV, Red Willow and Hilcorp are each individually referred to herein as "Working“Working Interest Owner"Owner” or collectively as the "Working“Working Interest Owners.""Contracts"“Contracts”. The Trustee has no power or authority to exercise any control over the operation of the Royalty Properties or the marketing of production therefrom.Trust'sTrust’s royalty income for two successive years is less than $250,000 per year or (ii) a vote by the unitholders in favor of termination. Upon termination of the Trust, the Trustee will sell for cash all the assets held in the Trust estate and make a final distribution to unitholders of any funds remaining after all Trust liabilities have been satisfied; andBPIKAV will reimburse the Trust for 59.34%, 27.45% and 1.77%, respectively, for general and administrative expenses of the Trust."Gross Proceeds"“Gross Proceeds” received by the Working Interest Owners"Gross Proceeds"“Gross Proceeds” is defined in the Conveyance as the amount received by the Working Interest Owners from the sale of "Subject Minerals"“Subject Minerals”, subject to certain adjustments. "Subject Minerals"“Subject Minerals” means all oil, gas and other minerals, whether similar or dissimilar, in and under, and which may be produced, saved and sold from, and which accrue and are attributable to, the Subject Interests from and after November 1, 1979. "Production costs"“Production costs” means, generally, costs incurred on an accrual basis by the Working Interest Owners in operating the Royalty Properties, including capital and non-capital costs. If production and capital costs exceed Gross Proceeds for any month, the excess, plus interest thereon at 120% of the prime rate of Bank of America, is recovered out of future Gross Proceeds prior to the making of further payment to the Trust. The Trust, however, is generally not liable for any operating costs or other costs or liabilities attributable to the Royalty Properties or minerals produced therefrom. The Trust is not obligated to return any Royalty income received in any period.Trust'sTrust’s transfer agent. Each unit ranks equally for purposes of distributions and has one vote on any matter submitted to unitholders. A total of 1,863,590 units were outstanding at March 30, 2020."Monthly“Monthly Distribution Amount"Amount”), which consists of the cash received from the Royalty during such month, minus the obligations of the Trust paid during such month asonlyscheduled to be made four times per calendar year, the Trustee distributes to each person who was a unitholder of record on one or more of the immediately preceding three monthly record dates, an amount equal to the Monthly Distribution Amount, if any, for the month or months that such holder was a unitholder of record plus interest earned on such Monthly Distribution Amount from the Monthly Record Date to the payment date. Under the terms of the Trust Indenture, interest is earned at a rate of 1.5% below the greater of (i) the prime rate charged by The Bank of New York Mellon Trust Company, N.A. or (ii) the interest rate which The Bank of New York Mellon Trust Company, N.A. pays in the normal course of business on amounts placed with it. Interest income may vary significantly across different payment dates.2019,2020, there were $23,629$8,565 of unreimbursed expenses.borrowings. During 2011, the Trustee withheld $1.0 million for future unknown contingent liabilities and expensesborrowings in accordance with the Trust Indenture. At any given time, the amount reserved for such future unknown contingent liabilities and expenses (the "Contingent Reserve"“Contingent Reserve”) is included in cash and short-term investments. For the year ended December 31, 2019, the Trustee increased the Contingent Reserve by (1) $56,793 of Royalty income received from BP in March 2019 after the distribution to unitholders had been announced for the month of March 2019, which Royalty income was included in the April 2018 distribution to unitholders, (2) $434 for a duplicated general and administrative expense paid in error by the Trust in February 2019 and not refunded to the Trust until April 2019, (3) $317 underpaid by Riviera in June 2019 due to a 2018 Ad Valorem tax under accrual but included in the June 2019 distribution to unitholders, which amount was then excluded from the July 2019 distribution to unitholders, (4) $812 due to a refund received from a vendor in September 2019 and (5) $843 due to an overpayment received in error from BP in December 2019 that was deducted from BP's January 2020 payment to the Trust. For the year ended December 31, 2019, the Trustee decreased the Contingent Reserve by (1) $434 for a duplicated general and administrative expense paid in error by the Trust in February 2019 and not refunded to the Trust until April 2019, (2) $38,364 for a cash refund of a duplicate payment from a vendor received in November 2018 and distributed to unitholders in February 2019, (3) $56,794 of Royalty income received from BP in March 2019 after the distribution to unitholders had been announced for the month of March 2019, which Royalty income was included in the April 2019 distribution to unitholders, (4) $317 underpaid by Riviera in June 2019 due to a 2018 Ad Valorem tax under accrual but included in the June 2019 distribution to unitholders, which amount was then excluded from the July 2019 distribution to unitholders, (5) $812 due to a refund received from a vendor in September 2019 which refund was included in the distribution to unitholders in November 2019 and (6) $23,629 for a reimbursement not received from Scout but included in the December 2019 distribution to unitholders. The net effects of the foregoing adjustments for the year ended December 31, 2019 resulted in the balance of the Contingent Reserve being equal to $977,212 as of December 31, 2019.Trust'sTrust’s assets (regardless of whether the assets are adequate to satisfy the liability) and in no event out of amounts distributed to, or other assets owned by, the unitholders. However, under Texas law, it is unclear whether a unitholder would be jointly and severally liable for any liability of the Trust in the event that all of the following conditions were to occur: (1) the satisfaction of such liability was not by contract limited to the assets of the Trust, (2) the assets of the Trust were insufficient to discharge such liability, and (3) the assets of the Trustee were insufficient to discharge such liability.Trust'sTrust’s units. Except where indicated, the discussion below describes general federal income tax considerations applicable to individuals who are citizens or residents of the U.S. Accordingly, the following discussion has limited application to domestic corporations, foreign persons and persons subject to specialized federal income tax treatment, such as regulated investment companies and insurance companies. It is impractical to comment on all aspects of federal, state, local and foreign laws that may affect the tax consequences of the transactions contemplated hereby and of an investment in the units as they relate to the particular circumstances of every unitholder.Each unitholder should consult its own tax advisor with respect to its particular circumstances."IRS"“IRS”) advised the Dallas District Director that the Trust is classifiable as a grantor trust and not as an association taxable as a corporation. As a grantor trust, the Trust incurs no federal income tax liability and each unitholder is subject to tax on such unitholder'sunitholder’s pro rata share of the income and expense of the Trust as if such unitholder were the direct owner of a pro rata share of the Trust'sTrust’s assets. In addition, there is no state tax liability for the period.("WHFIT"(“WHFIT”) for U.S. federal income tax purposes. Notwithstanding the foregoing, the middlemen holding units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury Regulations with respect to such units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the units.mtr.investorhq.businesswire.com/.("Code"(“Code”), existing and proposed Internal Revenue Treasury Regulations ("(“Treasury Regulations"Regulations”) thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. No assurance can be provided that the statements set forth herein (which do not bind the IRS or any court) will not be challenged by the IRS or will be sustained by any court if challenged."proved"“proved” at the time of the transfer. This rule is not applicable in the case of transfers of properties after October 11, 1990. Thus, eligible unitholders who acquired units after that date are entitled to claim an allowance for percentage depletion with respect to Royalty income attributable to such units to the extent that this allowance exceeds cost depletion as computed for the applicable period.taxpayer'staxpayer’s basis in the property. Under this provision, depletion attributable to a unit acquired after 1986 will be subject to recapture as ordinary income upon disposition of the unit or upon disposition of the oil and gas property to which the depletion is attributable. The balance of any gain or any loss will be capital gain or loss if the unit was held by the unitholder as a capital asset, either long-term or short-term depending on the holding period of the unit. This capital gain or loss will be long-term if a unitholder'sunitholder’s holding period exceeds one year at the time of sale or exchange. Under current law, the highest marginal U.S. federal income tax rate applicable to long-term capital gains of individuals is 20%. Moreover, this rate is subject to change by new legislation at any time. The deductibility of capital losses is subject to certain limitations. Capital gain or loss will be short-term if the unit has not been held for more than one year at the time of sale or exchange.tax—tax — also known as the Net Investment Income Tax ("NIIT"(“NIIT”)—on"non-U.S. unitholder"“non-U.S. unitholder” for purposes of this discussion, will be subject to tax on the gross income (without taking into account any deductions, such as depletion) produced by the Royalty at a rate equal to 30% or, if applicable, at a lower treaty rate. This tax will be withheld by the Trustee and remitted directly to the U.S. Treasury. A non-U.S. unitholder may elect to treat Royalty income as effectively connected with the conduct of a U.S. trade or business under provisions of the Code or pursuant to any similar provisions of applicable treaties. Upon making this election, a non-U.S. unitholder is entitled to claim all deductions with respect to that income, but he must file a U.S. federal income tax return to claim these deductions. This election once made is irrevocable unless an applicable treaty allows the election to be made annually."FATCA"“FATCA”), distributions from the Trust to "foreign“foreign financial institutions"institutions” and certain other "non-financial“non-financial foreign entities"entities” may be subject to U.S. withholding taxes. Specifically, certain "withholdable payments" (including“withholdable payments” (including certain royalties, interest and other income from U.S. sources) made to a foreign financial institution or non-financial foreign entity will generally be subject to the withholding tax unless the foreign financial institution or non-financial foreign entity complies with certain information reporting, withholding, identification, certification and related requirements imposed by FATCA. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the U.S. governing FATCA may be subject to different rules. Foreign unitholders are encouraged to consult their own tax advisors regarding the possible implications of these withholding provisions on their investment in Trust units."unrelated“unrelated business taxable income" (asincome” (as defined in Code § 512(b)), so long as, generally, a unitholder did not incur debt to acquire a unit or otherwise incur or maintain a debt that would not have been incurred or maintained if the unit had not been acquired. Legislative proposals have been made from time to time which, if adopted, would result in the treatment of Royalty income as unrelated business taxable income. Each tax-exempt unitholder is encouraged to consult its own advisor with respect to the treatment of Royalty income.20192020byfrom the Working Interest Owners.Scout'sScout’s working interest in 104,437 net producing acres in the Hugoton field of Kansas."FERC"“FERC”). See "Regulation“Regulation and Prices"Prices”.Trust'sTrust’s interest in the San Juan Basin Royalty Properties was conveyed from PNR'sPNR’s working interest in 31,328 net producing acres in Northwestern New Mexico and Southwestern Colorado. PNR completed the San Juan Basin Sale to ConocoPhillips on April 30, 1991. ConocoPhillips subsequently sold its underlying interest in substantially all of the San Juan Basin—Basin — Colorado Properties to MarkWest Energy Partners, Ltd. (effective January 1, 1993) and Red Willow Production Company (effective April 1, 1992). On October 26, 1994, MarkWest Energy Partners, Ltd. sold substantially all of its interest in the San Juan Basin—Basin — Colorado Properties to BP. On February 28, 2020, BP completed the sale of all of its interest in the San Juan Basin — Colorado Properties to IKAV Energy Inc. (“IKAV”). BP, under a transition services agreement with IKAV, operated the properties until December 1, 2020. Starting from the date of the San Juan Basin Sale and ending on July 31, 2017, ConocoPhillips operated substantially all of the San Juan Basin—Basin — New Mexico Properties, except for an immaterial number of properties assigned to XTO effective January 1, 2005. On July 31, 2017, ConocoPhillips sold its San Juan Basin assets to Hilcorp. On March 29, 2018, XTO sold to Hilcorp an immaterial number of properties, which comprise certain portions of the San Juan Basin—Basin — New Mexico Properties.Basin—Basin — New Mexico Properties. Other than that exploratory well, the Trust has not been informed by the other Working Interest Owners of any other exploratory or development wells drilled on any Royalty Properties during 2020, 2019 2018 or 2017."Reserve Report"“Reserve Report”) and attributable to the Trust has been made by Miller and Lents, independent petroleum engineering consultants, as of December 31, 2019.2020. A copy of this Reserve Report has been filed as Exhibit 99 to this Form 10-K. Miller and Lents restricts its activities exclusively to consultation. It does not accept contingency fees or other compensation that may be considered to be conditional upon the outcome of its studies. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. In serving the petroleum industry and financial community, the firm'sfirm’s experienced staff provides knowledge, independent judgment, integrity, and confidential service to its clients. The firm is a Texas Registered Engineering Firm, No. F-1442.nineten years of relevant2019,2020, of the Trust'sTrust’s ownership in the net overriding royalty interests in the Royalty Properties are presented below. Total liquid reserves (condensate and natural gas liquids) are expressed in thousands of barrels (Mbbl) and gas reserves are expressed in thousandsmillions of cubic feet (Mcf)(MMcf). IKAV Hilcorp Proved Developed Oil and Condensate 0 10 0 10 Natural Gas Liquids 0 306 0 306 Gas 1,341 4,032 0 5,373 Proved Undeveloped Oil and Condensate 0 0 0 0 Natural Gas Liquids 0 0 0 0 Gas 0 0 0 0 Total, Proved Oil and Condensate 0 10 0 10 Natural Gas Liquids 0 306 0 306 Gas 1,341 4,032 0 5,373 BP Hilcorp Scout Total(1) 0 11 0 11 0 375 5 380 2,419 5,176 110 7,706 0 0 0 0 0 0 0 0 0 0 0 0 0 11 0 11 0 375 5 380 2,419 5,176 110 7,706
(1)(1)20192020 and 20182019 are included in Net Proceeds paid to the Trust by Red Willow and Hilcorp.Trust'sTrust’s Royalty as of December 31, 20192020 is summarized in the table below. These estimates are provided based upon the economic assumptions furnished by the Working Interest Owners, and are expressed in thousands of dollars: IKAV Hilcorp Scout Total $ 1,044 $ 12,120 $ 0 $ 13,164 IKAV Hilcorp Scout Total
10% per annum(1) $ 687 $ 5,883 $ 0 $ 6,570 BP Hilcorp Scout Total $ 3,677 $ 17,514 $ 362 $ 21,553 BP Hilcorp Scout Total $ 2,138 $ 8,058 $ 298 $ 10,493 (1)"Summary“Summary Reserve Report from Miller and Lents"Lents” attached hereto as Exhibit 99 for more information.13, 2020.16, 2021. Net reserves ofattributable to the Trust's RoyaltyTrust are calculated at the aggregate level from the Trust’s net revenue ofrevenues for each of the Working Interest Owners. To estimate netprices—$41.57prices — $29.01 per Bbl; (2) natural gas liquids prices—$13.10prices — $14.63 per Bbl for the San Juan Basin Royalty Properties and $12.71$6.04 per Bbl for Hugoton Royalty Properties; and (3) natural gas prices—$2.35prices — $1.82 per Mcf for San Juan Basin-New Mexico Royalty Properties, $1.52$0.78 per Mcf for San Juan Basin-Colorado Royalty Properties and $2.68$1.76 per Mcf for Hugoton Royalty Properties, with the initial prices also used as weighted average prices held constant thereafter over the lives of the properties. Estimates of operating expenses were based on current expenses and used for the life of the Royalty Properties with no increases in the future based on inflation.("FASB"(“FASB”). Accordingly, the estimates are based on existing economic and operating conditions in effect at December 31, 2019,2020, with no provision for future increases or decreases except for periodic price redeterminations in accordance with existing gas contracts. Actual future prices and costs may be materially greater or less than the assumed amounts in the reserve reports. Because reserve reports are limited to proved reserves, future capital expenditures for recovery of reserves not classified as proved are not included in the calculation of estimated future net revenues. Reserve assessment is a subjective process of estimating the recovery from underground accumulations of gas and oil that cannot be measured in an exact way, and estimates of other persons might differ materially from those of Miller and Lents. Accordingly, reserve estimates are often different from the quantities of hydrocarbons that are ultimately recovered.Trust'sTrust’s interests in the Royalty Properties. Although the Trustee inquires with the third-party reserve engineer about the information provided by the Working Interest Owners and the assumptions made and methodologies used by the third-party reserve engineer, the Trustee does not control the information provided by the Working Interest Owners or the assumptions made or methodologies used by the third-party reserve engineer. Accordingly, such information is outside the scope of the internal controls of the Trust and the Trustee. Any past practices not consistent with the Conveyance could also cause the basis for the reserve estimates included above to differ from actual reserve quantities and future net revenues.threetwo fiscal years is included in the table below. As reflected in the table, natural gas represents the vast majority of production from the Royalty Properties. Although the Trust is exposed to pricing fluctuations with respect to oil and condensate and natural gas liquids, the pricing environment of natural gas has a much more significant impact on Royalty income than any other hydrocarbon. For additional information related to our Reserve Report, see "Note 7—“Note 7 — Supplemental Reserve Information (Unaudited)" under” in the Notes to Financial Statements contained in Item 8 of this Form 10-K. Hugoton San Juan Basin—New
Mexico(3) San Juan Basin—Colorado Total Natural
Gas Natural
Gas
Liquids Oil
and
Condensate Natural
Gas Natural
Gas
Liquids Oil
and
Condensate Natural
Gas Natural
Gas
Liquids Oil
and
Condensate Natural
Gas Natural
Gas
Liquids Oil
and
Condensate �� $ 3.52 $ 21.35 $ — $ 1.63 $ 16.00 $ 44.39 $ 1.38 $ — $ — $ 1.79 $ 17.04 $ 44.39 $ 8.40 $ 55.33 $ — $ 1.65 $ 20.32 $ 51.88 $ 0.39 $ — $ — $ 2.04 $ 27.14 $ 51.88 (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) 106,373 4,739 — 309,914 19,567 1,157 334,414 — — 750,701 24,306 1,157 $ 3.46 $ 25.98 $ — $ 2.04 $ 16.28 $ 37.59 $ 1.32 $ — $ — $ 2.03 $ 19.31 $ 37.59 $ 5.49 $ 40.45 $ — $ 1.30 $ 10.28 $ 22.93 $ 0.39 $ — $ — $ 1.69 $ 19.71 $ 22.93 (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) 147,685 9,553 — 395,629 21,015 399 309,558 — — 852,872 30,568 399 $ 3.66 $ 22.87 $ — $ 2.20 $ 16.17 $ 37.91 $ 1.61 $ — $ — $ 2.36 $ 19.24 $ 37.91 $ 2.03 $ 12.99 $ — $ 1.80 $ 13.10 $ 31.56 $ 0.39 $ — $ — $ 1.31 $ 13.05 $ 31.56 (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) 262,789 15,921 — 341,305 18,771 774 383,409 — — 987,503 34,692 774 Hugoton
Mexico(3) San Juan Basin — Colorado Total
Gas
Gas
Liquids
and
Condensate
Gas
Gas
Liquids
and
Condensate
Gas
Gas
Liquids
and
Condensate
Gas
Gas
Liquids
and
Condensate Average Sales Price $ 2.73 $ 10.01 $ — $ 1.53 $ 12.68 $ 41.42 $ 0.75 $ — $ — $ 1.28 $ 11.93 $ 41.42
Costs(1) $ 17.59 $ 29.39 $ — $ 4.62 $ 26.25 $ (225.13) $ 0.46 $ — $ — $ 4.27 $ 27.14 $ (225.13) Net production volumes attributable to the (Mcf) (Bbls) (Bbls) (Mcf) (Bbls) (Bbls) (Mcf) (Bbls) (Bbls) (Mcf) (Bbls) (Bbls) 68,957 6,011 — 144,318 15,271 (534) 254,346 — — 467,621 21,282 (534) Average Sales Price $ 3.52 $ 21.35 $ — $ 1.63 $ 16.00 $ 44.39 $ 1.38 $ — $ — $ 1.79 $ 17.04 $ 44.39
Costs(1) $ 8.40 $ 55.33 $ — �� $ 1.65 $ 20.32 $ 51.88 $ 0.39 $ — $ — $ 2.04 $ 27.14 $ 51.88 Net production volumes attributable to the (Mcf) (Bbls) (Bbls) (Mcf) (Bbls) (Bbls) (Mcf) (Bbls) (Bbls) (Mcf) (Bbls) (Bbls) 106,373 4,739 — 309,914 19,567 1,157 334,414 — — 750,701 24,306 1,157 Trust'sTrust’s Royalty interest in the Net Proceeds.(2)(3)Following Hilcorp's acquisition of ConocoPhillips' and XTO's interests in the San Juan Basin—New Mexico Properties, there was a transition period transfer historical information, knowledge and processes from one owner to the other. During this transition period, Hilcorp recorded estimates of revenues and expenses and made payments to the Trust based on historical amounts previously paid by ConocoPhillips, and the Trust recognized such amounts in accordance with its modified cash basis of accounting. Accordingly, Hilcorp made an estimated monthly payment of $97,150 in Net Proceeds to the Trust from September 2017 to March 2019 based upon the July 2017 production month previously paid by ConocoPhillips. In April 2019, Hilcorp began to generate actual (instead of estimated) Net Proceeds due to the Trust on a monthly basis. Hilcorp has informed the Trust that it will utilize actual revenue and expense amounts and either add or subtract reconciled historical amounts on a month by month basis, which will be recognized over time by the Trust in accordance with the Trust's modified cash basis of accounting. In December 2019, Hilcorp made the first payment to the Trust reconciling historical amounts, which was in the amount of $29,698 for the accounting month of September 2017 and was the only reconciliation payment made by Hilcorp during 2019. Until all estimated historical monthly amounts received by the Trust from September 2017 to March 2019 are fully reconciled and adjusted, Net Proceeds from the San Juan—New Mexico Properties will reflect adjustments to actual current production and costs to account for historical monthly reconciliations as they are completed. Becausecompleted by Hilcorp. See Trustee’s Discussion and Analysis of anticipated future adjustments, the amountsFinancial Condition and Results of Net Proceeds reported for theOperations — Operational Overview — San Juan Basin—New MexicoBasin Royalty Properties during the year ended December 31, 2019 may not be representative of Net Proceeds that will be received in future years.Hilcorp has informed the Trust that significant incremental costs of approximately $1.1 million attributable to the Trust were incurred in 2018 with respect to a newly drilled well in the San Juan Basin—New Mexico Properties. Incremental costs attributable to the Trust will reduce the Trust's future Net Proceeds over a period of time as adjustments are made by Hilcorp after taking into account actual revenues as well as costs for these properties during the applicable time period. The potential impact to Net Proceeds depends upon the results of allunder Item 7 of the reconciliation work currently being conducted by Hilcorp and is therefore uncertain. The Trust will undertake a review of the reconciliation calculations by Hilcorp and the amount of Net Proceeds calculated and paid and intends to engage third party consultants when appropriate to assist in the Trust's review.Pursuant to the Trust Indenture, the Trust is not required to pay to Hilcorp any amounts that could be owed if the estimated revenue exceeded actual revenue amounts or estimated expenses were less than actual expense amounts in past periods. However, Hilcorp may recover such amounts by withholding a portion or all of the Net Proceeds that would otherwise be payable to the Trust in subsequent periods. This could result in a decrease in Net Proceeds paid to the Trust and could result in future material reductions in distributions to the Trust's unitholders.
Table of ContentsCONTRACTS(formerly Riviera) from the Hugoton Royalty Properties accounted for approximately 26%29% of the Royalty income of the Trust for the year ended December 31, 2019.2020. Since June 1, 1995 natural gas produced from the Hugoton field has generally been sold under short-term and multi-month contracts at market clearing prices to multiple purchasers. Scout has advised the Trust that it expects to continue to market natural gas production from the Hugoton field under short-term and multi-month contracts. Overall average daily market prices received for natural gas from Hugoton Royalty Properties were lower for the year ended December 31, 20192020 as compared to the year ended December 31, 2018.2019. For the year ended December 31, 2019, Riviera2020, Scout provided and going forward Scout will continue to provide Process (as defined in the Conveyance) services for the Hugoton Royalty Properties, and such services are charged against the Royalty in accordance with the terms of the Conveyance.74%71% of the Royalty income of the Trust for the year ended December 31, 2019.2020. The majority of the natural gas produced from the San Juan Basin Royalty Properties is now being sold on the spot market.$3.17 per MMBtu in 2018 and decreased to $2.57 per MMBtu in 2019.2019 and decreased to $2.04 per MMBtu in 2020. Due to the seasonal nature of demand for natural gas and its effects on sales prices and production volumes, the amounts of cash distributions by the Trust may vary substantially on a seasonal basis. Generally, production volumes and prices are higher during the first and fourth quarters of each calendar year due primarily to peak demand in those periods. Because of the time lag between the date on which the Working Interest Owners receive payment for production from the Royalty Properties and the date on which distributions are made to unitholders, the seasonality that generally affects production volumes and prices is generally reflected in distributions to unitholders in later periods. Henry Hub Natural Gas Spot Prices are quoted in MMBtu, a commonly used energy measurement that has a conversion formula defined and published by the SEC for the purpose of estimating price per Mcf in the Reserve Report.Owners'Owners’ competitors in these areas include the major oil and gas companies, independent oil and gas companies, and individual producers and operators. There are numerous producers in the Hugoton field and the San Juan Basin. The Working Interest Owners have advised the Trustindicated that they believe that their competitive position in their respective areas is affected by price, contract terms and quality of service. Scout has also advised the Trust that it believes that its competitive position in the Hugoton field is enhanced by virtue of its substantial holdings and ownership and control of its wells, gathering systems and processing plants. Market conditions in the San Juan Basin aremay be negatively affected by the fact that most of the gas produced from such areas is transported on onea limited number of only two major pipelines, and the transportation of such gas is generally controlled by a few distribution companies.pipelines."FERC"“FERC”) regulates the sale of natural gas in interstate commerce for resale and the transportation of natural gas in interstate commerce by pipelines, but does not regulate natural gas gathering facilities. The FERC adopted regulations resulting in a restructuring of the natural gas industry. The principal elements of this restructuring were the requirement that interstate pipelines separate, or "unbundle,"“unbundle,” into individual components the various services offered on their systems, with all transportation services to be provided on a non-discriminatory basis, and the prohibition against an interstate pipeline providing gas sales services except through separately-organized affiliates. In various rulemaking proceedings following its initial unbundling requirement, the FERC has refined its regulatory program applicable to interstate pipelines in various respects, and it has announced that it will continue to monitor these and other regulations to determine whether further changes are needed. In addition to rulemaking proceedings, the FERC establishes new policies and regulations through policy statements and adjudications of individual pipeline matters. Further, additional changes to regulations may occur based on actions taken by Congress and/or the courts. As to these various developments, the Working Interest Owners have advised the Trust that the on-going and evolving nature of these regulatory initiatives makes it impossible to predict their ultimate impact on the prices, markets or terms of sale of natural gas related to the Trust.FERC'sFERC’s indexing methodology.The standards governing pipeline safety have undergone recent changes, and itIt is possible that future changes in applicable pipeline safety law may increase the stringency of the standards or expand the applicability of the standards to facilities not currently covered.Owners'Owners’ operations are subject to numerous federal, state and local laws and regulations controlling the discharge and release of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations, including their state counterparts, can impose liability upon the owner, operator or lessee under a lease for the cost of cleanup of discharged and released materials or damages to natural resources resulting from oil and gas operations. These laws and regulations may, among other things:••Owners'Owners’ financial position or"CERCLA"“CERCLA” or the Superfund law, and comparable state laws impose liability, potentially without regard to fault or legality of the activity at the time, on certain classes of persons that are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances that have been released at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released intoOwners'Owners’ control. These properties and the substances disposed or released on them may be subject to CERCLA, federal hazardous waste laws, and analogous state laws. Under such laws, the Working Interest Owners could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination regardless of whether or not such Working Interest Owner directly or indirectly caused the unpermitted discharge or release.Owners'Owners’ operations, equipment may be exposed to naturally occurring radiation associated with oil and natural gas deposits, and this exposure may result in the generation of wastes containing naturally occurring radioactive materials ("NORM"(“NORM”). NORM wastes exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements. Because some properties presently or previously comprising the Royalty Properties may have been used for oil and natural gas production operations for many years, it is possible that the Working Interest Owners may incur costs or liabilities associated with elevated levels of NORM."RCRA,"“RCRA,” and comparable state statutes, regulate the management and disposal of solid and hazardous waste. Some wastes associated with the exploration and production of oil and natural gas are exempted from the most stringent regulation in certain circumstances, such as drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas. However, these wastes and other wastes may be otherwise regulated by the Environmental Protection Agency (the "EPA"“EPA”) or state agencies. Moreover, in the ordinary course of oil and gas operations, industrial wastes such as paint wastes and waste solvents may be regulated as hazardous waste under RCRA or considered hazardous substances under CERCLA. It is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future."Clean“Clean Water Act"Act”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into regulated waters. The Oil Pollution Act of 1990 (the "OPA"“OPA”), as amended, which amends the Clean Water Act, imposes strict liability on owners and operators of facilities that are the site of a release of oil into regulated waters. The OPA and its associated regulations impose a"underground“underground injection."” At present, hydraulic fracturing is regulated at the state and local level. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal, state and local level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Repeal of the exemption would allow the EPA to promulgate new regulations. Many states have adopted rules that required operators to disclose chemicals and water volumes associated with hydraulic fracturing. In addition, hydraulic fracturing requires large amounts of water. This water, along with any produced water, is often sent to injection wells for disposal. This activity has been associated with earthquakes and some states, particularly Oklahoma, have limited injection well activity. If states in which the Working Interest Owners'Owners operate adopt limitations, it could have a negative impact on production.EPA'sEPA’s regulatory authority. Recently, EPA proposed rules to stay certain portions of the rules promulgated to control greenhouse gas emission related to oil and gas production. In addition, some states have taken or proposed legal measures to reduce emissions of greenhouse gases. For example, a number of states, including states in which the Royalty Properties are located, have indicated an intent to reduce greenhouse gases through state action or regional partnerships."OSHA,"“OSHA,” and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced by oil and gas operations and that this information be provided to employees, state and local government authorities and the public.Trust'sTrust’s units.net proceedsNet Proceeds available to the Trust and distributions to Trust unitholders.proceedsProceeds and the Trust'sTrust’s quarterly distributions are highly dependent upon the prices realized from the sale of natural gas and a material decrease in such prices could reduce the amount of Trust••••••••coronavirus (COVID-19),COVID-19 pandemic, or any government response to such occurrence or threat.2019,2020, crude oil prices per Bbl ranged from a high of approximately $66.30$65.65 in January to a low of approximately $45.41.$(40.32) in April. The negative price in April 2020 was primarily the result of rising volumes of oil held in U.S. storage and reduced consumption due to the COVID-19 pandemic. Oil demand rebounded in the second half of 2020. The NYMEX crude oil spot prices per Bbl were $61.06$48.52 and $45.15$61.06 as of December 31, 20192020 and 20182019, respectively. As of March 23, 2020,26, 2021, the price had fallenrisen to $19.48$60.97 per Bbl. The recent announcement by Saudi Arabia of a significant reduction in its export prices as well as a recent announcement by Russia that previously agreed upon production cuts will expire on April 1, 2020, have contributed to the recent significant decline in the price of oil. The Trust cannot predict the timing or the duration of any economic cycle and, depending on the prices realized, the financial condition of the Trust could be materially adversely affected. When natural gas prices decline, the Trust is affected in two ways. First, net royalties are reduced. Second, exploration and development activity on the underlying properties may decline as some projects may become uneconomic and are either delayed or eliminated. The volatility of energy prices reduces the predictability of future cash distributions to unitholders. Substantially all of the natural gas and natural gas liquids produced from the Royalty Properties are being sold under short-term or multi-month contracts at market clearing prices or on the spot market.net proceedsNet Proceeds available to the Trust and distributions to Trust unitholders.2019,2020, Henry Hub natural gas prices have ranged from a high of $8.15 per MMBtu in 2014 to a low of $1.49$1.33 per MMBtu in 2016.2020. On December 31, 2019,30, 2020, the Henry Hub Natural Gas Spot Price was $2.09$2.36 per MMBtu. As of March 17, 2020,26, 2021, the price had fallenrisen to $1.89$2.56 per MMBtu. The reduction in prices has been caused by many factors, including increases in natural gas production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand. The expected increase in natural gas production could cause the prices for natural gas to remain at current levels or fall to lower levels. If prices for natural gas continue to remain depressed for lengthy periods, we may be required to write down the value of our oil and gas properties. In addition, sustained low prices for gas will negatively impact the value of our estimatednet proceedsNet Proceeds and the amount of cash we would otherwise have available to pay cash distributions to unitholders.Trust'sTrust’s share of net proceeds.Net Proceeds. Production and development costs are impacted by increases in commodity prices both directly, through commodity-price dependent costs such as electricity, and indirectly, as a result of demand-driven increases in costs of oil field goods and services. Accordingly, higher or lower production and development costs, without concurrent increases in revenues, directly decrease or increase the amount received by the Trust for the Royalty.net proceedsNet Proceeds for those properties until future proceeds from production exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional revenue to repay the costs. Accordingly, there may not be sufficient net proceedsNet Proceeds to make a particular distribution.Trust has established a cash reserve for contingent liabilities andNet Proceeds payable to pay expenses in accordance with the Trust Indentureare derived from the sale of depleting assets. Accordingly, the portion of the distributions to unitholders attributable to depletion may be considered a return of capital. The reduction in proved reserve quantities is a common measure of depletion. Future maintenance and may increase such cash reserve indevelopment projects on the Royalty Properties will affect the quantity of proved reserves. The timing and sizewhich would reducerate of production decline of proved reserves may be higher than the rate currently expected by the Trust. For federal income tax purposes, depletion is reflected as a deduction. Please see the section entitled “Business — Description of the Units — Federal Income Tax Matters” under Item 1 of this Form 10-K.and distributions to Trust unitholders. The Trust's source of capital isunitholders, which could reduce the Royalty income received from its sharemarket value of the net proceeds fromTrust units over time. Eventually, properties underlying the Trust’s Royalty Properties. Pursuantwill cease to produce in commercial quantities and the Trust Indenture, the Trust may establish a cash reserve through the withholdingwill, therefore, cease to receive any distributions of cash for contingent liabilities and to pay expenses. In 2011, the Trustee established a cash reserve for contingent liabilities and expenses in accordance with the Trust Indenture and withheld approximately $83,333 per monthly distribution amount, or up to $250,000 per quarter, until the cash reserve was $1.0 million, which reduced net proceeds available to the Trust and distributions to Trust unitholders. The Trustee may increase the cash reserve in the future, which would reduce Net Proceeds available to the Trust and distributions to Trust unitholders. For more information, see "Trustee's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" under Item 7 of this Form 10-K.••••
net proceedsNet 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-off of reserves.Owners'Owners’ interests in the Royalty Properties can adversely affect Trust distributions.net proceedsNet Proceeds payable to the Trust. Most of the Any disruptions to natural gas produced in the San Juan Basin is transported on one of only two major pipelines in the area, and transportation of this gas is generally controlled by a small number of distribution companies. Accordingly, any disruptions toor transportation lines, or increases in transportation costs for production from these properties, could also adversely affect the Trust.2019.2020. Price differentials were calculated for each Working Interest Owner based on the monthly average price received and the monthly average historical benchmark prices and were applied on a constant basis for gas, condensate, and NGLs. The average prices, after appropriate adjustments, and the average operating costs were held constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the FASB in Accounting Standards Codification 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.Owners'Owners’ operations are subject to environmental, health and safety laws and regulations that may expose the Working Interest Owners to penalties, damages or costs of remediation or compliance which could adversely affect Trust distributions.Owners'Owners’ operations are subject to federal, regional, state and local laws and regulations relating to protection of natural resources and the environment, health and safety aspects of oil and gas operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on such operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from facilities, the imposition of substantial liabilities for pollution resulting from operations and the application of specific health and safety criteria addressing worker protection. Failure to comply with these laws and regulations could result in restrictions or orders suspending well operations, the assessment of administrative, civil and criminal penalties, the revocation of permits and the issuance of corrective action orders."Business—“Business — Regulation and Prices—Prices — Environmental Matters"Matters” under Item 1 of this Form 10-K for more information on the environmental laws and government regulations that may be applicable to the Working Interest Owners'Owners’ operations.Owners'Owners’ operations or could impose costs on other sources of emissions within the industrial or energy sectors. Such legislation or regulations could adversely affect demand for the production of oil and natural gas and increase operating costs by requiring additional expenditures to operate and maintain equipment and facilities, inventory emissions, install emissions controls, acquire allowances or pay taxes and fees relating to emissions, which could adversely affect Trust distributions. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases may produce changes in climate or weather, such as increased frequency and severity of storms, floods, drought and other climatic events, which if any such effects were to occur, could have adverse physical effects on the Working Interest Owners'Owners’ operations or physical assets."Business—“Business — Regulation and Prices—Prices — Environmental Matters"Matters” under Item 1 of this Form 10-K for more information on the environmental laws and government regulations that may be applicable to the Working Interest Owners'Owners’ operations.Trust unitholders andRISKS RELATED TO OWNERSHIP OF THE TRUST’S UNITSTrustee have no control over the operation or development of theTrust’s Royalty Properties and have little influence over operation or development. Neither the Trustee nor the unitholders can influence or control the operation or future development of the underlying properties. The Royalty Properties are owned by the Working Interest Owners, who are independent from the Trust. The Working Interest Owners manage the underlying properties and handle receipt and payment of funds relating to the Royalty Properties and payments toincome experiences a sustained decline, the Trust for the Royalty. 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 Working Interest Owners are under no obligation to continue operating the properties. Neither the Trustee nor the unitholders have the right to replace an operator.The Trustee relies upon the Working Interests Owners for information regarding the Royalty Properties. The Trustee relies on the Working Interest Owners for information regarding the Royalty Properties. The Working Interest Owners control (i) historical operating data and estimates, including production volumes, marketing of products, operating and capital expenditures, environmental and other liabilities, effects of regulatory changes and the number of producing wells and acreage, (ii) plans for future operating and capital expenditures, (iii) geological data relating to reserves, as well as related projections regarding production, operating expenses and capital expenses used in connection with the preparation of the reserve report, (iv) forward-looking information and estimates relating to production and drilling plans and (v) information regarding the Royalty Properties responsive to litigation claims. While the Trustee requests material information for use in periodic reports as part of its disclosure controls and procedures, the Trustee does not control this information and relies entirely on the Working Interest Owners to provide accurate and timely information when requested for use in the Trust's periodic reports. Information regarding operations has been subject to errors and adjustments in the past. Accordingly, the Trustee cannot assure unitholders that other errors or adjustments by the Working Interest Owners, whether historical or future, will not affect Royalty income and distributions by the Trust. Under the terms of the Trust Indenture, the Trustee is entitled to rely, and in fact relies, on certain experts in good faith. This reliance includes the use of an independent petroleum engineering consultant to prepare estimates of net proved reserves attributable to the Trust. This independent petroleum engineering consultant in turn relies on information provided to it by the Working Interest Owners. While the Trustee has no reason to believe its reliance on experts is unreasonable, this reliance on experts and limited access to information may be viewed as a weakness as compared to the management and oversight of entity forms other than trusts.The owner of anyterminated. In addition, Royalty Propertyinterests may abandon any property, terminating the related Royalty. The Working Interest Owners may at any time transfer all or part of the Royalty Property to another unrelated third party. Unitholders are not entitled to vote on any transfer, and the Trust will not receive any proceeds of any such transfer. Following any transfer, the Royalty Properties will continue to be subject to the Royalty, but the net proceeds from the transferred property would be calculated separately and paid by the transferee. The transferee would be responsible for all of the obligations relating to calculating, reporting and paying to the Trust the Royalty on the transferred portion of the Royalty Properties, and the current owner of the Royalty Properties would have no continuing obligation to the Trust for those properties. The Working Interest Owners or any transferee may abandon any well or property if it reasonably believes that the well or property can no longer produce in commercially economic quantities. This could result in termination of the Royalty relating to the abandoned well.The Royalty can be sold and the Trust can be terminated.sold.Trust'sTrust’s royalty income for each of two successive years is less than $250,000 per year. Following any such termination and liquidation, the net proceedsNet Proceeds of any such sale will be distributed to the unitholders, and the unitholders will receive no further distributions from the Trust. The Trustee may also enter into one or more transactions, subject to any required unitholder approval, by which a portion of the Royalty is sold, which could ultimately result in the termination of the Trust if the remaining Royalty does not generate sufficient income to maintain the $250,000 threshold. We cannot assure you that any such sale will be on terms acceptable to all unitholders.Trust assets are depleting assets and, if the Working Interest Owners or other operators The sale of the remaining Royalty Properties do not perform additional development projects,interests and the assets may deplete faster than expected. The net proceeds payabletermination of the Trust would be taxable events to the Trust are derived from the sale of depleting assets. Accordingly, the portion of the distributions to unitholders attributable to depletion may be considered a return of capital. The reduction in proved reserve quantities is a common measure of depletion. Future maintenance and development projects on the Royalty Properties will affect the quantity of proved reserves. The timing and size of these projects will depend on the market prices of natural gas. If operators of the Royalty Properties do not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by the Trust. For federal income tax purposes, depletion is reflected as a deduction. Please see the section entitled "Business—Description of the Units—Federal Income Tax Matters" under Item 1 of this Form 10-K. Because the net proceeds payable to the Trust are derived from the sale of depleting assets, the portion of distributions to unitholders attributable to depletion may be considered a return of capital as opposed to a return on investment. Distributions that are a return of capital will ultimately diminish the depletion tax benefits available to the Trust unitholders, which could reduce the market value of the Trust units over time. Eventually, properties underlying the Trust's Royalty will cease to produce in commercial quantities and the Trust will, therefore, cease to receive any distributions of net proceeds therefrom.Trust'sTrust’s rights against the current or future owners of the Royalty Properties.corporation'scorporation’s liabilities. The structure of the Trust does not include the interposition of a limited liability entity such as a corporation or a limited partnership which would provide further limited liability protection to Trust unitholders. While the Trustee is liable for any excess liabilities incurred if the Trustee fails to insure that such liabilities are 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, Trust unitholders may be exposed to personal liability.Trust'sTrust’s ultimate cash available for distribution is highly dependent on the financial condition of the operators of the wells. The ability to operate the underlying properties depends on all operators'operators’ current and future financial condition and economic performance and access to capital, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of such operators. If the reduced demand for crude oil and natural gas in the global market as a result of the economic effects of the outbreak of coronavirus (COVID-19)the COVID-19 pandemic and the recent reduction in the benchmark price of crude oil persist for the near future or longer, such factors could have a material negative impact on the financial condition and economic performance of Working Interest Owners or other operators of the underlying properties.("(“U.S. GAAP"GAAP”). Although this basis of accounting is permitted for royalty trusts by the SEC, the financial statements of the Trust differ from U.S. GAAP financial statements, because net profits income is not accrued in the month of production, expenses are not recognized when incurred, and cash reserves may be established for certain contingencies that would not be recorded in U.S. GAAP financial statements.Hilcorp'sHilcorp’s acquisition of ConocoPhillips'ConocoPhillips’ and XTO'sXTO’s interests in the San Juan Basin—Basin — New Mexico Properties, there was a transition period to transfer historical information, knowledge and processesTrust'sTrust’s modified cash basis of accounting. In December 2019, Hilcorp made the first payment to the Trust reconciling historical amounts which was infor one accounting month. For the amount of $29,698twelve months ended December 31, 2020, Hilcorp reconciled 10 additional historical amounts for the accounting monthmonths of SeptemberOctober 2017 and wasthrough July 2018, which resulted in a charge to the only reconciliation payment made by Hilcorp during 2019. Trust of $60,262.Juan—Juan — New Mexico Properties will reflect adjustments to actual current production and costs to account for historical monthly reconciliations as they are completed. Because of anticipated future adjustments, the amounts of Net Proceeds reported for the San Juan Basin—Basin — New Mexico Properties during the year ended December 31, 20192020 may not be representative of Net Proceeds that will be received in future years.Basin—Basin — New Mexico Properties. Incremental costs attributable to the Trust will reduce the Trust'sTrust’s future Net Proceeds over a period of time as adjustments are made by Hilcorp after taking into account actual revenues as well as costs for these properties during the applicable time period. The potential impact to Net Proceeds depends upon the results of all of the reconciliation work currently being conducted by Hilcorp and is therefore uncertain. TheWith the assistance of a third party consultant, the Trust will undertakehas undertaken a review of the reconciliation calculations by Hilcorp and the amount of Net Proceeds calculated and paid and intends to engage third party consultants when appropriate to assist in the Trust's review.Trust'sTrust’s unitholders. Net Proceeds from the San Juan Basin—New Mexico Properties for years ended December 31, 2019 and 2018 were $871,096 and $1,165,797, respectively, which revenue accounted for approximately 48% and 50%, respectively, of the total Royalty income reported by the Trust during those periods."Business—“Business — Description of Royalty Properties"Properties” contained in Item 1 of this Form 10-K.Registrant'sRegistrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities."MTR"“MTR”.27, 2020,25, 2021, the 1,863,590 units outstanding were held by 498471 unitholders of record. The Trust did not repurchase any units during the period covered by this Form 10-K.Trustee'sTrustee’s Discussion and Analysis of Financial Condition and Results of Operations.Trust'sTrust’s (the "Trust"“Trust”) financial condition and results of operations should be read in conjunction with the financial statements and notes thereto. The discussion of net production attributable to the Hugoton Royalty Properties and San Juan Basin Royalty Properties (as each is defined below) represents production volumes that are to a large extent hypothetical as the Trust does not own and is not entitled to any specific production volumes. Any discussion of "actual"“actual” production volumes represents the hydrocarbons that were produced from the properties in which the Trust has an overriding royalty interest."Trust Indenture"“Trust Indenture”). Through a series of conveyances, assignments, and acquisitions, the Trust currently owns an overriding royalty interest (the "Royalty"“Royalty”) equal to 11.44% of 90% of the Net Proceeds (as defined and described in an Overriding Royalty Conveyance, dated as of November 1, 1979 (the "Conveyance"“Conveyance”)) attributable to the specified interest in certain producing oil and gas properties located in the:"Hugoton“Hugoton Royalty Properties"Properties”);•"San“San Juan Basin—Basin — New Mexico Properties"Properties”);•"San“San Juan Basin—Basin — Colorado Properties"Properties”, and together with the "San“San Juan Basin—Basin — New Mexico Properties, the "San“San Juan Basin Royalty Properties"Properties”, and together with the Hugoton Royalty Properties, the "Royalty Properties"“Royalty Properties”).(formerly Riviera), Hilcorp, BP,IKAV, and Red Willow are the operators of certain portions of the Hugoton Royalty Properties and San Juan Basin Royalty Properties (each of Scout, Hilcorp, BP,IKAV, and Red Willow being a "Working“Working Interest Owner"Owner”, and together, the "Working“Working Interest Owners"Owners”). As used in this report, Scout refers to the current operator of the Hugoton Royalty Properties, Hilcorp refers to the current operator of the San Juan Basin—Basin — New Mexico Properties, and BPIKAV and Red Willow refer to the current co-operators of certain tracts of land included in the San Juan Basin—Basin — Colorado Properties, unless otherwise indicated.Trust's"Business—“Business — Description of the Trust"Trust” under Item 1 of this Form 10-K, the Trust'sTrust’s primary source of cash is the Royalty income received from its share of the net proceedsNet Proceeds from the Royalty Properties, and the only other source of cash is interest income earned pursuant to the Trust Indenture. For estimates of future Royalty income attributable to the Royalty, refer to the Notes to Financial Statements under Item 8 of this Form 10-K.20192020 and 2018,2019, there were $23,629$8,565 and $0$23,629 of unreimbursed expenses, respectively. In accordance with the provisions of the Conveyance, generally all revenues received by the Trust, net of unreimbursed Trust administrative expenses and sums paid to or from any reserves established pursuant to the Trust Indenture, are distributed to the unitholders. The terms of the Trust Indenture provide, among other things, that the Trustee may establish cash reserves and borrow funds to pay liabilities of the Trust, and may pledge assets of the Trust to secure payment of the borrowings. During 2011, the Trustee withheld $1.0 million to establish a reserve for future unknown contingent liabilities and expensesborrowings in accordance with the Trust Indenture. At any given time, the balance of the Contingent Reserve is included in cash and short-term investments. Hugoton San Juan Basin — Colorado Total
Gas
Gas
Liquids
Condensate
Gas
Gas
Liquids
Condensate
Gas
Gas
Liquids
Condensate
Gas
Gas
Liquids
Condensate
of – Gross Proceeds(1) $ 1,010,852 $ 196,435 $ — $ 881,596 $ 586,723 $ 97,964 $ 301,723 $ — $ — $ 2,194,171 $ 783,158 $ 97,964
share of – Capital costs (1,123) (207) — (50,124) (13,117) (32,354) — — — (51,247) (13,324) (32,354) Operating costs (1,211,937) (176,462) — (616,280) (387,758) (87,948) (117,130) — — (1,945,347) (564,220) (87,948) $ (202,208) $ 19,766 $ — $ 215,192 $ 185,848 $ (22,338) $ 184,593 $ — $ — $ 197,577 $ 205,614 $ (22,338) $ 188,274 $ 60,172 $ — $ 220,687 $ 193,704 $ (22,136) $ 191,448 $ — $ — $ 600,409 $ 253,876 $ (22,136) Average Sales Price $ 2.73 $ 10.01 $ — $ 1.53 $ 12.68 $ 41.42 $ 0.75 $ — $ — $ 1.28 $ 11.93 $ 41.42 $ 17.59 $ 29.39 $ — $ 4.62 $ 26.25 $ (225.13) $ 0.46 $ — $ — $ 4.27 $ 27.14 $ (225.13) Net production volumes attributable to the (Mcf) (Bbls) (Bbls) (Mcf) (Bbls) (Bbls) (Mcf) (Bbls) (Bbls) (Mcf) (Bbls) (Bbls) 68,957 6,011 — 144,318 15,271 (534) 254,346 — — 467,621 21,282 (534)
of – Gross Proceeds(1) $ 1,267,360 $ 363,402 $ — $ 1,017,563 $ 710,207 $ 111,188 $ 564,795 $ — $ — $ 2,849,718 $ 1,073,609 $ 111,188
share of – Capital costs (1) — — (32,047) (28,884) (5,719) — — — (32,048) (28,884) (5,719) Operating costs (893,033) (262,217) — (478,648) (368,629) (54,307) (129,665) — — (1,501,346) (630,846) (54,307) $ 374,326 $ 101,185 $ — $ 506,868 $ 312,694 $ 51,162 $ 435,130 $ — $ — $ 1,316,324 $ 413,879 $ 51,162 $ 374,326 $ 101,185 $ — $ 506,692 $ 313,039 $ 51,365 $ 461,771 $ — $ — $ 1,342,789 $ 414,224 $ 51,365 Average Sales Price $ 3.52 $ 21.35 $ — $ 1.63 $ 16.00 $ 44.39 $ 1.38 $ — $ — $ 1.79 $ 17.04 $ 44.39 $ 8.40 $ 55.33 $ — $ 1.65 $ 20.32 $ 51.88 $ 0.39 $ — $ — $ 2.04 $ 27.14 $ 51.88 Net production volumes attributable to the (Mcf) (Bbls) (Bbls) (Mcf) (Bbls) (Bbls) (Mcf) (Bbls) (Bbls) (Mcf) (Bbls) (Bbls) 106,373 4,739 — 309,914 19,567 1,157 334,414 — — 750,701 24,307 1,157 2020 2019 Royalty income $ 832,149 $ 1,808,378 Interest income 5,756 29,415 General and administrative expenses (193,947) (202,747) Cash reserves withheld for current Trust expenses (78,208) — Distributable income $ 565,750 $ 1,635,046 Distributable income per unit $ 0.3036 $ 0.8774 BP'sBP’s January 2020 payment to the Trust. See "Financial Review—Unreimbursed ExpensesContingent Reserve"containment measures being taken to mitigate its impact. The oil and gas industry has experienced sharp declines in the demand for complete information about adjustmentscrude oil and natural gas worldwide. The global economy and commodity prices are being severely negatively impacted, as economic activity and demand for energy have declined in response to the Contingent ReserveCOVID-19 pandemic, as well as due to other geopolitical factors. The magnitude of the impact of the COVID-19 pandemic will depend on the duration and extent of the pandemic, including increases in COVID-19 case counts, any additional waves of the virus, new variants of the virus and the availability and ultimate efficacy of the vaccine on new variants of the virus. The pandemic continues to have a material adverse effect on the Working Interest Owners’ costs, operations, business and financial condition, which is having an adverse effect on Trust distributions. The Trust has not made a distribution to unitholders since the income distribution for the month of May 2020, paid to unitholders on July 31, 2020, as costs, charges and expenses attributable to the Trust’s Royalty properties, and applicable reserves, exceeded2018. Capital Resources. The Trust is a passive entity that does not undertake or control any capital projects or make capital expenditures. While the Trust's Royalty income is net of capital expenditures,these capital expenditures are controlled and paid by the Working Interests Owners, and the Trust receives Royalty income net of these expenses. Therefore, the Trust has no material commitments for capital expenditures.Years Ended2020 as compared to December 31, 2019 was primarily due to lower natural gas and 2018 SUMMARY OF ROYALTY INCOME, PRODUCTION, PRICES AND COSTS (Unaudited) Hugoton San Juan Basin—New Mexico(5) San Juan Basin—Colorado Total Natural
Gas Natural
Gas
Liquids Oil and
Condensate Natural
Gas Natural
Gas
Liquids Oil and
Condensate Natural
Gas Natural
Gas
Liquids Oil and
Condensate Natural
Gas Natural
Gas
Liquids Oil and
Condensate $ 1,267,360 $ 363,402 $ — $ 1,017,563 $ 710,207 $ 111,188 $ 564,795 $ — $ — $ 2,849,718 $ 1,073,609 $ 111,188 (1 ) — — (32,047 ) (28,884 ) (5,719 ) — — — (32,048 ) (28,884 ) (5,719 ) (893,033 ) (262,217 ) — (478,648 ) (368,629 ) (54,307 ) (129,665 ) — — (1,501,346 ) (630,846 ) (54,307 ) $ 374,326 $ 101,185 $ — $ 506,868 $ 312,694 $ 51,162 $ 435,130 $ — $ — $ 1,316,324 $ 413,879 $ 51,162 $ 374,326 $ 101,185 $ — $ 506,692 $ 313,039 $ 51,365 $ 461,771 $ — $ — $ 1,342,789 $ 414,224 $ 51,365 $ 3.52 $ 21.35 $ — $ 1.63 $ 16.00 $ 44.39 $ 1.38 $ — $ — $ 1.79 $ 17.04 $ 44.39 $ 8.40 $ 55.33 $ — $ 1.65 $ 20.32 $ 51.88 $ 0.39 $ — $ — $ 2.04 $ 27.14 $ 51.88 (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) 106,373 4,739 — 309,914 19,567 1,157 334,414 — — 750,701 24,307 1,157 $ 1,320,945 $ 634,614 $ — $ 1,323,959 $ 558,539 $ 24,164 $ 540,034 $ — $ — $ 3,184,938 $ 1,193,153 $ 24,164 (1,578 ) (815 ) — (5,052 ) (2,125 ) (92 ) — — — (6,630 ) (2,940 ) (92 ) (808,487 ) (385,640 ) — (509,607 ) (213,808 ) (9,059 ) (119,564 ) — — (1,437,658 ) (599,448 ) (9,059 ) $ 510,880 $ 248,159 $ — $ 809,300 $ 342,606 $ 15,013 $ 420,470 $ — $ — $ 1,740,650 $ 590,765 $ 15,013 $ 510,880 $ 248,159 $ — $ 808,705 $ 342,094 $ 14,998 $ 407,483 $ — $ — $ 1,727,068 $ 590,253 $ 14,998 $ 3.46 $ 25.98 $ — $ 2.04 $ 16.28 $ 37.59 $ 1.32 $ — $ — $ 2.03 $ 19.31 $ 37.59 $ 5.49 $ 40.45 $ — $ 1.30 $ 10.28 $ 22.93 $ 0.39 $ — $ — $ 1.69 $ 19.71 $ 22.93 (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) 147,685 9,553 — 395,629 21,015 399 309,558 — — 852,872 30,568 399 (1)Gross Proceeds from natural gas liquids attributable to each ofprices, decreased net natural gas production volumes and higher operating and capital costs offset in part by higher net natural gas liquids production volumes from the Hugoton Royalty Properties in fiscal year 2020. 2020 2019
Gas
Gas
Liquids
Condensate
Gas
Gas
Liquids
Condensate Average sales price $ 2.73 $ 10.01 — $ 3.52 $ 21.35 — (Mcf) (Bbls) (Bbls) (Mcf) (Bbls) (Bbls)
attributable to the Royalty paid
for Hugoton Royalty
Properties 370,235 19,622 — 360,148 17,021 —
attributable to the Royalty paid
for Hugoton Royalty
Properties 68,957 6,011 — 106,373 4,739 — are net of a volumetric in-kind processing fee retained by Scoutis calculated and Hilcorp, respectively.(2)Royalty income is computed after deducting the Trust's proportionate share of capital costs, operating costs and interest on any cost carryforward from the Trust's proportionate share of Gross Proceeds. As a result of excess production costs incurred in one monthly operating period and then recovered in a subsequent monthly operating period, the Royalty income paid to the Trust may not agreeon a state-by-state basis depending upon whether the property is situated in Colorado and New Mexico. The majority of the Royalty income from the San Juan Basin Royalty Properties is attributable to the Trust's royalty interest in the Net Proceeds (as defined in the Conveyance). The excess production costs must be recovered by the Working Interest Owners before any distribution of Royalty income will be made to the Trust. Basin—Excess production costsSubstantially all of the natural gas produced from the San Juan Basin Royalty Properties is currently being sold in the amount of $5,321 and $4,948 as of December 31, 2019 and 2018, respectively, were relatedspot market.Basin—New MexicoBasin — Colorado Properties formerly operatedfor the years ended December 31, 2020 and 2019 was $191,448 and $461,771, respectively. The decrease of approximately 59% for the year ended December 31, 2020 as compared to December 31, 2019 was primarily due to decreased net natural gas production volumes and lower prices for natural gas, offset in part by XTO, currently operated by Hilcorp. Excess productionlower operating costs relatedfrom the San Juan Basin — Colorado Properties.Basin—Basin — Colorado Properties for the years ended December 31, 2020 and 2019 were $ 117,130 and $129,665, respectively. Accumulated excess production costs have increased with respect to the San Juan Basin — Colorado Properties operated by Red Willow, from $29,597 at December 31, 2019 to $36,453 at December 31, 2020, as reported by Red Willow. The Trust will not receive Net Proceeds for the San Juan Basin — Colorado Properties operated by Red Willow until future proceeds from production exceed the total accumulated excess costs plus accrued interest during the deficit period. 2020 2019
Gas
Gas
Liquids
Condensate
Gas
Gas
Liquids
Condensate Average sales price $ 0.75 — — $ 1.38 — — (Mcf) (Bbls) (Bbls) (Mcf) (Bbls) (Bbls)
the Royalty paid for San Juan
Basin – Colorado Properties 396,782 — — 411,851 — — Net production volumes attributable to the Royalty paid for San Juan Basin – Colorado Properties 254,346 — — 334,414 — — were approximately $373 and $0 for years endedfrom $5,321 at December 31, 2019 and 2018, respectively.to $18,874 at December 31, 2020, as reported by Hilcorp. The Trust recovered prior period excess production costs related towill not receive Net Proceeds for the San Juan Basin—Basin — New Mexico Properties formerly operated by XTO, currently operated by Hilcorp, of $1,121until future proceeds from production exceed the total accumulated excess costs plus accrued interest during the year ended December 31, 2018.San Juan Basin—Colorado Properties. Excess production costs in the amount of $29,597 and $2,957 as of December 31, 2019 and 2018, respectively, were related to the San Juan Basin—Colorado Properties operated by Red Willow. Excess production costs related to the San Juan Basin—Colorado Properties operated by Red Willow were approximately $26,641 and $0deficit period.2018,$66,650, respectively. The Trust recovered $12,987 prior period excess production costs related to the San Juan Basin—Colorado Properties operated by Red Willow duringincrease of approximately 43% for the year ended December 31, 2018.(3)Average production costs attributable2020 asRoyalty are calculated as statedreconciliations completed in 2020, capital costs plus operating costs, dividedwould have decreased by stated net production volumes attributable54% for the year ended December 31, 2020 as compare to the Royalty paid. As noted above in footnote (2), production costs may be incurred in one operating period and then recovered in a subsequent operating period, which may cause Royalty income paid to the Trust not to agree to the Trust's Royalty interest in the Net Proceeds.(4)Net production volumes attributable to the Royalty are determined by dividing Royalty income by the average sales price received. Any differences noted areDecember 31, 2019 primarily due to rounding.(5) 2020 2019
Gas
Gas
Liquids
Condensate
Gas
Gas
Liquids
Condensate Average sales price $ 1.53 $ 12.68 $ 41.42 $ 1.63 $ 16.00 $ 44.39 (Mcf) (Bbls) (Bbls) (Mcf) (Bbls) (Bbls) Actual production volumes attributable to the Royalty paid for San Juan Basin – New Mexico Properties 575,017 45,872 2,375 620,642 44,485 2,505
the Royalty paid for San Juan
Basin – New Mexico Properties 144,318 15,271 (534) 309,914 19,567 1,157 Hilcorp'sHilcorp’s acquisition of ConocoPhillips'ConocoPhillips’ and XTO'sXTO’s interests in the San Juan Basin—Basin — New Mexico Properties, there was a transition period to transfer historical information, knowledge and processes from one owner to the other. During this transition period, Hilcorp recorded estimates of revenues and expenses and made payments to the Trust based on historical amounts previously paid by ConocoPhillips, and the Trust recognized such amounts in accordance with its modified cash basis of accounting. Accordingly, Hilcorp made an estimated monthly payment of $97,150 in Net Proceeds to the Trust from September 2017 to March 2019 based upon the July 2017 production month previously paid by ConocoPhillips. In April 2019, Hilcorp began to generate actual (instead of estimated) Net Proceeds due to the Trust on a monthly basis. Hilcorp has informed the Trust that it will utilize actual revenue and expense amounts and either add or subtract reconciled historical amounts on a month by month basis, which will be recognized over time by the Trust in accordance with the Trust'sTrust’s modified cash basis of accounting. In December 2019, Hilcorp made the first payment to the Trust reconciling historical amounts which was infor one accounting month. For the amount of $29,698twelve months ended December 31, 2020, Hilcorp reconciled 10 additional historical amounts for the accounting monthmonths of SeptemberOctober 2017 and wasthrough July 2018, which resulted in a charge to the only reconciliation payment made by Hilcorp during 2019. Trust of $60,262.Juan—Juan — New Mexico Properties will reflect adjustments to actual current production and costs to account for historical monthly reconciliations as they are completed. Because of anticipated future adjustments, the amountsBasin—Basin — New Mexico Properties during the year ended December 31, 20192020 may not be representative of Net Proceeds that will be received in future years.Basin—Basin — New Mexico Properties. Incremental costs attributable to the Trust will reduce the Trust'sTrust’s future Net Proceeds over a period of time as adjustments are made by Hilcorp after taking into account actual revenues as well as costs for these properties during the applicable time period. The potential impact to Net Proceeds depends upon the results of all of the reconciliation work currently being conducted by Hilcorp and is therefore uncertain. TheWith the assistance of a third party consultant, the Trust will undertakehas undertaken a review of the reconciliation calculations by Hilcorp and the amount of Net Proceeds calculated and paid and intends to engage third party consultants when appropriate to assist in the Trust's review.Trust'sTrust’s unitholders.Financial Review 2019 2018 $ 1,808,378 $ 2,332,319 29,415 22,951 (202,747 ) (217,138 ) $ 1,635,046 $ 2,138,132 $ 0.8774 $ 1.1473 Royalty and Interest Income.32 The Trust's Royalty income was $1,808,378 and $2,332,319 for the years ended December 31, 2019 and 2018, respectively. The decrease for the year ended December 31, 2019 as compared to December 31, 2018 was primarily a result of lower natural gas and natural gas liquids prices, increased operating and capital costs for natural gas, natural gas liquids and oil and condensate and lower net natural gas and natural gas liquids production volumes, partially offset by higher prices and volumes for oil and condensate for the year ended December 31, 2019. The Trust's Interest income for the years ended December 31, 2019 and 2018 was $29,415 and $22,951, respectively. In accordance with the Trust Indenture and as explained below, interest on cash on hand was paid at a rate equivalent to 1.5% below the prime interest rate. General and Administrative Expense. General and administrative expense was $202,747 and $217,138 for the years ended December 31, 2019 and 2018, respectively. The Trustee's fees are included in general and administrative expense. For the year ended December 31, 2019, the Trustee was due $475,000 for its services. The Trust paid $433,153 of this amount to the Trustee, and $41,847 was allocated to offset against interest due to the Trust under the Trust Indenture. The Trust Indenture requires that cash being held by the Trustee earn interest at 1.5% below the prime rate, which would have yielded the Trust a 4.00% annualized return from January 1, 2019 through July 31, 2019, a 3.75% annualized return from August 1, 2019 through September 18, 2019, a 3.5% annualized return from September 19, 2019 through October 30, 2019 and a 3.25% annualized return from October 31, 2019 through December 31, 2019. However, due to the current interest rate environment, the Trustee was unable to obtain an account in which such an interest rate was available. In the event such an interest rate is unavailable in the future, the Trustee intends to allocate certain of its fees due to the Trust to meet the minimum interest rate payable under the Trust Indenture. In future periods the Trustee will continue to allocate a portion of the fees earned for its services to the Trust until all remaining interest due to the Trust is fully offset. Unreimbursed Expenses and the Contingent Reserve. The Working Interest Owners partially reimburse the Trust each quarter for amounts paid in connection with the Trustee's services. For the year ended December 31, 2019, the Trustee's aggregate fees were $433,153 and the Working Interest Owners reimbursed the aggregate sum of $383,588 to the Trustee, which was the same amount reimbursed for the year ended December 21, 2018. As of the years ended December 31, 2019 and 2018, the Trust incurred unreimbursed expenses of $23,629 and $0, respectively. During 2011, the Trustee, acting pursuant to the Trust Indenture, withheld $1.0 million to establish the Contingent Reserve, with such amount being included in cash and short-term investments. The Trustee reserves the right to determine whether or not to release cash reserves in future periods with respect to any reimbursement expenses. For the year ended December 31, 2019, the Trustee increased the Contingent Reserve by (1) $56,793 of Royalty income received from BP in March 2019 after the distribution to unitholders had been announced for the month of March 2019, which Royalty income was included in the April 2018 distribution to unitholders, (2) $434 for a duplicated general and administrative expense paid in error by the Trust in February 2019 and not refunded to the Trust until April 2019, (3) $317 underpaid by Riviera in June 2019 due to a 2018 Ad Valorem tax under accrual but included in the June 2019 distribution to unitholders, which amount was then excluded from the July 2019 distribution to unitholders, (4) $812 due to a refund received from a vendor in September 2019 and (5) $843 due to an overpayment received in error from BP in December 2019 that was deducted from BP's January 2020 payment to the Trust. For the year ended December 31, 2019, the Trustee decreased the Contingent Reserve by (1) $434 for a duplicated general and administrative expense paid in error by the Trust in February 2019 and not refunded to the Trust until April 2019, (2) $38,364 for a cash refund of a duplicate payment from a vendor received in November 2018 and distributed to unitholders in February 2019, (3) $56,794 of Royalty income received from BP in March 2019 after the distribution to unitholders had been announced for the month of March 2019, which Royalty income was included in the April 2019 distribution to unitholders, (4) $317 underpaid by Riviera in June 2019 due to a 2018 Ad Valorem tax under accrual but included in the June 2019 distribution to unitholders, which amount was then excluded from the July 2019 distribution to unitholders, (5) $812 due to a refund received from a vendor in September 2019 which refund was included in the distribution to unitholders in November 2019 and (6) and $23,629 for a reimbursement not received from Scout but included in the December 2019 distribution to unitholders. For the year ended December 31, 2018, the Trustee increased the Contingent Reserve by (1) $55,725 of Royalty income received from BP in March 2018 after the distribution to unitholders had been announced for the month of March 2018, which Royalty income was included in the April 2018 distribution to unitholders, (2) $3,627 of Royalty income received from BP in June 2018 after the distribution to unitholders had been announced for the month of June 2018, which Royalty income was included in the July 2018 distribution to unitholders, (3) $14,501 of general and administrative expense not reimbursed by Riviera in June 2018 but included in the June 2018 distribution to unitholders, which reimbursement was received in July 2018, (4) $3,000 of general and administrative expense not reimbursed by Riviera in September 2018 but included in the September 2018 distribution to unitholders, which reimbursement was received in October 2018 and (5) $38,364 cash refund from a vendor received in November 2018. For the year ended December 31, 2018, the Trustee decreased the Contingent Reserve by (1) $49,211 of Royalty income received from BP in December 2017 after the distribution to unitholders had been announced for the month of December 2017, which Royalty income was included in the January 2018 distribution to unitholders, (2) $70,460 of December 2017 expenses that were included in the distribution calculation for December 2017, but not paid by the Trust until January 2018, (3) $55,725 of Royalty income received from BP in March 2018 after the distribution to unitholders had been announced for the month of March 2018, which Royalty income was included in the April2018 distribution to unitholders, (4) $3,627 of Royalty income received from BP in June 2018 after the distribution to unitholders had been announced for the month of June 2018, which Royalty income was included in the July 2018 distribution to unitholders, (5) $14,501 of general and administrative expense not reimbursed by Riviera in June 2018 but included in the June 2018 distribution to unitholders, which reimbursement was received in July 2018 and (6) $3,000 of general and administrative expense not reimbursed by Riviera in September 2018 but included in the September 2018 distribution to unitholders, which reimbursement was received in October 2018. The net effects of the foregoing adjustments for the year ended December 31, 2018 resulted in the balance of the Contingent Reserve being equal to $1,038,364 as of December 31, 2018. Distributable Income Available for Distribution. The portion of the Trust's distributable income available for distribution each year includes the Royalty income received from the Working Interest Owners during such period, plus interest income earned to the date of distribution (if any) and increases or withdrawals to and from the Contingent Reserve (if any). Distributable income available for distribution for the years ended December 31, 2019 and 2018 was $1,696,197 and $2,219,438, respectively. For the years ended December 31, 2019 and 2018, the Trust calculated total aggregate distributions of $0.910 and $1.191 per unit, respectively.Operational ReviewHugoton Royalty Properties Royalty Income. Royalty income attributable to the Hugoton Royalty Properties for the years ended December 31, 2019 and 2018 was $475,511 and $759,039, respectively. The decrease of approximately 37% for the year ended December 31, 2019 as compared to December 31, 2018 was primarily due to lower natural gas liquids prices and decreased net natural gas and natural gas liquids production volumes, offset in part by lower operating costs from the Hugoton Royalty Properties in fiscal year 2019. Operating Costs and Capital Expenditures. Operating costs attributable to the Hugoton Royalty Properties for the years ended December 31, 2019 and 2018 were $1,155,250 and $1,194,128, respectively. 2019 2018 Natural
Gas Natural
Gas
Liquids Oil and
Condensate Natural
Gas Natural
Gas
Liquids Oil and
Condensate $ 3.52 $ 21.35 — $ 3.46 $ 25.98 — (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) 360,148 17,021 — 382,054 24,444 — 106,373 4,739 — 147,685 9,553 — Average Sales Prices. Average sales prices per Mcf of natural gas and Bbl for natural gas liquids for the Hugoton Royalty Properties is directly dependent on the prices Scout realizes for natural gas sold under short-term and multi-month contracts at market clearing prices to multiple purchasers. On April 18, 2018, Linn announced its Board of Directors' decision to separate Linn into two stand-alone public companies. On August 7, 2018 Linn completed the spin-off of Riviera through thepro rata distribution of all of the shares of Riviera's outstanding common stock to Linn's stockholders. In connection with such distribution, Linn ceased to be the operator of the Hugoton Royalty Properties, and since August 7, 2018, Riviera operated the Hugoton Royalty Properties. On November 22, 2019, Riviera completed the sale of its interest in its remaining properties located in the Hugoton Basin under the Purchase and Sale Agreement, dated August 28, 2019 (the "Purchase Agreement"), by and between the Riviera Upstream, LLC, Riviera Operating, LLC and Scout Energy Group V, LP ("Scout"). Pursuant to the Purchase Agreement, Riviera divested all of its interest in its oil and gas assets and contracts in the Hugoton Royalty Properties. Since November 23, 2019, Scout has operated the Hugoton Royalty Properties.San Juan Basin Royalty Properties Royalty income from the San Juan Basin Royalty Properties is calculated and paid to the Trust on a state-by-state basis depending upon whether the property is situated in Colorado and New Mexico. The majority of the Royalty income from the San Juan Basin Royalty Properties is attributable to the San Juan Basin—New Mexico Properties. Substantially all of the natural gas produced from the San Juan Basin Royalty Properties is currently being sold in the spot market.San Juan Basin—Colorado Properties Royalty Income. Royalty income attributable to the San Juan Basin—Colorado Properties for the years ended December 31, 2019 and 2018 was $461,771 and $407,483, respectively. The increase of approximately 13% for the year ended December 31, 2019 as compared to December 31, 2018 was primarily due to increased net natural gas production volumes and higher prices for natural gas, offset in part by higher operating costs from the San Juan Basin—Colorado Properties. Operating Costs and Capital Expenditures. Operating costs attributable to the San Juan Basin—Colorado Properties for the years ended December 31, 2019 and 2018 were $129,665 and $119,564, respectively. There were no capital expenditures attributable to the San Juan Basin—Colorado Properties for the years ended December 31, 2019 or 2018. 2019 2018 Natural
Gas Natural
Gas
Liquids Oil and
Condensate Natural
Gas Natural
Gas
Liquids Oil and
Condensate $ 1.38 — — $ 1.32 — — (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) 411,851 — — 409,647 — — 334,414 — — 309,558 — — San Juan Basin—New Mexico Properties Royalty Income. Royalty income attributable to the San Juan Basin—New Mexico Properties for the years ended December 31, 2019 and 2018 was $871,096 and $1,165,797, respectively. The decrease of approximately 25% for the year ended December 31, 2019 as compared to December 31, 2018 was primarily due to lower prices for natural gas and natural gas liquids, decreased net production volumes for natural gas and natural gas liquids and higher operating and capital expenditures, partially offset byhigher prices and increased net production for oil and condensate for the San Juan Basin—New Mexico Properties. Operating Costs and Capital Expenditures. Operating costs attributable to the San Juan Basin—New Mexico Properties for the years ended December 31, 2019 and 2018 were $901,584 and $732,474, respectively. The increase of approximately 23% for the year ended December 31, 2019 as compared to December 31, 2018 was primarily due to maintenance expense reductions in 2017 that continued to be used by Hilcorp as estimates through the first quarter of 2019. Capital expenditures on these properties were $66,650 for the year ended December 31, 2019, an increase of approximately $59,381 as compared to $7,269 for the year ended December 31, 2018 due primarily to very low capital investment in 2017 that continued to be used by Hilcorp as an estimate through the first quarter of 2019 and the addition in 2019 of well zone recompletes that bring on new zones of production and reserves. 2019 2018 Natural
Gas Natural
Gas
Liquids Oil and
Condensate Natural
Gas Natural
Gas
Liquids Oil and
Condensate $ 1.63 $ 16.00 $ 44.39 $ 2.04 $ 16.28 $ 37.59 (Mcf ) (Bbls ) (Bbls ) (Mcf ) (Bbls ) (Bbls ) 620,642 44,485 2,505 647,878 44,992 643 309,914 19,567 1,157 395,629 21,015 399 Following Hilcorp's acquisition of ConocoPhillips' and XTO's interests in the San Juan Basin—New Mexico Properties, there was a transition period to transfer historical information, knowledge and processes from one owner to the other. During this transition period, Hilcorp recorded estimates of revenues and expenses and made payments to the Trust based on historical amounts previously paid by ConocoPhillips, and the Trust recognized such amounts in accordance with its modified cash basis of accounting. Accordingly, Hilcorp made an estimated monthly payment of $97,150 in Net Proceeds to the Trust from September 2017 to March 2019 based upon the July 2017 production month previously paid by ConocoPhillips. In April 2019, Hilcorp began to generate actual (instead of estimated) Net Proceeds due to the Trust on a monthly basis. Hilcorp has informed the Trust that it will utilize actual revenue and expense amounts and either add or subtract reconciled historical amounts on a month by month basis, which will be recognized over time by the Trust in accordance with the Trust's modified cash basis of accounting. In December 2019, Hilcorp made the first payment to the Trust reconciling historical amounts, which was in the amount of $29,698 for the accounting month of September 2017 and was the only reconciliation payment made by Hilcorp during 2019. Until all estimated historical monthly amounts received by the Trust from September 2017 to March 2019 are fully reconciled and adjusted, Net Proceeds from the San Juan—New Mexico Properties will reflect adjustments to actual current production and costs to account for historical monthly reconciliations as they are completed. Because of anticipated future adjustments, the amounts of Net Proceeds reported for the San Juan Basin—New Mexico Properties during the year ended December 31, 2019 may not be representative of Net Proceeds that will be received in future years. Hilcorp has informed the Trust that significant incremental costs of approximately $1.1 million attributable to the Trust were incurred in 2018 with respect to a newly drilled well in the San Juan Basin—New Mexico Properties. Incremental costs attributable to the Trust will reduce the Trust's future Net Proceeds over a period of time as adjustments are made by Hilcorp after taking into accountactual revenues as well as costs for these properties during the applicable time period. The potential impact to Net Proceeds depends upon the results of all of the reconciliation work currently being conducted by Hilcorp and is therefore uncertain. The Trust will undertake a review of the reconciliation calculations by Hilcorp and the amount of Net Proceeds calculated and paid and intends to engage third party consultants when appropriate to assist in the Trust's review. Pursuant to the Trust Indenture, the Trust is not required to pay to Hilcorp any amounts that could be owed if the estimated revenue exceeded actual revenue amounts or estimated expenses were less than actual expense amounts in past periods. However, Hilcorp may recover such amounts by withholding a portion or all of the Net Proceeds that would otherwise be payable to the Trust in subsequent periods. This could result in a decrease in Net Proceeds paid to the Trust and could result in future material reductions in distributions to the Trust's unitholders.Trust'sTrust’s proportionate share of the net proceedsNet Proceeds for such month;net proceedsNet Proceeds from production for such month without regard to when calculated or received, general and administrative expenses would be recorded in the month they accrue, and interest income for a month would be calculated only through the end of such month.20192020 and 2018,2019, the related statements of distributable income and changes in trust corpus for each of the years in the two-year period ended December 31, 2019,2020, and the related notes (collectively, the financial statements). In our opinion, the financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of the Trust as of December 31, 20192020 and 2018,2019, and its distributable income and changes in trust corpus for each of the years in the two-year period ended December 31, 2019,2020, in conformity with the modified cash basis of accounting as described in Note 2.Trustee.Trust’s management. 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 the 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.Trust'sTrust’s internal control over financial reporting. Accordingly, we express no such opinion.(signed) KPMG LLPTrust'sTrust’s auditor since 2002.
March 30, 202031, 2021 Years Ended December 31, 2020 2019 Royalty income $ 832,149 $ 1,808,378 Interest income 5,756 29,415 General and administrative expenses (193,947) (202,747) Income available for distribution prior to cash reserves withheld for Trust expenses $ 643,958 $ 1,635,046 Cash reserves withheld for current Trust expenses (78,208) — Distributable income $ 565,750 $ 1,635,046 Distributable income per unit $ 0.3036 $ 0.8774 Years Ended December 31, 2019 2018 $ 1,808,378 $ 2,332,319 29,415 22,951 (202,747 ) (217,138 ) $ 1,635,046 $ 2,138,132 $ 0.8774 $ 1.1473 (The
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS December 31, 2020 2019 ASSETS Cash and short-term investments $ 1,076,485 $ 1,233,060 Net overriding royalty interests in oil and gas properties 42,498,034 42,498,034 Accumulated amortization (40,984,296) (40,890,724) Total assets $ 2,590,223 $ 2,840,370 LIABILITIES AND TRUST CORPUS Distributions payable $ — $ 255,848 Trust corpus (1,863,590 units of beneficial interest, issued and outstanding) 2,590,223 2,584,522 Total liabilities and trust corpus $ 2,590,223 $ 2,840,370 December 31, 2019 2018 $ 1,233,060 $ 1,604,884 42,498,034 42,498,034 (40,890,724 ) (40,744,388 ) $ 2,840,370 $ 3,358,530 $ 255,848 $ 566,518 2,584,522 2,792,012 $ 2,840,370 $ 3,358,530 (The(The accompanying notes are an integral part of these financial statements.)
STATEMENTS OF CHANGES IN TRUST CORPUS Years Ended December 31, 2020 2019 Trust corpus, beginning of year $ 2,584,522 $ 2,792,012 Cash reserves withheld for current Trust expenses 78,208 — Distributable income 565,750 1,635,046 Distributions to unitholders (544,685) (1,696,197) Amortization of net overriding royalty interests (93,572) (146,339) Trust corpus, end of year $ 2,590,223 $ 2,584,522 Years Ended December 31, 2019 2018 $ 2,792,012 $ 3,097,932 1,635,046 2,138,132 (1,696,197 ) (2,219,438 ) (146,339 ) (224,614 ) $ 2,584,522 $ 2,792,012 (The(The accompanying notes are an integral part of these financial statements.)
MESA ROYALTY TRUST1—1 — Trust Organization and Provisions"Trustee"“Trustee”), 601 Travis Street, Floor 16, Houston, Texas 77002. The telephone number of the Trust is 713-483-6020. The Bank of New York Mellon Trust Company, N.A., is the successor Trustee from JPMorgan Chase Bank, N.A., which is the successor by mergers to the originally named Trustee, Texas Commerce Bank National Association. The Trust has no employees. Administrative functions of the Trust are performed by the Trustee. The Trustee maintains a website for the Trust that makes available, free of charge, filings by the Trust with the Securities and Exchange Commission ("SEC"(“SEC”) and other information. Any reports filed with the SEC are accessible through our website as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The Trust'sTrust’s website is http://mtr.investorhq.businesswire.com/."Trust"“Trust”) was created on November 1, 1979 and is now governed by the Mesa Royalty Trust Indenture (as amended, the "Trust Indenture"“Trust Indenture”). Through a series of conveyances, assignments, and acquisitions, the Trust currently owns an overriding royalty interest (the "Royalty"“Royalty”) equal to 11.44% of 90% of the Net Proceeds (as defined in the Conveyance and described below) attributable to the specified interest in certain producing oil and gas properties located in the:"Hugoton“Hugoton Royalty Properties"Properties”);•"San“San Juan Basin—Basin — New Mexico Properties"Properties”); and•"San“San Juan Basin—Basin — Colorado Properties"Properties”, and together with the "San“San Juan Basin—Basin — New Mexico Properties"Properties”, the "San“San Juan Basin Royalty Properties"Properties”, and together with the Hugoton Royalty Properties, the "Royalty Properties"“Royalty Properties”).("MLP"(“MLP”), which was the predecessor to MESA Inc., conveyed to the Trust the Royalty equal to 90% of the Net Proceeds (as defined in the conveyance and described below) attributable to the specified interests in properties conveyed by the assignor on that date (the "Subject Interests"“Subject Interests”). The Subject Interests consisted of interests in the Royalty Properties described above. The Royalty is evidenced by counterparts of an Overriding Royalty Conveyance, dated November 1, 1979 (the "Conveyance"“Conveyance”). In 1985, the Trust Indenture was amended, and the Trust conveyed to an affiliate of Mesa Petroleum Co. 88.5571% of the original Royalty (such transfer, the "1985 Assignment"“1985 Assignment”). The effect of the 1985 Assignment was an overall reduction of approximately 88.56% in the size of the Trust. As a result, the Trust is now entitled to receive 11.44% of 90% of the Net Proceeds attributable to each month. Until August 7, 1997, MESA Inc. operated the Hugoton Royalty Properties through Mesa Operating Co., its wholly owned subsidiary. On August 7, 1997, MESA Inc. merged with and into Pioneer Natural Resources Company ("Pioneer"), formerly a wholly owned subsidiary of MESA Inc., and Parker & Parsley Petroleum Company merged with and into Pioneer Natural Resources USA, Inc. (successor to Mesa Operating Co.), a wholly owned subsidiary of Pioneer ("PNR") (collectively, the mergers are referred to herein as the "Merger"). Subsequent to the Merger, the Hugoton Royalty Properties were operated by PNR until December 31, 2014, at which point Linn Energy Holdings, LLC, a subsidiary of Linn Energy, LLC ("Old Linn") took over as operator. Pursuant to the bankruptcy proceedings and court-approved plans of reorganization involving Old Linn, whichMESA ROYALTY TRUSTNOTES TO FINANCIAL STATEMENTS (Continued)Note 1—Trust Organization and Provisions (Continued)are described below, Linn Energy, Inc. (together with its subsidiaries, "Linn") became the operator of the Hugoton Royalty Properties on February 28, 2017. On April 18, 2018, Linn announced its Board of Directors' decision to separate Linn into two stand-alone public companies. On August 7, 2018 Linn completed the spin-off of Riviera Resources, Inc. ("Riviera") through the pro rata distribution of all of the shares of Riviera's outstanding common stock to Linn's stockholders. In connection with such distribution, Linn ceased to be the operator of the Hugoton Royalty Properties, and since August 7, 2018, Riviera operated the Hugoton Royalty Properties. On November 22, 2019, Riviera Resources, Inc. (“Riviera”) completed the sale of its interest in its remaining properties located in the Hugoton Basin under the Purchase and Sale Agreement, dated August 28, 2019 (the "Purchase Agreement"“Purchase Agreement”), by and between the Riviera Upstream, LLC, Riviera Operating, LLC and Scout Energy Group V, LP ("Scout"(“Scout”). Pursuant to the Purchase Agreement, Riviera divested all of its interest in its oil and gas assets and contracts in the Hugoton Royalty Properties. Since November 23, 2019, Scout has operated the Hugoton Royalty Properties.Basin—Basin — Colorado Properties. On April 30, 1991, MLP sold to Conoco, Inc. ("ConocoPhillips"(“ConocoPhillips”) its interests in the San Juan Basin Royalty Properties (the "San“San Juan Basin Sale"Sale”). The Trust'sTrust’s interest in the San Juan Basin Royalty Properties was conveyed from PNR'sPNR’s working interest in 31,328 net producing acres in northwestern New Mexico and southwestern Colorado. ConocoPhillips sold the portion of its interests in the San Juan Basin—Basin — Colorado Properties to MarkWest Energy Partners, Ltd. (effective January 1, 1993) and Red Willow Production Company ("(“Red Willow"Willow”) (effective April 1, 1992). On October 26, 1994, MarkWest Energy Partners, Ltd. sold substantially all of its interest in the San Juan Basin—Basin — Colorado Properties to BP Amoco Company ("BP"(“BP”). On February 28, 2020, BP completed the sale of all of its interest in the San Juan Basin — Colorado Properties to IKAV Energy Inc. (“IKAV”). BP,Basin—Basin — Colorado Properties.Basin—Basin — New Mexico Properties. Starting from the date of the San Juan Basin Sale and ending on July 31, 2017, ConocoPhillips operated substantially all of the San Juan Basin—Basin — New Mexico Properties, except an immaterial number of properties assigned to XTO Energy, Inc. ("XTO"(“XTO”) effective January 1, 2005. On July 31, 2017, ConocoPhillips sold its San Juan Basin assets to Hilcorp San Juan LP ("Hilcorp"(“Hilcorp”), an affiliate of Hilcorp Energy Company. On March 29, 2018, XTO sold to Hilcorp an immaterial number of properties, which comprise certain portions of the San Juan Basin—Basin — New Mexico Properties. Hilcorp currently operates all of the San Juan Basin—Basin — New Mexico Properties.Hilcorp'sHilcorp’s acquisition of ConocoPhillips'ConocoPhillips’ and XTO'sXTO’s interests in the San Juan Basin—Basin — New Mexico Properties, there was a transition period to transfer historical information, knowledge and processes from one owner to the other. During this transition period, Hilcorp recorded estimates of revenues and expenses and made payments to the Trust based on historical amounts previously paid by ConocoPhillips, and the Trust recognized such amounts in accordance with its modified cash basis of accounting. Accordingly, Hilcorp made an estimated monthly payment of $97,150 in Net Proceeds to the Trust from September 2017 to March 2019 based upon the July 2017 production month previously paid by ConocoPhillips. In April 2019, Hilcorp began to generate actual (instead of estimated) Net Proceeds due to the Trust on a monthly basis. Hilcorp has informed the Trust that it will utilize actual revenue and expense amounts and either add or subtract reconciled historical amounts on a month by month basis, which will be recognized over time by the Trust in accordance with the Trust'sTrust’s modified cash basis of accounting. In December 2019, Hilcorp made the first payment to the Trust reconciling historical amounts which was infor one accounting month. For the amount of $29,698twelve months ended December 31, 2020, Hilcorp reconciled 10 additional historical amounts for the accounting monthmonths of SeptemberOctober 2017 and wasthrough July 2018, which resulted in a charge to the only reconciliation payment made by Hilcorp during 2019. Trust of $60,262.MESA ROYALTY TRUSTNOTES TO FINANCIAL STATEMENTS (Continued)Note 1—Trust Organization and Provisions (Continued)Juan—Juan — New Mexico Properties will reflect adjustments to actual current production and costs to account for historical monthly reconciliations as they are completed. Because of anticipated future adjustments, the amounts of Net Proceeds reported for the San Juan Basin—Basin — New Mexico Properties during the year ended December 31, 20192020 may not be representative of Net Proceeds that will be received in future years.Basin—Basin — New Mexico Properties. Incremental costs attributable to the Trust will reduce the Trust'sTrust’s future Net Proceeds over a period of time as adjustments are made by Hilcorp after taking into account actual revenues as well as costs for these properties during the applicable time period. The potential impact to Net Proceeds depends upon the results of all of the reconciliation work currently being conducted by Hilcorp and is therefore uncertain. TheWith the assistance of a third party consultant, the Trust will undertakehas undertaken a review of the reconciliation calculations by Hilcorp and the amount of Net Proceeds calculated and paid and intends to engage third party consultants when appropriate to assist in the Trust's review.Trust'sTrust’s unitholders.Basin—Basin — New Mexico Properties for years ended December 31, 2020 and 2019 were $392,256 and 2018 were $871,096, and $1,165,797, respectively, which revenue accounted for approximately 49%48% and 50%48%, respectively, of the total Royalty income reported by the Trust during those periods.Basin—Basin — New Mexico Properties, and BPIKAV and Red Willow refer to the current co-operators of certain tracts of land included in the San Juan Basin—Basin — Colorado Properties, unless otherwise indicated. Scout, BP,IKAV, Red Willow and Hilcorp are each individually referred to herein as "Working“Working Interest Owner"Owner” or collectively as the "Working“Working Interest Owners.""Contracts"“Contracts”. The Trustee has no power or authority to exercise any control over the operation of the Royalty Properties or the marketing of production therefrom. In addition, the Trust does not undertake or control any capital projects or make capital expenditures related to any of the Royalty Properties.MESA ROYALTY TRUSTNOTES TO FINANCIAL STATEMENTS (Continued)Note 1—Trust Organization and Provisions (Continued)Trust'sTrust’s royalty income for two successive years is less than $250,000 per year or (ii) a vote by the unitholders in favor of termination. Upon termination of the Trust, the Trustee will sell for cash all the assets held in the Trust estate and make a final distribution to unitholders of any funds remaining after all Trust liabilities have been satisfied; andBPIKAV will reimburse the Trust for 59.34%, 27.45% and 1.77%, respectively, for general and administrative expenses of the Trust. Trustee'sTrustee’s Fees. Pursuant to the Trust Indenture, the Trust pays the Trustee fees for its services each quarter and the Working Interest Owners partially reimburse the Trust for the fees paid in connection with the Trustee'sTrustee’s services. The net amount of these reimbursements is included in the general and administrative expenses of the Trust. For the year ended December 31, 2019,2020, the Trustee was due $475,000 for its services. The Trust paid $433,153 of this amount to the Trustee, and $41,847 was allocated to offset against interest due to the Trust under the Trust Indenture. The Trust Indenture requires that cash being held by the Trustee earn interest at 1.5% below the prime rate, which would have yielded the Trust a 4.00%3.25% annualized return from January 1, 20192020 through July 31, 2019,March 2, 2020, a 3.75%2.75% annualized return from August 1, 2019 to September 18, 2019,March 3, 2020 through March 14, 2020 and a 3.50%1.75% annualized return from September 19, 2019 through October 30, 2019, a 3.25% annualized return from October 31, 2019March 15, 2020 through December 31, 2019.2020. However, due to the current interest rate environment, the Trustee was unable to obtain an account in which such an interest rate was available. In the event such an interest rate is unavailable in the future, the Trustee intends to allocate certain of its fees due to the Trust to meet the minimum interest rate payable under the Trust Indenture.Trustee'sTrustee’s services. For the year ended December 31, 2019,2020, the Trustee'sTrustee’s fees were $433,153 and the Working Interest Owners reimbursed a sum of $383,588 to the Trustee, which was the same amount reimbursed for the year ended December 31, 2018."Gross Proceeds"“Gross Proceeds” received by the Working Interest OwnersMESA ROYALTY TRUSTNOTES TO FINANCIAL STATEMENTS (Continued)Note 1—Trust Organization and Provisions (Continued)Owners "Gross Proceeds"“Gross Proceeds” is defined in the Conveyance as the amount received by the Working Interest Owners from the sale of "Subject Minerals"“Subject Minerals”, subject to certain adjustments. "Subject Minerals"“Subject Minerals” means all oil, gas and other minerals, whether similar or dissimilar, in and under, and which may be produced, saved and sold from, and which accrue and are attributable to, the Subject Interests from and after November 1, 1979. "Production costs"“Production costs” means, generally, costs incurred on an accrual basis by the Working Interest Owners in operating the Royalty Properties, including capital and non-capital costs. If production and capital costs exceed Gross Proceeds for any month, the excess, plus interest thereon at 120% of the prime rate of Bank of America, is recovered out of future Gross Proceeds prior to the making of further payment to the Trust. The Trust, however, is generally not liable for any operating costs or other costs or liabilities attributable to the Royalty Properties or minerals produced therefrom. The Trust is not obligated to return any Royalty income received in any period.2—2 — Basis of PresentationMESA ROYALTY TRUSTNOTES TO FINANCIAL STATEMENTS (Continued)Note 2—Basis of Presentation (Continued)basis:Trust'sTrust’s proportionate share of the net proceedsNet Proceeds for such month;3—3 — Legal ProceedingsMESA ROYALTY TRUSTNOTES TO FINANCIAL STATEMENTS (Continued)4—4 — Income Tax Matters"IRS"“IRS”) advised the Dallas District Director that the Trust is classifiable as a grantor trust and not as an association taxable as a corporation. As a grantor trust, the Trust incurs no federal income tax liability and each unitholder is subject to tax on the unitholder'sunitholder’s pro rata share of the income and expense of the Trust as if the unitholder were the direct owner of a pro rata share of the Trust'sTrust’s assets. In addition, there is no state tax liability for the period.tax—tax — also known as the Net Investment Income Tax ("NIIT"(“NIIT”)—on their net investment income. Grantor trusts such as Mesa Royalty Trust are not subject to the NIIT; however, the unitholders may be subject to the tax. For these purposes, investment income would generally include certain income derived from investments, such as the royalty income derived from the units and gain realized by a unitholder from a sale of the units.("WHFIT"(“WHFIT”) for U.S. federal income tax purposes. Bank of New York Mellon Trust Company, N.A., 601 Travis Street, Floor 16, Houston, Texas 77002, telephone number 713-483-6020, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT.5—5 — Excess Production Costs
December 31,
2020
December 31,
2019 Hugoton Properties $ 430,888 $ — San Juan Basin – Colorado Properties – Red Willow 36,453 29,597 San Juan Basin – New Mexico Properties – Hilcorp 18,874 5,321 Total $ 486,215 $ 34,918 As of December 31, 2019 As of December 31, 2018 $ 29,597 $ 2,957 5,321 4,948 $ 34,918 $ 7,905 MESA ROYALTY TRUSTNOTES TO FINANCIAL STATEMENTS (Continued)6—6 — Distributable Income Per Unit During 2011, thewithheld $1.0 millionmay withhold Royalty income for future unknown contingent liabilities and expenses (such cumulative withholding being the "Contingent Reserve"“Contingent Reserve”). The Trustee reserves the right to determine whether or not to release cash reserves in future periods with respect to any reimbursement expenses. At any given time, the Contingent Reserve is included in cash and short-term investments.BP'sBP’s January 2020 payment to the Trust. For the year ended December 31, 2018, the Trustee increased the Contingent Reserve by (1) $55,725 of Royalty income received from BP in March 2018 after the distribution to unitholders had been announced for the month of March 2018, which Royalty income was included in the April 2018 distribution to unitholders, (2) $3,627 of Royalty income received from BP in June 2018 after the distribution to unitholders had been announced for the month of June 2018, which Royalty income was included in the July 2018 distribution to unitholders, (3) $14,501 of general and administrative expense not reimbursed by Riviera in June 2018 but included in the June 2018 distribution to unitholders, which reimbursement was received in July 2018, (4) $3,000 of general and administrative expense not reimbursed by Riviera in September 2018 but included in the September 2018 distribution to unitholders, which reimbursement was received in October 2018 and (5) $38,364 cash refund from a vendor received in November 2018. For the year ended December 31, 2018, the Trustee decreased the Contingent Reserve by (1) $49,211 of Royalty income received from BP in December 2017 after the distribution to unitholders had been announced for the month of December 2017, which Royalty income was included in theMESA ROYALTY TRUSTNOTES TO FINANCIAL STATEMENTS (Continued)Note 6—Distributable Income Per Unit (Continued)January 2018 distribution to unitholders, (2) $70,460 of December 2017 expenses that were included in the distribution calculation for December 2017, but not paid by the Trust until January 2018, (3) $55,725 of Royalty income received from BP in March 2018 after the distribution to unitholders had been announced for the month of March 2018, which Royalty income was included in the April 2018 distribution to unitholders, (4) $3,627 of Royalty income received from BP in June 2018 after the distribution to unitholders had been announced for the month of June 2018, which Royalty income was included in the July 2018 distribution to unitholders, (5) $14,501 of general and administrative expense not reimbursed by Riviera in June 2018 but included in the June 2018 distribution to unitholders, which reimbursement was received in July 2018 and (6) $3,000 of general and administrative expense not reimbursed by Riviera in September 2018 but included in the September 2018 distribution to unitholders, which reimbursement was received in October 2018. The net effects of the foregoing adjustments for the year ended December 31, 2018 resulted in the balance of the Contingent Reserve being equal to $1,038,364 as of December 31, 2018. 2020 2019 Income available for distribution prior to cash reserves withheld for Trust expenses $ 643,958 $ 1,635,046 Increase in the Contingent Reserve (320,537) (59,199) Withdrawal from the Contingent Reserve 221,264 120,350 Distributable Income Available for Distribution $ 544,685 $ 1,696,197 Distributable Income Available for Distribution per unit $ 0.292 $ 0.910 Units outstanding 1,863,590 1,863,590 2019 2018 $ 1,635,046 $ 2,138,132 (59,199 ) (115,217 ) 120,350 196,523 $ 1,696,197 $ 2,219,438 $ 0.910 $ 1.191 1,863,590 1,863,590 7—7 — Supplemental Reserve Information (Unaudited)20192020 are based on the reserve report prepared by Miller and Lents, independent petroleum engineering consultants. Prior to Miller and Lents, the Trust used DeGolyer and MacNaughton as its independent pertroleumpetroleum engineering consultants. The estimates were prepared in accordance withTrust'sTrust’s Royalty were estimated by allocating to the Trust a portion of the estimated combined net reserve volumes of the Hugoton Royalty Properties and San Juan Basin Royalty Properties based on future net revenue. Production volumes are allocated based solely on royalty income. Because the net reserve volumes attributable to the Trust'sTrust’s Royalty are estimated using an allocation of reserve volumes based on estimates of future net revenue, a change in prices or costs will result in changes in the estimated net reserve volumes. Therefore, the estimated net reserve volumes attributable to the Trust'sTrust’s Royalty will vary if different future price and cost assumptions are used. Only costs necessary to develop and produce existing proved reserve volumes were assumed in the allocation of reserve volumes to the Royalty.20192020 were based on the average price during the 12-month period,MESA ROYALTY TRUSTNOTES TO FINANCIAL STATEMENTS (Continued)Note 7—Supplemental Reserve Information (Unaudited) (Continued)Table of ContentsMESA ROYALTY TRUSTNOTES TO FINANCIAL STATEMENTS (Continued)Note 7—Supplemental Reserve Information (Unaudited) (Continued)
ESTIMATED QUANTITIES OF PROVED, PROVED DEVELOPED,
AND PROVED UNDEVELOPED RESERVES
(Unaudited)
Condensate
Gas
Liquids
Gas (Bbls) (Bbls) (Mcf) Proved Reserves: December 31, 2016 5,238 232,870 4,083,799 Revisions to previous estimates 3,713 161,831 3,214,039 Extensions, discoveries and other additions — — — Production (774) (34,692) (987,502) December 31, 2017 8,177 360,009 6,310,336 Revisions to previous estimates 2,219 103,606 1,834,431 Extensions, discoveries and other additions — — — Production (399) (30,568) (852,872) December 31, 2018 9,997 433,047 7,291,895 Revisions to previous estimates 3,358 (1,488) 1,826,202 Extensions, discoveries and other additions — — — Production (2,355) (51,559) (1,412,097) December 31, 2019 11,000 380,000 7,706,000 Revisions to previous estimates (1,534) (52,718) (1,865,379) Extensions, discoveries and other additions — — — Production 534 (21,282) (467,621) December 31, 2020 10,000 306,000 5,373,000 Proved Developed Reserves: December 31, 2016 5,238 232,870 4,083,799 December 31, 2017 8,177 360,009 6,310,336 December 31, 2018 9,997 433,047 7,291,895 December 31, 2019 11,000 380,000 7,706,000 December 31, 2020 10,000 306,000 5,373,000 Oil and
Condensate Natural
Gas
Liquids Natural
Gas (Bbls) (Bbls) (Mcf) 6,295 287,019 5,249,794 (228 ) (29,399 ) (566,548 ) — — — (829 ) (24,750 ) (599,447 ) 5,238 232,870 4,083,799 3,713 161,831 3,214,039 — — — (774 ) (34,692 ) (987,502 ) 8,177 360,009 6,310,336 2,219 103,606 1,834,431 — — — (399 ) (30,568 ) (852,872 ) 9,997 433,047 7,291,895 3,358 (1,488 ) 1,826,202 — — — (2,355 ) (51,559 ) (1,412,097 ) 11,000 380,000 7,706,000 6,295 287,019 5,249,794 5,238 232,870 4,083,799 8,177 360,009 6,310,336 9,997 433,047 7,291,895 11,000 380,000 7,706,000 — — — — — — — — — — — — — — —
••1%0%, 8%1% and 20%8% of the estimated proved natural gas liquids reserves and 1%0%, 9%1% and 21%9% of the estimated proved natural gas reserves as of December 31, 2020, 2019 and 2018, and 2017, respectively.MESA ROYALTY TRUSTNOTES TO FINANCIAL STATEMENTS (Continued)Note 7—Supplemental Reserve Information (Unaudited) (Continued)•2016 and 20152016 reserve estimates for the Hugoton Royalty Properties were prepared by a third-party reservoir engineering firm.
OIL AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM
(Unaudited Estimates) As of December 31, 2020 2019 2018 (In thousands) The Trust’s proportionate share of future Gross Proceeds $ 20,082 $ 35,252 $ 41,480 The Trust’s proportionate share of future operating costs (5,602) (12,649) (20,596) Future capital costs (1,407) (1,214) (1) Future Royalty income $ 13,073 $ 21,389 $ 20,883 Discount at 10% per annum (6,503) (10,896) (10,243) Standardized measure of future Royalty income from proved oil and gas reserves $ 6,570 $ 10,493 $ 10,640 As of December 31, 2019 2018 2017 (In thousands) $ 35,252 $ 41,480 $ 49,439 (12,649 ) (20,596 ) (25,507 ) (1,214 ) (1 ) (1 ) $ 21,389 $ 20,883 $ 23,931 (10,896 ) (10,243 ) (10,585 ) $ 10,493 $ 10,640 $ 13,346
CHANGES IN THE STANDARDIZED MEASURE OF FUTURE ROYALTY INCOME FROM
PROVED OIL AND GAS RESERVES, DISCOUNTED AT 10% PER ANNUM
(Unaudited Estimates) As of December 31, 2020 2019 2018 (In thousands) Standardized measure of future Royalty income from proved oil and gas reserves at beginning of year $ 10,493 $ 10,640 $ 13,346 Revisions of previous estimates (892) (3,273) 757 Net changes in price and production costs (3,062) 4,072 (2,209) Royalty income (832) (1,808) (2,332) Accretion of discount 863 862 1,078 Net changes in standardized measure $ (3,923) $ (147) $ (2,706) Standardized measure of future Royalty income from proved oil and gas reserves at end of year $ 6,570 $ 10,493 $ 10,640 As of December 31, 2019 2018 2017 (In thousands) $ 10,640 $ 13,346 $ 7,057 (3,273 ) 757 549 4,072 (2,209 ) 7,115 (1,808 ) (2,332 ) (3,029 ) 862 1,078 1,654 $ (147 ) $ (2,706 ) $ 6,289 $ 10,493 $ 10,640 $ 13,346
••3%0% and 21%3% of the standardized measure of future royalty income for 2020 and 2019, and 2018, respectively.•20192020 was calculated using natural gas prices of $2.68$1.76 per thousands of cubic feet (Mcf) for Hugoton Royalty Properties, $2.35$1.82 per Mcf for San Juan Basin—Basin — New Mexico Royalty Properties and $1.52$0.78 per Mcf for the San Juan Basin-Colorado Royalty Properties, natural gas liquids prices of $12.71$6.04 per barrel ("Bbl"(“Bbl”) for Hugoton Royalty Properties and $13.10$14.63 per Bbl for the San Juan Basin Royalty Properties, and oil and condensate prices of $41.57$29.01 per Bbl for the San Juan Basin Royalty Properties.
MESA ROYALTY TRUSTNOTES TO FINANCIAL STATEMENTS (Continued)Note 8—Selected Quarterly Financial Data (Unaudited) Summarized Results for the Quarters Ended March 31 June 30 September 30 December 31 $ 726,869 $ 588,481 $ 203,160 $ 289,868 $ 687,295 $ 547,327 $ 168,176 $ 232,248 $ 0.3688 $ 0.2937 $ 0.0902 $ 0.1247 $ 747,618 $ 530,259 $ 449,556 $ 604,886 $ 635,418 $ 484,006 $ 410,827 $ 607,881 $ 0.3410 $ 0.2597 $ 0.2204 $ 0.3262 "Exchange Act"“Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC'sSEC’s rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act is accumulated and communicated by the Working Interest Owners to The Bank of New York Mellon Trust Company, N.A., as Trustee of the Trust, and its employees who participate in the preparation of the Trust'sTrust’s periodic reports as appropriate to allow timely decisions regarding required disclosure.Trustee'sTrustee’s disclosure controls and procedures. The officer acting on behalf of the Trustee concluded that the Trust'sTrust’s disclosure controls and procedures were effective with respect to the Trustee and its employees."Risk Factors—“Risk Factors — Trust unitholders and the Trustee have no control over the operation or development of the Royalty Properties and have little influence over operation or development"development” and "—“— The Trustee relies upon the Working Interest Owners for information regarding the Royalty Properties"Properties” for a description of certain risks relating to these arrangements and reliance, including filings such as this filing outside the time periods specified notwithstanding effective disclosure controls and procedures, of the Trustee regarding information under its control."Trustee's“Trustee’s Discussion and Analysis of Financial Condition and Results of Operations—Operations — Liquidity and Capital Resources"Resources” under Item 7 of this Form 10-K for information concerning controls and procedures with respect to the Royalty and information related to the Trustee'sTrustee’s review of certain information and calculations by the Working Interest Owners. Trustee'sTrustee’s Report on Internal Control over Financial Reporting. The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Exchange Act, and on the basis of accounting as described in Note 2 in the Notes to Financial Statements under Item 8 of this Form 10-K. The Trustee conducted an evaluation of the effectiveness of the Trust'sTrust’s internal control over financial reporting ("(“internal control over financial reporting"reporting”) based on the criteria established in "“Internal Control—Control — Integrated Framework (2013)"” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee'sTrustee’s evaluation under the framework in "“Internal Control—Control — Integrated Framework (2013),"” the Trustee concluded that the Trust'sTrust’s internal control over financial reporting was effective as of December 31, 2019.2020.Trustee'sTrustee’s disclosure controls and procedures relating to the Trust or the Trustee'sTrustee’s internal control over financial reporting relating to the Trust will prevent all errors and all fraud. A registrant'sregistrant’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 generally accepted accounting principles. A registrant'sregistrant’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the registrant; (ii) provide reasonable assurance that transactions are recorded as necessary toregistrant'sregistrant’s assets that could have a material effect on the financial statements.Trust'sTrust’s last fiscal quarter, no change in the Trust'sTrust’s internal control over financial reporting was identified that has materially affected, or is reasonably likely to materially affect, the Trust'sTrust’s internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, has not evaluated and makes no statement concerning, the internal control over financial reporting of the Working Interest Owners.trustee'strustee’s code of ethics.Trust'sTrust’s units are required to file with the SEC initial reports of ownership of units and reports of changes in such ownership pursuant to Section 16 under the Exchange Act. 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 that occurred in 2019.2020. Not applicable.Beneficial Owner Trust Units Beneficially Owned Percent of Class Wells Fargo & Company 125,105(1) 6.71% Trust'sTrust’s financial statements for the years ended December 31, 20192020 and 2018,2019, as well as fees billed for other services rendered by KPMG LLP. 2020 2019 $ 580,000 $ 525,000 Audit-related fees — — 92,000 90,000 All other fees — — Total fees $ 672,000 $ 615,000 2019 2018 $ 525,000 $ 525,000 — — 90,000 86,000 — — $ 615,000 $ 611,000
(1)(1)Trust'sTrust’s financial statements, and reimbursement of expenses related to the audit and quarterly reviews for the years ended December 31, 20192020 and 2018.2019. The Trust is reimbursed by the Working Interest Owners for approximately 88.56% of all general and administrative expenses incurred.(2)Trust'sTrust’s tax information for its unitholders, which includes work performed on the taxes, returns and other items billed during the years ended December 31, 20192020 and 2018.2019. The Trust is reimbursed by the Working Interest Owners for approximately 88.56% of all general and administrative expenses incurred.
Number ExhibitNumberSEC File or
Registration
Number
Number 4(a) *Mesa Royalty Trust Indenture between Mesa Petroleum Co. and Texas Commerce Bank National Association, as Trustee, dated November 1, 1979 2-65217 1(a) 4(b) *Form of Overriding Royalty Conveyance between Mesa Petroleum Co. and Texas Commerce Bank, as Trustee, dated November 1, 1979 2-65217 1(b) 4(c) *First Amendment to the Mesa Royalty Trust Indenture dated as of March 14, 1985 (Exhibit 4(c) to Form 10-K for year ended December 31, 1984 of Mesa Royalty Trust) 1-7884 4(c) 4(d) *Form of Assignment of Overriding Royalty Interest, effective April 1, 1985, from Texas Commerce Bank National Association, as Trustee, to MTR Holding Co. (Exhibit 4(d) to Form 10-K for year ended December 31, 1984 of Mesa Royalty Trust) 1-7884 4(d) 4(e) *Purchase and Sale Agreement, dated March 25, 1991, by and among Mesa Limited Partnership, Mesa Operating Limited Partnership and ConocoPhillips, as amended on April 30, 1991 (Exhibit 4(e) to Form 10-K for year ended December 31, 1991 of Mesa Royalty Trust) 1-7884 4(e) 4(f)4(f) Description of Trust Units (Incorporated by reference to Exhibit 4(f) to the Trust’s Annual Report on Form 10-K for the year ended December 31, 2019) 2323 3131 3232 Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 9999 SIGNATURES Mesa Royalty Trust MESA ROYALTY TRUST
TRUST COMPANY, N.A., TRUSTEE
ELAINA RODGERS
Elaina Rodgers
Vice President & Trust Officer 30, 2020