MESA ROYALTY TRUST/TX - Quarter Report: 2017 September (Form 10-Q)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q


ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period ended September 30, 2017
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to

Commission File Number: 1-7884

MESA ROYALTY TRUST
(Exact name of registrant as specified in its charter)


Texas (State or other jurisdiction of Incorporation or Organization)		76-6284806 (I.R.S. Employer Identification No.)
The Bank of New York Mellon Trust Company, N.A., Trustee 601 Travis Street, Floor 16 Houston, Texas (Address of Principal Executive Offices)		77002 (Zip Code)

1-713-483-6020
(Registrant's Telephone Number, Including Area Code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

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

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


Large accelerated filer o		Accelerated filer o		Non-accelerated filer ý (Do not check if a smaller reporting company)		Smaller reporting company o Emerging growth company o

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

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

As of November 14, 2017—1,863,590 Units of Beneficial Interest were outstanding in Mesa Royalty Trust.

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-Q includes "forward-looking statements" about Mesa Royalty Trust (the "Trust") and other matters discussed herein that are subject to risks and uncertainties that are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical fact included in this document, including, without limitation, statements under "Management's Discussion and Analysis of Financial Condition and Results of Operations," including the Trust's or any Working Interest Owner's (as defined in "Note 1—Trust Organization and Provisions") future financial position, status in any insolvency proceeding, business strategy, budgets, projected costs and plans and objectives for future operations, information regarding target distributions, statements pertaining to future development activities and costs, statements regarding the number of development wells to be completed in future periods, and information regarding production and reserve growth, are forward-looking statements. Actual outcomes and results may differ materially from those projected. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "potential," "could," "may," "can," "foresee," "plan," "goal," "assume," "target," "should," "intend" or other words that convey the uncertainty of future events or outcomes. These statements are based on certain assumptions made by the Trust in light of its experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. The Trustee relies on the Working Interest Owners for information regarding the Subject Interests (as defined in "Note 1—Trust Organization and Provisions"), the Royalty (as defined in "Note 1—Trust Organization and Provisions"), and the Working Interest Owners themselves.

Although the Working Interest Owners have advised the Trust that they believe that the expectations reflected in the forward-looking statements contained herein are reasonable, no assurance can be given that such expectations will prove to be correct. However, whether actual results and developments will conform with such expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in Item 1A of Part I of the Trust's Annual Report on Form 10-K for the year ended December 31, 2016, and those set forth from time to time in the Trust's filings with the Securities and Exchange Commission (the "SEC"), which could affect the future results of the energy industry in general, and the Trust and Working Interest Owners in particular, and could cause those results to differ materially from those expressed in such forward-looking statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on the Working Interest Owners' businesses and the Trust. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. The Trust undertakes no obligation to publicly update or revise any forward-looking statements, except as required by applicable law.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

MESA ROYALTY TRUST

STATEMENTS OF DISTRIBUTABLE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,

	2017			2016			2017			2016
Royalty income	$	626,384		$	451,782		$	2,262,152		$	839,415
Interest income		3,182			548			6,828			1,255
General and administrative expense		(35,609	)		(36,228	)		(133,681	)		(123,211	)

Distributable income	$	593,957		$	416,102		$	2,135,299		$	717,459



Distributable income per unit	$	0.3187		$	0.2233		$	1.1458		$	0.3850



Units outstanding		1,863,590			1,863,590			1,863,590			1,863,590

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

	September 30, 2017			December 31, 2016

	(Unaudited)
ASSETS
Cash and short-term investments	$	1,641,797		$	1,604,112
Net overriding royalty interest in oil and gas properties		42,498,034			42,498,034
Accumulated amortization		(40,442,978	)		(40,058,695	)

Total assets	$	3,696,853		$	4,043,451



LIABILITIES AND TRUST CORPUS
Distributions payable	$	643,104		$	604,112
Trust corpus (1,863,590 units of beneficial interest authorized, issued and outstanding)		3,053,749			3,439,339

Total liabilities and trust corpus	$	3,696,853		$	4,043,451

(The accompanying notes are an integral part of these financial statements.)

MESA ROYALTY TRUST

STATEMENTS OF CHANGES IN TRUST CORPUS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,

	2017			2016			2017			2016
Trust corpus, beginning of period	$	3,212,552		$	3,646,568		$	3,439,339		$	3,727,980
Distributable income		593,957			416,102			2,135,299			717,459
Distributions to unitholders		(643,104	)		(307,732	)		(2,136,606	)		(603,062	)
Amortization of net overriding royalty interest		(109,656	)		(104,207	)		(384,283	)		(191,646	)

Trust corpus, end of period	$	3,053,749		$	3,650,731		$	3,053,749		$	3,650,731

(The accompanying notes are an integral part of these financial statements.)

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

Note 1—Trust Organization and Provisions

Trust Corpus Description. The Mesa Royalty Trust (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 in the Conveyance and described below) 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").

Trust Corpus Conveyance History. On November 1, 1979, Mesa Petroleum Co., predecessor to Mesa Limited Partnership ("MLP"), which was the predecessor to MESA Inc., conveyed to the Trust the Royalty equal to 90% of the Net Proceeds (as defined in the Conveyance and described below) attributable to the specified interests in properties conveyed by the assignor on that date (the "Subject Interests"). The Subject Interests consisted of interests in the Royalty Properties described above. The Royalty is evidenced by counterparts of an Overriding Royalty Conveyance dated as of November 1, 1979 (the "Conveyance"). In 1985, the Trust Indenture was amended and the Trust conveyed to an affiliate of Mesa Petroleum Co. 88.5571% of the original Royalty (such transfer, the "1985 Assignment"). The effect of the 1985 Assignment was an overall reduction of approximately 88.56% in the size of the Trust. As a result, the Trust is now entitled to receive 11.44% of 90% of the Net Proceeds attributable to each month.

Hugoton Royalty Properties. Until August 7, 1997, MESA Inc. operated the Hugoton Royalty Properties through Mesa Operating Co., a wholly owned subsidiary of MESA Inc. On August 7, 1997, MESA Inc. merged with and into Pioneer Natural Resources Company ("Pioneer"), formerly a wholly owned subsidiary of MESA Inc., and Parker & Parsley Petroleum Company merged with and into Pioneer Natural Resources USA, Inc. (successor to Mesa Operating Co.), a wholly owned subsidiary of Pioneer ("PNR") (collectively, the mergers are referred to herein as the "Merger"). Subsequent to the Merger, the Hugoton Royalty Properties were operated by PNR until December 31, 2014, at which point Linn Energy Holdings, LLC ("Linn") took over as operator.

San Juan Basin—Colorado Properties. On April 30, 1991, MLP sold to Conoco, Inc. ("ConocoPhillips") its interests in the San Juan Basin Royalty Properties (the "San Juan Basin Sale"). 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.

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 1—Trust Organization and Provisions (Continued)

ConocoPhillips sold the portion of its interests in the San Juan Basin—Colorado Properties to MarkWest Energy Partners, Ltd. (effective January 1, 1993) and Red Willow Production Company ("Red Willow") (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 Amoco Company ("BP"), a subsidiary of BP p.l.c. BP and Red Willow currently operate the San Juan Basin—Colorado Properties.

San Juan Basin—New Mexico Properties. Starting from the date of the San Juan Basin Sale and ending on July 31, 2017, ConocoPhillips operated substantially all of the San Juan Basin—New Mexico Properties, except an immaterial number of properties assigned to XTO Energy, Inc. ("XTO") effective January 1, 2005. On July 31, 2017, ConocoPhillips sold its San Juan Basin assets to Hilcorp San Juan LP ("Hilcorp"), an affiliate of Hilcorp Energy Company.

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 refers to the current co-operators of certain tracts of land included in the San Juan Basin—Colorado Properties, unless otherwise indicated.

Trustee and Terms of Trust Indenture. Effective October 2, 2006, The Bank of New York Mellon Trust Company, N.A. (the "Trustee") succeeded JP Morgan Chase Bank, N.A. as Trustee of the Trust. JPMorgan Chase Bank, N.A. is the successor by mergers to the originally named Trustee, Texas Commerce Bank National Association. 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 payments of liabilities to the Trust, to the unitholders. The Trust has no sources of liquidity or capital resources other than the revenues, if any, attributable to the Royalties and interest on cash held by the Trustee as a reserve for liabilities or for distribution. The terms of the Trust Indenture provide, among other things, that:

(a) the Trust cannot engage in any business or investment activity or purchase any assets;

(b) the Royalty can be sold in part or in total for cash upon approval by the unitholders;

(c) the Trustee can establish cash reserves and borrow funds to pay liabilities of the Trust and can pledge assets of the Trust to secure payment of the borrowings;

(d) the Trustee will make cash distributions to the unitholders in January, April, July and October each year as discussed more fully in Note 2;

(e) the Trust will terminate upon the first to occur of the following events: (i) at such time as the Trust's royalty income for two successive years is less than $250,000 per year or (ii) a vote by the unitholders in favor of termination. Upon termination of the Trust, the Trustee will sell for

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 1—Trust Organization and Provisions (Continued)

cash all the assets held in the Trust estate and make a final distribution to unitholders of any funds remaining after all Trust liabilities have been satisfied; and

(f) Linn, Hilcorp, and BP (each, a "Working Interest Owner", and collectively, the "Working Interest Owners") will reimburse the Trust for 59.34%, 27.45% and 1.77%, respectively, for general and administrative expenses of the Trust.

Trustee's Fees. Pursuant to the Trust Indenture, the Trust pays the Trustee fees for its services each quarter and the Working Interest Owners partially reimburse the Trust for the fees paid in connection with the Trustee's services. The net amount of these reimbursements are included in the general and administrative expenses of the Trust. For the quarter ended September 30, 2017, the Trustee was due $118,750 for its services. The Trust paid $108,288 of this amount to the Trustee, and $10,462 was allocated to offset against interest due to the Trust under the Trust Indenture. The Trustee was due $356,250 for its services for the nine months ended September 30, 2017. The Trust paid $324,865 of this amount to the Trustee, and $31,385 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 through June 14, 2017 and a 2.75% annualized return from June 15, 2017 through September 30, 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.

The Working Interest Owners partially reimburse the Trust each quarter for amounts paid in connection with the Trustee's services. For the quarter ended September 30, 2017, the Trustee's fees were $108,288 and the Working Interest Owners reimbursed a sum of $95,897 to the Trustee, which was the same amount reimbursed for the quarter ended September 30, 2016. For the nine months ended September 30, 2017, the Trustee's fees were $324,865 and the Working Interest Owners reimbursed a sum of $287,691 to the Trustee, which was the same amount reimbursed for the nine months ended September 30, 2016.

Linn Energy Reorganization. On May 11, 2016, Linn Energy, LLC ("Old Linn"), LinnCo, LLC ("LinnCo"), an affiliate of Old Linn, and certain of Old Linn's direct and indirect subsidiaries (collectively with Old Linn and LinnCo, the "Debtors"), filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the "Court"). The Debtors' Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16-60040.

On January 27, 2017, the Court entered the Order Confirming (I) Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and its Debtor Affiliates Other Than Linn Acquisition Company, LLC

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 1—Trust Organization and Provisions (Continued)

and Berry Petroleum Company, LLC and (II) Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC, which approved and confirmed the Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the "Plan"). The Plan became effective on February 28, 2017 (the "Effective Date").

Pursuant to the Plan, on the Effective Date, all assets of Old Linn (other than equity interests in Linn Acquisition Company, LLC and Berry Petroleum Company, LLC) were conveyed to Linn Energy, Inc. (or a subsidiary thereof), and LinnCo, LLC and Linn Energy, LLC were wound down and liquidated. Subsequent to the effectiveness of the Plan, Linn Energy, Inc. is now the reorganized successor to Old Linn. Under the Plan Supplement, as amended, filed with the Court, the Debtors assumed all executory contracts and unexpired leases with the Trust and Mesa Operating Limited Partnership as the counterparty. Furthermore, pursuant to the Plan, the royalty interests in the Hugoton Royalty Properties owned by the Trust shall be preserved and remain in full force and effect in accordance with the terms of the granting instruments or other governing documents.

Note 2—Basis of Presentation

The accompanying unaudited financial information has been prepared by the Trustee in accordance with the instructions to Form 10-Q. The preparation of the financial statements requires estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of income and expenses during the reporting period. Actual results could differ from those estimates. The Trustee believes such information includes all the disclosures necessary to make the information presented not misleading. The information furnished reflects all adjustments which are, in the opinion of the Trustee, necessary for a fair presentation of the results for the interim periods presented. The financial information should be read in conjunction with the financial statements and notes thereto included in the Trust's Annual Report on Form 10-K for the year ended December 31, 2016. The Trust considers all highly liquid investments with a maturity of three months or less to be cash equivalents. Subsequent events were evaluated through the issuance date of the financial statements.

In accordance with the Conveyance, the Working Interest Owners are obligated to calculate and pay the Trust each month an amount equal to 90% of the Net Proceeds (as defined in the Conveyance) attributable to the month.

The financial statements of the Trust are prepared on the following basis:

(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;

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2—Basis of Presentation (Continued)

(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 because 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. However, cash distributions are made quarterly in January, April, July and October, and include interest earned from the monthly record dates to the date of distribution.

This basis for reporting distributable income is considered to be the most meaningful because distributions to the unitholders for a month are based on net cash receipts for such month. However, these statements differ from financial statements prepared in accordance with accounting principles generally accepted in 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 calculated or received, general and administrative expenses would be recorded in the month they accrue, and interest income for a month would be calculated only through the end of such month.

Note 3—Legal Proceedings

There are no pending legal proceedings to which the Trust is a named party. The Trustee has been advised by Linn, Hilcorp, and BP that the Trust may be subject to litigation in the ordinary course of business for certain matters that include the Royalty Properties. While each of the Working 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 were made against Royalty income, such charges could have a material impact on future Royalty income.

Note 4—Income Tax Matters

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

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 4—Income Tax Matters (Continued)

For taxable years beginning after December 31, 2012, individuals, estates, and trusts with income above certain thresholds are subject under Section 1411 of the Internal Revenue Code to an additional 3.8% tax—also known as the "Medicare contribution tax"—on their net investment income. Grantor trusts such as Mesa Royalty Trust are not subject to the 3.8% tax; 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 units.

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.

Note 5—Excess Production Costs

	As of September 30, 2017		As of December 31, 2016

San Juan Basin—Colorado Properties—BP	$	—	$	3,860
San Juan Basin—Colorado Properties—Red Willow		13,000		12,532
San Juan Basin—New Mexico Properties—XTO		5,941		3,591

Total	$	18,941	$	19,983

Excess production costs result when costs, charges, and expenses attributable to a working interest property exceed the revenue received from the sale of oil, gas, and other hydrocarbons produced from such property. The excess production costs must be recovered by the Working Interest Owners before any distribution of Royalty income from the properties will be made to the Trust.

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 6—Distributable Income Per Unit

During 2011, the Trustee, acting pursuant to the Trust Indenture, withheld $1.0 million for future unknown contingent liabilities and expenses (such cumulative withholding being the "Contingent Reserve"). The Trustee reserves the right to determine whether or not to release cash reserves in future periods with respect to any reimbursement expenses. At any given time, the Contingent Reserve is included in cash and short term investments.

For the three months ended September 30, 2017, the Trustee decreased the Contingent Reserve by (1) $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 and (2) the amount of expected expense reimbursement cash receipts of $1,307.

For the nine months ended September 30, 2017, the Trustee increased the Contingent Reserve by (1) $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 and (2) $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. For the nine months ended September 30, 2017, the Trustee decreased the Contingent Reserve by (1) $82,244 and $47,840 of aggregate royalty income received from BP and (2) the amount of expected expense reimbursement cash receipts of $1,307. As of September 30, 2017, the value of the Contingent Reserve was $998,693, which is included in cash and short-term investments. On October 18, 2017, the Trust received $1,307 of the expected expense reimbursement cash receipts, which increased the Contingent Reserve by that same amount but is not included in the figures below reported as of September 30, 2017. The effect on distributable income per unit of adjustments to the Contingent Reserve is as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,

	2017		2016			2017			2016
Distributable Income Before Reserve for Contingent Liabilities and Expenses	$	593,957	$	416,102		$	2,135,299		$	717,459
Increase in the Contingent Reserve		—		(108,471	)		(130,084	)		(115,310	)
Withdrawal from the Contingent Reserve		49,147		101			131,391			913

Distributable income Available for Distribution	$	643,104	$	307,732		$	2,136,606		$	603,062



Distributable income Available for Distribution per unit	$	0.3450	$	0.1651		$	1.1465		$	0.3236



Units outstanding		1,863,590		1,863,590			1,863,590			1,863,590

Item 2. Trustee's Discussion and Analysis of Financial Condition and Results of Operations.

The following review of Mesa Royalty Trust's (the "Trust") financial condition and results of operations should be read in conjunction with the financial statements and notes thereto. 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, Linn Energy Holdings, LLC ("Linn"), Hilcorp San Juan LP ("Hilcorp"), 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, BP, and Red Willow being a "Working Interest Owner", and together, "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 refers to the currents co-operators of certain tracts of land included in the San Juan Basin—Colorado Properties, unless otherwise indicated.

The discussion of net production attributable to the interests in the Royalty Properties 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. See Note 9 to the financial statements in the Trust's Annual Report on Form 10-K for the year ended December 31, 2016. Any discussion of "actual" production volumes represents the hydrocarbons that were produced from the properties in which the Trust has an overriding royalty interest.

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 payments of liabilities to the Trust, to the unitholders. The Trust has no sources of liquidity or capital resources other than the revenues, if any, attributable to the Royalties and interest on cash held by the Trustee as a reserve for liabilities or for distribution. The Trust 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. In addition, the Trust does not have any off-balance sheet arrangements or other contingent obligations.

Note Regarding Forward-Looking Statements

This Form 10-Q includes "forward-looking statements" about the Trust and other matters discussed herein that are subject to risks and uncertainties that are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this document, including, without limitation, statements under "Trustee's Discussion and Analysis of Financial Condition and Results of Operations," including the Trust's or any Working Interest Owner's future financial position, status in any insolvency proceeding, business strategy, budgets, projected costs and plans and objectives for future operations, information regarding target distributions, statements pertaining to future development activities and costs, statements regarding the number of development wells to be completed in future periods, and information regarding production and reserve growth, are forward-looking statements. Actual outcomes and results may differ materially from those projected. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "potential," "could," "may," "can," "foresee," "plan," "goal," "assume," "target," "should," "intend" or other words that convey the uncertainty of future events or outcomes. These statements are based on certain assumptions made by the Trust in light of its experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. The Trustee relies on the Working Interest Owners for information regarding the Subject Interests (as defined herein in "Note 1—Trust Organization and Provisions"), the Royalty, and the Working Interest Owners themselves.

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

Royalty income is computed after deducting the Trust's proportionate share of capital costs, operating costs and interest on any cost carryforward from the Trust's proportionate share of "Gross Proceeds," as defined in the Conveyance. The following summary illustrates the net effect of the components of the actual Royalty computation for the periods indicated.

	Three Months Ended September 30,

	2017									2016
	Natural Gas			Natural Gas Liquids			Oil and Condensate			Natural Gas			Natural Gas Liquids			Oil and Condensate
The Trust's proportionate share of Gross Proceeds(1)	$	829,485		$	263,977		$	18,172		$	694,467		$	222,512		$	15,887
Less the Trust's proportionate share of:
Capital costs recovered		(5,189	)		(1,798	)		(56	)		(6,020	)		(2,709	)		(267	)
Operating costs		(349,871	)		(120,448	)		(8,389	)		(349,925	)		(114,570	)		(8,251	)

Net proceeds(2)	$	474,425		$	141,731		$	9,727		$	338,522		$	105,233		$	7,369



Royalty income(2)	$	474,053		$	142,604		$	9,727		$	338,918		$	105,474		$	7,390



Average sales price	$	2.40		$	17.41		$	38.15		$	1.54		$	13.75		$	34.34



Average production costs(3)	$	1.80		$	14.93		$	33.12		$	1.62		$	15.29		$	39.58



Net production volumes attributable to the Royalty paid(4)	197,139	8,189	255	219,802	7,669	215

	Nine Months Ended September 30,

	2017									2016
	Natural Gas			Natural Gas Liquids			Oil and Condensate			Natural Gas			Natural Gas Liquids			Oil and Condensate
The Trust's proportionate share of Gross Proceeds(1)	$	2,689,744		$	814,859		$	47,594		$	1,840,730		$	570,555		$	36,702
Less the Trust's proportionate share of:
Capital costs recovered		(12,013	)		(4,448	)		(274	)		(21,858	)		(8,734	)		(771	)
Operating costs		(931,260	)		(319,273	)		(21,736	)		(1,132,082	)		(357,334	)		(21,400	)

Net proceeds(2)	$	1,746,471		$	491,138		$	25,584		$	686,790		$	204,487		$	14,531



Royalty income(2)	$	1,744,605		$	491,974		$	25,573		$	619,757		$	205,016		$	14,643



Average sales price	$	2.45		$	19.21		$	37.94		$	1.59		$	11.66		$	28.81



Average production costs(3)	$	1.32		$	12.64		$	32.66		$	2.96		$	20.82		$	43.62



Net production volumes attributable to the Royalty paid(4)	712,042	25,609	674	389,270	17,850	508

(1): Gross Proceeds from natural gas liquids attributable to the Hugoton Royalty Properties and San Juan Basin Royalty Properties are net of a volumetric in-kind processing fee retained by Linn and Hilcorp, respectively.
(2): Royalty income is computed after deducting the Trust's proportionate share of capital costs, operating costs and interest on any cost carryforward from the Trust's proportionate share of Gross Proceeds. As a result of excess production costs incurred in one monthly operating period and then recovered in a subsequent monthly operating period, the Royalty income paid to the Trust may not agree to the Trust's royalty interest in the Net Proceeds (as defined in the Conveyance). The excess production costs must be recovered by the Working Interest Owners before any distribution of Royalty income will be made to the Trust.

San Juan Basin—New Mexico Properties. Excess production costs in the amount of $5,941 and $2,652 as of September 30, 2017 and 2016, respectively, were related to the San Juan Basin—New Mexico Properties operated by XTO. Excess production costs related to the San Juan Basin—New Mexico Properties operated by XTO were approximately $2,468 and $559 for the three months ended September 30, 2017 and 2016, respectively. Excess production costs related to the San Juan Basin—New Mexico Properties operated by XTO were approximately $2,350 and $1,545 for the nine months ended September 30, 2017 and 2016, respectively.

San Juan Basin—Colorado Properties. Excess production costs related to the San Juan Basin—Colorado Properties operated by BP and Red Willow were approximately $0 and $13,000, respectively, as of September 30, 2017. Excess production costs related to the San Juan Basin—

Colorado Properties operated by BP and Red Willow were approximately $0 and $9,547, respectively as of September 30, 2016.

Excess production costs related to the San Juan Basin—Colorado Properties operated by BP and Red Willow were approximately $0 and $0, respectively, for the three months ended September 30, 2017, and $0 and $98, respectively, for the three months ended September 30, 2016. The Trust recovered prior period excess production costs of $1,967 related to the San Juan Basin—Colorado Properties operated by Red Willow during the quarter ended September 30, 2017.

Excess production costs related to the San Juan Basin—Colorado Properties operated by BP and Red Willow were approximately $0 and $468, respectively, for the nine months ended September 30, 2017, and $0 and $4,399, respectively, for the nine months ended September 30, 2016. The Trust recovered prior period excess production costs of $3,860 related to the San Juan Basin—Colorado Properties operated by BP during the nine months ended September 30, 2017. The Trust recovered prior period excess production costs of $72,336 related to the San Juan Basin—Colorado Properties operated by BP during the nine months ended September 30, 2016.

(3): Average production costs attributable to the Royalty are calculated as stated capital costs plus operating costs, divided by stated net production volumes attributable to the Royalty paid. As noted above in footnote (2), production costs may be incurred in one operating period and then recovered in a subsequent operating period, which may cause Royalty income paid to the Trust not to agree to the Trust's Royalty interest in the Net Proceeds.
(4): Net production volumes attributable to the Royalty are determined by dividing Royalty income by the average sales price received.

Three Months Ended September 30, 2017 and 2016

Financial Review

	Three Months Ended September 30,

	2017			2016
Royalty income	$	626,384		$	451,782
Interest income		3,182			548
General and administrative expense		(35,609	)		(36,228	)

Distributable income	$	593,957		$	416,102



Distributable income per unit	$	0.3187		$	0.2233



Units outstanding		1,863,590			1,863,590

Royalty Income. The Trust's Royalty income was $626,384 for the quarter ended September 30, 2017, an increase of approximately 39% as compared to $451,782 for the quarter ended September 30, 2016. The increase was primarily as a result of higher natural gas, natural gas liquids and oil and condensate prices, increased net production of natural gas liquids and oil and condensate and a reduction in capital expenditures, offset in part by higher operating expenses in the quarter ended September 30, 2017, as compared to the quarter ended September 30, 2016.

Distributable Income. The portion of the Trust's distributable income available for distribution each period includes the Royalty income received from the Working Interest Owners during such period, plus interest income earned to the date of distribution (if any) and increases or withdrawals from the reserve for contingent liabilities and expenses (if any). Trust administration expenses are deducted in the computation of distributable income available for distribution. Distributable income available for distribution for the quarter ended September 30, 2017 was $643,104, representing $0.3450 per unit, compared to $307,732, representing $0.1651, for the quarter ended September 30, 2016. Based on 1,863,590 units outstanding for the quarters ended September 30, 2017 and 2016, respectively, the per unit distributions were as follows:

	2017		2016

July	$	0.1160	$	0.0644
August		0.1043		0.0413
September		0.1247		0.0594

	$	0.3450	$	0.1651

General and Administrative Expense. General and administrative expense was $35,609 and $36,228 for the quarters ended September 30, 2017 and 2016, respectively. The Trustee's fees are included in general and administrative expense. For the quarter ended September 30, 2017, the Trustee was due $118,750 for its services. The Trust paid $108,288 of this amount to the Trustee, and $10,462 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 2.75% annualized return from July 1, 2017 through September 30, 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 $19,180 of interest due to the Trust is fully offset.

Unreimbursed Expenses and the Contingent Reserve. During 2011, the Trustee, acting pursuant to the Trust Indenture, withheld $1.0 million for future unknown contingent liabilities and expenses (such cumulative withholding being the "Contingent Reserve"). The Trustee reserves the right to determine whether or not to release cash reserves in future periods with respect to any reimbursement expenses. At any given time, the Contingent Reserve is included in cash and short term investments. As of September 30, 2017, there were $1,307 of unreimbursed expenses. The Trust anticipated receipt of these expense reimbursements by month-end when it published its September distribution press release on a Form 8-K filed September 18, 2017, and included these amounts in distributions payable and distributable income per unit as of September 30, 2017. For the three months ended September 30, 2017, the Trustee decreased the Contingent Reserve by (1) $47,840 of royalty income received from BP and (2) the amount of expected expense reimbursement cash receipts of $1,307. As of September 30,

2017, the value of the Contingent Reserve was $998,693, which is included in cash and short-term investments.

Operational Review

Hugoton Royalty Properties

Natural gas and natural gas liquids production attributable to the Hugoton Royalty Properties accounted for approximately 44% of the Royalty income of the Trust during the third quarter of 2017.

	Three Months Ended September 30,

	2017		2016
Royalty income attributable to Hugoton Royalty Properties	$	275,605	$	153,791
Operating costs attributable to Hugoton Royalty Properties	$	216,483	$	177,501
Capital expenditures attributable to Hugoton Royalty Properties	$	5,498	$	—

Royalty Income. Royalty income attributable to the Hugoton Royalty Properties increased to $275,605 in the third quarter of 2017 from $153,791 in the third quarter of 2016 primarily due to increases in natural gas and natural gas liquids prices and increased net natural gas and natural gas liquids production volumes, offset in part by an increase in capital expenditures and operating costs from the Hugoton Royalty Properties in the third quarter of 2017 compared to the third quarter of 2016.

Operating Costs and Capital Expenditures. Operating costs were $216,483 in the third quarter of 2017, an increase of approximately 22% as compared to $177,501 in the third quarter of 2016, primarily due to timing of ad valorem tax payments and an increase in severance taxes consistent with higher production during the third quarter of 2017. Capital expenditures attributable to the Hugoton Royalty Properties were $5,498 in the third quarter of 2017, as compared to $0 in the third quarter of 2016.

	Three Months Ended September 30,

	2017						2016
	Natural Gas		Natural Gas Liquids		Oil and Condensate		Natural Gas		Natural Gas Liquids		Oil and Condensate
Average sales price	$	3.55	$	21.01	$	—	$	2.53	$	13.46	$	—



Actual production volumes attributable to the Royalty paid for Hugoton Royalty Properties	103,505	6,229	—	95,541	6,846	—



Net production volumes attributable to the Royalty paid for Hugoton Royalty Properties	57,270	3,453	—	43,171	3,311	—

Average Sales Price. Overall market prices received for natural gas from Hugoton Royalty Properties were higher for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016. Linn has advised the Trust that since June 1, 1995 natural gas produced from the Hugoton Royalty Properties has generally been sold under short-term and multi-month contracts at market clearing prices to multiple purchasers. During the third quarter of 2017, four customers, Kansas Gas Service, Koch Energy Services, Macquarie Energy and Oneok Hydrocarbon purchased approximately 70% of the total products sold from the Hugoton Royalty Properties. Linn has advised the Trust that it expects to continue to market gas production from the Hugoton Royalty Properties under short-term and multi-month contracts.

San Juan Basin Royalty Properties

Royalty income from the San Juan Basin Royalty Properties is calculated and paid to the Trust on a state-by-state basis depending upon whether the property is situated in Colorado or New Mexico. A majority of the royalty income from the San Juan Basin Royalty Properties is attributable to the San Juan Basin—New Mexico Properties. Substantially all of the natural gas produced from the San Juan Basin Royalty Properties is currently being sold on the spot market.

San Juan Basin—New Mexico Properties

	Three Months Ended September 30,

	2017		2016
Royalty income attributable to San Juan Basin—New Mexico Properties	$	261,471	$	188,174
Operating costs attributable to San Juan Basin—New Mexico Properties	$	237,923	$	202,595
Capital expenditures attributable to San Juan Basin—New Mexico Properties	$	1,545	$	8,996

Royalty Income. Royalty income from the San Juan Basin—New Mexico Properties was $261,471 during the third quarter of 2017 as compared with Royalty income of $188,174 during the third quarter of 2016. This increase in Royalty income was due primarily to an increase in natural gas, natural gas liquids and oil and condensate prices, increased net production volumes of natural gas, natural gas liquids and oil and condensate and reduced capital expenditures for the third quarter of 2017 compared to the third quarter of 2016, offset in part by an increase in operating costs during the third quarter of 2017 compared to the third quarter of 2016.

Operating Costs and Capital Expenditures. Operating costs were $237,923 in the third quarter of 2017, an increase of approximately 17% as compared to $202,595 in the third quarter of 2016 due primarily to well inspection costs and increased severance taxes. Capital expenditures on these

properties were $1,545 in the third quarter of 2017, a decrease of approximately 83% as compared to $8,996 in the third quarter of 2016.

	Three Months Ended September 30,

	2017						2016
	Natural Gas		Natural Gas Liquids		Oil and Condensate		Natural Gas		Natural Gas Liquids		Oil and Condensate
Average sales price	$	2.16	$	14.80	$	38.08	$	1.62	$	13.98	$	34.34



Actual production volumes attributable to the Royalty paid for San Juan Basin—New Mexico Properties	160,618	11,591	477	156,707	12,560	463



Net production volumes attributable to the Royalty paid for San Juan Basin—New Mexico Properties	84,051	4,736	255	74,001	4,358	215

San Juan Basin—Colorado Properties

	Three Months Ended September 30,

	2017		2016
Royalty income attributable to San Juan Basin—Colorado Properties	$	89,308	$	109,815
Operating costs attributable to San Juan Basin—Colorado Properties	$	24,302	$	92,650

Royalty Income. Royalty income from the San Juan Basin—Colorado Royalty Properties was $89,308 during the third quarter of 2017, compared to $109,815 during the third quarter of 2016. This decrease in Royalty income was due primarily to lower net production volumes for natural gas, offset in part by lower operating costs and higher market prices in the third quarter of 2017 compared to the third quarter of 2016.

Operating Costs. Operating costs on these properties were $24,302 in the third quarter of 2017, a decrease of approximately 74% as compared to $92,650 in the third quarter of 2016 due primarily to higher repair and recompletion costs in 2016 compared with 2017.

	Three Months Ended September 30,

	2017						2016
	Natural Gas		Natural Gas Liquids		Oil and Condensate		Natural Gas		Natural Gas Liquids		Oil and Condensate
Average sales price	$	1.60	$	—	$	—	$	1.07	$	—	$	—



Actual production volumes attributable to the Royalty paid for San Juan Basin—Colorado Properties	70,554	—	—	188,472	—	—



Net production volumes attributable to the Royalty paid for San Juan Basin—Colorado Properties	55,817	—	—	102,631	—	—

Nine Months Ended September 30, 2017 and 2016

Financial Review

	Nine Months Ended September 30,

	2017			2016
Royalty income	$	2,262,152		$	839,415
Interest income		6,828			1,255
General and administrative expense		(133,681	)		(123,211	)

Distributable income	$	2,135,299		$	717,459



Distributable income per unit	$	1.1458		$	0.3850



Units outstanding		1,863,590			1,863,590

Royalty Income. The Trust's Royalty income was $2,262,152 for the nine months ended September 30, 2017, an increase of approximately 169% as compared to $839,415 for the nine months ended September 30, 2016, primarily as a result of increased natural gas, natural gas liquids and oil and condensate prices and net production volumes, reduced capital expenditures and lower operating costs in the first nine months of 2017 as compared to the first nine months of 2016.

deducted in the computation of distributable income available for distribution. Distributable income available for distribution for the nine months ended September 30, 2017 was $2,136,606, representing $1.1465 per unit, compared to $603,062, representing $0.3236 per unit, for the nine months ended September 30, 2016.

General and Administrative Expense. General and administrative expense was $133,681 and $123,211 for the nine months ended September 30, 2017 and 2016, respectively. The Trustee's fees are included in general and administrative expense. The Trustee was due $356,250 for its services for the nine months ended September 30, 2017. The Trust paid $324,865 of this amount to the Trustee, and $31,385 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 through June 14, 2017 and a 2.75% annualized return from June 15, 2017 through September 30, 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 $19,180 of interest due to the Trust is fully offset.

The Working Interest Owners partially reimburse the Trust each quarter for amounts paid in connection with the Trustee's services. For the nine months ended September 30, 2017, the Trustee's fees were $324,865 and the Working Interest Owners reimbursed a sum of $287,691 to the Trustee, which was the same amount reimbursed for the nine months ended September 30, 2016.

Unreimbursed Expenses and the Contingent Reserve. As of September 30, 2017, there were $1,307 of unreimbursed expenses. The Trust anticipated receipt of these expense reimbursements by month-end when it published its September distribution press release on a Form 8-K dated September 18, 2017, and included these amounts in distributions payable and distributable income per unit as of September 30, 2017. On October 18, 2017, the Trust received $1,307 of the expected expense reimbursement cash receipts, which increased the Contingent Reserve by that same amount.

During 2011, the Trustee withheld $1.0 million to create the Contingent Reserve. At any given time, the Contingent Reserve is included in cash and short-term investments, and the Trustee reserves the right to determine whether or not to release cash reserves in future periods with respect to any unreimbursed expenses. For the nine months ended September 30, 2017, the Trustee increased the Contingent Reserve by (1) $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 and (2) $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. For the nine months ended September 30, 2017, the Trustee decreased the Contingent Reserve by (1) $82,244 and $47,840 of aggregate royalty income received from BP and (2) the amount of expected expense reimbursement cash receipts of $1,307. As of September 30, 2017, the value of the Contingent Reserve was $998,693 and is included in cash and short-term investments.

Operational Review

Hugoton Royalty Properties

Natural gas and natural gas liquids revenue from the Hugoton Royalty Properties accounted for approximately 46% of the Royalty income of the Trust during the nine months ended September 30, 2017.

	Nine Months Ended September 30,

	2017		2016
Royalty income attributable to Hugoton Royalty Properties	$	1,035,190	$	298,865
Operating costs attributable to Hugoton Royalty Properties	$	490,335	$	691,887
Capital expenditures attributable to Hugoton Royalty Properties	$	7,775	$	2,630

Royalty Income. Royalty income attributable to the Hugoton Royalty Properties increased to $1,035,190 for the nine months ended September 30, 2017 from $298,865 for the same period in 2016 primarily due to higher prices for natural gas and natural gas liquids, an increase in net natural gas and natural gas liquids production volumes and decreased operating costs, offset in part by an increase in capital expenditures from the Hugoton Royalty Properties in the first nine months of 2017 compared to the first nine months of 2016.

Operating Costs and Capital Expenditures. Operating costs were $490,335 during the nine months ended September 30, 2017, a decrease of approximately 29% as compared to $691,887 during the nine months ended September 30, 2016. The decrease in operating costs was due primarily to a true-up for actual ad valorem taxes paid versus taxes reserved.

	Nine Months Ended September 30,

	2017						2016
	Natural Gas		Natural Gas Liquids		Oil and Condensate		Natural Gas		Natural Gas Liquids		Oil and Condensate
Average sales price	$	3.71	$	22.65	$	—	$	2.69	$	11.06	$	—



Actual production volumes attributable to the Royalty paid for Hugoton Royalty Properties	304,143	17,916	—	280,310	21,682	—



Net production volumes attributable to the Royalty paid for Hugoton Royalty Properties	205,188	12,096	—	82,427	6,974	—

Linn Energy Reorganization. On May 11, 2016, Linn Energy, LLC ("Old Linn"), LinnCo, LLC ("LinnCo"), an affiliate of Old Linn, and certain of Old Linn's direct and indirect subsidiaries

(collectively with Old Linn and LinnCo, the "Debtors"), filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the "Court"). The Debtors' Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16-60040.

On January 27, 2017, the Court entered the Order Confirming (I) Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and its Debtor Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC and (II) Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC, which approved and confirmed the Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the "Plan"). The Plan became effective on February 28, 2017 (the "Effective Date").

San Juan Basin Royalty Properties

San Juan Basin—New Mexico Properties

	Nine Months Ended September 30,

	2017		2016
Royalty income attributable to San Juan Basin—New Mexico Properties	$	793,633	$	400,676
Operating costs attributable to San Juan Basin—New Mexico Properties	$	690,330	$	627,880
Capital expenditures attributable to San Juan Basin—New Mexico Properties	$	8,960	$	28,733

Royalty Income. Royalty income from the San Juan Basin—New Mexico Properties was $793,633 for the first nine months of 2017, as compared to $400,676 for the first nine months of 2016. The increase in Royalty income was due primarily to higher natural gas, natural gas natural gas liquids and oil and condensate prices, higher net production volumes for natural gas, natural gas liquids and oil and condensate and reduced capital expenditures, offset in part by an increase in operating costs in the first nine months of 2017 from the San Juan Basin Royalty Properties compared to the same period in 2016.

Operating Costs and Capital Expenditures. The operating costs for the San Juan Basin—New Mexico Properties were $690,330 during the nine months ended September 30, 2017, an increase of approximately 10% as compared to $627,880 during the nine months ended September 30, 2016 due

primarily to well inspection costs and increased severance taxes. Capital expenditures were $8,960 during the nine months ended September 30, 2017, a decrease of approximately 69% as compared to $28,733 during the nine months ended September 30, 2016.

	Nine Months Ended September 30,

	2017						2016
	Natural Gas		Natural Gas Liquids		Oil and Condensate		Natural Gas		Natural Gas Liquids		Oil and Condensate
Average sales price	$	2.26	$	16.13	$	37.95	$	1.47	$	12.06	$	28.81



Actual production volumes attributable to the Royalty paid for San Juan Basin—New Mexico Properties	457,384	33,827	1,254	472,812	36,990	1,272



Net production volumes attributable to the Royalty paid for San Juan Basin—New Mexico Properties	243,319	13,513	674	175,615	10,606	508

San Juan Basin—Colorado Properties

	Nine Months Ended September 30,

	2017		2016
Royalty income attributable to San Juan Basin—Colorado Properties	$	433,329	$	139,875
Operating costs attributable to San Juan Basin—Colorado Properties	$	91,604	$	191,050

Royalty Income. Royalty income from the San Juan Basin—Colorado Properties was $433,329 for the nine months ended September 30, 2017, as compared to $139,875 during the same period in 2016. The increase in Royalty income was primarily the result of higher prices for natural gas, lower operating costs and increased net natural gas production in the nine months ended September 30, 2017 compared to the same period in 2016.

Operating Costs. Operating costs on these properties were $91,604 for the nine months ended September 30, 2017, a decrease of approximately 52% as compared to $191,050 in the same period in 2016 due primarily to higher repair and recompletion costs in 2016 compared with 2017.

	Nine Months Ended September 30,

	2017						2016
	Natural Gas		Natural Gas Liquids		Oil and Condensate		Natural Gas		Natural Gas Liquids		Oil and Condensate
Average sales price	$	1.64	$	—	$	—	$	1.07	$	—	$	—



Actual production volumes attributable to the Royalty paid for San Juan Basin—Colorado Properties	314,433	—	—	375,019	—	—



Net production volumes attributable to the Royalty paid for San Juan Basin—Colorado Properties	263,535	—	—	131,229	—	—

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

The Trust does not engage in any operations, and does not utilize market risk sensitive instruments, either for trading purposes or for other than trading purposes. The Trust's monthly distributions are highly dependent upon the prices realized from the sale of natural gas and natural gas liquids. Natural gas and natural gas liquids prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and the Working Interest Owners. Factors that contribute to price fluctuation include, among others:

•: political conditions worldwide, in particular political disruption, war or other armed conflict in or affecting oil producing regions;
•: worldwide economic conditions;
•: weather conditions, including hurricanes and tropical storms in North America;
•: the supply and price of foreign natural gas;
•: the level of consumer demand;
•: the price and availability of alternative fuels;
•: the proximity to, and capacity of, transportation facilities; and
•: the effect of worldwide energy conservation measures.

Moreover, government regulations, such as regulation of natural gas transportation and regulation of greenhouse gas and other emissions associated with fossil fuel combustion and price controls, can affect product prices in the long term.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that

it files or submits under the "Exchange Act", is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act is accumulated and communicated by the Working Interest Owners to The Bank of New York Mellon Trust Company, N.A., as Trustee of the Trust, and its employees who participate in the preparation of the Trust's periodic reports as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, the Trust officer acting on behalf of the Trustee responsible for the administration of the Trust conducted an evaluation of the Trustee's disclosure controls and procedures. The officer acting on behalf of the Trustee concluded that the Trust's disclosure controls and procedures were effective.

Due to the contractual arrangements of (i) the Trust Indenture and (ii) the rights of the Trust under the Conveyance regarding information furnished by the Working Interest Owners, the Trustee relies on information provided by the Working Interest Owners, including (i) the status of litigation, (ii) historical operating data, plans for future operating and capital expenditures and reserve information, (iii) information relating to projected production, and (iv) conclusions regarding reserves by their internal reserve engineers or other experts in good faith. See Part I Item 1A. "Risk Factors—Trust unitholders and the Trustee have no control over the operation or development of the Royalty Properties and have little influence over operation or development" and "The Trustee relies upon the Working Interest Owners for information regarding the Royalty Properties" in the Trust's Annual Report on Form 10-K for the year ended December 31, 2016 for a description of certain risks relating to these arrangements and reliance, including filings such as this filing outside the time periods specified notwithstanding effective disclosure controls and procedures of the Trustee regarding information under its control.

The officer acting on behalf of the Trustee has not conducted a separate evaluation of the disclosure controls and procedures with respect to information furnished by the Working Interest Owners. The Trustee notes that it is conducting an ongoing review of certain information and calculations by the Working Interest Owners, along with an outside joint venture auditor. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" under Item 7 on Form 10-K for the year ended December 31, 2016 for information concerning controls and procedures with respect to the Royalty.

Changes in Internal Control over Financial Reporting. In connection with the evaluation by the Trustee of changes in internal control over financial reporting of the Trust that occurred during the Trust's last fiscal quarter, no change in the Trust's internal control over financial reporting was identified that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, has not evaluated and makes no statement concerning the internal control over financial reporting of the Working Interest Owners.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings.

There are no pending legal proceedings to which the Trust is a named party. The Trustee has been advised by Linn, Hilcorp and BP that the Trust may be subject to litigation in the ordinary course of business for certain matters that include the Royalty Properties. While each of the Working 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 were made against Royalty income, such charges could have a material impact on future Royalty income.

Item 1A. Risk Factors.

For a discussion of the Trust's potential risks and uncertainties, please see "Risk Factors" in Item 1A to Part 1 of the Trust's Annual Report on Form 10-K for the year ended December 31, 2016. During the quarter ended September 30, 2017, there was no material change in such risk factors.

Item 6. Exhibits.

(Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. The Bank of New York Mellon Trust Company, N.A. is the successor trustee to JPMorgan Chase Bank, N.A. JPMorgan Chase Bank, N.A. was formerly known as The Chase Manhattan Bank and was successor by mergers to the originally named Trustee, Texas Commerce Bank National Association).



4(a	)*	Mesa Royalty Trust Indenture between Mesa Petroleum Co. and Texas Commerce Bank National Association, as Trustee, dated November 1, 1979	2-65217	1(a	)

4(b	)*	Overriding Royalty Conveyance between Mesa Petroleum Co. and Texas Commerce Bank, as Trustee, dated November 1, 1979	2-65217	1(b	)

4(c	)*	First Amendment to the Mesa Royalty Trust Indenture dated as of March 14, 1985 (Exhibit 4(c) to Form 10-K for year ended December 31, 1984 of Mesa Royalty Trust)	1-7884	4(c	)

4(d	)*	Form of Assignment of Overriding Royalty Interest, effective April 1, 1985, from Texas Commerce Bank National Association, as Trustee, to MTR Holding Co. (Exhibit 4(d) to Form 10-K for year ended December 31, 1984 of Mesa Royalty Trust)	1-7884	4(d	)

4(e	)*	Purchase and Sale Agreement, dated March 25, 1991, by and among Mesa Limited Partnership, Mesa Operating Limited Partnership and Conoco, as amended on April 30, 1991 (Exhibit 4(e) to Form 10-K for year ended December 31, 1991 of Mesa Royalty Trust)	1-7884	4(e	)

31		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		Mesa Royalty Trust
		By:		The Bank of New York Mellon Trust Company, N.A., as Trustee
		By:		/s/ ELAINA RODGERS Elaina Rodgers Vice President & Trust Officer

Date: November 14, 2017

The Registrant, Mesa Royalty Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided.

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DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS
PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

MESA ROYALTY TRUST STATEMENTS OF DISTRIBUTABLE INCOME (Unaudited)
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
MESA ROYALTY TRUST STATEMENTS OF CHANGES IN TRUST CORPUS (Unaudited)
MESA ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS (Unaudited)

Item 2. Trustee's Discussion and Analysis of Financial Condition and Results of Operations.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Item 4. Controls and Procedures.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings.

Item 1A. Risk Factors.

Item 6. Exhibits.

SIGNATURES