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, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

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, 2016—1,863,590 Units of Beneficial Interest were outstanding in Mesa Royalty Trust.

	Three Months Ended September 30,					Nine Months Ended September30,

	2016			2015		2016			2015
Royalty income	$	451,782		$	401,139	$	839,415		$	1,647,067
Interest income		548			—		1,255			25
General and administrative income (expense)		(36,228	)		10,823		(123,211	)		(130,268	)

Distributable income	$	416,102		$	411,962	$	717,459		$	1,516,824



Distributable income per unit	$	0.2233		$	0.2211	$	0.3850		$	0.8139



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

	September 30, 2016			December 31, 2015

	(Unaudited)
ASSETS
Cash and short-term investments	$	1,415,391		$	1,408,413
Net overriding royalty interest in oil and gas properties		42,498,034			42,498,034
Accumulated amortization		(39,954,962	)		(39,763,316	)

Total assets	$	3,958,463		$	4,143,131



LIABILITIES AND TRUST CORPUS
Distributions payable	$	307,732		$	415,151
Trust corpus (1,863,590 units of beneficial interest authorized, issued and outstanding)		3,650,731			3,727,980

Total liabilities and trust corpus	$	3,958,463		$	4,143,131

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

	2016			2015			2016			2015
Trust corpus, beginning of period	$	3,646,568		$	3,804,659		$	3,727,980		$	4,013,833
Distributable income		416,102			411,962			717,459			1,516,824
Distributions to unitholders		(307,732	)		(347,952	)		(603,062	)		(1,507,250	)
Amortization of net overriding royalty interest		(104,207	)		(68,005	)		(191,646	)		(222,743	)

Trust corpus, end of period	$	3,650,731		$	3,800,664		$	3,650,731		$	3,800,664

The Mesa Royalty Trust (the "Trust") was created on November 1, 1979. On that date, Mesa Petroleum Co., predecessor to Mesa Limited Partnership ("MLP"), which was the predecessor to MESA Inc., conveyed to the Trust an overriding royalty interest (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 certain producing oil and gas properties located in the Hugoton field of Kansas, the San Juan Basin field of New Mexico and Colorado and the Yellow Creek field of Wyoming (the "Royalty Properties"). The Royalty is evidenced by counterparts of an Overriding Royalty Conveyance dated as of November 1, 1979 (the "Conveyance"). On April 30, 1991, MLP sold its interests in the Royalty Properties located in the San Juan Basin field to ConocoPhillips. ConocoPhillips sold the portion of its interests in the San Juan Basin Royalty Properties located in Colorado 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 Colorado San Juan Basin Royalty Properties to BP Amoco Company ("BP"), a subsidiary of BP p.l.c. 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. Substantially all of the San Juan Basin Royalty Properties located in New Mexico are operated by ConocoPhillips. Effective January 1, 2005, ConocoPhillips assigned its interest in an immaterial number of San Juan Basin Royalty Properties located in New Mexico to XTO Energy Inc. The San Juan Basin Royalty Properties located in Colorado are operated by BP. As used in this report, Linn refers to the current operator of the Hugoton Royalty Properties, ConocoPhillips refers to the operator of the San Juan Basin Royalty Properties, other than the portion of such properties located in Colorado, and BP refers to the operator of the Colorado San Juan Basin Royalty Properties unless otherwise indicated.

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 original name of the Trustee, Texas Commerce Bank National Association. The terms of the Mesa Royalty Trust Indenture (as amended, the "Trust Indenture") provide, among other things, that:

As of September 30, 2016, there were $0 unreimbursed expenses. 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 is included in cash and short term investments. For the three months ended September 30, 2016, the Trustee decreased the reserve for future unknown contingent liabilities and expenses for a prior period expense refund received from a vendor in the amount of $101 and increased the reserve for future unknown contingent liabilities and expenses by (i) the amounts received during the third quarter of 2016 related to expense reimbursement cash receipts for previous periods totaling $812 and (ii) $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 royalty income was included in the October 2016 distribution to unitholders. For the nine months ended September 30, 2016, the Trustee increased the reserve for future unknown contingent liabilities and expenses 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 royalty income was included in the October 2016 distribution to unitholders. For the nine months ended September 30, 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 and (ii) the amount of expected expense reimbursement cash receipts of $812. As of September 30, 2016, the reserve for unknown contingent liabilities and expenses was $1,107,659 and is 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 unreimbursed expenses.

The Trustee was due $118,750 for its services for the quarter ended September 30, 2016. 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 2.0% return as of September 30, 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 $33,223 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 quarter ended September 30, 2016, the Trustee's fees were $118,750 and such reimbursements totaled $95,897. For the nine months ended September 30, 2016, the Trustee's fees were $324,865 and such reimbursements totaled $287,691. For the quarter and the nine months ended September 30, 2015, the Trustee's fees were $118,750 and $324,965, respectively. Reimbursements received for the quarter and the nine months ended September 30, 2015 were $95,900 and $287,787, respectively.

On May 11, 2016, Linn Energy, LLC ("Linn Energy"), Linn's parent company, announced that Linn Energy, LinnCo, LLC ("LinnCo") and Berry Petroleum Company, LLC ("Berry" and together with Linn Energy and LinnCo, the "Linn Parties") entered into a Restructuring Support Agreement with holders of at least 66.67% by aggregate outstanding principal amounts of Linn Energy's Amended and Restated Credit Agreement, dated as of April 24, 2013, as amended, and Berry's Second Amended and Restated Credit Agreement, dated as of November 15, 2010, as amended. In order to implement the terms of the Restructuring Support Agreement, Linn Energy announced that the Linn Parties filed voluntary petitions for restructuring under Chapter 11 of the Bankruptcy Code ("Chapter 11") in the United States Bankruptcy Court for the Southern District of Texas.

On October 21, 2016, the Linn Parties entered into the First Amended and Restated Restructuring Support Agreement (the "Amended and Restated RSA") with (i) certain holders of Linn Energy's 12% Senior Secured Second Lien Notes due December 2020 (such holders, the "Consenting Second Lien Noteholders"); (ii) certain holders of Linn Energy's unsecured notes (such holders, the "Consenting Unsecured Noteholders," and together with the Consenting Second Lien Noteholders, the "Consenting Noteholders"); and (iii) certain lenders (the "Consenting Linn Lenders," and together with the Consenting Noteholders, the "Consenting Creditors") under Linn Energy's Sixth Amended and Restated Credit Agreement, dated as of April 24, 2013 (the "Linn Credit Agreement"). The Amended and Restated RSA amends and restates that certain restructuring support agreement dated as of October 7, 2016, by and among the Linn Parties and the Consenting Noteholders. In addition, the Amended and Restated RSA replaces and supersedes that certain restructuring support agreement with

certain of the Consenting Linn Lenders, dated as of May 10, 2016, with respect to the terms of the restructuring of the Linn Parties.

The Amended and Restated RSA sets forth, subject to certain conditions, the commitment of the Linn Parties and the Consenting Creditors to support a comprehensive restructuring of the Linn Parties' long-term debt (the "Restructuring"). The Restructuring will be effectuated through the Proposed Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and its Debtor Affiliates (the "Plan") filed with the Court on October 21, 2016.

The Amended and Restated RSA includes limited changes to the treatment of claims under the Linn Credit Agreement, including that such claims will be allowed as fully secured claims under the Plan and will not be subject to off-set, avoidance, recharacterization, recoupment, or subordination. Further, the Amended and Restated RSA provides that holders of claims under the Linn Credit Agreement will receive, as part of the Plan, (i) a cash paydown equal to the sum of (a) $500 million from cash equity contributions at the closing of a take-back debt facility, plus (b) other amounts from Linn Energy's cash on hand (net of Chapter 11 and transaction expenses) consistent with the Plan and subject to anti-cash hoarding provisions in the take-back debt facility, and (ii) a take-back debt facility on the terms and conditions set forth in the Amended and Restated RSA.

In light of the pending Chapter 11 cases, the extent of the impact, if any, on the Trust is currently unclear. However, the Linn Parties' Chapter 11 process may result in reduced production of reserves and decreased distributions to unitholders. For more information on the potential impact of the Linn Parties' bankruptcy filing on the Trust's financial condition and results of operations, see Part II Item 1A "Risk Factors—The financial condition of operators of the underlying properties could impede the operation of wells" in this Form 10-Q.

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, 2015. 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. 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.

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.

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.

In a technical advice memorandum dated February 26, 1982, 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.

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.

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 for the period reported. 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. As of September 30, 2016 and December 31, 2015, there were $12,199 and $78,591, respectively, of excess production costs. Excess production costs in the amount of $2,652 and $1,107 as of September 30, 2016 and December 31, 2015, respectively, related to the San Juan Basin—New Mexico properties operated by XTO Energy Inc. XTO Energy Inc. made distributions to the Trust during the first and second quarters of 2015 without recovering the $478 excess production costs. The remainder of the excess production costs in the amount of $9,547 as of September 30, 2016 and $77,484 as of December 31, 2015, related to the San Juan Basin—Colorado properties operated by BP and Red Willow. Excess production costs related to the San Juan Basin—Colorado properties operated by BP were approximately $0 and $72,336 as of September 30, 2016 and December 31, 2015, respectively. Excess production costs related to the San Juan Basin—Colorado properties operated by Red Willow were approximately $9,547 and $5,148 as of September 30, 2016 and December 31, 2015, respectively.

During 2011, the Trustee withheld $1.0 million for future unknown contingent liabilities and expenses in accordance with the Trust Indenture. For the three months ended September 30, 2016, the Trustee decreased the reserve for future unknown contingent liabilities and expenses for a prior period expense refund received from a vendor in the amount of $101 and increased the reserve for future unknown contingent liabilities and expenses by (i) the amounts received during the third quarter of 2016 related to expense reimbursement cash receipts for previous periods totaling $812 and (ii) $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 royalty income was included in the October 2016 distribution to unitholders. For the nine months ended September 30, 2016, the Trustee increased the reserve for future unknown contingent liabilities and expenses 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 royalty income was included in the October 2016 distribution to unitholders. For the nine months ended September 30, 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 and (ii) the amount of expected expense reimbursement cash receipts of $812. The effect on distributable income per unit is as follows:

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

	2016			2015			2016			2015
Distributable Income Before Reserve for Contingent Liabilities and Expenses	$	416,102		$	411,962		$	717,459		$	1,516,824
Increase in Reserve for Contingent Liabilities and Expenses (See Note 1)		(108,471	)		(67,816	)		(115,310	)		(183,700	)
Withdrawal from Reserve for Contingent Liabilities and Expenses (See Note 1)		101			3,806			913			174,126

Distributable income Available for Distribution	$	307,732		$	347,952		$	603,062		$	1,507,250



Distributable income Available for Distribution per unit	$	0.1651		$	0.1867		$	0.3236		$	0.8088



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

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

The following review of the Trust's 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 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, 2015. 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.

This Form 10-Q includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this Form 10-Q, including without limitation the statements under "Management's Discussion and Analysis of Financial Condition and Results of Operations," are forward-looking statements. 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. Important factors that could cause actual results to differ materially from expectations ("Cautionary Statements") are disclosed in this Form 10-Q and in the Trust's Annual Report on Form 10-K for the year ended December 31, 2015, including under "Item 1A. Risk Factors". All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements.

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,

	2016									2015
	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)	$	694,467		$	222,512		$	15,887		$	763,681		$	266,351		$	22,006
Less the Trust's proportionate share of:
Capital costs recovered		(6,020	)		(2,709	)		(267	)		(38,019	)		(16,941	)		(2,242	)
Operating costs		(349,925	)		(114,570	)		(8,251	)		(587,813	)		(137,923	)		(9,426	)

Net proceeds(2)	$	338,522		$	105,233		$	7,369		$	137,849		$	111,487		$	10,338



Royalty income(2)	$	338,918		$	105,474		$	7,390		$	279,199		$	111,591		$	10,349



Average sales price	$	1.54		$	13.75		$	34.34		$	1.93		$	14.13		$	44.14



Average production costs(3)	$	1.62		$	15.29		$	39.58		$	4.32		$	19.60		$	49.77



	(Mcf)			(Bbls)			(Bbls)			(Mcf)			(Bbls)			(Bbls)
Net production volumes attributable to the Royalty paid(4)		219,802			7,669			215			145,024			7,899			234

	Nine Months Ended September 30,

	2016									2015
	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)	$	1,840,730		$	570,555		$	36,702		$	2,698,616		$	857,115		$	60,346
Less the Trust's proportionate share of:
Capital costs recovered		(21,858	)		(8,734	)		(771	)		(88,134	)		(36,847	)		(4,059	)
Operating costs		(1,132,082	)		(357,334	)		(21,400	)		(1,608,760	)		(397,892	)		(25,627	)

Net proceeds(2)	$	686,790		$	204,487		$	14,531		$	1,001,722		$	422,376		$	30,660



Royalty income(2)	$	619,757		$	205,016		$	14,643		$	1,193,238		$	422,480		$	30,671



Average sales price	$	1.59		$	11.66		$	28.81		$	2.56		$	13.77		$	42.09



Average production costs(3)	$	2.96		$	20.82		$	43.62		$	3.64		$	14.17		$	40.74



	(Mcf)			(Bbls)			(Bbls)			(Mcf)			(Bbls)			(Bbls)
Net production volumes attributable to the Royalty paid(4)		389,270			17,850			508			466,351			30,682			729

(2)

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. Excess production costs in the amount of $2,652 and $777 as of September 30, 2016 and September 30, 2015, respectively, related to the San Juan Basin—New Mexico properties operated by XTO Energy Inc. Excess production costs related to the San Juan Basin—New Mexico properties operated by XTO Energy Inc. were approximately $559 and $1,545 for the three and nine months ended September 30, 2016, respectively. Excess production costs related to the San Juan Basin—New Mexico properties operated by XTO Energy Inc. were approximately $299 and $299 for the three and nine months ended September 20, 2015, respectively.

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 $187,089 and $4,243, respectively as of September 30, 2015.

Excess production costs related to the San Juan Basin—Colorado properties operated by BP and Red Willow were approximately $0 and $98, respectively for the three months ended September 30, 2016 and $0 and $4,399, respectively for the nine months ended September 30, 2016. The trust recovered prior period excess production costs of $0 and $72,336 related to the San Juan Basin—Colorado properties operated by BP during the three and nine months ended September 30, 2016, respectively.

Excess production costs related to the San Juan Basin—Colorado properties operated by BP and Red Willow were approximately $138,273 and $2,893, respectively for the three months ended September 30, 2015 and $187,089 and $4,243, respectively for the nine months ended September 30, 2015.

There was a $677 joint venture audit adjustment by PNR for the quarter ended March 31, 2015.

The excess production costs must be recovered by the Working Interest Owners before any distribution of Royalty income will be made to the Trust.

(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.

The Trust's Royalty income was $451,782 in the third quarter of 2016, an increase of approximately 13% as compared to $401,139 in the third quarter of 2015, primarily as a result of decreased capital expenditures and operating costs in the third quarter of 2016, offset in part by lower natural gas, natural gas liquids and oil and condensate prices and reduced production of natural gas liquids and oil and condensate in the third quarter of 2016 as compared to the third quarter of 2015.

General and Administrative expense was $36,228 in the third quarter of 2016. General and Administrative income for the quarter ended September 30, 2015 was $10,823 which was the result of net reimbursements of $49,826 from the second quarter of 2015 exceeding Trust expenses of $39,003 for the third quarter of 2015.

The distributable income available for distribution of the Trust for 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 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, 2016 was $307,732, representing $0.1651 per unit, compared to $347,952, representing $0.1867 per unit, for the quarter ended September 30, 2015. Based on 1,863,590 units outstanding for the quarters ended September 30, 2016 and 2015, respectively, the per unit distributions were as follows:

expenses for a prior period expense refund received from a vendor in the amount of $101 and increased the reserve for future unknown contingent liabilities and expenses by (i) the amounts received during the third quarter of 2016 related to expense reimbursement cash receipts for previous periods totaling $812 and (ii) $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 royalty income was included in the October 2016 distribution to unitholders. For the nine months ended September 30, 2016, the Trustee increased the reserve for future unknown contingent liabilities and expenses 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 royalty income was included in the October 2016 distribution to unitholders. For the nine months ended September 30, 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 and (ii) the amount of expected expense reimbursement cash receipts of $812. As of September 30, 2016, the reserve for unknown contingent liabilities and expenses was $1,107,659 and is 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 unreimbursed expenses.

The Trustee was due $118,750 for its services for the quarter ended September 30, 2016. 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 2.0% return as of September 30, 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 $33,223 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 quarter ended September 30, 2016, the Trustee's fees were $118,750 and such reimbursements totaled $95,897. For the quarter ended September 30, 2015, the Trustee's fees were $108,288. Reimbursements received for the quarter ended September 30, 2015 were $95,900.

Natural gas and natural gas liquids production attributable to the Royalty from the Hugoton field accounted for approximately 34% of the Royalty income of the Trust during the third quarter of 2016.

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 gas production from the Hugoton field under short-term and multi-month contracts. Overall market prices received for natural gas from Hugoton Royalty Properties were lower for the three months ended September 30, 2016 as compared to the three months ended September 30, 2015.

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, Linn Midstream acquired the gathering line from Oneok. Oneok will continue to provide compression under a new Gas Compression Agreement effective January 1, 2016 through December 31, 2018, and then month-to-month thereafter, at a rate of $0.13 per Mcf, to be escalated beginning April 1, 2017, and annually each April 1 thereafter using the Consumer Price Index. Linn Midstream began providing gathering services under a new Gas Gathering Agreement effective January 1, 2016, under a three year agreement that continues month-to-month thereafter, at a rate of $0.06 per Mcf, to be escalated beginning April 1, 2017, and annually each April 1 thereafter using the Consumer Price Index.

Royalty income attributable to the Hugoton Royalty increased to $153,791 in the third quarter of 2016 from $152,433 in the third quarter of 2015 primarily due to lower operating costs, offset in part by decreases in natural gas and natural gas liquids prices, reduced natural gas and natural gas liquids volumes and a reduction in capital expenditures from the Hugoton Royalty Properties in the third quarter of 2016 compared to the third quarter of 2015. The average price received in the third quarter of 2016 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $2.53 per Mcf and $13.46 per barrel, respectively, as compared to $3.08 per Mcf and $12.87 per barrel, respectively, in the third quarter of 2015. Net production of natural gas attributable to the Hugoton Royalty increased to 43,171 Mcf in the third quarter of 2016 from 36,205 Mcf in the third quarter of 2015. Net production of natural gas liquids attributable to the Hugoton Royalty increased to 3,311 barrels in the third quarter of 2016 from 3,171 barrels in the third quarter of 2015. Actual production volumes from the Hugoton properties decreased to 94,541 Mcf of natural gas and to 6,846 barrels of natural gas liquids in the third quarter of 2016 as compared to 96,115 Mcf of natural gas and to 8,583 barrels of natural gas liquids for the same period in 2015 due primarily to natural decline as well as a reduced capital program due to the lower commodity price environment.

The Hugoton capital expenditures were $0 in the third quarter of 2016, as compared to $124 in the third quarter of 2015. Operating costs were $177,501 in the third quarter of 2016 as compared to $254,170 in the third quarter of 2015. The decrease in operating costs was due primarily to cost saving initiatives and a reduction in ad valorem taxes in the third quarter of 2016 compared with the third quarter of 2015.

Royalty income from the San Juan Basin Royalty Properties is calculated and paid to the Trust on a state-by-state basis. Substantially all of the royalty income from the San Juan Basin Royalty Properties is attributable to the Royalty Properties located in the State of New Mexico.

Royalty income from the San Juan Basin—New Mexico was $188,174 during the third quarter of 2016 as compared with Royalty income of $248,706 during the third quarter of 2015. This decrease in Royalty income was due primarily to a decrease in natural gas liquids and oil and condensate prices and lower natural gas, natural gas liquids and oil and condensate production volumes for the third quarter of 2016 compared to the third quarter of 2015, offset in part by an increase in natural gas price

and a reduction in capital expenditures and operating costs during the third quarter of 2016 compared to the third quarter of 2015. Net production attributable to the San Juan Basin Royalty Properties located in New Mexico was 74,001 Mcf of natural gas, 4,358 barrels of natural gas liquids and 215 barrels of oil and condensate in the third quarter of 2016, as compared to 108,819 Mcf of natural gas, 4,728 barrels of natural gas liquids and 234 barrels of oil and condensate in the third quarter of 2015. The average price received in the third quarter of 2016 for natural gas, natural gas liquids and oil and condensate sold from the San Juan Basin Royalty Properties located in the State of New Mexico was $1.62 per Mcf, $13.98 per barrel and $34.34 per barrel, respectively, compared to $1.54 per Mcf, $14.97 per barrel and $44.14 per barrel during the same period in 2015. Actual production volumes of natural gas attributable to the San Juan Basin Royalty Properties located in the State of New Mexico decreased to 156,707 Mcf in the third quarter of 2016 from 236,389 Mcf of natural gas for the same period in 2015. Actual production volumes of natural gas liquids attributable to the San Juan Basin Royalty Properties located in the State of New Mexico decreased to 12,560 barrels in the third quarter of 2016 from 14,188 barrels for the same period in 2015. Actual production volumes of oil and condensate attributable to the San Juan Basin Royalty Properties located in the State of New Mexico decreased to 463 barrels in the third quarter of 2016 from 499 barrels for the same period in 2015.

Capital expenditures on these properties were $8,996 in the third quarter of 2016, a decrease of approximately 84% as compared to $56,553 in the third quarter of 2015, primarily due to decreased spending on facilities in the third quarter of 2016 compared with the third quarter of 2015. Operating costs were $202,595 in the third quarter of 2016, a decrease of approximately 14% as compared to $236,055 in the third quarter of 2015. The decrease in operating costs was primarily the result of cost saving initiatives, a decrease in severance taxes due to the natural decline in volumes from the field as well as the decline in the price of natural gas liquids and oil and condensate.

The Trust's interest in the San Juan Basin was conveyed from PNR's working interest in 31,328 net producing acres in northwestern New Mexico and southwestern Colorado. Substantially all of the natural gas produced from the San Juan Basin is currently being sold on the spot market.

Royalty income from the San Juan Basin—Colorado Royalty Properties was $109,815 during the third quarter of 2016, compared to $0 during the third quarter of 2015. This increase in Royalty income was due primarily to a decrease in operating expenses and an increase in natural gas production volumes in the third quarter of 2016 compared to the third quarter of 2015 offset in part by a decrease in the average price received for natural gas in the third quarter of 2016 compared to the third quarter of 2015. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 102,631 Mcf of natural gas during the third quarter of 2016 with 0 Mcf of natural gas attributable to the Trust during the third quarter of 2015. The average price received in the third quarter of 2016 for natural gas sold from the San Juan Basin Colorado Properties was $1.07 per Mcf, as compared to average price of $1.38 per Mcf for the third quarter of 2015. Actual production volumes attributable to the San Juan Basin Colorado Properties increased to 188,472 Mcf of natural gas in the third quarter of 2016 from 75,478 Mcf of natural gas for the same period in 2015.

Operating costs on these properties were $92,650 in the third quarter of 2016 as compared to $244,937 in the third quarter of 2015. The decrease in operating costs was due primarily to repairs and recompletions in 2015 compared with 2016.

The Trust's Royalty income was $839,415 for the nine months ended September 30, 2016, a decrease of approximately 49% as compared to $1,647,067 for the nine months ended September 30, 2015, primarily as a result of decreased natural gas, natural gas liquids and oil and condensate prices and production volumes, offset in part by reduced capital expenditures and lower operating costs in the first nine months of 2016 as compared to the first nine months of 2015.

The distributable income available for distribution of the Trust for 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 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 nine months ended September 30, 2016 was $603,062, representing $0.3236 per unit, compared to $1,507,250, representing $0.8088, for the nine months ended September 30, 2015.

contingent liabilities and expenses for (i) a prior period expense refund received from a vendor in the amount of $101 and (ii) the amount of expected expense reimbursement cash receipts of $812. As of September 30, 2016, the reserve for unknown contingent liabilities and expenses was $1,107,659 and is 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 unreimbursed expenses.

As of September 30, 2015, there were $8,416 of unreimbursed expenses, including $1,733 from the quarter ended March 31, 2015 and $2,877 from the quarter ended June 30, 2015. The Trust anticipated receipt of these expense reimbursements by month-end when it published its March, June and September distribution press releases on March 20, 2015, June 17, 2015 and September 16, 2015, respectively, and included these amounts in distributions payable and distributable income per unit as of March 31, 2015, June 30, 2015 and September 30, 2015. 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 is included in cash and short-term investments. For the nine months ended September 30, 2015, the Trustee decreased the reserve for future unknown contingent liabilities and expenses by the amount of expected expense reimbursement cash receipts of $174,126. Additionally, the Trustee increased the reserve for future unknown contingent liabilities and expenses by the amounts received during the nine months ended September 30, 2015 related to expense reimbursement cash receipts for previous periods totaling $165,710 and by $17,990 of royalty income received from Linn Energy in September 2015 after the distribution to Unitholders had been announced for the month of September 2015. Such royalty income was included in the October 2015 distribution to unitholders. As of September 30, 2015, the reserve for unknown contingent liabilities and expenses was $1,009,574, which was included in cash and short term investments. The Trust has subsequently received $8,416 of the expected expense reimbursement cash receipts as of November 13, 2015, 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.

The Trustee was due $356,250 for its services for the nine months ended September 30, 2016. The Trust paid $324,865 of this amount to the Trustee, and $31,386 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 2.0% return for the nine months ended September 30, 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 $33,223 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 nine months ended September 30, 2016, the Trustee's fees were $324,865 and such reimbursements totaled $287,691. For the nine months ended September 30, 2015, such fees were $324,965. Reimbursements received for the nine months ended September 30, 2015 were $287,787.

Natural gas and natural gas liquids revenue from the Hugoton field attributable to the Royalty accounted for approximately 36% of the Royalty income of the Trust during the nine months ended September 30, 2016.

Royalty income attributable to the Hugoton Royalty Properties decreased to $298,865 for the nine months ended September 30, 2016 from $729,390 for the same period in 2015 primarily due to lower prices for natural gas and natural gas liquids and lower natural gas and natural gas liquids production volumes, offset in part by lower operating costs and reduced capital expenditures from the Hugoton Royalty Properties in the first nine months of 2016 compared to the first nine months of 2015. The average price received in the first nine months of 2016 for natural gas and natural gas liquids sold from the Hugoton field was $2.69 per Mcf and $11.06 per barrel, respectively, compared to $3.54 per Mcf and $14.48 per barrel, respectively, during the same period in 2015. Net production attributable to the Hugoton Royalty Properties decreased to 82,427 Mcf of natural gas and 6,974 barrels of natural gas liquids for the nine months ended September 30, 2016 as compared to 156,549 Mcf of natural gas and 12,053 barrels of natural gas liquids for the nine months ended September 30, 2015. Actual production volumes attributable to the Hugoton Royalty Properties decreased to 280,310 Mcf of natural gas and 21,682 barrels of natural gas liquids in the nine months ended September 30, 2016 as compared to 304,013 Mcf of natural gas and 24,791 barrels of natural gas liquids for the same period in 2015. The decrease in volumes was due primarily to natural decline as well as a reduced capital program due to the lower commodity price environment.

Capital expenditures on these properties were $2,630 during the nine months ended September 30, 2016 as compared to $10,388 during the nine months ended September 30, 2015. Operating costs were $691,887 during the nine months ended September 30, 2016 as compared to $696,088 during the nine months ended September 30, 2015.

Royalty income from the San Juan Basin—New Mexico was $400,676 for the first nine months of 2016 compared to $900,128 for the first nine months of 2015. The decrease in Royalty income was due primarily to lower natural gas, natural gas liquids and oil and condensate prices and lower production volumes for natural gas, natural gas liquids and oil and condensate, offset in part by reduced capital expenditures and lower operating costs in the first nine months of 2016 from the San Juan Basin properties compared to the same period in 2015. The average price received in the first nine months of 2016 for natural gas, natural gas liquids and oil and condensate sold from the San Juan Basin Royalty Properties located in the State of New Mexico was $1.47 per Mcf, $12.06 per barrel and $28.81 per barrel, respectively, compared to $2.07 per Mcf, $13.31 per barrel and $42.09 per barrel during the same period in 2015. Net production attributable to the San Juan Basin Royalty located in New Mexico was 175,615 Mcf of natural gas, 10,606 barrels of natural gas liquids and 508 barrels of oil and condensate for the nine months ended September 30, 2016 as compared to 300,704 Mcf of natural gas, 18,629 barrels of natural gas liquids and 729 barrels of oil and condensate for the nine months ended September 30, 2015. Actual production volumes attributable to the San Juan Basin Royalty Properties decreased to 472,812 Mcf of natural gas, 36,990 barrels of natural gas liquids and 1,272 barrels of oil and condensate in the nine months ended September 30, 2016 as compared to 595,859 Mcf of natural

gas, 42,934 barrels of natural gas liquids and 1,434 barrels of oil and condensate for the same period in 2015.

San Juan Basin—New Mexico capital expenditures were $28,733 during the nine months ended September 30, 2016, a decrease of approximately 76% as compared to $118,127 during the nine months ended September 30, 2015. This decrease is due to decreased spending on facilities during the nine months ended September 30, 2016 when compared to the nine months ended September 30, 2015. Operating costs were $627,880 during the nine months ended September 30, 2016, a decrease of approximately 19% as compared to $772,781 during the nine months ended September 30, 2015. The decrease in operating costs was primarily affected by the decrease in severance taxes due to the natural decline in volumes from the field as well as the decline in the price of natural gas, natural gas liquids and oil and condensate.

Royalty income from the San Juan Basin—Colorado Royalty Properties was $139,875 for the nine months ended September 30, 2016, compared to $17,549 during the same period in 2015. The increase in Royalty income was primarily the result of lower operating costs and increased natural gas production, offset in part by lower prices for natural gas in the nine months ended September 30, 2016 compared to the same period in 2015. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 131,229 Mcf of natural gas during the nine months ended September 30, 2016 with 9,099 Mcf of natural gas attributable to the Trust during the same period in 2015. The average price received for the nine months ended September 30, 2016 for natural gas sold from the San Juan Basin Colorado Properties was $1.07 per Mcf, compared to $1.93 per Mcf received during the same period in 2015. Actual production volumes attributable to the San Juan Basin—Colorado Royalty Properties increased to 375,019 Mcf of natural gas for the nine months ended September 30, 2016 as compared to 204,700 Mcf of natural gas for the same period in 2015.

Operating costs on these properties were $191,050 for the nine months ended September 30, 2016 a decrease of approximately 66% as compared to $563,410 in the same period in 2015 due primarily to repairs and recompletions in the first nine months of 2015 compared with 2016.

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:

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.

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 Securities Exchange Act of 1934, as amended, 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, 2015 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, 2015 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.

There are no pending legal proceedings to which the Trust is a named party. The Trustee has been advised by Linn, ConocoPhillips and BP that it is 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.

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, 2015. In addition, the following supplements and amends the risk factors described in the Trust's Annual Report on Form 10-K for the year ended December 31, 2015.

The financial condition of 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.

Please see Part I, Item 2—"Management's Discussion and Analysis of Financial Condition and Results of Operations—Three Months Ended September 30, 2016 and 2015—Operational Review" for additional information.

In light of the pending Chapter 11 cases, the extent of the impact, if any, on the Trust is currently unclear. However, the Linn Parties' Chapter 11 process or any other such bankruptcies may result in reduced production of reserves and decreased distributions to unitholders.

(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 original name of the 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

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.

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.


ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period ended September 30, 2016
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to


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)


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

	2016		2015

July	$	0.0644	$	0.0614
August		0.0413		0.0572
September		0.0594		0.0681

	$	0.1651	$	0.1867


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