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included in general and administrative expenses, which results in a reduction of distributable income. As of December 31, 2016,2017, there were $0 unreimbursed expenses.

        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 for future unknown contingent liabilities and expenses in accordance with the Trust Indenture. At any given time, the amount currently reserved for such future unknown contingent liabilities and expenses (the "Contingent Reserve") is included in cash and short-term investments.

        For the year ended December 31, 2017, the Trustee increased the Contingent Reserve by (i) $82,244 of Royalty income received from BP in March 2017 after the distribution to unitholders had been announced for the month of March 2017, which Royalty income was included in the April 2017 distribution to unitholders, (ii) $47,840 of Royalty income received from BP in June 2017 after the distribution to unitholders had been announced for the month of June 2017, which Royalty income was included in the July 2017 distribution to unitholders, (iii) $1,307 for the amount of September expected expense reimbursement cash receipts, received in October 2017, (iv) $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, and (v) $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. For the year ended December 31, 2017, the Trustee decreased the Contingent Reserve by (i) $82,244 and $47,840 of aggregate Royalty income received from BP in March 2017 and June 2017, respectively, and (ii) $1,307 for expected expense reimbursement cash receipts. The net effects of the foregoing adjustments for the year ended December 31, 2017 resulted in the balance of the Contingent Reserve being equal to $1,119,671 as of December 31, 2017.

        For the year ended December 31, 2016, the Trustee increased the reserve for future unknown contingent liabilities and expensesContingent Reserve by (i) the amounts received during the first quarter$6,738 and third quarter of 2016 related to$812 for expense reimbursement cash receipts for previous periods totaling $6,738the first and $812,third quarters of 2016, respectively, (ii) $101 for a prior period expense refund received from a vendor, in the amount of $101 and (iii) $107,659 of royaltyfor Royalty income received from BP in September 2016 after the distribution to unitholders had been announced for the month of September 2016. Such royalty2016, which Royalty income was included in the October 2016 distribution to unitholders. For the twelve monthsyear ended December 31, 2016, the Trustee decreased the reserveContingent Reserve by (i) $101 for future unknown contingent liabilities and expenses for (i) a prior period expense refund received from a vendor, in the amount of $101, (ii) the amount of$812 for expected expense reimbursement cash receipts, of $812 and (iii) $107,659 of royaltyfor Royalty income received from BP in September 2016 after the distribution to unitholders had been announced for the month of September 2016. Such royalty2016, which Royalty income was included in the October 2016 distribution to unitholders. AsThe net effects of December 31, 2016, the reserveforegoing adjustments for unknown contingent liabilities and expenses was $1,000,000 and is included in cash and short term investments.

        For the year ended December 31, 2015,2016 resulted in the Trustee decreasedbalance of the reserve for future unknown contingent liabilities and expenses by the amount of expected expense reimbursement cash receipts of $180,864. Additionally, the Trustee increased the reserve for future unknown contingent liabilities and expenses by the amounts received during the twelve months ended December 31, 2015 relatedContingent Reserve being equal to expense reimbursement cash receipts for previous periods totaling $174,126. As$1,000,000 as of December 31, 2015, the reserve for unknown contingent liabilities and expenses was $993,261, which was included in cash and short term investments. The Trust has subsequently received $6,739 of the expected expense reimbursement cash receipts as of January 31, 2016, which has increased the reserve for unknown contingent liabilities and expenses. The Trustee reserves the right to determine whether or not to release cash reserves in future periods with respect to any unreimbursed expenses.2016.

Liability of Unitholders

        In regardsregard to the unitholders, the Trustee is fully liable if the Trustee incurs any liability without ensuring that such liability will be satisfiable only out of the TrustTrust'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

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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. Although each unitholder should weigh this potential exposure in deciding whether to retain or transfer his units, the Trustee is of the opinion that because of the passive nature of the Trust assets, the restrictions on the power of the Trustee to incur

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liabilities, and the required financial net worth of any trustee, the imposition of any liability on a unitholder is extremely unlikely.

Federal Income Tax Matters

        This section is a summary of federal income tax matters of general application, which addresses the material tax consequences of the ownership and sale of the Trust's units. Except where indicated, the discussion below describes general federal income tax considerations applicable to individuals who are citizens or residents of the United States.U.S. Accordingly, the following discussion has limited application to domestic corporations 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 is encouraged toshould consult its own tax advisor with respect to its particular circumstances.

        This summary is based on current provisions of the Internal Revenue Code of 1986, as amended (the "Code"), existing and proposed Treasury Regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. Some of the applicable provisions of the Code have not been interpreted by the courts or the Internal Revenue Service (the "IRS"). No assurance can be provided that the statements set forth herein (which do not bind the IRS or the courts) will not be challenged by the IRS or will be sustained by a court if so challenged.

Classification of the Trust

        In a technical advice memorandum dated February 26, 1982, the National Office of the IRSInternal Revenue Services (the "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 thesuch unitholder's pro rata share of the income and expense of the Trust as if thesuch unitholder were the direct owner of a pro rata share of the Trust's assets. In addition, there is no state tax liability for the period.

        The Trustee assumes that some Trust units are held by a middleman, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust ("WHFIT") for U.S. federal income tax purposes. The 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. 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.

        The U.S. Tax Cuts and Job Act (the "2017 Tax Act") was enacted on December 22, 2017. The 2017 Tax Act is comprehensive legislation that contains substantial changes to U.S. taxation. The Trust does not expect the new tax law to have any significant impact due to the Trust being classified as a grantor trust for U.S. income tax purposes. However, unitholders should consult with their personal tax advisors to determine how the 2017 Tax Act impacts any items of income or deduction received from the Trust.

        This summary is based on current provisions of the Internal Revenue Code of 1986, as amended ("Code"), existing and proposed Internal Revenue Treasury Regulations ("Treasury Regulations") thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. In addition, the Code and Treasury Regulations are expected to be changed based on the enactment of the 2017 Tax Act. The 2017 Tax Act has not been interpreted by the courts or the IRS. No assurance can be provided that the statements set forth herein

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(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.

Income and Depletion

        Royalty income, net of depletion and severance taxes, is portfolio income. Subject to certain exceptions and transitional rules, royalty income cannot be offset by passive losses. Additionally, interest income is portfolio income. Administrative expense is an investment expense.

        Generally, prior to the Revenue Reconciliation Act of 1990, the transferee of an oil and gas property could not claim percentage depletion with respect to production from the property if it was "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 royaltyRoyalty income attributable to thesesuch units to the extent that this allowance exceeds cost depletion as computed for the relevantapplicable period.

Backup Withholding

        Distributions from the Trust are generally subject to backup withholding at a rate of 28%. Backup withholding will not normally apply to distributions to a unitholder however, unless the unitholder fails to properly provide to the Trust his taxpayer identification number or the IRS notifies the Trust that the taxpayer identification number provided by the unitholder is incorrect.

Sale of Units

        Generally, except for recapture items, the sale, exchange or other disposition of a unit will result in capital gain or loss measured by the difference between the tax basis in the unit and the amount realized. Effective for property placed in service after December 31, 1986, the amount of gain, if any, realized upon the disposition of oil and gas property is treated as ordinary income up to the amount of intangible drilling and development costs incurred with respect to the property and depletion claimed to the extent it reduced the taxpayer'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'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 are 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.

Additional Tax on Net Investment Income

        Individuals, estates, and trusts with income above certain thresholds are subject under Section 1411 of the Code to an additional 3.8% tax—also known as the Net Investment Income Tax ("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.

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Non-U.S. Unitholders

        In general, a unitholder who is a nonresident alien individual or which is a foreign corporation, each a "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 United StatesU.S. Treasury. A non-U.S. unitholder may elect to treat theRoyalty income from the

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Royalty as effectively connected with the conduct of a United StatesU.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 United StatesU.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.

        The Code and the Treasury Regulations thereunder treat the publicly traded Trust as if it were a United StatesU.S. real property holding corporation. Accordingly, a non-U.S. unitholder may be subject to United StatesU.S. federal income tax on the gain on the disposition of his units if he meets certain ownership thresholds.

        In addition, if a foreign corporation elects under provisions of the Code to treat theRoyalty income from the Royalty as effectively connected with the conduct of a United StatesU.S. trade or business, the corporation may also be subject to the U.S. branch profits tax at a rate of 30%. This tax is imposed on U.S. branch profits of a foreign corporation that are not reinvested in the U.S. trade or business. This taxbusiness, and is in addition to the tax on effectively connected income. The branch profits tax may be either reduced or eliminated by treaty. Federal income taxation of a non-U.S. unitholder is a highly complex matter which may be affected by many considerations. Therefore, each non-U.S. unitholder is encouraged to consult with his own tax advisor with respect to its ownership of Trust units.

        Pursuant to the Foreign Account Tax Compliance Act (commonly referred to as "FATCA"), distributions from the Trust to "foreign financial institutions" and certain other "non-financial foreign entities" may be subject to U.S. withholding taxes. Specifically, certain "withholdable payments" (including certain royalties, interest and other gains or 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 United StatesU.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.

Tax-Exempt Organizations

        The Royalty and interest income should not be unrelated"unrelated business taxable incomeincome" (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.

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DESCRIPTION OF ROYALTY PROPERTIES

Producing Acreage and Wells as of December 31, 20162017:

Hugoton FieldRoyalty Properties

        The principal property interest conveyed to the Trust accounts was carved out of Linn's working interest in 104,437 net producing acres in the Hugoton field.field of Kansas. The life of the field is expected to extend beyond the year 2041.2042.

        The natural gas produced from the Hugoton properties is available for sale on the spot market. See "Contracts.""Contracts". Since the Hugoton field gas is sold in the intrastate and interstate markets, it is subject to state and federal laws and regulations. The Kansas Corporation Commission (the "KCC") is the state regulatory agency responsible for overseeing oil and gas operations in the state of Kansas. Hugoton field gas is also affected by the rules and regulations of the Federal Energy Regulatory Commission (the "FERC"). See "Regulation and Prices."Prices".

San Juan Basin Royalty Properties

        The Trust's interest in the San Juan Basin Royalty Properties was conveyed from PNR's working interest in 31,328 net producing acres in Northwestern New Mexico and Southwestern Colorado. PNR completed the sale of its underlying interest in the San Juan Basin Royalty PropertiesSale to ConocoPhillips on April 30, 1991. Substantially all of the natural gas produced from the San Juan Basin is currently being sold on the spot market. ConocoPhillips subsequently sold its underlying interest in substantially all of the Colorado portion of the San Juan Basin RoyaltyBasin—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—Colorado Properties to BP. Starting from the date of the San Juan Basin RoyaltySale and ending on July 31, 2017, ConocoPhillips operated substantially all of the San Juan Basin—New Mexico Properties, to BP. Effective January 1, 2005, ConocoPhillips assigned its interest inexcept for an immaterial number of properties assigned to XTO effective January 1, 2005. On July 31, 2017, ConocoPhillips sold its San Juan Basin Royalty Properties located in New Mexicoassets to XTOHilcorp San Juan LP ("Hilcorp"), an affiliate of Hilcorp Energy Inc.Company. Substantially all of the natural gas produced from the San Juan Basin is currently being sold on the spot market. See "Description of the Trust" under Item 1 of this Form 10-K..

Drilling

        There were no exploratory wells drilled on theany Royalty Properties during 2017, 2016, 2015 or 2014.2015.

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Reserves

        A study of the proved oil and gas reserves covering the Hugoton Area and San Juan Basin oilRoyalty Properties (the "Reserve Report") and gas reserves attributable to the Trust has been made by DeGolyer and MacNaughton, independent petroleum engineering consultants, as of December 31, 2016.2017. A copy of this Reserve Report has been filed as an exhibitExhibit 99.1 to this annual

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report on Form 10-K. DeGolyer and MacNaughton is a Delaware corporation with offices in Dallas, Houston, Astana, Moscow and Algiers. The firm's more than 150 professionals include engineers, geologists, geophysicists, petrophysicists, and economists engaged in the appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies, and equity studies related to the domestic and international energy industry. These services have been provided for over 70 years. DeGolyer and MacNaughton restricts its activities exclusively to consultation; it does not accept contingency fees, nor does it own operating interests in any oil, gas, or mineral properties, or securities or notes of clients. 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's experienced staff provides knowledge, independent judgment, integrity, and confidential service to its clients. The firm is a Texas Registered Engineering Firm, No. F-716.

        The Senior Vice President at DeGolyer and MacNaughton primarily responsible for overseeing the preparation of the reserve estimatesReserve Report is a Registered PetroleumProfessional Engineer in the State of Texas with more than 4035 years of experience in oil and gas reservoir studies and reserve evaluations. He graduated with a Bachelor of Science degree in PetroleumCivil Engineering from Texas A&M University in 19741979 and he is a member of the International Society of Petroleum Engineers and the American AssociationSociety of Petroleum Geologists.Evaluation Engineers.

        The Hugoton Area and San Juan Basin Reserve Report reflects estimated production, reserve quantities and future net revenue based upon estimates of the future timing of actual production without regard to when received in cash by the Trust, which differs from the manner in which the Trust recognizes and accounts for its Royalty income.

        Estimates of the gross and net proved reserves, as of December 31, 2016,2017, of the Trust's ownership in the net overriding royalty interestinterests 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 thousands of cubic feet (Mcf).

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        The estimated future net revenue and standardized measure of future net royalty income, discounted at 10 percent per annum attributable to the Trust's overriding royalty interestRoyalty as of December 31, 2016, under2017 is summarized in the table below. These estimates are provided based upon the economic assumptions furnished by the working interest owners is summarized as follows,Working Interest Owners, and are expressed in thousands of dollars:

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        Please read "Summary Reserve Report from DeGolyer and MacNaughton" attached hereto as Exhibit 99.1 for more information.

        The Reserve Report was delivered to the Trustee on March 10, 2017.19, 2018. Net reserves of the Trust's Royalty are calculated at the aggregate level from the net revenue of each of the Working Interest Owners. To estimate net gas reserves, the total net revenue of the Working Interest Owners is divided by the net value of 1 Mcf of gas. The net value of 1 Mcf of gas is the gas price per Mcf, plus the condensate value per Mcf of gas, plus the NGL value per Mcf of gas. The net condensate and NGL reserves are calculated by multiplying their respective yields by the net gas reserves. Revenue values used in the Reserve Report were estimated using the following prices: (1) condensate prices—$41.1935.91 per Bbl;barrel ("Bbl"); (2) NGLnatural gas liquids prices—$14.1617.25 per Bbl for the San Juan properties, $11.45Basin Royalty Properties and $22.85 per Bbl for Hugoton properties;Royalty Properties; and (3) natural gas prices—$2.232.81 per Mcf for San Juan properties, $2.85Basin Royalty Properties and $3.65 per Mcf for Hugoton properties,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 propertiesRoyalty Properties with no increases in the future based on inflation.

Preparation of Reserve Estimates

        For further information regarding the Net Overriding Royalty Interest, the Basis of Accounting and Supplemental Reserve Information, see Notes 1, 2 3 and 9,7, respectively, in the Notes to Financial Statements contained in Item 8 of this Form 10-K.

        There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures, including many factors beyond the control of the producer. Reserve data included above and in these reports represent estimates only and should not be construed as being exact. The discounted present values shown by the reserve reportsReserve Report should not be construed as the current market value of the estimated gas and oil reserves attributable to the Royalty Properties or the costs that would be incurred to obtain equivalent reserves, since a market value determination would include many additional factors.

        The Trustee has been advised that each of the foregoing estimates were prepared in accordance with guidelines established by the SEC and the Financial Accounting Standards Board ("FASB"). Accordingly, the estimates are based on existing economic and operating conditions in effect at December 31, 2016,2017, 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 the reserve reports are limited to proved reserves, future capital expenditures for recovery of reserves not classified as proved

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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 DeGolyer and MacNaughton. Accordingly, reserve estimates are often different from the quantities of hydrocarbons that are ultimately recovered.

        The Trustee relies on DeGolyer and MacNaughton to prepare the reserve estimates attributable to the Trust's interests in the Royalty Properties. Although the Trustee inquires with the third-party reserve engineer about the information provided by the working interest ownersWorking Interest Owners and the assumptions made and methodologies used by the third-party reserve engineer, the Trustee does not control the

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information provided by the working interest ownersWorking 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.

        As noted in this report, the Trustee is currently investigating certain payments and differences from original estimates. The Trustee is also reviewing, with the assistance of outside experts, prior allocations of payments of Royalty income by the working interest owners.Working Interest Owners. 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.

Income, Production and Production Prices and Production Costs

        ReferenceSales and production data from the Royalty Properties for the last three fiscal years is madeincluded in the table below. For additional information related to "Management's Discussionour Reserve Report, see "Note 7—Supplemental Reserve Information" under Item 8 of this Form 10-K.

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CONTRACTS

Hugoton FieldRoyalty Properties

        Natural gas and natural gas liquids produced by Linn from the Hugoton field and attributable to the Royalty Properties accounted for approximately 34%44% of the Royalty income of the Trust during 2016.

for the year ended December 31, 2017. Linn has advised the Trust that 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. During 2016, the primary purchasers were Kansas Gas Service, Continuum Energy Service, LLC and Enterprise Products Operating, LLC. Linn 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 lowerhigher for the year ended December 31, 20162017 as compared to the year ended December 2015.31, 2016.

        In June 1994, PNR entered into a Gas Transportation Agreement ("Gas Transportation Agreement") with Western Resources, Inc. ("WRI") for a primary term of five years, commencing June 1, 1995. Thereafter, this contract has renewed on a year to year basis. WRI subsequently assigned its rights and obligations under the Gas Transportation Agreement to Oneok Field Services ("Oneok"), and PNR subsequently assigned its rights and obligations under the Gas Transportation Agreement to Linn. In their termination notice issued May 12, 2015, Oneok noted they were agreeable to negotiating a new agreement in order to continue to provide gathering and compression service. On January 1, 2016, an affiliate of Linn acquired the gathering line from Oneok. Oneok will continueand a new gas compression agreement was entered into. However, Oneok continued to provide compression services under asuch new Gas Compression Agreement effectivegas compression agreement from January 1, 2016 through December 31, 2018, and then month-to-month thereafter,2016 at a rate of $0.13 per Mcf, and Linn provided other services under the new gas compression agreement at a rate of $0.06 per Mcf. In connection with Linn's reorganization and bankruptcy proceedings, Linn rejected the Oneok gas compression agreement under applicable bankruptcy laws, and thereafter, Oneok ceased to be escalated beginning April 1, 2017, and annually each April 1 thereafter usingprovide any services for the Consumer Price Index.Hugoton Royalty Properties. An affiliate of Linn began providing gathering services under a new Gas Gathering Agreementsimilar to those set forth in the Oneok gas compression agreement effective January 1, 2016, under a three year agreement that continues month-to-month thereafter,2017, and began charging the Royalty from the Hugoton Royalty Properties at a rate of $0.06$0.1569 per Mcf, to be escalated beginning April 1,Mcf. For the entirety of the year ended December 31, 2017 and annually each April 1 thereafter usingas of the Consumer Price Index.date of this Form 10-K, Linn has provided and continues to provide services pursuant to the new agreement.

San Juan Basin

        Natural gas, oil, condensate and natural gas liquids produced from the San Juan Basin field and attributable to the Royalty Properties accounted for approximately 48%56% of the Royalty income of the Trust during 2016.for the year ended December 31, 2017. The majority of the natural gas produced from the San Juan Basin Royalty Properties is now being sold on the spot market.

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Market for Natural Gas

        The amount of cash distributions by the Trust is dependent on, among other things, the sales prices realized for natural gas produced from the Royalty Properties and the quantities of gas sold. The Henry Hub Natural Gas Spot Prices were $4.37 per mcf in 2014, decreased to $2.62 per mcf in 2015 and decreased to $2.50 per mcf in 2016 accordingAccording to the U.S. Energy Information Administration of the Department of Energy.Energy, the Henry Hub Natural Gas Spot Prices were $2.50 per MMBtu in 2016 and increased to $2.99 per MMBtu in 2017. 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 thesethose periods. Because of the time lag between the date

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on which the working interest ownersWorking 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.

Competition

        The production and sale of gas infrom the Hugoton field and San Juan Basin areasRoyalty Properties are highly competitive, and the working interest owners'Working Interest 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 areas.Basin. The working interest ownersWorking Interest Owners have advised the Trust that they believe that their competitive position in their respective areas is affected by price, contract terms and quality of service. Linn 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 plant.plants. Market conditions in the San Juan Basin are negatively affected by the fact that most of the gas produced from such areas is transported on one of only two major pipelines, and the transportation of such gas is generally controlled by a small numberfew distribution companies.

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REGULATION AND PRICES

General

        The production and sale of natural gas from the Royalty Properties are affected from time to time in varying degrees by political developments and federal, state and local laws and regulations. In particular, oil and gas production operations and economics are, or in the past have been, affected by price controls, taxes, conservation, safety, environmental and other laws relating to the petroleum industry, by changes in such laws, and by constantly changing administrative regulations.

FERC Regulation

        In general, the 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," 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

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regulations may occur based on actions taken by the United States Congress and/or the courts. As to these various developments, the working interest ownersWorking 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.

        In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act of 1978 and culminated in adoption of the Natural Gas Wellhead Decontrol Act that removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

        Sales of crude oil, condensate, and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls at any time in the future. Sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be just and reasonable and may be derived in a number of ways including, but not limited to, the FERC's indexing methodology.

        As to these various types of regulation, 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.

State and Other Regulation

        AllEach of the jurisdictions in whichencompassing the TrustRoyalty Properties has an interest in producing oil and gas properties have statutory provisions regulating the production and sale of crude oil and natural gas. The regulations often require permits for the drilling of wells but extend alsoand may specify rules related to the spacing of wells, the prevention of waste of oil and gas resources, the rate of production, the prevention and clean-up of pollution, and other matters. See "Contracts—Hugoton Field" for a discussion

Table of Linn's allowables in the Hugoton Royalty Properties.Contents

        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. For example, Oklahoma, Kansas and Texas prohibit discriminatory gathering rates.rates, but Colorado and New Mexico do not.

        Natural gas pipeline facilities used for the transportation of natural gas in interstate commerce are subject to Federalfederal minimum safety requirements. These requirements, however, are not applicable to,inter alia, onshore gathering of gas (i) through a pipeline that operates at less than 0 psig; (ii) through a pipeline that is not a regulated onshore gathering line (as determined in Section49 C.F.R. § 192.8); and (iii) within the inlets of the Gulf of Mexico, except for the requirements in Section 192.612.See49 C.F.R. § 192.1(b). We are informed that theThe Royalty Properties are located in the Hugoton field inof Kansas and the San Juan Basin inof New Mexico and Colorado. Each of Colorado, Kansas and the Yellow Creek field of Wyoming. Furthermore, those states haveNew Mexico has adopted the Federalfederal minimum safety requirements for intrastate pipelines within their borders. The standards governing pipeline safety have undergone recent changes, and it is possible that future changes in the regulations and statutes may occur whichapplicable law may increase the stringency of the standards or expand the applicability of the standards to facilities not currently covered.

Environmental Matters

        The working interest owners'Working Interest 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

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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:

•

restrict the types, quantities and concentration of various substances that can be discharged and released into the environment in connection with oil and natural gas drilling and production activities;



•

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and



•

require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

        Violations of environmental laws, regulations, or permits can result in civil and criminal penalties as well as potential injunctions curtailing operations in affected areas. The working interest ownersWorking Interest Owners have advised the Trust that they are not at this time involved in any administrative or judicial proceedings relating to the Royalty Properties arising under federal, state or local environmental protection laws and regulations or which would have a material adverse effect on the working interest owners'Working Interest Owners' financial position or results of operations. The working interest ownersWorking Interest Owners have also advised the Trust that they maintain insurance for costs of cleanup obligations, but that they are not fully insured against all such risks.

        The following is a summary of the existingcertain material laws, rules and regulations to which the operations of the properties comprising the underlying propertiesRoyalty Properties may be subject that are material to the operation of the Royalty Properties.subject.

        Hazardous Substances.    The Comprehensive Environmental Response, Compensation and Liability Act, referred to as "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

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relationships with landowners, working interest partners, pipeline companies and others.

        Changes in these factors and assumptions can materially change reserve estimates and future net revenue estimates.

        The reserve quantities attributable to the Royalty and revenues are based on estimates of reserves and revenues for the underlying properties. The method of allocating a portion of those reserves to the Trust is further complicated because the Trust holds an interest in the Royalty and does not own a specific percentage of the natural gas reserves. Ultimately, actual production, revenues and expenditures for the underlying properties, and therefore actual net proceeds payable to the Trust, will vary from estimates and those variations could be material. Results of drilling, testing and production after the date of those estimates may require substantial downward revisions or write-off of reserves.

Physical effects of climatic change have the potential to damage the facilities of the working interest owners, disrupt production activities on the Royalty Properties, and cause the working interest owners to incur significant costs in preparing for or responding to those effects and can adversely affect Trust distributions as a result.

        Scientific studies and government reports, such as those published by the Intergovernmental Panel on Climate Change established by the United Nations and World Meteorological Organization indicate 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,

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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. 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.

        The Trustee relies entirely on reserve estimates and related information prepared by DeGoyler and McNaughton based on information provided by the working interest owners. While the Trustee has no reason to believe the reserve estimates included in this report are not accurate, to the extent additional information exists that could affect their reserve estimates, the estimated reserves in these reports could also be too low.

Operating risks for the working interest owners'Working Interest Owners' interests in the Royalty Properties can adversely affect Trust distributions.

        There are operational risks and hazards associated with the production and transportation of natural gas, including without limitation natural disasters, blowouts, explosions, fires, leakage of natural gas, releases of other hazardous materials, mechanical failures, cratering and pollution. Any of these or similar occurrences could result in the interruption or cessation of operations, personal injury or loss of life, property damage, damage to productive formations or equipment, or damage to the environment or natural resources, and associated cleanup obligations. The occurrence of drilling, production or transportation accidents and other natural disasters at any of the Royalty Properties will reduce Trust distributions by the amount of uninsured costs. These occurrences include blowouts, cratering, explosives and other environmental damage that may result in personal injuries, property damage, and damage to productive formations or equipment and environmental damages. Any uninsured costs would be deducted as a production cost in calculating net proceeds payable to the Trust.

        Most of the 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 to transportation lines or increases in transportation costs for production from these properties could also affect the Trust.

        Further, the present value of future net cash flows from proved reserves may not be the current market value of estimated natural gas and oil reserves attributable to the Royalty. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on the 12-month average oil and gas index prices, calculated as the un-weighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs 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.

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

        Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in response, cause instability in the global financial and energy markets. Terrorism and sustained military campaigns could adversely affect Trust distributions or the market price of the units in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in natural gas prices, or the possibility that the infrastructure on which the operators

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developing the underlying properties rely could be a direct target or an indirect casualty of an act of terror.

The operators of the working interestsWorking Interest Owners are subject to extensive governmental regulation.

        Oil and gas operations have been, and in the future will be, affected by federal, state and local laws and regulations and other political developments, such as price or gathering rate controls and environmental protection regulations. These regulations and changes in regulations could have a material adverse effect on Royalty income payable to the Trust.

The working interest owners'Working Interest Owners' operations are subject to environmental, health and safety laws and regulations that may expose the working interest ownersWorking Interest Owners to penalties, damages or costs of remediation or compliance which could adversely affect Trust distributions.

        The working interest owners'Working Interest 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.

        There is inherent risk of environmental costs and liabilities in the oil and gas business as a result of the handling of petroleum hydrocarbons and oilfield and industrial wastes, air emissions and wastewater discharges related to current operations as well as historical industry operations and waste disposal practices. Some environmental laws and regulations may impose strict liability, which means that in some situations, the working interest ownersWorking Interest Owners could be exposed to liability as a result of conduct that was without fault or lawful at the time it occurred or as a result of the conduct of, or conditions caused by, prior operators or other third parties. Clean-up costs and other damages arising as a result of environmental laws and costs associated with changes in environmental laws and regulations could be substantial and could have a material adverse effect on Trust distributions.

        Laws protecting the environment generally have become more stringent over time and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. The modification or interpretation of existing laws or regulations, or the adoption of new laws or regulations, could curtail exploratory or developmental drilling for oil and natural gas. The working interest ownersWorking Interest Owners may not be able to recover some or any of such costs of compliance with these laws and regulations from insurance.

        Please read "Business—Regulation and Prices—Environmental 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'Working Interest Owners' operations.

Physical effects of climatic change have the potential to damage the facilities of the Working Interest Owners, disrupt production activities on the Royalty Properties, and cause the Working Interest Owners to incur significant costs in preparing for or responding to those effects and can adversely affect Trust distributions as a result.

        Scientific studies and government reports, such as those published by the Intergovernmental Panel on Climate Change established by the United Nations and World Meteorological Organization indicate that climate change could have global, regional or local effects on the severity of weather (including

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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.

        The Trustee relies entirely on reserve estimates and related information prepared by DeGolyer and McNaughton based on information provided by the Working Interest Owners. While the Trustee has no reason to believe the reserve estimates included in this report are not accurate, to the extent additional information exists that could affect their reserve estimates, the estimated reserves in these reports could also be too low.

Climate change legislation or regulations restricting or regulating emissions of greenhouse gases could result in increased operating costs and could adversely affect Trust distributions.

        The EPA has adopted various regulations under the federal Clean Air Act addressing emissions of greenhouse gases that may affect the oil and gas industry, including mandatory reporting and emission reduction. Such changes will affect state air permitting programs in states that administer the federal Clean Air Act under a delegation of authority, including states in which the Royalty Properties are located. Some states have also indicated an intent to regulate or impose restrictions or costs on greenhouse gas emissions or fossil fuels. The adoption and implementation of any international treaty or of any federal or state legislation or regulations imposing restrictions on emissions of greenhouse gases could require the working interest ownersWorking Interest Owners to incur costs to comply with such requirements and possibly require the reduction or limitation of emissions of greenhouse gases associated with the working interest owners'Working Interest 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'Working Interest Owners' operations or physical assets.

        Please read "Business—Regulation and Prices—Environmental 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'Working Interest Owners' operations.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays on the Royalty properties in which the Trust holds an interest.

        Hydraulic fracturing is an important and commonly used process in the completion of unconventional natural gas wells in shale and coal formations, as well as tight conventional formations including many of those Royalty properties in which the Trust holds an interest. This process involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Some states have adopted and others are considering legislation to restrict hydraulic

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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. Further, the EPA has finalized a study of the impacts ofIn addition, hydraulic fracturing in December 2016. At that time, the EPA concluded that under certain circumstances, the "water cycle" activitiesrequires 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 hydraulic fracturing may impact drinking water resources. In addition, anyearthquakes 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.

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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.

        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 working interest owners.from the Trust. The working interest ownersWorking Interest Owners manage the underlying properties and handle receipt and payment of funds relating to the Royalty Properties and payments to 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 current working interest ownersWorking 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 ownersWorking Interest Owners for information regarding the Royalty Properties. The working interest ownersWorking 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 ownersWorking 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 working interest owners,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.Working Interest Owners. While the Trustee has no reason to believe its reliance on experts is unreasonable, this reliance

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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 any Royalty Property may abandon any property, terminating the related Royalty.

        The working interest ownersWorking 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 current working interest ownersWorking 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.

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The Royalty can be sold and the Trust can be terminated.

        The Trust will be terminated and the Trustee must sell the Royalty if holders of a majority of the units of beneficial interest of the Trust approve the sale or vote to terminate the Trust, or if the Trust's royalty income for each of two successive years is less than $250,000 per year. Following any such termination and liquidation, the net proceeds of any sale will be distributed to the unitholders and unitholders will receive no further distributions from the Trust. 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 ownersWorking Interest Owners or other operators of the Royalty Properties do not perform additional development projects, the assets may deplete faster than expected.

        The net proceeds payable 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.

Unitholders have limited voting rights.

        Voting rights as a unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of unitholders or for an annual or other periodic re-election of the Trustee. Additionally, Trust unitholders have no voting rights in Linn or ConocoPhillips.any

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of the Working Interest Owners. Unlike corporations which are generally governed by boards of directors elected by their equity holders, the Trust is administered by a corporate Trustee in accordance with the Trust Indenture and other organizational documents. The Trustee has extremely limited discretion in its administration of the Trust.

Unitholders have limited ability to enforce the Trust's rights against the current or future owners of the Royalty Properties.

        The Trust Agreement and related trust law permit the Trustees and the Trust to sue the working interest ownersWorking Interest Owners to compel them to fulfill the terms of the Conveyance of the Royalty. If the Trustee does not take appropriate action to enforce provisions of the Conveyance, the recourse of a unitholder would likely be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. Unitholders probably would not be able to sue the working interest ownersWorking Interest Owners directly.

The limited liability of the Trust unitholders is uncertain.

        The Trust unitholders are not protected from the liabilities of the Trust to the same extent that a shareholder would be protected from a corporation's liabilities. The structure of the Trust does not

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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.

The future financial condition of Working Interest Owners or other operators of the underlying properties could impede the operation of wells.

        The value of the Royalty and the Trust's ultimate cash available for distribution is highly dependent on the financial condition of the operators of the wells. The ability to operate the underlying properties depends on all 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.

        In the event of the bankruptcy of any operator of the underlying properties, the Working Interest Owners in the affected properties, creditors or the debtor-in-possession may have to seek a new party to perform the operations of the affected wells. The creditors or debtor-in-possession may not be able to find a replacement operator, and they may not be able to enter into a new agreement with such replacement party on favorable terms or within a reasonable period of time.

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

        The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles ("U.S. 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.

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Item 1B.    Unresolved Staff Comments.

        None.

Item 2.    Properties.

        The Trust owns property interests in the Hugoton Area (Kansas)field of Kansas and the San Juan Basin (Northwesternof Northwestern New Mexico and Southwestern Colorado).Colorado. See "Business—Description of Royalty Properties" contained in Item 1 of this Form 10-K.

Item 3.    Legal Proceedings.

        There are no pending legal proceedings to which the Trust is a named party. The Trustee has been advised by Linn, ConocoPhillips and BPthe Working Interest Owners that it ismay be subject to litigation in the ordinary course of business for certain matters that include the Royalty Properties. While each of the working interest ownersWorking Interest Owners has advised the Trustee that it does not currently believe any of the pending litigation will have a material adverse effect net to the Trust, in the event such matters were adjudicated or settled in a material amount and charges wereare made against Royalty income, such charges could have a material impact on future Royalty income.

Item 4.    Mine Safety Disclosures.

        Not applicable.

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PART II

Item 5.    Market for the Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

        The units of beneficial interest of the Trust are traded on the New York Stock Exchange under the ticker symbol "MTR". The high and low sales prices and distributions per unit for each quarter in the two years ended December 31 2016 and December 31, 2015, were as follows:

        At March 31, 2017,30, 2018, the 1,863,590 units outstanding were held by 606551 unitholders of record.

Item 6.    Selected Financial Data.

        Not applicable.

Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations.

Trust Overview

        The following review of theMesa Royalty Trust's (the "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 and San Juan propertiesBasin 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.

Critical Accounting Policies

        The financial statements Any discussion of the Trust are prepared on the following basis:"actual"

        (a)   Royalty income recorded for a month is the amount computed and paid by the working interest owners to the Trustee for such month rather than either the value of a portion of the oil and gas produced by the working interest owners for such month or the amount subsequently determined to be the Trust's proportionate share of the net proceeds for such month;

        (b)   Interest income, interest receivable and distributions payable to unitholders include interest to be earned on short-term investments from the financial statement date through the next date of distribution;

        (c)   Trust general and administrative expenses, net of reimbursements, are recorded in the month they are included in the calculation of the monthly distribution amount;

        (d)   Amortization of the Royalty is computed on a unit-of-production basis and is charged directly to trust corpus since such amount does not affect distributable income; and

        (e)   Distributions payable are determined on a monthly basis and are payable to unitholders of record as of the last business day of each month or such later date as the Trustee determines is required to comply with applicable law or stock exchange requirements.

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        This basisproduction volumes represents the hydrocarbons that were produced from the properties in which the Trust has an overriding royalty interest.

        The Trust was created on November 1, 1979, and is now governed by the Mesa Royalty Trust Indenture (as amended, the "Trust Indenture"). Through a series of conveyances, assignments, and acquisitions, the Trust currently owns an overriding royalty interest (the "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")) attributable to the specified interest in certain producing oil and gas properties located in the:

•

Hugoton field of Kansas (the "Hugoton Royalty Properties");



•

San Juan Basin field of New Mexico (the "San Juan Basin—New Mexico Properties");



•

San Juan Basin field of Colorado (the "San Juan Basin—Colorado Properties", and together with the "San Juan Basin—New Mexico Properties, the "San Juan Basin Royalty Properties", and together with the Hugoton Royalty Properties and the San Juan Basin Royalty Properties, the "Royalty Properties").

        Pursuant to past conveyances and bankruptcy proceedings, Linn Energy, Inc. ("Linn"), Hilcorp San Juan LP ("Hilcorp"), XTO Energy, Inc. ("XTO"), BP Amoco Company ("BP"), and Red Willow Production Company ("Red Willow") are the operators of certain portions of the Hugoton Royalty Properties and San Juan Basin Royalty Properties (each of Linn, Hilcorp, XTO, BP, and Red Willow being a "Working Interest Owner", and together, the "Working Interest Owners"). As used in this report, Linn refers to the current operator of the Hugoton Royalty Properties, Hilcorp refers to the current operator of the San Juan Basin—New Mexico Properties, and BP and Red Willow refer to the currents co-operators of certain tracts of land included in the San Juan Basin—Colorado Properties, unless otherwise indicated.

        The Trust is a passive entity 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 reporting distributablepayments 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 Trust does not undertake or control any capital projects or make capital expenditures. While the Trust's Royalty income is considered to benet of capital expenditures, these capital expenditures are controlled and paid by the most meaningful because distributions toWorking Interests Owners, and the unitholders for a month are based onTrust receives Royalty income net cash receipts for such month. However,of these statements differ from financial statements prepared in accordance with accounting principles generally accepted inexpenses. In addition, the United States of America because, under such principles, royalty income for a month would be based on net proceeds from production for such month without regard to when calculatedTrust does not have any off-balance sheet arrangements 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.other contingent obligations.

Liquidity and Capital Resources

        Liquidity.    As discussed underin "Business—Description of the Trust" inunder Item 1 of this Form 10-K, the Trust's primary source of cash is the Royalty income received from its share of the net proceeds from the Royalty Properties. ReferenceProperties, and the only other source of cash is madeinterest 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-K10-K.

        In addition, the Working Interest Owners reimburse the Trust each quarter for estimatescertain expenses incurred by the Trust on their behalf. As of future Royalty income attributable to the Royalty.

December 31, 2017 and 2016, there were $0 and $0 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 amount of established reserves,Trust Indenture, are distributed currently to the unitholders.

        The Trustee engaged an independent consulting firm to audit revenues, expenses and established reserves of certain working interest owners. As a result of the audit, the Trustee and PNR entered into a Settlement Agreement, dated effective as of February 21, 2014, pursuant to which PNR agreed to pay the Trust for certain audit exceptions noted by the Trustee for calendar years 2006 through 2013. As such, the Trust income distribution for the month of April 2014 included $881,595 from PNR. The Trustee agreed to release PNR from any claims related to any of the matters raised in the audit exceptions for any year prior to 2013 and all such exceptions are deemed closed. However, the Trust continues to review certain potential audit exceptions with respect to various operators, including potential PNR audit exceptions subsequent to 2013. These reviews with respect to payments made by PNR and other working interest owners and audits are ongoing. The Trust income distribution for the month of September 2014 also included $52,868 from PNR and $369,585 from BP. PNR advised the Trustee that the $52,868 amount represents the Trust's share of an audit settlement completed regarding the Satanta plant. BP advised the Trustee that the $369,585 amount includes the Trust's share of an audit adjustment related to prior periods. Amounts received from PNR and BP for the twelve months ended December 31, 2014 were $934,463 and $369,585, respectively. While these audits have highlighted issues that remain open, the Trustee has not made a determination at this time whether any additional audit exceptions will result in any material gains or expenses net to the Trust. The Trust income distribution for the month of December 2015 included $15,167 from BP. BP advised the Trustee that the $15,167 amount included the Trust's share of an audit adjustment related to prior periods.

        As of December 31, 2016, there were $0 of unreimbursed expenses.

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

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of the borrowings. During 2011, the Trustee withheld $1.0 million to establish a reserve for future unknown contingent liabilities and expenses (the "Contingent Reserve") in accordance with the Trust Indenture. At any given time, the amount currently reserved for such future unknown contingent liabilities and expensesbalance of the Contingent Reserve is included in cash and short-term investments.

        For the year ended December 31, 2017, the Trustee increased the Contingent Reserve by (i) $82,244 of Royalty income received from BP in March 2017 after the distribution to unitholders had been announced for the month of March 2017, which Royalty income was included in the April 2017 distribution to unitholders, (ii) $47,840 of Royalty income received from BP in June 2017 after the distribution to unitholders had been announced for the month of June 2017, which Royalty income was included in the July 2017 distribution to unitholders, (iii) $1,307 for the amount of September expected expense reimbursement cash receipts, received in October 2017, (iv) $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, and (v) $70,460 of December 2017 expenses that was included in the distribution calculation for December 2017, but not paid by the Trust until January 2018. For the year ended December 31, 2017, the Trustee decreased the Contingent Reserve by (i) $82,244 and $47,840 of aggregate Royalty income received from BP in March 2017 and June 2017, respectively, and (ii) $1,307 for expected expense reimbursement cash receipts. The net effects of the foregoing adjustments for the year ended December 31, 2017 resulted in the balance of the Contingent Reserve being equal to $1,119,671 as of December 31, 2017. See "Financial Review—Unreimbursed Expenses and the Contingent Reserve" for complete information about adjustments to the Contingent Reserve for the year ended December 31, 2016.

        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.

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Years Ended December 31, 2017 and 2016

SUMMARY OF ROYALTY INCOME, PRODUCTION, PRICES AND COSTS (Unaudited)

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Financial Review

        Royalty and Interest Income.    The Trust's Royalty income was $3,028,793 and $1,364,791 for the years ended December 31, 2017 and 2016, respectively. The increase for the year ended December 31, 2017 as compared to December 31, 2016 was primarily a result of higher natural gas, natural gas liquids and oil and condensate prices, reduced capital expenditures and operating costs, and increased net natural gas and natural gas liquids production volumes for the year ended December 31, 2017. The Trust's Interest income for the years ended December 31, 2017 and 2016 was $10,221 and $1,899, 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 $100,795 and $152,778 for the years ended December 31, 2017 and 2016, respectively. The Trustee's fees are included in general and administrative expense. The decrease for the year ended December 31, 2017 as compared to December 31, 2016 was primarily a result of general and administrative expenses in the amount of $70,460 for December 2017 being paid by the Trust in January 2018. If the Trust had paid such expenses in December 2017, general and administrative expenses for the year ended December 31, 2017 would have been $171,255.

        For the year ended December 31, 2017, the Trustee was due $475,000 for its services. The Trust paid $433,152 of this amount to the Trustee, and $41,848 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 2.25% annualized return from January 1, 2017 through March 15, 2017, a 2.50% annualized return from March 16, 2017 to June 14, 2017, a 2.75% annualized return from June 15, 2017 through December 13, 2017, and a 3.00% annualized return from December 14, 2017 through December 31, 2017. 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 the remaining $15,365 of 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, 2017, the Trustee's aggregate fees were $433,152 and the Working Interest Owners reimbursed the aggregate sum of $383,588 to the Trustee. For the year ended December 31, 2016, the Trustee's aggregate fees were $433,152 and the Working Interest Owners reimbursed the aggregate sum of $383,588 to the Trustee. As of the years ended December 31, 2017 and 2016, the Trust incurred unreimbursed expenses of $0 and $0, respectively.

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        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, 2017, the Trustee increased the Contingent Reserve by (i) $82,244 of Royalty income received from BP in March 2017 after the distribution to unitholders had been announced for the month of March 2017, which Royalty income was included in the April 2017 distribution to unitholders, (ii) $47,840 of Royalty income received from BP in June 2017 after the distribution to unitholders had been announced for the month of June 2017, which Royalty income was included in the July 2017 distribution to unitholders, (iii) $1,307 for the amount of September expected expense reimbursement cash receipts, received in October 2017, (iv) $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, and (v) $70,460 of December 2017 expenses that was included in the distribution calculation for December 2017, but not paid by the Trust until January 2018. For the year ended December 31, 2017, the Trustee decreased the Contingent Reserve by (i) $82,244 and $47,840 of aggregate Royalty income received from BP in March 2017 and June 2017, respectively, and (ii) $1,307 for expected expense reimbursement cash receipts. The net effects of the foregoing adjustments for the year ended December 31, 2017 resulted in the balance of the Contingent Reserve, which is included in cash and short-term investments, being equal to $1,119,671 as of December 31, 2017.

        For the year ended December 31, 2016, the Trustee increased the reserve for future unknown contingent liabilities and expensesContingent Reserve by (i) the amounts received during the first quarter and third quarter of 2016 related to expense reimbursement cash receipts for previous periods totaling $6,738 and $812, respectively, (ii) a prior period expense refund received from a vendor in the amount of $101 and (iii) $107,659 of royalty income received from BP in September 2016 after the distribution to unitholders had been announced for the month of September 2016. Such royalty2016, which Royalty income was included in the October 2016 distribution to unitholders. For the twelve months

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ended December 31, 2016, the Trustee decreased the reserve for future unknown contingent liabilities and expenses for (i) a prior period expense refund received from a vendor in the amount of $101, (ii) the amount of expected expense reimbursement cash receipts of $812 and (iii) $107,659 of royaltyRoyalty income received from BP in September 2016 after the distribution to unitholders had been announced for the month of September 2016. Such royalty2016, which Royalty income was included in the October 2016 distribution to unitholders. AsThe net effects of December 31, 2016, the reserveforegoing adjustments for unknown contingent liabilities and expenses was $1,000,000 and is included in cash and short term investments.

        For the year ended December 31, 2015,2016 resulted in the Trustee decreasedbalance of the reserve for future unknown contingent liabilities and expenses by the amount of expected expense reimbursement cash receipts of $180,865. Additionally, the Trustee increased the reserve for future unknown contingent liabilities and expenses by the amounts received during the twelve months ended December 31, 2015 relatedContingent Reserve being equal to expense reimbursement cash receipts for previous periods totaling $174,126. As$1,000,000 as of December 31, 2015, the reserve2016.

        Distributable Income Available for unknown contingent liabilities and expenses was $993,261, which was included in cash and short term investments.Distribution.    The Trust has subsequently received $6,739portion of the expected expense reimbursement cash receipts as of January 31, 2016, which has increased the reserve for unknown contingent liabilities and expenses. The Trustee reserves the right to determine whether or not to release cash reserves in future periods with respect to any unreimbursed expenses.

Financial Review

Years 2016 and 2015

        The Trust's Royalty income was $1,364,791 in 2016, a decrease of approximately 34% as compared to $2,076,841 in 2015, primarily as a result of lower prices for natural gas, natural gas liquids and oil and condensate and decreased natural gas and natural gas liquids production volumes, offet in part by reduced capital expenditures and operating costs in 2016 compared with 2015. The Trust's Interest income in 2016 was $1,899, an increase from $29 in 2015. In accordance with the Trust Indenture, interest on cash on hand was paid at a rate of 1.5% below the prime interest rate. In addition, general and administrative expense decreased to $152,778 in 2016 compared with $161,207 in 2015. The Trust income distribution for the month of December 2015 included $15,167 from BP. BP advised the Trustee that the $15,167 amount included the Trust's share of an audit adjustment related to prior periods.

        The distributable income available for distribution of the Trust for each periodyear includes the Royalty income received from the working interest ownersWorking Interest Owners during such period, plus interest income earned to the date of distribution (if any) and increases or withdrawals to and from the reserve for contingent liabilities and expensesContingent Reserve (if any). Trust administration expenses are deducted in the computation of distributable income available for distribution. Distributable income available for distribution for the twelve monthsyears ended December 31, 2017 and 2016 was $2,818,548 and $1,207,174, representingrespectively. For the years ended December 31, 2017 and 2016, the Trust calculated total aggregate distributions of $1.5124 and $0.6478 per unit, comparedrespectively.

Operational Review

Hugoton Royalty Properties

        Natural gas and natural gas liquids production attributable to $1,922,401, representing $1.0315 per unit,the Hugoton Royalty Properties accounted for approximately 44% of the twelve months ended December 31, 2015.

        The Trustee was due $475,000 for its services forRoyalty income of the Trust during the year ended December 31, 2016. The Trust paid $433,152 of this amount to the Trustee, and $41,848 was allocated to offset against interest due to the Trust under the Trust Indenture. The Trust Indenture requires that cash being held by the Trustee2017.

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earn interest at 1.5% below the prime rate, which would have yielded the Trust a 2.00% return through December 14, 2016 and 2.25% through December 31, 2016. 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. The Trustee will continue to allocate a portion of the fees earned for its services to the Trust until the remaining $29,290 of interest due to the Trust is fully offset, and it may do so in future periods in which unpaid interest is due to the Trust. 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, 2016 such fees were $433,152. Reimbursements received for year ended December 31, 2016 were $383,588. For the year ended December 31, 2015 such fees were $433,253. Reimbursements received for the year ended December 31, 2015 were $383,676.

Hugoton Field        Royalty Income.

    Royalty income attributable to the Hugoton Royalty Properties for the years ended December 31, 2017 and 2016 was $1,326,012 and $457,295, in 2016, a decreaserespectively. The increase of approximately 49%,190% for the year ended December 31, 2017 as compared to 903,158 in 2015,December 31, 2016 was primarily due to lower prices forhigher natural gas and natural gas liquids decreased production volumes forprices, increased net natural gas and natural gas liquids production volumes and higherlower operating costs offset in part by reduced capital expenditures during 2016 compared to 2015. There was a $677 joint venture audit adjustment by PNR for the quarter ended March 31, 2015. The average price received for natural gas and natural gas liquids from the Hugoton Royalty Properties was $2.86 per Mcfin fiscal year 2017.

        Operating Costs and $11.38 per Bbl, respectively, in 2016 as compared to $3.47 per Mcf and $13.83 per Bbl, respectively, in 2015. Net productionCapital Expenditures.    Operating costs attributable to the Hugoton Royalty Properties for the years ended December 31, 2017 and 2016 were $731,521 and $931,217, respectively. Linn has informed the Trust that the approximately 21% decrease for the year ended December 31, 2017 as compared to December 31, 2016 was 121,662primarily due to actual ad valorem taxes paid and a decrease in the reserve amount, partially offset by an increase in severance taxes which is in line with higher production. Capital expenditures attributable to the Hugoton Royalty Properties for the years ended December 31, 2017 and 2016 were $7,921 and $8,040, respectively.