Mesa Offshore Trust 10Q 2007 Q1 Quarterly report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007

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 1-8432

MESA OFFSHORE TRUST

(Exact name of Registrant as Specified in its Charter)

Texas		76-6004065
(State of Incorporation		(I.R.S. Employer
or Organization)		Identification No.)
JPMorgan Chase Bank, N.A., Trustee Institutional Trust Services 919 Congress Avenue Austin, Texas		78701
(Address of Principal Executive Offices)		(Zip Code)

1-800-852-1422 / 1-512-479-2562

(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 x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer o

Accelerated filer o

Non-accelerated filer x

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

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

As of May 15, 2007—71,980,216 Units of Beneficial Interest were outstanding in Mesa Offshore Trust.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

MESA OFFSHORE TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
(Unaudited)

	Three Months Ended March 31,
	2007			2006
Royalty income	$	—		$	40,765
Interest income	5,080			5,188
General and administrative	(5,080		)	(45,953		)
Distributable income	$	—		$	—
Distributable income per unit	$	—		$	—

STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS

	March 31, 2007			December 31, 2006
	(Unaudited)
ASSETS
Cash and short-term investments	$	378,345		$	797,074
Interest receivable	—			2,970
Net overriding royalty interest in oil and gas properties	380,905,000			380,905,000
Accumulated amortization	(380,902,063		)	(380,902,063		)
Total assets	$	381,282		$	802,981
LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses	$	378,345		$	800,044
Trust corpus (71,980,216 units of beneficial interest authorized and outstanding)	2,937			2,937
Total liabilities and trust corpus	$	381,282		$	802,981

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

MESA OFFSHORE TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
(Unaudited)

	Three Months Ended March 31,
	2007			2006
Trust corpus, beginning of period		$	2,937		$	3,048
Distributable income		—			—
Distributions to unitholders		—			—
Amortization of net overriding royalty interest		—			(23		)
Trust corpus, end of period		$	2,937		$	3,025

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

MESA OFFSHORE TRUST
NOTES TO FINANCIAL STATEMENTS
(Unaudited)

Note 1—Trust Organization

The Mesa Offshore Trust (the “Trust”) was created effective December 1, 1982. On that date, Mesa Petroleum Co., predecessor to Mesa Limited Partnership, which was the predecessor to MESA Inc., transferred to the Trust a 99.99% interest in the Mesa Offshore Royalty Partnership (the “Partnership”). The Partnership was created to receive and hold a net overriding royalty interest (the “Royalty”) in ten producing and nonproducing oil and gas properties located in federal waters offshore Louisiana and Texas (the “Royalty Properties”). Mesa Inc. created the Royalty out of its working interest in the Royalty Properties and transferred it to the Partnership. Until August 7, 1997, MESA Inc. owned and operated its assets through Mesa Operating Co. (“Mesa”), the operator and the managing general partner of the Royalty Properties. 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) a wholly owned subsidiary of Pioneer (“PNR”) (collectively, the mergers are referred to herein as the “Merger”). Subsequent to the Merger, Pioneer owns and operates its assets through PNR and is also the managing general partner of the Partnership. As hereinafter used in this report, the term PNR generally refers to the operator of the Royalty Properties, unless otherwise indicated.

JPMorgan Chase Bank, N.A. is the Trustee (the “Trustee”) of the Trust. JPMorgan Chase & Co. and The Bank of New York Company (“BNY”) announced in April 2006 an agreement pursuant to which BNY would acquire a portion of JPMorgan Chase’s corporate trust business in exchange for BNY’s consumer small business and middle market banking business. This transaction did not include any transfer by JPMorgan Chase Bank, N.A. of its obligations as Trustee of this Trust.

Note 2—Status of the Trust, Legal Proceedings, and Timing of Liquidation

Status of the Trust

The Trust Indenture provides that the Trust will terminate if the total amount of cash per year received by the Trust falls below certain levels for each of three successive years. As a result of continued declines in production on Royalty Properties nearing the end of their estimated productive lives, Royalty income received by the Trust in 2002, 2003 and 2004 fell below the Termination Threshold prescribed by the Trust Indenture. The Trustee has previously taken steps to begin the process of liquidating the Trust. See “—Timing of Liquidation” below in this Note. The Trustee, which has no authority or discretionary control over the timing of expenditures, production or income on the Royalty Properties, has no discretion regarding the occurrence of the Termination Threshold or its consequences.

may also require bidders to identify themselves clearly and to represent or evidence sufficient financing in order to participate, as the Trustee expects payment will be required promptly after the close of bidding without any financing conditions. Accordingly, the auction may not be a “public” auction in the sense that it may not be open to anyone who does not satisfy these requirements. The Trustee is currently reviewing a potential online bidding process for participants in order to provide current public information on bidding to the marketplace. The Trustee will also determine a duration of bidding that it deems in the best interest of the Unitholders.

Legal Proceedings

On April 11, 2005, MOSH Holding, L.P. (“MHLP”) filed an Original Petition in the District Court of Travis County, Texas, 250th Judicial District, against Pioneer Natural Resources Company; Pioneer Natural Resources USA, Inc. (referred to below in this Note collectively with Pioneer Natural Resources Company, as “Pioneer”); Woodside Energy (USA), Inc. (“Woodside”); and JPMorgan, as Trustee of the Mesa Offshore Trust (Case No. GN501113) (the “Lawsuit”). The Lawsuit is currently before the 334th Judicial District of Harris Country, Texas (the “Court”). MHLP’s Original Petition alleges Pioneer and Woodside are liable for various actions, including (1) a wrongful farmout by Pioneer to Woodside of the Brazos A-39 Lease, (2) a wrongful delay by Pioneer in producing the Brazos A-39 Lease and the Midway #5 well drill thereon, (3) fraudulent accounting practices by Pioneer, (4) breach of fiduciary duty by Pioneer, (5) aiding and abetting breach of fiduciary duty by Woodside, (6) misapplication of Trust property by Pioneer, (7) conspiracy to misapply fiduciary property by Woodside and Pioneer, (8) common law fraud by Pioneer, (9) gross negligence by Pioneer, and (10) breach of the conveyance agreement by Pioneer. As described below, MHLP later added claims against the Trustee for (1) an accounting, and (2) breach of fiduciary duty. The remedies MHLP seeks include (a) reconstruing the Trust Indenture to determine that the Trust is not terminated because there has or should have been production that would have generated revenues to extend the life of the Trust, (b) requiring the Trustee to pursue certain claims, or to allow MHLP to pursue such claims, (c) setting aside any farmouts by Pioneer in which there have been conveyances to an alleged affiliate of Pioneer, (d) the removal of JPMorgan as Trustee, (e) the return or forfeiture of compensation to JPMorgan, (f) monetary damages against Pioneer, Woodside and JPMorgan, and (g) unspecified exemplary damages against all defendants.

MHLP’s Original Petition did not contain any claims against the Trustee, except to enjoin the Trustee from terminating the Trust during the pendency of the Lawsuit. In April 2005, the Trustee voluntarily entered into an agreement with MHLP whereby the Trustee would not terminate the Trust without first giving MHLP at least sixty days written notice. This agreement allowed MHLP time to obtain documents and discovery from Pioneer and Woodside, and allowed the Trustee time to investigate the claims asserted by MHLP against Pioneer and Woodside to determine if they had any merit and, most importantly, whether they would benefit the Trust. During the six month period between April and October 2005, the Trustee conducted an independent investigation including: numerous meetings and discussions with the parties; reviewing the relevant documents with the Trustee’s counsel; employing independent reservoir engineers to evaluate the reserves in which the Trust has an interest; engaging independent joint venture auditors to examine the accounting records of the operator, Pioneer, relating to revenues and expenses allocated to the Partnership’s interests; and obtaining from both MHLP and Pioneer their respective legal analyses of the challenged farmout.

Throughout 2005, the parties also anticipated that the Midway #5 well on the Brazos A-39 Lease that is the primary subject of the Lawsuit would go into production. Given the vast discrepancy between the reserves claimed by the MHLP and those projected by Pioneer for the Midway #5 well, actual production results would significantly impact the Trustee’s assessment of whether the Trust was better off with the cost-free override created by the Pioneer/Woodside farmout, or the prior cost-burdened net profits interest that MHLP seeks to restore through the Lawsuit. Unfortunately, Hurricane Katrina struck the Gulf of Mexico in August 2005 and delayed the commencement of production until 2006.

Faced with this post-Katrina situation, the Trustee urged all the parties to consent to a bifurcated trial of the farmout issue on an expedited basis. The Trustee proposed to MHLP that if the Court determined that the farmout was not valid and that restoring the net profit interest would benefit the Trust, then the Trust would reimburse MHLP’s reasonable attorneys’ fees, up to $100,000, and the Trustee would allow MHLP’s counsel to represent the Trust in prosecuting the damages portion of the case. Conversely, if MHLP were to lose on the expedited determination of the farmout issue, and in the absence of more evidence to support any ancillary claims, then MHLP would dismiss the other claims and would not be reimbursed, and the Trustee would move forward to terminate the Trust.

While the Trustee, Pioneer, and Woodside all agreed to an expedited trial of the farmout issues, MHLP balked. Contrary to the assertions of MHLP and the Intervenor Plaintiffs identified below, the Trustee never agreed that the claims asserted by MHLP against Pioneer and Woodside “had merit”—the Trustee simply stated that the farmout issue might merit adjudication at that time to determine (1) if MHLP was legally correct, and (2) if setting aside the farmout would benefit the Trust.

When MHLP refused to agree to an expedited and bifurcated trial as proposed by the Trustee, the Trustee informed MHLP that the Trustee’s investigation of MHLP’s allegations beyond the farmout issues failed to convince the Trustee of either their merit or that pursuing those claims and incurring the related legal fees and expenses would benefit the Trust. Moreover, the Trustee informed MHLP that the Trustee’s independent joint venture auditors and reservoir engineers had not found any evidence to date to support any of MHLP’s allegations.

It was at this point, in November 2005, in the midst of the Trustee’s negotiations with MHLP to obtain an agreed adjudication of MHLP’s claims, that MHLP alleged for the first time that the Trustee had a conflict of interest because of JPMorgan’s long-standing lending relationship with Pioneer. Although it is clear under the Trust Indenture, the Texas Trust Act, and relevant case law that JPMorgan is not precluded, by holding the position of Trustee, from pursuing commercial banking activities not involving Trust funds, MHLP amended its petition and asserted claims against the Trustee on November 28, 2005.

Although MHLP’s claims against the Trustee were meritless, to avoid any further assertion that the Trustee could not impartially evaluate MHLP’s claims, on November 30, 2005, JPMorgan announced its intention to resign as Trustee, effective January 31, 2006. On December 13, 2005, the lawsuit was transferred to the 334th Judicial District Court of Harris County, Texas. At a hearing on January 27, 2006 in the Harris County Court, the Court denied MHLP’s motion for a temporary injunction to remove JPMorgan as Trustee and appoint a principal of MHLP, Timothy Roberson, as a temporary Trustee. At the Court’s suggestion, JPMorgan agreed to continue as Trustee, until such time as a substitute trustee was found that fulfilled the qualifications of Trustee stated in the Trust Indenture. Since that hearing, neither MHLP nor Pioneer have identified a willing qualified successor Trustee that is not also a lender under one of Pioneer’s credit facilities (which status MHLP contends is an alleged conflict of interest).

On December 8, 2006, Dagger-Spine Hedgehog Corporation (“Dagger-Spine”) filed a petition to intervene in the Lawsuit as a Plaintiff, alleging claims virtually identical to MHLP. Another group of unitholders, led by Keith A. Wiegand (together with Dagger-Spine, the “Intervenors”), also filed on March 9, 2007 a petition to intervene as plaintiffs in the Lawsuit, incorporating and adopting the same claims asserted by MHLP.

On January 26, 2007, the Trustee reached a conditional settlement of the claims asserted by MHLP and the Intervenors against Pioneer and Woodside. The conditional settlement is set forth in the Mutual Release and Settlement Agreement dated as of January 26, 2007 (the “Conditional Settlement Agreement”). The Trustee filed a motion for approval of the Conditional Settlement Agreement with the Court on January 30, 2007.

The Conditional Settlement Agreement is the product of extensive investigations and negotiations by the Trustee. In 2006, after the Court denied MHLP’s attempt to remove JPMorgan as Trustee, the parties pursued formal discovery in the Lawsuit. During this period, the Trustee continued to evaluate the merits of the alleged claims against Pioneer and Woodside. A central allegation by MHLP and the Intervenors is that Pioneer and Woodside delayed the commencement of production from the well drilled pursuant to the Pioneer-Woodside Farmout—the Midway #5 well on the Brazos A-39 Lease. Woodside and Pioneer witnesses have given sworn testimony in depositions about the commercial and technical reasons for the delays in bringing the well on line. The well commenced production in April 2006. After this time, the Trustee instructed its independent petroleum reserve engineers to evaluate how the production results and projected production from the well might affect the value of the Trust’s interests. The Trustee’s independent engineers determined that the initial data regarding projected production from the well did not warrant a material change in prior assessments of the value of the Trust’s assets.

Pioneer subsequently reported to the Trustee that production from the well was suspended in July 2006 due to mercury contamination identified at downstream facilities where the production from the well is commingled with production from other wells. An updated evaluation from the Trustee’s independent petroleum reserve engineers estimated that revenues from future production from the well likely would not exceed the costs of drilling and completing the well. Accordingly, if the Partnership’s interest in the underlying lease had remained, or was, a cost-burdened net profits interest, instead of the cost-free overriding royalty interest the Partnership held as a result of the Pioneer-Woodside Farmout, the Partnership would not have received, or would not receive, any payments from this production, and the Trust accordingly would not have received any associated distributions. Further, the production data did not support reserves of the size asserted by MHLP and the Intervenors. The well resumed production in February 2007. The well was shut in on April 18, 2007 due to an increase in H2S content coincidental with an increase in water production. PNR is in the process of developing an H2S contingency plan as required by the MMS and will install the necessary alarm and safety systems. The well is expected to return to production during the second quarter of 2007 pending MMS approval of the H2S contingency plan. The last rate on production was 2.4—3 MMCFD psi flowing tubing pressure.

Under the Conditional Settlement Agreement, Pioneer has agreed to assign to the Trust an interest confirming its right to a 4.5% cost-free overriding royalty interest in the Brazos A-39 Lease until payout of the Midway #5 well, and to assign to the Trust an interest in the Brazos A-39 Lease, to be effective from and after payout if payout occurs, equal to a 45% net profits interest. Pioneer would also agree to pay for and satisfy approximately $1.4 million of plugging, abandonment, and decommissioning costs relating to several of the assigned Royalty Properties that Pioneer has informed the Trustee would otherwise be

allocated to the Partnership’s Royalty. Finally, Pioneer and the Trustee have agreed that Pioneer shall arrange for the sale of all assets of the Partnership as provided for under the Trust Indenture on, or as soon as practical after, July 1, 2007, or on an earlier date as set forth in the proposed settlement. The Conditional Settlement Agreement, if approved by the Court, would settle all claims in the Lawsuit that the Trust or the Partnership has or might have against Pioneer and Woodside and any claims that Pioneer and Woodside might have against the Trust or the Partnership.

Based on the information available to the Trustee and its analysis outlined above, the Trustee believes that the benefits received under the Conditional Settlement Agreement outweigh the potential benefits that may be achieved by the Trust litigating any of the asserted claims against Pioneer and Woodside, which would require the Trust to incur and assume the risk of further significant litigation costs. As a result, the Trustee believes the Conditional Settlement Agreement is in the best interest of the unitholders of the Trust. The Trustee has executed the Conditional Settlement Agreement and is recommending to the Court that the agreement be approved.

The Conditional Settlement Agreement is subject to certain conditions, including approval by the Court. The Court has currently scheduled a hearing on the approval for May 21, 2007. MHLP and the Intervenors are not signatories or parties to the settlement and they, or other unitholders of the Trust, may comment or object to the settlement. The settlement is not final until approved by the Court. If the Court approves the proposed settlement, it will enter an order that approves the settlement and dismisses the Lawsuit with prejudice as to all claims that may be brought on behalf of the Trust, either by the Trustee or by unitholders seeking to assert claims on behalf of themselves or the Trust, against Pioneer and Woodside based on the facts asserted in the Lawsuit.

The Trustee will make the full detail of the underlying data of the December 31, 2006 reserve report available for use in connection with the sale of the Partnership’s Royalty Properties as part of the Trust termination. For more information regarding the estimated remaining life of each of the Royalty Properties, the estimated future net revenues of the Royalty Properties and information relating to farm-outs of interests on the Royalty Properties based on information provided by PNR to DeGoyler & McNaughton (D&M), see pages 23 and 24 of the Form 10-K for the year ended December 31, 2006 and Note 6 in the Notes to Financial Statements included elsewhere in the Form 10-K. The final distribution to unitholders will be an amount net of funds required to satisfy all Trust liabilities.

Timing of Liquidation

The Trust Indenture provides that the Trust will terminate if the total amount of cash per year received by the Trust falls below certain levels for each of three successive years. As a result of continued declines in production on Royalty Properties nearing the end of their estimated productive lives, Royalty income received by the Trust in 2002, 2003 and 2004 fell below the Termination Threshold prescribed by the Trust Indenture. Under the proposed Conditional Settlement Agreement, Pioneer and the Trustee have agreed that Pioneer shall arrange for the sale of all assets of the Partnership as provided for under the Trust Indenture on, or as soon as practical after, July 1, 2007, or on an earlier date as set forth in the proposed settlement. The Trustee filed a motion for approval of the Conditional Settlement Agreement with the court on January 30, 2007. See “Legal Proceedings” above in this note for further discussion of the Conditional Settlement Agreement.

Due to the pending litigation, the Trustee cannot predict the timing of the sale of all or a portion of the Trust properties as part of the Trust Termination.

Note 3—Liquidity for Trust Expenses

As of March 31, 2007, the Trust had $378,345 in cash and short-term investments reserved for Trust expenses. Based on current general and administrative expenditures being incurred in connection with the litigation, in the absence of Royalty income the Trustee expects that it will be required to borrow money in accordance with the Trust Indenture to fund future Trust expenses. The Trustee is currently reviewing alternatives for loans to the Trust permitted under the Trust Indenture, including loans on a secured basis. In the event any loans are made to the Trust, the Trust Indenture will prohibit the Trustee from making any distributions to unitholders until those loans are repaid in full.

Note 4—Net Overriding Royalty Interest

The instruments conveying the Royalty to the Partnership provide that PNR will calculate and pay to the Partnership each month an amount equal to 90% of aggregate net proceeds for the preceding month. Generally, net proceeds means the excess of the amounts received by PNR from sales of its share of oil and gas from the Royalty Properties (gross proceeds) over the operating and capital costs incurred. Costs exceeding gross proceeds for any month are recovered by PNR, with interest thereon at the prime rate of the Bank of America plus one-half percent, out of future gross proceeds prior to making further Royalty payments to the Partnership.

Amortization of the Royalty, which is calculated on the basis of current Royalty income in relation to estimated future Royalty income, is charged directly to trust corpus since such amounts do not affect distributable income.

Note 5—Basis of Presentation

The accompanying unaudited financial information has been prepared by the Trustee in accordance with the instructions to Form 10-Q. JPMorgan Chase Bank, N.A. was formerly known as The Chase Manhattan Bank and is the successor by mergers to the original name of the Trustee, Texas Commerce Bank National Association. 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 2006 Annual Report on Form 10-K.

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

(a) Royalty income recorded for a month is the Trust’s interest in the amount computed and paid by the working interest owner to the Partnership for such month rather than either the value of a portion of the oil and gas produced by the working interest owner for such month or the amount subsequently determined to be 90% 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; and

This basis for reporting Royalty 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, it will differ from the basis used for financial statements prepared in accordance with accounting principles generally accepted in the United States because, under such accounting principles, Royalty income for a month would be based on net proceeds from production for such month without regard to when calculated or received and interest income for a month would be calculated only through the end of such month.

The instruments conveying the Royalty provide that the working interest owner will calculate and pay the Partnership each month an amount equal to 90% of the net proceeds for the preceding month. Generally, net proceeds means the excess of the amounts received by the working interest owner from sales of oil and gas from the Royalty Properties plus other cash receipts over operating and capital costs incurred. For the three months ended March 31, 2007, no royalty income was received by the Trust; accordingly, no Trust distribution to the unit holders was made.

Generally, net proceeds means the excess of the amounts received by the working interest owner from sales of oil and gas from the Royalty Properties plus other cash receipts over operating and capital costs incurred. As of March 31, 2007 there is a deficit balance due PNR of approximately $1.4 million, which will be deducted from any future gross proceeds on the Royalty properties, which will reduce future Royalty income. PNR has not withheld any funds for future abandonment costs at March 31, 2007. Currently, PNR estimates that the abandonment accrual for amounts expended but not recouped and for projected future abandonment expenses for properties in which the Trust has an interest is $1.4 million, net to the Trust, which is included in the deficit balance above. These costs will be deducted from any future gross proceeds on the Royalty properties, which will reduce future Royalty income. See Note 2 “—Status of the Trust, Legal Proceedings, and Timing of Liquidation” for the terms of the contracted settlement agreement that, if approved would substantially eliminate the deficit balance.

No Royalty income will be distributed to unitholders until the Trustee recoups Trust expenses being paid from the reserve that the Trustee has established for anticipated future expenses. As of March 31, 2007, $1.6 million will be withheld by the Trustee from future Royalty income before Trust distributions to the unitholders will resume. During the three months ended March 31, 2007 and 2006, the Trust had no distributable income. Interest income and the reserve for Trust expenses were used to pay the Trust’s general and administrative expenses for the three months ended March 31, 2007 of $426,780.

Below is a summary of general and administrative expenses and the adjustments made to the reserve for Trust expenses:

	Three Months Ended March 31,
	2007			2006
General and administrative costs incurred during the period	$	426,780		$	356,613
(Deductions from) additions to reserve for Trust expenses	(421,700		)	(310,660		)
General and administrative costs as reported	$	5,080		$	45,953

Note 6—Distributions to Unitholders

Under the terms of the Trust Indenture, the Trustee must distribute to the unitholders all cash receipts, after paying liabilities and providing for cash reserves as determined necessary by the Trustee.

The amounts distributed are determined on a monthly basis and are payable to unitholders of record as of the last business day of each month. However, cash distributions are made quarterly in January, April, July and October, and include interest earned from the monthly record dates to the dates of distribution.

Note 7—Federal Income Taxes

The Trustee reports on the basis that the Trust is a grantor trust. Based on its previous audit policy, the Internal Revenue Service (the “IRS”) is expected to concur with such action. No IRS ruling has been received or requested with respect to the Trust, however, and no court case has been decided involving identical facts and circumstances. It is possible, therefore, that the IRS would assert upon audit that the Trust is taxable as a corporation and that a court might agree with such assertion.

As a grantor trust, the Trust will incur no federal income tax liability. In addition, it will incur little or no federal income tax liability if it is held to be a non-grantor trust. If the Trust were held to be taxable as a corporation, it would have to pay tax on its net taxable income at the corporate rate.

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.

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 Pioneer has advised the Trust that it believes that the expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from expectations (“Cautionary Statements”) are disclosed in this Form 10-Q, including, without limitation, in conjunction with the forward-looking statements included in this Form 10-Q and in the Trust’s Form 10-K for the year ended 2006, 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.

Financial Review

The amount of cash distributed by the Trust is dependent on, among other things, the sales prices and quantities of gas, crude oil, condensate and natural gas liquids produced from the Royalty Properties and the quantities sold. Substantial uncertainties exist with regard to future gas and oil prices, which are subject to fluctuations due to the regional supply and demand for natural gas and oil, production levels and other activities of the Organization of the Petroleum Exporting Countries (“OPEC”) and other oil and gas producers, weather, storage levels, industrial growth, conservation measures, competition and other variables.

Below is a summary of Royalty income received on the Trust properties for the three months ended March 31, 2007 and 2006:

	Three Months Ended March 31,
	2007			2006
Gross proceeds @ 90%	$	—		$	76,525
Operating expenditures @ 90%	(6,495		)	(27,723		)
Capital expenditures @ 90%	—			(8,033		)
Net proceeds (deficit)	(6,495		)	40,769
Increase (decrease) in deficit	6,495			—
Net proceeds after deficit recovery	—			40,769
Royalty Income (99.99%)	$	—		$	40,765

Below is a summary of distributable income for the three months ended March 31, 2007 and 2006:

	Three Months Ended March 31,
	2007			2006
Royalty income	$	—		$	40,765
Interest income	5,080			5,188
General and administrative expenses	(5,080		)	(45,953		)
Distributable income	$	—		$	—
Distributable income per unit	$	—		$	—
Accumulated deficit (as of end of period)	$	1,424,405		$	—

During the first quarters of 2007 and 2006, the Trust had no distributable income. Interest income and the reserve for trust expenses were used to pay the Trust’s first quarter of 2007 general and administrative expenses of $426,780.

Below is a summary of general and administrative expenses and the adjustments made to the reserve for Trust expenses:

	Three Months Ended March 31,
	2007			2006
General and administrative costs incurred during the period	$	426,780		$	356,613
(Deductions from) additions to reserve for Trust expenses	(421,700		)	(310,660		)
General and administrative costs as reported	$	5,080		$	45,953

General and administrative expenses of the Trust for the first quarter of 2007 increased 20% to $426,780 as compared to $356,613 for the same period in 2006. The increase in general and administrative expenses in 2007 is primarily due to an increase in legal fees as a result of pending litigation and expenditures related to the anticipated sale of Trust properties pursuant to the Trust’s termination.

Operational Review

PNR has advised the Trust that during the first quarter of 2007 its offshore gas production was marketed under short-term contracts at spot market prices primarily to TOTAL S.A. and that it expects to continue to market its production under short-term contracts for the foreseeable future. Spot market prices for natural gas in the first quarter of 2007 were generally lower than spot market prices in the first quarter of 2006.

The amount of cash distributed by the Trust is dependent on, among other things, the sales prices and quantities of gas, crude oil and condensate produced from the Royalty Properties and the quantities sold. Substantial uncertainties exist with regard to future gas and oil prices, which are subject to fluctuations due to the regional supply and demand for natural gas and oil, production levels and other activities of the Organization of the Petroleum Exporting Countries (“OPEC”) and other oil and gas producers, weather, storage levels, industrial growth, conservation measures, competition and other variables.

Below is an operational review of the remaining producing Trust properties:

Brazos A-7 and A-39

	Three Months Ended March 31,
	2007			2006
Gross proceeds @ 90%	$	—		$	45,237
Operating expenditures @ 90%	(4,450		)	(22,625		)
Capital expenditures @ 90%	—			—
Net proceeds (deficit)	$	(4,450	)	$	22,612

As of March 31, 2007, these two blocks had one well capable of producing, the Brazos A-39 # 5 which was shut-in during the first quarter of 2007 due to the detection of mercury. The Brazos A-7 No. B-1 well, operated by Newfield, was no longer producing as of December 31, 2006. PNR entered into farmout agreements for the Partnership’s interest in both of these blocks so that two exploration prospects could be drilled and in which the Trust will retain an overriding royalty interest. The first prospect on Brazos A-7 was drilled during 2003 and was determined to be a dry hole. As such, the well was plugged and abandoned.

The second exploration prospect, the Brazos A-39 #5, was drilled on Brazos A-39, which PNR announced as a discovery. A production test was completed in 2005. PNR, the operator on this property, has informed the Trustee that the lower horizon of the prospect was determined to be non-commercial, while the middle horizon in the Big Hum 4 sand produced at 10,000 Mcf of gas per day during a seventeen hour flow test. This well came on line April 20, 2006. However, this well has been shut in from time to time since then as the operator has encountered and addressed hydrogen sulfide issues. The well has also produced a carbon dioxide content that exceeds pipeline specifications. This higher content requires the operator to mix production at the platform with production from other fields in order to transport the product. Production is being routed to the A-52C platform owned by Coldren Resources LP. That platform is being operated by Arena, which is also serving as the contract operator for the Midway property. The well was shut in July 21, 2006 by Williams Pipeline due to reported detection of mercury in the gas stream. Following the installation of vessels with mercury absorbing media and negotiation of the required agreements with the owner and operator of the Brazos A-52C host platform, the well was returned to production on February 13, 2007. The well was shut in on April 18, 2007 due to an increase in hydrogen sulfide content coincidental with an increase in water production. PNR is in the process of developing an hydrogen sulfide contingency plan as required by the MMS and will install the necessary alarm and safety systems. The well is expected to return to production during the second quarter of 2007 pending MMS approval of the hydrogen sulfide contingency plan. The last rate on production was 2.4—3 MMCFD psi flowing tubing pressure.

Under the terms of a Farmout Agreement between PNR and Woodside Energy (USA) Inc., PNR farmed out to Woodside the undivided one-half interest previously burdened by the Partnership’s net profits interest, but expressly providing that the farmed out interest would not be subject to the Partnership’s net profits interest. PNR reserved a 10% overriding royalty interest, proportionately reduced to the interest conveyed, which interest, upon Woodside’s recoupment of specified costs and expenses, would increase to 12.5%, proportionately reduced to the interest conveyed. The Partnership’s net profits

interest burdens the overriding royalty interest reserved by PNR. PNR has informed the Trustee that it believes this process is consistent with the terms of the original conveyance and with the handling of other farmout transactions involving lands burdened by the Partnership’s net profits interest.

PNR continues to own the undivided one-half interest not burdened by the Partnership’s net profits interest and will participate in and operate the well as owner of that undivided one-half interest (subject to an agreement with Woodside to grant Woodside such interest in PNR’s remaining undivided one-half interest to equalize those parties participation in the well).

PNR has noted to the Trustee that the Farmout Agreement enabled the drilling costs of these prospects to be carried on the Partnership’s interest in part by Woodside. PNR further noted that the Partnership’s net profits interest would not have entitled the Trust (through the Partnership) to payment until drilling costs and applicable interest were recovered, whereas the overriding royalty interest retained under the Farmout Agreement entitles the Trust (through the Partnership) to payments prior to the recoupment of expenses incurred by Woodside and PNR. As noted above, the first prospect on Brazos A-7 was determined to be a dry hole. Under the Farmout Agreement and related agreements, those drilling and abandonment costs have been born entirely by PNR and Woodside and are not subject to recoupment from any proceeds otherwise payable to the Partnership or the Trust. Similarly, the Partnership’s current interest in the “Midway” prospect on Brazos A-39 will be entitled to payment prior to PNR’s and Woodside’s recovery of expenses for drilling, completion, sub-sea tie backs and other costs.

West Delta 61 and Other

	Three Months Ended March 31,
	2007			2006
Gross proceeds @ 90%	$	—		$	31,288
Operating expenditures @ 90%	(2,045		)	(5,098		)
Capital expenditures @ 90%	—			(8,033		)
Net proceeds (deficit)	$	(2,045	)	$	18,157

Hurricane Katrina struck the Gulf of Mexico in August 2005. The operator of the West Delta properties informed PNR that the West Delta properties have been shut in since August 27, 2005 due to damage to the platform, the pipeline and the sales terminal. The operator has notified PNR that they expect production at West Delta to resume during the second quarter of 2007. The proceeds for the quarter ended March 31, 2006 consist of revenue adjustments related to prior periods received by the Trust during the first quarter of 2006, and as such do not relate to production at the West Delta properties during the quarter.

The PNR-operated wells ceased production in 2002, and the wells were plugged and abandoned by year-end with the facilities being completely abandoned during 2003. The only remaining wells on this block are in West Delta 61. PNR farmed out a portion of West Delta 61 to Stone Energy retaining a 12.5% (11.25% net to the Trust through the Partnership) overriding royalty interest.

Capital Expenditures

PNR does not anticipate any significant capital expenditures on the Royalty Properties in the future. Due to the limited financial capacity of the Trust, PNR has advised that it intends to farm out the Trust’s interest in the blocks it believes may be produced economically, retaining an overriding royalty interest for the Trust.

Abandonment Expenditures

The table below provides a rollforward of the abandonment and removal costs cash reserve that PNR has withheld from the Trust:

Balance, December 31, 2006	$	—
Abandonment (costs incurred) credits received	—
Balance, March 31, 2007	$	—

During the first nine months of 2006, PNR exhausted the $348,066 cash reserve established as of December 31, 2005. In the third quarter of 2006, PNR revised their estimate of abandonment expenses incurred, but not recouped from the Partnership and expenses yet to be incurred for properties, in which the Partnership has an interest to approximately $1.4 million. This revision was caused by increased work; necessary because of damages caused by Hurricane Katrina, and increased day rates for labor due to the high demand for labor following Hurricanes Katrina and Rita. As of March 31, 2007, PNR had spent approximately $867,000 of the $1.4 million estimate, while approximately $533,000 of PNR’s original estimate for total repairs remains to be spent. As the reserve for future abandonment cost was fully utilized during 2006, the total $1.4 million of the Partnership’s interest in estimated repairs will be deducted from any future gross proceeds on the Royalty Properties, which will reduce future Royalty income. No Royalty income will be distributed to unitholders in the future until PNR recoups the Partnership’s portion of abandonment expenses from gross proceeds.

Production and Price Review

Production volumes for natural gas decreased to 0 Mcf in the first quarter of 2007 as compared with 4,487 Mcf in the first of quarter 2006 primarily due to decreased production at West Delta 61 due to damages related to Hurricane Katrina and due to the shut-in of Brazos A-39. The average sales price received for natural gas in the first quarter of 2007 was $0 per Mcf as compared with $13.03 per Mcf in the first quarter of 2006. Crude oil, condensate and natural gas liquids production volumes decreased to 0 barrels in the first quarter of 2007 as compared to 290 barrels in the first quarter of 2006. The average sales price in the first quarter of 2007 for crude oil, condensate and natural gas liquids was $0 per barrel as compared to $62.56 per barrel in the first quarter of 2006.

Termination of the Trust

the Trust Indenture. During 2005, the Trustee has previously taken steps to begin the process of liquidating the Trust. See “—Timing of Liquidation” above in Note 2. The Trustee, which has no authority or discretionary control over the timing of expenditures, production or income on the Royalty Properties, has no discretion regarding the occurrence of the Termination Threshold or its consequences.

The Trust Indenture provides the Trustee a two-year period during which it must sell all of the Trust properties. The Trust Indenture provides that such properties must be sold for cash and not for any other consideration. The Trustee expects that the sale process will be open to any persons desiring to participate, but, as is customary, access to information and participation may be limited to persons who execute confidentiality agreements regarding information provided by the working interest owners. The Trustee may also require bidders to identify themselves clearly and to represent or evidence sufficient financing in order to participate, as the Trustee expects payment will be required promptly after the close of bidding without any financing conditions. Accordingly, the auction may not be a “public” auction in the sense that it may not be open to anyone who does not satisfy these requirements. The Trustee is currently reviewing a potential online bidding process for participants in order to provide current public information on bidding to the marketplace. The Trustee will also determine a duration of bidding that it deems in the best interest of the Unitholders.

Assets and Liabilities in the Process of Liquidation

As a result of the contractual termination of the Trust effective January 1, 2005, the Trust is in the process of liquidation. The below table presents the assets of the Trust at their estimated fair value:

	March 31,
	2007
ASSETS
Cash and short term investments	$	378,345
Interest receivable	—
Net overriding royalty interest in oil and gas properties	1,487,179
Total assets	$	1,865,524
LIABILITIES
Reserve for Trust expenses	$	378,345
Total liabilities	378,345
Net assets in process of liquidation	$	1,487,179

The net overriding royalty interest in oil and gas properties at March 31, 2007 reflect the Trustee’s estimate of value, (in the absence of third-party appraisals or evaluations) based on the Trust’s share of future net revenues from the net overriding royalty interest in the properties as of March 31, 2007. This estimate is based on the Trustee’s current assessment of the impact of selling existing assets based on current market conditions, and includes the following assumptions:

· The Trust’s estimated share of proved oil and gas reserve volumes at March 31, 2007, which were derived from the December 31, 2006 reserve report prepared by DeGolyer and MacNaughton (D&M) and updated for first quarter of 2007 production. The working interest owner has not prepared a reserve report as of March 31, 2007, and therefore any revisions in oil and gas reserves

during the first quarter of 2007 have not been considered in the estimate of fair value of the net overriding royalty interest in oil and gas properties. The estimated fair value also does not include any value for probable or possible oil and gas reserves.

· Forward strip commodity prices on March 31, 2007 and then escalated 2% thereafter.

· Includes approximately $1.4 million of future abandonment costs.

· Discount rate of 10%.

Legal Proceedings

On April 11, 2005, MOSH Holding, L.P. (“MHLP”) filed an Original Petition in the District Court of Travis County, Texas, 250th Judicial District, against Pioneer Natural Resources Company (“PNR”); Pioneer Natural Resources USA, Inc. (together with PNR, “Pioneer”); Woodside Energy (USA), Inc. (“Woodside”); and JPMorgan Chase Bank, N.A., as Trustee of the Mesa Offshore Trust (Case No. GN501113) (the “Lawsuit”). The Lawsuit is currently before the 334th Judicial District of Harris Country, Texas (the “Court”). MHLP’s Original Petition alleges Pioneer and Woodside are liable for various actions, including (1) a wrongful farmout by Pioneer to Woodside of the Brazos A-39 Lease, (2) a wrongful delay by Pioneer in producing the Brazos A 39 Lease and the Midway #5 well drill thereon, (3) fraudulent accounting practices by Pioneer, (4) breach of fiduciary duty by Pioneer, (5) aiding and abetting breach of fiduciary duty by Woodside, (6) misapplication of Trust property by Pioneer, (7) conspiracy to misapply fiduciary property by Woodside and Pioneer, (8) common law fraud by Pioneer, (9) gross negligence by Pioneer, and (10) breach of the conveyance agreement by Pioneer. As described below, MHLP later added claims against the Trustee for (1) an accounting, and (2) breach of fiduciary duty. The remedies MHLP seeks include (a) reconstruing the Trust Indenture to determine that the Trust is not terminated because there has or should have been production that would have generated revenues to extend the life of the Trust, (b) requiring the Trustee to pursue certain claims, or to allow MHLP to pursue such claims, (c) setting aside any farmouts by Pioneer in which there have been conveyances to an alleged affiliate of Pioneer, (d) the removal of JPMorgan as Trustee, (e) the return or forfeiture of compensation to JPMorgan, (f) monetary damages against Pioneer, Woodside and JPMorgan, and (g) unspecified exemplary damages against all defendants.

MHLP nor Pioneer have identified a willing qualified successor Trustee that is not also a lender under one of Pioneer’s credit facilities (which status MHLP contends is an alleged conflict of interest).

On December 8, 2006, Dagger-Spine Hedgehog Corporation (“Dagger-Spine”) filed a petition to intervene in the Lawsuit as a Plaintiff, alleging claims virtually identical to MHLP. Another group of unitholders, led by Keith A. Wiegand, (together with Dagger-Spine, the “Intervenors”) also filed on March 9, 2007 a petition to intervene as plaintiffs in the Lawsuit, incorporating and adopting the same claims asserted by MHLP.

The Trustee will make the full detail of the underlying data of the December 31, 2006 reserve report available for use in connection with the sale of the Partnership’s Royalty Properties as part of the Trust termination. For more information regarding the estimated remaining life of each of the Royalty Properties, the estimated future net revenues of the Royalty Properties and information relating to farm-outs of interests on the Royalty Properties based on information provided by PNR to D&M, see pages 23 and 24 of the Form 10-K for the year ended December 31, 2006 and Note 6 in the Notes to Financial Statements included elsewhere in the Form 10-K. The final distribution to unitholders will be an amount net of funds required to satisfy all Trust liabilities.

Liquidity for Trust Expenses

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

The Trust does not utilize market risk sensitive instruments. However, see the discussion of marketing by PNR above.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act 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 is accumulated and communicated by Pioneer, as the managing general partner of the Partnership, and the working interest owners to JPMorgan Chase Bank, 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 Trustee carried out an evaluation of the Trust’s disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded that the controls and procedures are effective.

Due to the contractual arrangements of (i) the Trust Indenture, (ii) the Partnership Agreement and (iii) the rights of the Partnership under the Conveyance regarding information furnished by the working interest owners, the Trustee relies on: (A) information provided by the working interest owners, including (i) the status of litigation, (ii) historical operating data, plans for future operating and capital expenditures, reserve information, as well as (iii) information relating to projected production; (B) information provided by the managing general partner of the Partnership that is collected by the managing general partner from the working interest owners; and (C) conclusions regarding reserves by reserve engineers or other experts in good faith. See Item 1A. Risk Factors “—None of the Trust nor its unitholders control 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 and managing general partner for information regarding the Royalty Properties” in the Trust’s 10-K for the year ended 2006 for a description of certain risks relating to these arrangements and reliance.

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 or the managing general partner of the Partnership.

PART II

Item 6. Exhibits

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

				SEC File or Registration Number		Exhibit Number
4	(a)	*	Mesa Offshore Trust Indenture between Mesa Petroleum Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982		2-79673		10	(gg)
4	(b)	*	Overriding Royalty Conveyance between Mesa Petroleum Co. and Mesa Offshore Royalty Partnership, dated December 15, 1982		2-79673		10	(hh)
4	(c)	*	Partnership Agreement between Mesa Offshore Management Co. and Texas Commerce Bank National Association, as Trustee, dated December 15, 1982		2-79673		10	(ii)
4	(d)	*	Amendment to Partnership Agreement between Mesa Offshore Management Co., Texas Commerce Bank National Association, as Trustee, and Mesa Operating Limited Partnership, dated December 27, 1985 (Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of Mesa Offshore Trust)		1-8432		4	(d)
4	(e)	*	Amendment to Partnership Agreement between Texas Commerce Bank National Association, as Trustee and Mesa Operating dated as of January 5, 1994 (Exhibit 4(e) to Form 10-K for year ended December 31, 1993 of Mesa Offshore Trust)		1-8432		4	(e)
31			Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32			Certification furnished 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 OFFSHORE TRUST
	By:	/s/ JPMORGAN CHASE BANK, N.A., as Trustee
	By:	/s/ MIKE ULRICH
		*Mike Ulrich*
		*Vice President*
Date: May 15, 2007		The Bank of New York Trust Company, N.A., as attorney-in-fact for the Trustee

The Registrant, Mesa Offshore 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.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. junior Bad

Mesa Offshore Trust (MOSH) Inactive 10-Q2007 Q1 Quarterly report

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