Mesa Royalty Trust 10Q 2016 Q2 Quarterly report

QuickLinks -- Click here to rapidly navigate through this document

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 June 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

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, 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.


Large accelerated filer o		Accelerated filer o		Non-accelerated filer ý (Do not check if a smaller reporting company)		Smaller reporting company 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 August 12, 2016—1,863,590 Units of Beneficial Interest were outstanding in Mesa Royalty Trust.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

MESA ROYALTY TRUST

STATEMENTS OF DISTRIBUTABLE INCOME

(Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,

	2016			2015		2016			2015
Royalty income	$	182,988		$	455,838	$	387,633		$	1,245,928
Interest income		450			25		707			25
General and administrative income (expense)		(38,303	)		23,840		(86,983	)		(141,091	)

Distributable income	$	145,135		$	479,703	$	301,357		$	1,104,862



Distributable income per unit	$	0.0779		$	0.2574	$	0.1617		$	0.5929



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

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

	June 30, 2016			December 31, 2015

	(Unaudited)
ASSETS
Cash and short-term investments	$	1,145,135		$	1,408,413
Net overriding royalty interest in oil and gas properties		42,498,034			42,498,034
Accumulated amortization		(39,850,755	)		(39,763,316	)

Total assets	$	3,792,414		$	4,143,131



LIABILITIES AND TRUST CORPUS
Distributions payable	$	145,846		$	415,151
Trust corpus (1,863,590 units of beneficial interest authorized, issued and outstanding)		3,646,568			3,727,980

Total liabilities and trust corpus	$	3,792,414		$	4,143,131

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

MESA ROYALTY TRUST

STATEMENTS OF CHANGES IN TRUST CORPUS

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,

	2016			2015			2016			2015
Trust corpus, beginning of period	$	3,693,641		$	3,805,922		$	3,727,980		$	4,013,833
Distributable income		145,135			479,703			301,357			1,104,862
Distributions to unitholders		(145,846	)		(416,521	)		(295,330	)		(1,159,298	)
Amortization of net overriding royalty interest		(46,362	)		(64,445	)		(87,439	)		(154,738	)

Trust corpus, end of period	$	3,646,568		$	3,804,659		$	3,646,568		$	3,804,659

(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

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:

(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;

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 1—Trust Organization and Provisions (Continued)

(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 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, ConocoPhillips and BP (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.

As of June 30, 2016, there were $812 of unreimbursed expenses. The Trust anticipated receipt of these expense reimbursements by month-end when it published its June distribution press release on June 16, 2016, and included these amounts in distributions payable and distributable income per unit as of June 30, 2016. 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 June 30, 2016, the Trustee decreased the reserve for future unknown contingent liabilities and expenses by the amount of expected expense reimbursement cash receipts of $812 and increased the reserve for future unknown contingent liabilities and expenses for a prior period expense refund received from a vendor in the amount of $101. For the six months ended June 30, 2016, the Trustee increased the reserve for future unknown contingent liabilities and expenses by (i) the amounts received during the first quarter of 2016 related to expense reimbursement cash receipts for previous periods totaling $6,738 and (ii) a prior period expense refund received from a vendor in the amount of $101 during the second quarter of 2016. The Trustee decreased the reserve for future unknown contingent liabilities and expenses by the amount of expected expense reimbursement cash receipts of $812. As of June 30, 2016, the reserve for unknown contingent liabilities and expenses was $999,289 and is included in cash and short term investments. The Trust has subsequently received $812 of the expected expense reimbursement cash receipts as of July 5, 2016, which has increased the reserve for unknown contingent liabilities and expenses. The Trustee reserves the right to determine whether or not to release cash reserves in future periods with respect to any unreimbursed expenses.

The Trustee was due $118,750 for its services for the quarter ended June 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 June 30,

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 1—Trust Organization and Provisions (Continued)

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 $38,191 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 June 30, 2016, the Trustee's fees were $118,750 and such reimbursements totaled $95,897. For year to date June 30, 2016, the Trustee's fees were $216,576 and such reimbursements totaled $191,794. For the quarter ended June 30, 2015 and the six months ended June 30, 2015, the Trustee's fees were $108,388 and $216,676, respectively. Reimbursements received for the quarter ended June 30, 2015 and the six months ended June 30, 2015 were $95,988 and $191,888, 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. 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.

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

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2—Basis of Presentation (Continued)

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.

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;

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

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

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

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

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

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, 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.

Note 4—Income Tax Matters

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.

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 5—Excess Production Costs

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 June 30, 2016 and December 31, 2015, there were $11,542 and $78,591, respectively, of excess production costs. Excess production costs in the amount of $2,093 and $1,107 as of June 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 $9,449 as of June 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 June 30, 2016 and December 31, 2015, respectively. Excess production costs related to the San Juan Basin—Colorado properties operated by Red Willow were approximately $9,449 and $5,148 as of June 30, 2016 and December 31, 2015, respectively.

Note 6—Distributable Income Per Unit

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 June 30, 2016, the Trustee decreased the reserve for future unknown contingent liabilities and expenses by the amount of expected expense reimbursement cash receipts of $812 and increased the reserve for future unknown contingent liabilities and expenses for a prior period expense refund received from a vendor in the amount of $101. For the six months ended June 30, 2016, the Trustee increased the reserve for future unknown contingent liabilities and expenses by the amounts received during the first quarter of 2016 related to expense reimbursement cash receipts for previous periods totaling $6,738 and a prior period expense refund received from a vendor in the amount of $101 during the second quarter of 2016. The Trustee decreased the reserve for future unknown contingent liabilities and expenses by the amount of

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 6—Distributable Income Per Unit (Continued)

expected expense reimbursement cash receipts of $812. The effect on distributable income per unit is as follows:

	Three Months Ended June 30,						Six Months Ended June 30,

	2016			2015			2016			2015
Distributable Income Before Reserve for Contingent Liabilities and Expenses	$	145,135		$	479,703		$	301,357		$	1,104,862
Increase in Reserve for Contingent Liabilities and Expenses (See Note 1)		(101	)		(115,885	)		(6,839	)		—
Withdrawal from Reserve for Contingent Liabilities and Expenses (See Note 1)		812			52,703			812			54,436

Distributable income Available for Distribution	$	145,846		$	416,521		$	295,330		$	1,159,298



Distributable income Available for Distribution per unit	$	0.0783		$	0.2235		$	0.1585		$	0.6221



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.

Note Regarding Forward-Looking Statements

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.

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 June 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)	$	492,476		$	172,321		$	10,289		$	825,298		$	288,786		$	18,145
Less the Trust's proportionate share of:
Capital costs recovered		(5,551	)		(2,096	)		(144	)		(19,993	)		(9,274	)		(711	)
Operating costs		(338,598	)		(123,027	)		(6,764	)		(509,111	)		(145,752	)		(8,357	)

Net proceeds(2)	$	148,327		$	47,199		$	3,381		$	296,194		$	133,760		$	9,077



Royalty income(2)	$	132,244		$	47,326		$	3,418		$	313,001		$	133,760		$	9,077



Average sales price	$	1.45		$	10.63		$	24.56		$	2.44		$	14.83		$	37.41



Average production costs(3)	$	3.77		$	28.09		$	49.64		$	4.13		$	17.19		$	37.38



	(Mcf)			(Bbls)			(Bbls)			(Mcf)			(Bbls)			(Bbls)
Net production volumes attributable to the Royalty paid(4)		91,276			4,454			139			128,107			9,018			243

	Six Months Ended June 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)	$	1,146,263		$	348,043		$	20,815		$	1,934,935		$	590,764		$	38,340
Less the Trust's proportionate share of:
Capital costs recovered		(15,838	)		(6,025	)		(504	)		(50,115	)		(19,906	)		(1,817	)
Operating costs		(782,157	)		(242,764	)		(13,149	)		(1,020,947	)		(259,969	)		(16,201	)

Net proceeds(2)	$	348,268		$	99,254		$	7,161		$	863,873		$	310,899		$	20,322



Royalty income(2)	$	280,839		$	99,542		$	7,253		$	914,039		$	310,899		$	20,322



Average sales price	$	1.67		$	10.67		$	25.63		$	2.91		$	13.98		$	41.00



Average production costs(3)	$	4.76		$	26.66		$	48.24		$	3.41		$	12.59		$	36.36



	(Mcf)			(Bbls)			(Bbls)			(Mcf)			(Bbls)			(Bbls)
Net production volumes attributable to the Royalty paid(4)		167,814			9,330			283			313,808			22,238			496

(1): Gross Proceeds from natural gas liquids attributable to the Hugoton and San Juan Basin Properties are net of a volumetric in-kind processing fee retained by Linn and ConocoPhillips, respectively.

(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 $2,093 and $478 as of June 30, 2016 and June 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 $490 and $986 for the three and six months ended June 30, 2016, respectively.

Excess production costs related to the San Juan Basin—Colorado properties operated by BP and Red Willow were approximately $0 and $9,449, respectively as of June 30, 2016. Excess production costs related to the San Juan Basin—Colorado properties operated by BP and Red Willow were approximately $48,816 and $1,350, respectively as of June 30, 2015.

Excess production costs related to the San Juan Basin—Colorado properties operated by BP and Red Willow were approximately $0 and $3,368, respectively for the three months ended June 30, 2016 and $0 and $4,301, respectively for the six months ended June 30, 2016. The trust recovered prior period excess production costs of $19,776 and $72,336 related to the San Juan Basin—Colorado properties operated by BP during the three and six months ended June 30, 2016, respectively.

Excess production costs related to the San Juan Basin—Colorado properties operated by BP and Red Willow were approximately $15,547 and $1,350, respectively for the three months ended June 30, 2015 and $48,816 and $1,350, respectively for the six months ended June 30, 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.

Three Months Ended June 30, 2016 and 2015

Financial Review

	Three Months Ended June 30,

	2016			2015
Royalty income	$	182,988		$	455,838
Interest income		450			25
General and administrative expense		(38,303	)		23,840

Distributable income	$	145,135		$	479,703



Distributable income per unit	$	0.0779		$	0.2574



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

The Trust's Royalty income was $182,988 in the second quarter of 2016, a decrease of approximately 60% as compared to $455,838 in the second quarter of 2015, primarily as a result of

lower natural gas, natural gas liquids and oil and condensate prices, and reduced production of natural gas, natural gas liquids and oil and condensate in the second quarter of 2016 as compared to the second quarter of 2015, offset in part by decreased capital expenditures and operating costs in the second quarter of 2016 compared to the second 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 June 30, 2016 was $145,846, representing $0.0783 per unit, compared to 416,521, representing $0.2235 per unit, for the quarter ended June 30, 2015. Based on 1,863,590 units outstanding for the quarters ended June 30, 2016 and 2015, respectively, the per unit distributions were as follows:

	2016		2015

April	$	0.0203	$	0.0780
May		0.0221		0.0573
June		0.0359		0.0882

	$	0.0783	$	0.2235

As of June 30, 2016, there were $812 of unreimbursed expenses. The Trust anticipated receipt of these expense reimbursements by month-end when it published its June distribution press releases on June 18, 2016, and included these amounts in distributions payable and distributable income per unit as of June 30, 2016. 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 June 30, 2016, the Trustee decreased the reserve for future unknown contingent liabilities and expenses by the amount of expected expense reimbursement cash receipts of $812 and increased the reserve for future unknown contingent liabilities and expenses for a prior period expense refund received from a vendor in the amount of $101. For the six months ended June 30, 2016, the Trustee increased the reserve for future unknown contingent liabilities and expenses by (i) the amounts received during the first quarter of 2016 related to expense reimbursement cash receipts for previous periods totaling $6,738 and (ii) a prior period expense refund received from a vendor in the amount of $101 during the second quarter of 2016. The Trustee decreased the reserve for future unknown contingent liabilities and expenses by the amount of expected expense reimbursement cash receipts of $812. As of June 30, 2016, the reserve for unknown contingent liabilities and expenses was $999,289 and is included in cash and short term investments. The Trust has subsequently received $812 of the expected expense reimbursement cash receipts as of July 5, 2016, which has increased the reserve for unknown contingent liabilities and expenses. The Trustee reserves the right to determine whether or not to release cash reserves in future periods with respect to any unreimbursed expenses.

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 $38,191 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 June 30, 2016, the Trustee's fees were $118,750 and such reimbursements totaled $95,897. For year to date June 30, 2016, the Trustee's fees were $216,576 and such reimbursements totaled $191,794. For the quarter ended June 30, 2015, the Trustee's fees were $108,388. Reimbursements received for the quarter ended June 30, 2015 were $95,988.

Operational Review

Hugoton Field

Natural gas and natural gas liquids production attributable to the Royalty from the Hugoton field accounted for approximately 36% of the Royalty income of the Trust during the second 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 June 30, 2016 as compared to the three months ended June 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 decreased to $65,948 in the second quarter of 2016 from $202,655 in the second quarter of 2015 primarily due to decreases in natural gas and natural gas liquids prices, reduced natural gas and natural gas liquids volumes and increased operating costs from the Hugoton Royalty Properties, offset in part by a reduction in capital expenditures in the second quarter of 2016 compared to the second quarter of 2015. The average price received in the

second quarter of 2016 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $2.60 per Mcf and $9.83 per barrel, respectively, as compared to $3.31 per Mcf and $14.10 per barrel, respectively, in the second quarter of 2015. Net production of natural gas attributable to the Hugoton Royalty decreased to 19,291 Mcf in the second quarter of 2016 from 46,037 Mcf in the second quarter of 2015. Net production of natural gas liquids attributable to the Hugoton Royalty decreased to 1,606 barrels in the second quarter of 2016 from 3,565 barrels in the second quarter of 2015. Actual production volumes from the Hugoton properties decreased to 90,178 Mcf of natural gas and to 7,514 barrels of natural gas liquids in the second quarter of 2016 as compared to 101,439 Mcf of natural gas and to 8,175 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 $2,539 in the second quarter of 2016, as compared to $8,684 in the second quarter of 2015. Operating costs were $239,298 in the second quarter of 2016 as compared to $239,001 in the second quarter of 2015.

San Juan Basin

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 $86,981 during the second quarter of 2016 as compared with Royalty income of $251,930 during the second quarter of 2015. This decrease in Royalty income was due primarily to a decrease in natural gas, natural gas liquids and oil and condensate prices and lower natural gas, natural gas liquids and oil and condensate production volumes for the second quarter of 2016 compared to the second quarter of 2015, offset in part by a reduction in capital expenditures and operating costs during the second quarter of 2016 compared to the second quarter of 2015. Net production attributable to the San Juan Basin Royalty Properties located in New Mexico was 43,356 Mcf of natural gas, 2,848 barrels of natural gas liquids and 139 barrels of oil and condensate in the second quarter of 2016, as compared to 81,273 Mcf of natural gas, 5,453 barrels of natural gas liquids and 243 barrels of oil and condensate in the second quarter of 2015. The average price received in the second 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 $1.19 per Mcf, $11.03 per barrel and $24.29 per barrel, respectively, compared to $1.96 per Mcf, $15.31 per barrel and $37.41 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 157,586 Mcf in the second quarter of 2016 from 173,454 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 11,907 barrels in the second quarter of 2016 from 13,745 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 421 barrels in the second quarter of 2016 from 485 barrels for the same period in 2015.

Capital expenditures on these properties were $5,252 in the second quarter of 2016, a decrease of approximately 75% as compared to $21,294 in the second quarter of 2015, primarily due to decreased spending on facilities in the second quarter of 2016 compared with the second quarter of 2015. Operating costs were $198,586 in the second quarter of 2016, a decrease of approximately 24% as compared to $259,858 in the second quarter of 2015. The decrease in operating costs was primarily the result of 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.

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 $30,060 during the second quarter of 2016, compared to $1,253 during the second 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 second quarter of 2016 compared to the second quarter of 2015 offset in part by a decrease in the average price received for natural gas in the second quarter of 2016 compared to the second quarter of 2015. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 28,629 Mcf of natural gas during the second quarter of 2016 with 797 Mcf of natural gas attributable to the Trust during the second quarter of 2015. The average price received in the second quarter of 2016 for natural gas sold from the San Juan Basin Colorado Properties was $1.02 per Mcf, as compared to average price of $1.57 per Mcf for the second quarter of 2015. Actual production volumes attributable to the San Juan Basin Colorado Properties increased to 75,401 Mcf of natural gas in the second quarter of 2016 from 77,096 Mcf of natural gas for the same period in 2015.

Operating costs on these properties were $30,505 in the second quarter of 2016 as compared to $164,361 in the second quarter of 2015. The decrease in operating costs was due primarily to repairs and recompletions in 2015 compared with 2016.

Six Months Ended June 30, 2016 and 2015

Financial Review

	Six Months Ended June 30,

	2016			2015
Royalty income	$	387,633		$	1,245,928
Interest income		707			25
General and administrative expense		(86,983	)		(141,091	)

Distributable income	$	301,357		$	1,104,862



Distributable income per unit	$	0.1617		$	0.5929



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

The Trust's Royalty income was $387,633 for the six months ended June 30, 2016, a decrease of approximately 69% as compared to $1,245,928 for the six months ended June 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 six months of 2016 as compared to the first six 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 six months ended June 30, 2016 was $295,330, representing $0.1585 per unit, compared to 1,159,298, representing $0.6221 per unit, for the six months ended June 30, 2015.

As of June 30, 2016, there were $812 of unreimbursed expenses. The Trust anticipated receipt of these expense reimbursements by month-end when it published its June distribution press releases on June 18, 2016, and included these amounts in distributions payable and distributable income per unit as of June 30, 2016. 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 June 30, 2016, the Trustee decreased the reserve for future unknown contingent liabilities and expenses by the amount of expected expense reimbursement cash receipts of $812 and increased the reserve for future unknown contingent liabilities and expenses for a prior period expense refund received from a vendor in the amount of $101. For the six months ended June 30, 2016, the Trustee increased the reserve for future unknown contingent liabilities and expenses by (i) the amounts received during the first quarter of 2016 related to expense reimbursement cash receipts for previous periods totaling $6,738 and (ii) a prior period expense refund received from a vendor in the amount of $101 during the second quarter of 2016. The Trustee decreased the reserve for future unknown contingent liabilities and expenses by the amount of expected expense reimbursement cash receipts of $812. As of June 30, 2016, the reserve for unknown contingent liabilities and expenses was $999,289 and is included in cash and short term investments. The Trust has subsequently received $812 of the expected expense reimbursement cash receipts as of July 5, 2016, which has increased the reserve for unknown contingent liabilities and expenses.

As of June 30, 2015, there were $54,436 of unreimbursed expenses, including $1,733 from the quarter ended March 31, 2015. The Trust anticipated receipt of these expense reimbursements by month-end when it published its March and June distribution press releases on March 20, 2015 and June 17, 2015, respectively, and included these amounts in distributions payable and distributable income per unit as of March 31, 2015 and June 30, 2015. For the three months ended June 30, 2015, the Trustee decreased the reserve for future unknown contingent liabilities and expenses by the amount of expected expense reimbursement cash receipts of $52,703. Additionally, the Trustee increased the reserve for future unknown contingent liabilities and expenses by the amounts received during the second quarter of 2015 related to expense reimbursement cash receipts for previous periods totaling $115,885. As of June 30, 2015, the reserve for unknown contingent liabilities and expenses was $945,564 and was included in cash and short term investments. The Trust has subsequently received $49,825 of the expected expense reimbursement cash receipts as of August 14, 2015, which increased the reserve for unknown contingent liabilities and expenses.

The Trustee was due $237,500 for its services for the six months ended June 30, 2016. The Trust paid $216,576 of this amount to the Trustee, and $20,924 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 six months ended June 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 $38,191 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 six months ended June 30, 2016, such reimbursements totaled $191,794. For year to date June 30, 2016, such fees were $216,576. For the six months ended June 30, 2015, trustee fees were $216,676. Reimbursements received for the quarter ended June 30, 2015 were $191,888.

Operational Review

Hugoton Field

Natural gas and natural gas liquids revenue from the Hugoton field attributable to the Royalty accounted for approximately 37% of the Royalty income of the Trust during the six months ended June 30, 2016.

Royalty income attributable to the Hugoton Royalty Properties decreased to $145,073 for the six months ended June 30, 2016 from $576,957 for the same period in 2015 primarily due to lower prices for natural gas and natural gas liquids, lower natural gas and natural gas liquids production volumes and increased operating costs, offset in part by reduced capital expenditures from the Hugoton Royalty Properties in the first six months of 2016 compared to the first six months of 2015. The average price received in the first six months of 2016 for natural gas and natural gas liquids sold from the Hugoton field was $2.77 per Mcf and $9.95 per barrel, respectively, compared to $3.75 per Mcf and $15.33 per barrel, respectively, during the same period in 2015. Net production attributable to the Hugoton Royalty Properties decreased to 40,616 Mcf of natural gas and 3,273 barrels of natural gas liquids for the six months ended June 30, 2016 as compared to 118,017 Mcf of natural gas and 8,722 barrels of

natural gas liquids for the six months ended June 30, 2015. Actual production volumes attributable to the Hugoton Royalty Properties decreased to 185,769 Mcf of natural gas and 14,836 barrels of natural gas liquids in the six months ended June 30, 2016 as compared to 207,898 Mcf of natural gas and 16,208 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 six months ended June 30, 2016, a decrease of approximately 74% as compared to $10,264 during the six months ended June 30, 2015. Operating costs were $514,386 during the six months ended June 30, 2016, an increase of approximately 16% as compared to $441,918 during the six months ended June 30, 2015. The increase in operating costs was due primarily to increased labor and supervision costs.

San Juan Basin

Royalty income from the San Juan Basin—New Mexico was $212,501 for the first six months of 2016 compared to $651,422 for the first six months of 2015. The decrease in Royalty income was due primarily to lower natural gas, 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 six months of 2016 from the San Juan Basin properties compared to the same period in 2015. The average price received in the first six 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 $1.39 per Mcf, $11.01 per barrel and $25.30 per barrel, respectively, compared to $2.42 per Mcf, $13.11 per barrel and $41.01 per barrel during the same period in 2015. Net production attributable to the San Juan Basin Royalty located in New Mexico was 98,766 Mcf of natural gas, 6,057 barrels of natural gas liquids and 283 barrels of oil and condensate for the six months ended June 30, 2016 as compared to 187,834 Mcf of natural gas, 13,516 barrels of natural gas liquids and 496 barrels of oil and condensate for the six months ended June 30, 2015. Actual production volumes attributable to the San Juan Basin Royalty Properties decreased to 316,105 Mcf of natural gas, 24,430 barrels of natural gas liquids and 809 barrels of oil and condensate in the six months ended June 30, 2016 as compared to 359,470 Mcf of natural gas, 28,746 barrels of natural gas liquids and 935 barrels of oil and condensate for the same period in 2015.

San Juan Basin—New Mexico capital expenditures were $19,737 during the six months ended June 30, 2016, a decrease of approximately 68% as compared to $61,574 during the six months ended June 30, 2015. This decrease is due to decreased spending on facilities during the six months ended June 30, 2016 when compared to the six months ended June 30, 2015. Operating costs were $425,285 during the six months ended June 30, 2016, a decrease of approximately 21% as compared to $536,726 during the six months ended June 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 $30,060 for the six months ended June 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 six months ended June 30, 2016 compared to the same period in 2015. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 28,432 Mcf of natural gas during the six months ended June 30, 2016 with 7,958 Mcf of

natural gas attributable to the Trust during the same period in 2015. The average price received for the six months ended June 30, 2016 for natural gas sold from the San Juan Basin Colorado Properties was $1.05 per Mcf, compared to $2.21 per Mcf received during the same period in 2015. Actual production volumes attributable to the San Juan Basin—Colorado Royalty Properties increased to 186,547 Mcf of natural gas for the six months ended June 30, 2016 as compared to 129,222 Mcf of natural gas for the same period in 2015.

Operating costs on these properties were $98,400 for the six months ended June 30, 2016 a decrease of approximately 69% as compared to $318,473 in the same period in 2015 due primarily to repairs and recompletions in the first six months of 2015 compared with 2016.

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 the Gulf of Mexico;
•: 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 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.

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, 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.

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, 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.

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. 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.

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 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

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 CONLEY Elaina Conley Vice President & Trust Officer

Date: August 12, 2016

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.

QuickLinks

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. Management'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

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. senior Avg

Mesa Royalty Trust (MTR) 10-Q2016 Q2 Quarterly report

Content analysis