Mesa Offshore Trust 10Q 2006 Q3 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 SEPTEMBER 30, 2006

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 1-08432

MESA OFFSHORE TRUST

(Exact name of Registrant as Specified in its Charter)

Texas (State of Incorporation or Organization)		76-6004065 (I.R.S. Employer Identification No.)
JPMorgan Chase Bank, N.A., Trustee Institutional Trust Services 221 West Sixth Street 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 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 Exchange Act). Yes o No x

As of November 14, 2006—71,980,216 Units of Beneficial Interest in Mesa Offshore Trust.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

MESA OFFSHORE TRUST

STATEMENTS OF DISTRIBUTABLE INCOME

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Royalty income	$	31,097		$	288,534		$	145,642		$	967,403
Interest income	7,808			1,838			18,017			3,785
General and administrative expense	(38,905		)	(290,372		)	(163,659		)	(971,188		)
Distributable income	$	—		$	—		$	—		$	—
Distributable income per unit	$	—		$	—		$	—		$	—

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

	September 30, 2006			December 31, 2005
	(Unaudited)
ASSETS
Cash and short-term investments	$	1,075,213		$	1,846,798
Interest receivable	4,876			1,582
Net overriding royalty interest in oil and gas properties	380,905,000			380,905,000
Accumulated amortization	(380,902,063		)	(380,901,952		)
Total assets	$	1,083,026		$	1,851,428
LIABILITIES AND TRUST CORPUS
Reserve for Trust expenses	$	1,080,089		$	1,848,380
Distributions payable	—			—
Trust corpus (71,980,216 units of beneficial interest authorized and outstanding)	2,937			3,048
Total liabilities and trust corpus	$	1,083,026		$	1,851,428

MESA OFFSHORE TRUST

STATEMENTS OF CHANGES IN TRUST CORPUS

(Unaudited)

	Three Months Ended September 30,								Nine Months Ended September 30,
	2006				2005				2006			2005
Trust corpus, beginning of period		$	2,966			$	5,224		$	3,048		$	11,127
Distributable income		—				—			—			—
Distributions to unitholders		—				—			—			—
Amortization of net overriding royalty interest		(29		)		(539		)	(111		)	(6,442		)
Trust corpus, end of period		$	2,937			$	4,685		$	2,937		$	4,685

(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

Hurricane Operations Update

Hurricane Katrina struck the Gulf of Mexico in August 2005. PNR has notified the Trust of its current assessments regarding damages from Hurricanes Katrina and Rita to production facilities for properties in which the Trust has an interest. The operator of the West Delta properties has 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 as early as the second quarter of 2007.

Status of the Trust

the Termination Threshold prescribed by the Trust Indenture. The Trustee has 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.

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. See “—Timing of Liquidation” for further update.

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.; Woodside Energy (USA), Inc.(Woodside); and JPMorgan Chase Bank, N.A., as Trustee of the Mesa Offshore Trust (Case No. GN501113). On November 28, 2005, Plaintiff amended its petition. In the amended petition, MHLP asserts claims against Pioneer and Woodside for matters including (1) a wrongful farmout of Brazos A-39 by Pioneer , (2) a wrongful delay by Pioneer in producing Brazos A-39, (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. MHLP asserts claims for damages against the Trustee for (1) an accounting; and (2) breach of fiduciary duty. The plaintiff remedies being sought include (a) reconstruing the Trust Indenture to determine that the Trust is not terminated because there has or should have been production which would have generated revenues to extend the life of the Trust, (b) requiring the Trustee to pursue certain claims, or to allow plaintiff to pursue such claims, (c) setting aside any farmouts by Pioneer in which there have been conveyances to an affiliate of Pioneer in violation of the Trust’s Conveyance and as a self-dealing transaction, and (d) removing JPMorgan Chase Bank, N.A. as Trustee, (e) seeking return or forfeiture of compensation to JPMorgan Chase Bank, N.A., (f) recovering monetary damages against Pioneer, Woodside and JPMorgan Chase Bank, N.A., and (g) pursuing exemplary damages against all defendants.

On November 30, 2005, JPMorgan Chase Bank, N.A. announced its intention to resign as Trustee of the Mesa Offshore Trustee effective January 31, 2006. Since that announcement, MHLP and others have sought a qualified institution willing to serve as successor Trustee. However, 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 January 27, 2006, a hearing was held in the 334th Judicial District Court of Harris County, Texas, regarding MHLP’s Verified Application for Emergency Appointment of a Temporary Trustee in Case No. 2006-01984, MOSH Holding, L.P. v. Pioneer Natural Resources Company; Pioneer Natural Resources USA, Inc; Woodside Energy (USA), Inc.; and JPMorgan Chase Bank, N.A., as Trustee of the Mesa Offshore Trust. This case follows the transfer of prior claims filed by the plaintiff in Case No. GN501113. At this hearing, the court declined to approve MHLP’s motion to appoint Timothy J. Roberson, a principal and affiliate of MHLP, as temporary Trustee and declined to appoint any other person as temporary or successor Trustee.

In light of this development, and the absence of an identified successor Trustee, JPMorgan Chase Bank, N.A. withdrew its resignation as Trustee. The Trustee continues to desire the appointment of a qualified successor Trustee.

To date, the Trustee has allowed MHLP to proceed on the issue of whether the farmout by Pioneer was a valid farmout. While Pioneer has provided a reasoned analysis of why it believes the farmout was in fact valid under the terms of the conveyance, only a court, and not the Trustee, can make a final adjudication. Further, while MHLP’s claims on the farmout issue may merit adjudication, based on facts known to the Trustee at this time, the Trustee is unable to determine, even if MHLP prevailed on its uncertain liability claims, whether the Trust would realize any economic benefit. Based on information received to date, the Trustee has not concluded that it would be in the best interest of the unitholders to fund the MHLP claims directly with Trust funds. However, as noted above, the Trustee has not opposed MHLP’s pursuit of its claims on behalf of the unitholders at their own expense, which reasonable expenses would be subject to repayment of the claims proved successful and a benefit were conferred upon all unitholders of the Trust. In connection with both the anticipated sale of Trust properties pursuant to the Trust’s termination and the pending litigation, the Trustee has (1) engaged an independent reserve engineer to review the estimated reserves and (2) had an independent joint venture auditor review certain historical expenditures and revenue receipts on Trust properties. The Trustee believes expenditures for these reviews were prudent and in the interest of the unitholders.

The Trustee will make the full detail of the underlying data of the December 31, 2005 reserve report available for use in connection with the sale of the Trust 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 farmout of interests on the Royalty Properties based on information provided by DeGolyer & MacNaughton (D&M), see pages 22 and 23 of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2005 and Note 6 in the Notes to Financial Statements included elsewhere in the Trust’s Form 10-K for the year ended December 31, 2005. The sale of the assets of the Trust estate may include the related abandonment liabilities that have not been previously withheld. The final distribution to unitholders will be an amount net of funds required to satisfy all Trust liabilities.

Timing of Liquidation

MHLP. However, the review of reserves by the independent reserve engineer has not shown the existences of significant reserves not previously included in the reserve report prepared by PNR in quantities originally alleged in the plaintiff’s petition. The Trustee has performed additional joint venture audits of the Trust properties by an independent auditor. This is a process that the Trust had already begun in its inquiry in the ordinary course as part of the termination of the Trust, and the Trustee will continue to review MHLP’s claims.

As previously mentioned, the Trustee engaged an independent joint venture auditor in October 2004 to review the Trust properties as part of the termination of the Trust. The joint venture auditor reviewed the periods from 2003 through 2004. The Trustee believed this engagement of an outside expert on these matters to be a prudent step to identify any potential benefits to the Trust, as well as any limitations on potential benefits, due to differing interpretations of accounting matters that commonly occur in the oil and gas production industry. The review of the independent joint venture auditor was completed in December 2005, and it was the joint venture auditor’s opinion that the charges and credits and revenue to the Trust were in accordance with the applicable agreements, except for certain items noted in the report. The report notes exceptions, which may or may not turn out to be meritorious, as to amounts due to the Trust of $204,219. PNR, Stone Energy (Stone) and Newfield Exploration Company (Newfield) responded to these exceptions on April 20, 2006. PNR, Stone and Newfield have granted and denied exceptions on all of the areas pointed in the Joint Venture Audit findings. The Trust is in the process of reviewing the exceptions denied before accepting or rejecting PNR, Stone and Newfield’s answers.

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—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 Annual Report on Form 10-K for the year ended December 31, 2005.

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;

(d) Amortization of the net overriding royalty interest, 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 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 other day as the Trustee determines is required to comply with legal 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 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 of America 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 and nine months ended September 30, 2006, Royalty income was applied solely to cover a portion of general and administrative expenses; 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 September 30, 2006 there is a deficit balance due PNR of $848,519, which will be deducted from any future gross proceeds on the Royalty properties, which deduction will reduce future Royalty income. The unexpended amount withheld by PNR for future abandonment costs at September 30, 2006 was $0. 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 $1,400,000, net to the Trust. These costs will be deducted from any future gross proceeds on the Royalty properties, which deduction will reduce future Royalty income. 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 September 30, 2006, $919,911 will be withheld by the Trustee from future Royalty income before Trust distributions to the unitholders will resume.

During the three and nine months ended September 30, 2006 and 2005, the Trust had no distributable income. Royalty and interest income and the reserve for Trust expenses were used to pay the Trust’s general and administrative expenses for the three and nine months ended September 30, 2006 of $262,381 and $931,254, respectively.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006			2005		2006			2005
General and administrative costs incurred during the period	$	262,381		$	188,644	$	931,254		$	604,600
Deductions from (additions to) reserve for Trust expenses	(223,476		)	101,728		(767,595		)	366,588
General and administrative costs as reported	$	38,905		$	290,372	$	163,659		$	971,188

Note 4—Assets and Liabilities in 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. The reserve for Trust expenses represents the amount the Trustee has withheld from distributable income as of September 30, 2006. The Trustee will continue to reserve funds to recoup its previously established reserves to pay Trust expenses, which will primarily consist of expenses incurred by the Trustee to liquidate the Trust’s assets. Any funds remaining after all expenses have been paid will be distributed to the Unitholders.

	September 30, 2006
ASSETS
Cash and short term investments		$	1,075,213
Interest receivable		4,876
Net overriding royalty interest in oil and gas properties(1)(2)		2,460,785
Total assets		$	3,540,874
LIABILITIES
Reserve for Trust expenses		$	1,080,089
Total liabilities		1,080,089
Net assets in process of liquidation		$	2,460,785

The net overriding royalty interest in oil and gas properties at September 30, 2006 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 September 30, 2006. 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 oil and gas reserve volumes at September 30, 2006, which were derived from the December 31, 2005 reserve report prepared by DeGoyler & MacNaughton, and updated for year to date 2006 production (1). A reserve report as of September 30, 2006 has not been prepared, and therefore any revisions in oil and gas reserves during the nine months ended

September 30, 2006 have not been considered in the estimate of fair value of the net overriding royalty interest in oil and gas properties.

· Forward strip commodity prices on September 30, 2006 for the life of the reserves.

· Discount rate of 10%.

The actual net proceeds from the sales of oil and gas properties may vary substantially from these estimates in value due to changes in current and estimated future oil and gas prices, subsequent production, estimates of actual abandonment costs and other factors which may be applied by the buyers.

For all other assets presented in the above table, the Trustee believes that historical cost approximates fair market value due to the short-term nature of such assets. The Trustee will continue to reserve funds to recoup its previously established reserves to pay Trust expenses, which will primarily consist of expenses incurred by the Trustee to liquidate the Trust’s assets. Any funds remaining after all expenses have been paid will be distributed to the Unitholders.

(1) As a result of the litigation described above, the Trust has been unable to obtain necessary information from the working interest owner regarding such owner’s own current estimate of the fair value of the proved reserves on the Midway Prospect. The Trustee engaged D&M, an independent reserve engineer, to review all oil and gas reserves pertaining to the Royalty, including the Midway Prospect reserves and the Trust’s interest in these reserves as of December 31, 2005.

(2) The sale of the assets currently owned by the Partnership will include the related rights to abandonment cost, if any, previously withheld by the working interest owner. As of September 30, 2006, the working interest owner had no funds withheld to cover the Trust’s share of estimated future abandonment and removal costs. To the extent the abandonment is completed for an amount less than funds withheld by the working interest owner, those funds would be distributed to the Trust. The December 31, 2005 reserve report assumed that amounts previously withheld by the working interest owner were sufficient to cover future abandonment and removal costs, and accordingly, those costs were not reflected as a reduction of future net revenue. During the third quarter of 2006, the working interest owner notified the Trust that it currently anticipates amounts expended and projected future abandonment expenses for properties in which the Trust has an interest to be $1,400,000, net to the Trust. These amounts have not been withheld from the Trust and will reduce the Trust’s future net revenue to the extent withheld or incurred by the working interest owner and thus reduce the amount reflected in “Net overriding royalty interest in oil and gas properties”. Given the timing of receiving this information from the working interest owner, the Trustee has not been able to assess the reasonableness of upward change in the estimated abandonment and removal costs. The Trustee intends to assess the reasonableness to the abandonment reserve during the fourth quarter and also will engage D&M to perform a reserve study as of December 31, 2006.

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” and Note 4 to the financial statements of the Trust regarding the estimated fair value of assets of the Trust, 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 December 31, 2005, including under Part I, 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 and nine months ended September 30, 2006 and 2005:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Gross proceeds @ 90%	$	65,057		$	250,349		$	229,623		$	1,058,280
Operating expenditures @ 90%	(72,479		)	(34,400		)	(114,456		)	(92,045		)
Change in abandonment estimate @ 90%	(810,082		)	—			(810,082		)	—
Capital expenditures @ 90%	—			60,306			(8,032		)	60,306
Net proceeds (deficit)	$	(817,504	)	$	276,255		$	(702,947	)	$	1,026,541
Increase (decrease) in deficit	848,604			12,308			848,604			(59,041		)
Net proceeds	$	31,100		$	288,563		$	145,657		$	967,500
Royalty Income (99.99%)	$	31,097		$	288,534		$	145,642		$	967,403

Below is a summary of distributable income for the three and nine months ended September 30, 2006 and 2005:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Royalty Income	$	31,097		$	288,534		$	145,642		$	967,403
Interest income	7,808			1,838			18,017			3,785
General and administrative expenses	(38,905		)	(290,372		)	(163,659		)	(971,188		)
Distributable income	$	—		$	—		$	—		$	—
Distributable income per unit	$	—		$	—		$	—		$	—
Accummulated deficit due PNR (as of end of period)	$	848,519		$	(12,307	)	$	848,519		$	(12,307	)

During the third quarters of 2006 and 2005, the Trust had no distributable income. Royalty income and the reserve for Trust expenses were used to pay the Trust’s third quarter 2006 general and administrative expenses of $262,381.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006			2005		2006			2005
General and administrative costs incurred during the period	$	262,381		$	188,644	$	931,254		$	604,600
Deductions from (additions to) reserve for Trust expenses	(223,476		)	101,728		(767,595		)	366,588
General and administrative costs as reported	$	38,905		$	290,372	$	163,659		$	971,188

General and administrative expenses of the Trust for the third quarter of 2006 increased 39% to $262,381 as compared to $188,644 for the same period in 2005. General and administrative expenses for the first nine months of 2006 increased 54% to $931,254 as compared to $604,600 for the same period in 2005. The increase in general and administrative expenses in 2006 is primarily due to an increase in legal fees as a result of pending litigation discussed in “Legal Proceedings”.

Operational Review

PNR has advised the Trust that during the third quarter of 2006 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 third quarter of 2006 were generally lower than spot market prices in the third quarter of 2005.

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

Brazos A-7 and A-39

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Gross proceeds @ 90%	$	65,057		$	31,227		$	142,483		$	126,051
Operating expenditures @ 90%	(72,479		)	(26,640		)	(107,313		)	(70,865		)
Change in abandonment estimate @ 90%	(810,082		)	—			(810,082		)	—
Capital expenditures @ 90%	—			6,750			—			6,750
Net proceeds (deficit)	$	(817,504	)	$	11,337		$	(774,912	)	$	61,936

The Brazos A-7 and A-39 blocks continued to experience a decrease in natural gas production due to natural production decline. As of September 30, 2006, these two blocks had one well capable of producing, the Brazos A-39 # 5. The Brazos A-7 No. B-1 well, operated by Newfield, is no longer producing as of September 30, 2006. PNR entered into farmout agreements for the Trust’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. In 2005, PNR performed abandonment procedures at the PNR operated Brazos A-7 and the A-39 blocks, with minor sitework clearance remaining. These abandonment procedures have been substantially completed during 2006.

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. Timing for resolution of this issue remains unclear. The last flow rate prior to shut in was 2,800 Mcf a day with 4200 psi flowing tubing pressure, with a gradually declining flowing 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 Trust’s net profits interest, but expressly providing that the farmed out interest would not be subject to the Trust’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 Trust’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 Trust’s net profits interest.

PNR continues to own the undivided one-half interest not burdened by the Trust’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 Trust’s interest in part by Woodside. PNR further noted that the Trust’s net profits interest would not have entitled the Trust to payment until drilling costs and applicable interest were recovered, whereas the overriding royalty interest retained under the Farmout Agreement entitles the Trust 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 Trust. Similarly, the Trust’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.

The Brazos A-7 and A-39 blocks also experienced a significant decrease in operating expenditures.

West Delta 61 and 62

	Three Months Ended September 30,					Nine Months Ended September 30,
	2006		2005			2006			2005
Gross proceeds @ 90%	$	—	$	219,122		$	87,140		$	932,229
Operating expenditures @ 90%	—		(7,760		)	(7,143		)	(21,180		)
Change in abandonment estimate @ 90%	—		—			—			—
Capital expenditures @ 90%	—		—			(8,032		)	—
Net proceeds (deficit)	$	—	$	211,362		$	71,965		$	911,049

Hurricane Katrina struck the Gulf of Mexico in August 2005. The operator of the West Delta properties has 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 as early as the second quarter of 2007. The proceeds for the nine months ended September 30, 2006 consist of revenues adjustments related to prior periods received by the Trust in the nine months ended September 30, 2006.

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 retaining a 12.5% (11.25% net to the Trust) 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. In the third quarter of 2005, the Trust received from PNR proceeds of $53,550 related to the sale of the South Marsh Island 155 platform that was abandoned by PNR and a $6,750 credit for casing related to the PNR Brazos A-39 platform.

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, 2005	$	348,066
Abandonment cost incurred	(348,066		)
Balance, September 30, 2006	$	—

In the third quarter of 2006, PNR notified the Trust that the cash reserve for abandonment and removal costs had been depleted. 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 $1,400,000, net to the Trust. These costs will be deducted from any future gross proceeds on the Royalty properties owned by PNR, which deduction will reduce future Royalty income.

Production and Price Review

Production volumes for natural gas decreased to 9,930 Mcf in the third quarter of 2006 as compared with 27,490 Mcf in the third quarter of 2005. The average sales price received for natural gas in the third quarter of 2006 was $6.44 per Mcf as compared with $6.90 per Mcf in the third quarter of 2005. Crude oil, condensate and natural gas liquids production volumes decreased to 16 barrels in the third quarter of 2006 as compared to 1,437 barrels in the third quarter of 2005. The average sales price in the third quarter of 2006 for crude oil, condensate and natural gas liquids was $66.50 per barrel as compared with $50.69 per barrel in the third quarter of 2005.

Production volumes for natural gas decreased to 26,844 Mcf for the nine months ended September 30, 2006 as compared with 115,038 Mcf for the nine months ended September 30, 2005. The average sales price received for natural gas for the nine months ended September 30, 2006 was $7.78 per Mcf as compared with $6.49 per Mcf for the nine months ended September 30, 2005. Crude oil, condensate and natural gas liquids production volumes decreased to 354 barrels for the nine months ended September 30, 2006 as compared to 6,795 barrels for the nine months ended September 30, 2005. The average sales price for the nine months ended September 30, 2006 for crude oil, condensate and natural gas liquids was $58.63 per barrel as compared with $45.80 per barrel for the nine months ended September 30, 2005.

Termination 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 (the “Termination Threshold”). 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 taken steps to begin the process of liquidating the Trust. See “—Timing of Liquidation” for further update. 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.

Legal Proceedings

compensation to JPMorgan Chase Bank, N.A., (f) recovering monetary damages against Pioneer, Woodside and JPMorgan Chase Bank, N.A., and (g) pursuing exemplary damages against all defendants.

The Trustee will make the full detail of the underlying data of the December 31, 2005 reserve report available for use in connection with the sale of the Trust 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 farmout of interests on the Royalty Properties based on information provided by DeGoyler & MacNaughton (D&M), see pages 22 and 23 of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2005 and Note 6 in the Notes to Financial Statements included elsewhere in the Trust’s Form 10-K for the year ended December 31, 2005. The sale of the assets of the Trust estate may include the related abandonment

liabilities that have not been previously withheld. The final distribution to unitholders will be an amount net of funds required to satisfy all Trust liabilities.

Timing of Liquidation

In connection with this litigation, the Trustee has agreed that it will give MHLP at least 60 days notice prior to the sale of any Trust properties in connection with the termination of the Trust. As of the date of this filing, based on the information currently provided by Pioneer and the preliminary state of the proceeding, the Trustee has not made any definitive conclusions as to the validity of the claims asserted by MHLP. However, the review of reserves by the independent reserve engineer has not shown the existence of significant reserves not previously included in the reserve report prepared by Pioneer in quantities originally alleged in the plaintiff’s petition. The Trustee has performed additional joint venture audits of the Trust properties by an independent auditor. This is a process that the Trust had already begun in its inquiry in the ordinary course as part of the termination of the Trust, and the Trustee will continue to review MHLP’s claims.

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.

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 (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, 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 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 Trustee’s disclosure controls and procedures. Mike Ulrich, as Vice President of The Bank of New York Trust Company, N.A., as attorney-in-fact for JPMorgan Chase Bank, National Association as Trustee of the Trust, has concluded that the disclosure controls and procedures were not effective for purposes of this report due to information and comments received from the managing general partner of the Partnership immediately prior to the filing deadline that did not permit a timely filing.

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 Part I, 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” in the Trust’s Form 10-K for the year ended December 31, 2005 for a description of certain risks relating to these arrangements and reliance.

Changes in Internal Control over Financial Reporting. During the three months ended September 30, 2006, there has been no change in the Trustee’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trustee’s internal control over financial reporting relating to the Trust. 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.

Item 1A. Risk Factors.

There has not been any material changes from the risk factors previously disclosed in response to Part I, Item 1A. “Risk Factors” of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2005.

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., Trustee
	By:	The Bank of New York Trust Company, N.A., as attorney-in-fact
	By:
		*Mike Ulrich*
		*Vice President*

Date: November 14, 2006

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.

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Mesa Offshore Trust (MOSH) Inactive 10-Q2006 Q3 Quarterly report

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