Mesa Royalty Trust 10Q 2011 Q2 Quarterly report

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

FORM 10-Q


ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period ended June 30, 2011
or
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 919 Congress Avenue Austin, Texas (Address of Principal Executive Offices)		78701 (Zip Code)

1-800-852-1422
(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 ý		Non-accelerated filer o (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 8, 2011—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,

		2011			2010			2011			2010
Royalty income		$	1,503,570		$	2,043,341		$	2,942,774		$	3,813,900
Interest income			24			31			24			120
General and administrative expense			(43,525	)		(58,632	)		(89,390	)		(99,041	)

	Distributable income	$	1,460,069		$	1,984,740		$	2,853,408		$	3,714,979

	Distributable income per unit	$	.7835		$	1.0650		$	1.5311		$	1.9934

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

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

		June 30, 2011			December 31, 2010

		(Unaudited)
ASSETS
Cash and short-term investments		$	1,710,069		$	1,390,833
Net overriding royalty interest in oil and gas properties			42,498,034			42,498,034
Accumulated amortization			(37,130,434	)		(36,940,287	)

	Total assets	$	7,077,669		$	6,948,580

LIABILITIES AND TRUST CORPUS
Distributions payable		$	1,210,069		$	1,390,833
Trust corpus (1,863,590 units of beneficial interest authorized, issued and outstanding)			5,867,600			5,557,747

	Total liabilities and trust corpus	$	7,077,669		$	6,948,580

(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,

		2011			2010			2011			2010
Trust corpus, beginning of period		$	5,710,498		$	6,164,213		$	5,557,747		$	6,386,000
	Distributable income		1,460,069			1,984,740			2,853,408			3,714,979
	Distributions to unitholders		(1,210,069	)		(1,984,740	)		(2,353,408	)		(3,714,979	)
	Amortization of net overriding royalty interest		(92,898	)		(305,170	)		(190,147	)		(526,957	)

Trust corpus, end of period		$	5,867,600		$	5,859,043		$	5,867,600		$	5,859,043

(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 have been operated by PNR. 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, PNR refers to the 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 JPMorgan 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 (the "Trust Indenture") provide, among other things, that:

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

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

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

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 1—Trust Organization and Provisions (Continued)

(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) PNR, 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.

Effective January 1, 2011, the Trustee is withholding $83,333 of cash per month for future unknown contingent liabilities and expenses in accordance with the Trust Indenture. The cash withholding will be established through the withholding of cash received during 2011 of approximately $83,333 per monthly distribution amount, or up to $250,000 per quarter, until the cash withholding is $1.0 million. At June 30, 2011, the Trust has withheld a total of $500,000 which is included in cash and short term investments.

Note 2—Basis of Presentation

The accompanying unaudited financial information has been prepared by the Trustee in accordance with the instructions to Form 10-Q. The preparation of the financial statements requires estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of income and expenses during the reporting period. Actual results could differ from those estimates. The Trustee believes such information includes all the disclosures necessary to make the information presented not misleading. The information furnished reflects all adjustments which are, in the opinion of the Trustee, necessary for a fair presentation of the results for the interim periods presented. The financial information should be read in conjunction with the financial statements and notes thereto included in the Trust's Annual Report on Form 10-K for the year ended December 31, 2010. 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.

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 2—Basis of Presentation (Continued)

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.

Note 3—Legal Proceedings

There are no pending legal proceedings to which the Trust is a named party. The Trustee has been advised by each of PNR, ConocoPhillips and BP Amoco 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.

MESA ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS (Continued)

(Unaudited)

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.

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. Bank of New York Mellon Trust Company, N.A., 919 Congress Avenue, Austin, Texas 78701, telephone number 1-800-852-1422, 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.

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. 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, 2011 and December 31, 2010, there were no excess production costs on the Trust Properties.

Note 6—Tax Assessment

PNR has advised the Trustee that it received a proposed assessment from the Kansas Department of Revenue on September 10, 2009, for additional tax, penalty and interest of approximately $4.1 million resulting primarily from the settlement of the lawsuitJohn Steven Alford and Robert Larrabee, individually and on behalf of a Plaintiff Class v. Pioneer Natural Resources USA, Inc. in early 2007. The portion of the tax assessment net to the Trust is approximately $181,000, which could adversely affect Trust distributions. PNR has submitted a written response objecting to the proposed assessment. On March 25, 2010, The Kansas Department of Revenue issued a final assessment, which included additional interest and penalties, increasing the amount assessed to approximately $4.5 million. The portion of the tax assessment net to the Trust is approximately $197,000, which could adversely affect Trust distributions. On June 24, 2011, the hearing examiner of the Department of Revenue upheld the earlier assessment. PNR has filed an appeal to the Court of Tax Appeals in Kansas. No assurance can be made that any objections or disputed items raised by PNR will be successful.

PNR has also advised the Trustee as of September 30, 2010, it filed approximately $3.0 million of severance tax refunds with the state of Kansas, the estimated share of the refund due and already paid to the Trust is approximately $167,000. There can be no assurance that the state will agree to PNR's position which in turn could adversely affect Trust distributions in the future.

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, 2010. 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, 2010, 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,

		2011						2010
		Natural Gas			Oil, Condensate and Natural Gas Liquids			Natural Gas			Oil, Condensate and Natural Gas Liquids
The Trust's proportionate share of Gross Proceeds(1)			1,290,811			1,061,626			1,731,595			1,018,886
Less the Trust's proportionate share of:
	Capital costs recovered		(96,358	)		(83,678	)		(52,898	)		(44,897	)
	Operating costs		(374,486	)		(294,345	)		(379,060	)		(230,285	)

Net Proceeds			819,967			683,603			1,299,637			743,704

Royalty income(2)			819,967			683,603			1,299,637			743,704

Average sales price		$	3.38		$	41.01		$	4.43		$	47.80

		(Mcf)			(Bbls)			(Mcf)			(Bbls)
Net production volumes attributable to the Royalty paid(3)			242,813			16,668			293,091			15,558

		Six Months Ended June 30,

		2011						2010
		Natural Gas			Condensate and Natural Gas Liquids			Natural Gas			Oil, Condensate and Natural Gas Liquids
The Trust's proportionate share of Gross Proceeds(1)			2,547,009			2,096,063			3,260,283			2,095,958
Less the Trust's proportionate share of:
	Capital costs recovered		(155,761	)		(139,249	)		(109,893	)		(103,245	)
	Operating costs		(760,731	)		(585,112	)		(803,919	)		(504,989	)

Net Proceeds			1,630,517			1,371,702			2,346,471			1,487,724

Royalty income(2)			1,630,517			1,371,702			2,326,176			1,487,724

Average sales price		$	3.32		$	38.92		$	4.11		$	41.41

		(Mcf)			(Bbls)			(Mcf)			(Bbls)
Net production volumes attributable to the Royalty paid(3)			490,707			35,242			565,328			35,927

(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 PNR and ConocoPhillips, respectively.
(2): Due to an adjustment of $60,000 to royalty income at December 31, 2010, the natural gas royalty income and oil condensate and natural gas liquids royalty income may not agree to the six months ended June 30, 2011 royalty income.
(3): Net production volumes attributable to the Royalty are determined by dividing Royalty income by the average sales price received.

Three Months Ended June 30, 2011 and 2010

Financial Review

	Three Months Ended June 30,

	2011			2010
Royalty income	$	1,503,570		$	2,043,341
Interest income		24			31
General and administrative expense		(43,525	)		(58,632	)

Distributable income	$	1,460,069		$	1,984,740

Distributable income per unit	$	.7835		$	1.0650

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

The Trust's Royalty income was $1,503,570 in the second quarter of 2011, a decrease of approximately 26% as compared to $2,043,341 in the second quarter of 2010, primarily as a result of

lower natural gas prices and lower natural gas production volumes in the second quarter of 2011 as compared to the second quarter of 2010.

The distributable income 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). Trust administration expenses are deducted in the computation of distributable income. Distributions are then calculated by deducting the amount to be withheld in reserve. Distributable income for the quarter ended June 30, 2011 was $1,460,069, representing $.7835 per unit. The amount used to calculate the distribution totaled $1,210,069, representing $.6493 per unit, compared to $1,984,740, representing $1.0650 per unit, for the quarter ended June 30, 2010. Based on 1,863,590 units outstanding for the quarters ended June 30, 2011 and 2010, respectively, the per unit distributions were as follows:

	2011		2010

April	$	.2112	$	.4046
May		.2181		.3422
June		.2200		.3182

	$	.6493	$	1.0650

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 2011.

PNR 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 the first six months of 2011, the primary purchaser was Oneok Gas Marketing, Inc. PNR has advised the Trust that it expects to continue to market gas production from the Hugoton field under short-term and multi-month contracts. As discussed below, overall market prices received for natural gas from the Hugoton Royalty Properties were lower in the second quarter of 2011 compared to the second quarter of 2010.

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. This contract has renewed on a year-to-year basis being effective June 1, 2001. The contract is renewed a year in advance, so PNR extended the contract to June 1, 2012. Pursuant to the Gas Transportation Agreement, WRI agreed to compress and transport up to 160 MMcf per day of gas and redeliver such gas to PNR at the inlet of PNR's Satanta Plant. PNR agreed to pay WRI a fee of

$0.06 per Mcf escalating 4% annually as of June 1, 1996. This Gas Transportation Agreement was assigned to Kansas Gas Service.

Royalty income attributable to the Hugoton Royalty decreased to $536,300 in the second quarter of 2011, from $970,715 in the second quarter of 2010 primarily due to decreases in natural gas prices and production from the Hugoton Royalty Properties, and increased capital expenditures and operating costs, offset in part by higher natural gas liquids prices. The average price received in the second quarter of 2011 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $4.34 per Mcf and $49.30 per barrel, respectively, as compared to $5.59 per Mcf and $47.43 per barrel, respectively, in the second quarter of 2010. Net production of natural gas attributable to the Hugoton Royalty decreased to 80,359 Mcf in the second quarter of 2011 from 116,652 Mcf in the second quarter of 2010. Net production of natural gas liquids attributable to the Hugoton Royalty decreased from 6,718 barrels in the second quarter of 2010 to 3,804 barrels in the second quarter of 2011. Actual production volumes from the Hugoton properties decreased to 137,221 Mcf of natural gas and 6,384 barrels of natural gas liquids in the second quarter of 2011 as compared to 142,601 Mcf of natural gas and 8,203 barrels of natural gas liquids for the same period in 2010.

The Hugoton capital expenditures were $68,017 in the second quarter of 2011, an increase of approximately 2,143% as compared to $3,032 in the second quarter of 2010. The increase in capital expenditures was primarily due to increased drilling activity. Operating costs were $305,496 in the second quarter of 2011, an increase of approximately 44% as compared to $212,260 in the second quarter of 2010. The increase in operating costs was primarily due to the lower severance tax refund due to the lower gas price received.

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. The Royalty income from the San Juan Basin Royalty Properties located in the state of New Mexico was $867,949 during the second quarter of 2011 as compared with Royalty income of $942,537 in the second quarter of 2010. The decrease in Royalty income was due primarily to reduction in natural gas production volumes and decline in natural gas price for the second quarter of 2011 compared to the second quarter of 2010. Net production attributable to the San Juan Basin Royalty located in New Mexico was 129,091 Mcf of natural gas and 12,864 barrels of natural gas liquids in the second quarter of 2011, as compared to 145,372 Mcf of natural gas and 11,161 barrels of natural gas liquids in the second quarter of 2010. The average price received in the second quarter of 2011 for natural gas and natural gas liquids sold from the San Juan Basin Royalty Properties located in the state of New Mexico was $2.90 per Mcf and $35.07 per barrel, respectively, compared to $3.74 per Mcf and $39.63 per barrel during the same period in 2010. Actual production volumes of natural gas attributable to the San Juan Basin properties located in the state of New Mexico decreased to 196,134 Mcf in the second quarter of 2011 as compared to 211,175 Mcf of natural gas for the same period in 2010. Actual production volumes of natural gas liquids attributable to the San Juan Basin properties located in the state of New Mexico increased to 21,304 barrels in the second quarter of 2011 compared to 16,460 barrels for the same period in 2010.

Capital expenditures on these properties were $112,012 in the second quarter of 2011, an increase of approximately 18% as compared to $94,763 in the second quarter of 2010. Operating costs were

$329,268 in the second quarter 2011, a decrease of approximately 7% as compared to $352,855 in the second quarter of 2010.

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 $96,743 during the second quarter of 2011, compared to $130,089 during the second quarter of 2010. The decrease in Royalty income was due primarily to lower gas prices in the second quarter of 2011 compared to the second quarter of 2010. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 33,363 Mcf of natural gas during the second quarter of 2011with 31,067 Mcf of natural gas attributable to the Trust during the second quarter of 2010. The average price received in the second quarter of 2011 for natural gas sold from the San Juan Basin Colorado Properties was $2.90, as compared to average price of $4.19 for the second quarter of 2010. Actual production volumes attributable to the San Juan Basin Colorado Properties decreased to 43,863 Mcf of natural gas in the second quarter of 2011 as compared to 45,004 Mcf of natural gas for the same period in 2010. Royalty income reported from BP is net of pre-main line production costs. These costs were charged to the Trust in error and as a result the Royalty income for previous periods was reduced. Because Royalty income recorded for a month is the amount computed and paid by BP, the additional Royalties, if any, will not be recorded until received by the Trust.

Operating costs on these properties were $30,464 in the second quarter of 2011, a decrease of approximately 31% as compared to $44,230 in the second quarter of 2010.

Six Months Ended June 30, 2011 and 2010

Financial Review

	Six Months Ended June 30,

	2011			2010
Royalty income	$	2,942,774		$	3,813,900
Interest income		24			120
General and administrative expense		(89,390	)		(99,041	)

Distributable income	$	2,853,408		$	3,714,979

Distributable income per unit	$	1.5311		$	1.9934

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

The Trust's Royalty income was $2,942,774 for the six months ended June 30, 2011, a decrease of approximately 23% as compared to $3,813,900 for the six months ended June 30, 2010, primarily as a result of lower natural gas prices and lower natural gas and NGL production volumes in the first six months of 2011 as compared to the first six months of 2010.

income for the six months ended June 30, 2011 was $2,353,408, representing $1.2628 per unit, compared to $3,714,979, representing $1.9934 per unit, for the six months ended June 30, 2010.

Operation Review

Hugoton Field

Natural gas and natural gas liquids revenue from the Hugoton field attributable to the Royalty accounted for approximately 38% of the Royalty income of the Trust during the six months ended June 30, 2011.

Royalty income attributable to the Hugoton Royalty Properties decreased to $1,144,989 for the six months ended June 30, 2011 from $1,659,367 for the same period in 2010 primarily due to lower prices for natural gas and increased capital and operating expenditures from the Hugoton Royalty Properties. The average price received in the first six months of 2011 for natural gas and natural gas liquids sold from the Hugoton field was $4.11 per Mcf and $48.35 per barrel, respectively, compared to $4.98 per Mcf and $45.53 per barrel, respectively, during the same period in 2010. Net production attributable to the Hugoton Royalty Properties decreased to 173,457 Mcf of natural gas and 8,937 barrels of natural gas liquids for the six months ended June 30, 2011 as compared to 218,629 Mcf of natural gas and 12,532 barrels of natural gas liquids for the six months ended June 30, 2010. Actual production volumes attributable to the Hugoton Royalty Properties decreased to 283,326 Mcf of natural gas and 14,250 barrels of natural gas liquids in the six months ended June 30, 2011 as compared to 288,464 Mcf of natural gas and 16,628 barrels of natural gas liquids for the same period in 2010. The decrease in production is a result of natural production decline.

The Hugoton capital expenditures were $99,794 during the six months ended June 30, 2011, an increase of approximately 2,138% as compared to $4,457 during the six months ended June 30, 2010. The increase in the capital expenditures was primarily due to increased drilling activity. Operating costs were $606,840 during the six months ended June 30, 2011, an increase of approximately 15% as compared to $528,539 during the six months ended June 30, 2010 primarily due to the severance tax refund filed with the state of Kansas and already paid to the Trust. See Note 6 above.

San Juan Basin

The Royalty income from the San Juan Basin Royalty Properties located in the state of New Mexico was $1,692,221 for the first six months of 2011 compared to $1,996,168 in the first six months of 2010. The decrease in Royalty income was due primarily to lower natural gas prices and lower production volumes in the first six months of 2011 from the San Juan Basin properties. The average price received in the six months ended June 30, 2011 for natural gas and natural gas liquids sold from the San Juan Basin Royalty Properties located in the state of New Mexico was $2.94 per Mcf and $43.90 per barrel, respectively, compared to $3.71 per Mcf and $39.39 per barrel, respectively, during the same period in 2010. Net production attributable to the San Juan Basin Royalty located in New

Mexico was 257,799 Mcf of natural gas and 26,305 barrels of natural gas liquids for the six months ended June 30, 2011 as compared to 292,503 Mcf of natural gas and 23,395 barrels of natural gas liquids for the six months ended June 30, 2010. Actual production volumes attributable to the San Juan Basin Royalty Properties decreased to 386,533 Mcf of natural gas and increased to 42,988 barrels of natural gas liquids in the six months ended June 30, 2011 as compared to 421,827 Mcf of natural gas and 33,999 barrels of natural gas liquids for the same period in 2010.

San Juan-New Mexico capital expenditures were $195,265 during the six months ended June 30, 2011, a decrease of approximately 6% as compared to $208,681 during the six months ended June 30, 2010. This decrease is due to less drilling activity during the six months ended June 30, 2011 when compared to the six months ended June 30, 2010. Operating costs were $645,032 during the six months ended June 30, 2011, a decrease of approximately 7% as compared to $699,071 during the six months ended June 30, 2010.

Royalty income from the San Juan Basin—Colorado Royalty Properties was $160,311 for the six months ended June 30, 2011, compared to $158,365 received during the same period in 2010. The increase in Royalty income was primarily the result of increase natural gas production offset in part by lower natural gas prices and increased operating costs in the six months ended June 30, 2011 compared to the same period in 2010. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 59,452 Mcf of natural gas during the six months ended June 30, 2011 with 54,196 Mcf of natural gas attributable to the Trust during the same period in 2010. The average price received for the six months ended June 30, 2011 for natural gas sold from the San Juan Basin Colorado Properties was $2.69, compared to $3.23 received during the same period in 2010. Actual production volumes attributable to the San Juan Basin Colorado Properties increased to 91,787 Mcf of natural gas for the six months ended June 30, 2011 as compared to 72,863 Mcf of natural gas for the same period in 2010.

Operating costs on these properties were $86,948 for the six months ended June 30, 2011, an increase of approximately 7% as compared to $81,298 in the same period in 2010 due to a decrease in drilling charges.

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. Natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and the working interest owners. Factors that contribute to price fluctuation include, among others:

•: 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, regulation of green house 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, 2010 for a description of certain risks relating to these arrangements and reliance.

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 with respect to the annual reports on Form 10-K for December 31, 2007 and 2008, and with respect to the quarterly reports during 2008 and for the first two quarters of 2009, the Trust did not file its reports in a timely manner due to the Trustee's need to reconcile and verify ownership, calculations of the Trust's interest in proceeds and other information provided by working interest owners. This information was required by the reserve engineer to prepare the reserve report for the Trustee to present the required reserve information in the SEC reports, and for the Trustee to complete the Trust's financial statements, and a review of the basis for this information was needed prior to filing these reports. The source of this information is not within the control of the Trustee, and thus the initial information provided to the Trustee and the timely receipt of accurate information for the preparation of these reports was not within scope of the Trustee's disclosure controls and procedures. The Trustee's review of certain information and calculations by the working interest owners, along with an outside joint venture auditor, remains ongoing. 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, 2010 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.

Item 1A. Risk Factors.

There have not been any material changes from risk factors previously disclosed in Item 1A to Part 1 of the Trust's Annual Report on Form 10-K for the year ended December 31, 2010.

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/ MIKE ULRICH Mike Ulrich Vice President

Date: August 9, 2011

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

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

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

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. junior Avg

Mesa Royalty Trust (MTR) 10-Q2011 Q2 Quarterly report

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