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 2008, 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.

                                           Three Months Ended        Nine Months Ended
                                             September 30,             September 30,
                                           2009         2008        2009          2008
Gross proceeds @ 90%                     $  87,295   $  198,416   $ 261,842   $  1,050,465
Operating expenditures @ 90%                (1,173 )    (14,509 )    (4,436 )      (16,801 )
Expense reserve @ 90%                            -            -           -              -
Recoupment of abandonment expenses @
90%                                              -      104,145           -        104,145
Other proceeds @ 90%                             -      112,780           -        112,780
Capital expenditures @ 90%                       -            -           -              -
Net proceeds (deficit)                   $  86,122   $  400,832   $ 257,406   $  1,250,589
Increase (decrease) in deficit                   -     (400,832 )         -     (1,250,589 )

Net proceeds after deficit recovery(1)   $  86,122   $        -   $ 257,406   $          -

Royalty Income (99.99%)                  $  86,113   $        -   $ 301,243   $          -

Below is a summary of distributable income for the three and nine months ended September 30, 2009 and 2008:

                                             Three Months Ended       Nine Months Ended
                                               September 30,            September 30,
                                              2009        2008         2009        2008
Royalty income                             $   86,113   $       -   $  301,243   $       -
Interest income                                     7           -           53           -
General and administrative expenses           (86,120 )         -     (301,296 )         -

Distributable income                       $        -   $       -   $        -   $       -
Distributable income per unit              $        -   $       -   $        -   $       -
Accumulated deficit (as of end of
period)                                    $        -   $ 226,538   $        -   $ 226,538

During the first, second and third quarters of 2009 and 2008, the Trust had no distributable income. The reserve for Trust expenses and advances under the Demand Promissory Note with JPMorgan and other advances were used to pay $215,587 of the Trust's general and administrative expenses of $373,326 for the three months ended September 30, 2009 and $249,601 of accrued expenses from the second quarter of 2009. The reserve for Trust expenses and advances under the Demand Promissory Note and other advances with JPMorgan were used to pay $1,605,829 of the Trust's general and administrative expenses of $2,068,479 for the nine months ended September 30, 2009, and $270,595 of accrued expenses from 2008. The reserve for Trust expenses and advances under the Demand Promissory Note with JPMorgan were used to pay $673,383 of the Trust's general and administrative expenses of $535,254 for the three months ended September 30, 2008 and $146,245 of accrued expenses from the second quarter of 2008. The reserve for Trust expenses and advances under the Demand

Promissory Note with JPMorgan were used to pay $1,646,962 of the Trust's general and administrative expenses of $1,576,015 for the nine months ended September 30, 2008 and $190,955 of accrued expenses from 2007. The Trust had unpaid expenses of $382,741 and $120,008 as of September 30, 2009 and 2008, respectively.

On September 28, 2007 the Trust entered into a Demand Promissory Note with JPMorgan which was amended on December 3, 2007, August 25, 2008 and January 12, 2009, in which loans will be advanced by the lender from time to time not to exceed $5 million. This Demand Promissory Note will be used to pay any unpaid administrative expenses related to the operation of the Trust. As of September 30, 2009, $5,260,198 has been advanced to the Trust to pay Trust expenses, including $5.0 million under the Demand Promissory Note.

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

                                       Three Months Ended           Nine Months Ended
                                          September 30,               September 30,
                                        2009         2008          2009           2008
General and administrative costs
incurred during the period           $  373,326   $  535,254   $  2,068,479   $  1,576,015
(Deductions from) additions to
reserve for Trust expenses             (115,036 )     (1,050 )       47,515         (2,900 )
Total expenses paid by JPMorgan
during current period                  (264,073 )   (672,333 )   (1,702,552 )   (1,644,062 )
Unpaid trust expenses                  (382,741 )     (8,116 )     (382,741 )     (120,008 )
Unpaid trust expenses from prior
period                                  474,644      146,245        270,595        190,955

General and administrative costs
as reported                          $   86,120   $        -   $    301,296   $          -

General and administrative expenses of the Trust incurred during the third quarter of 2009 decreased $161,928 or 30% to $373,326 as compared to $535,254 for the same period in 2008. General and administrative expenses of the Trust for the nine months ended September 30, 2009, increased $492,464 or 31% to $2,068,479 compared to $1,576,015 for the first nine months of 2008. The increase in general and administrative expenses in the nine months ended September 30, 2009 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 third quarter of 2009 and 2008 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 2009 were generally lower than spot market prices in the third quarter of 2008.

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       Nine Months Ended
                                          September 30,            September 30,
                                         2009         2008        2009        2008
       Gross proceeds @ 90%           $    21,966   $ 41,147   $   27,940   $ 93,342
       Operating expenditures @ 90%        (1,173 )      515       (4,436 )      272
       Capital expenditures @ 90%               -          -            -          -

       Net proceeds (deficit)         $    20,793   $ 41,662   $   23,504   $ 93,614

The Brazos A-39 block continued to experience a decrease in natural gas production due to natural production decline. As of September 30, 2009, this block 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 #B-1 well, operated by Newfield, was no longer producing and abandoned in 2007. PNR previously 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 well, 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, 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 Beryl Oil and Gas. 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. Pioneer implemented a hydrogen sulfide contingency plan, which was required and approved by the Minerals Management Service ("MMS"), including the installation of the necessary alarm and safety systems. The well was shut in October 4, 2008 after discovery of corrosion in the production separator on the host platform. A replacement production separator was installed on the host platform. The well was returned to production on March 19, 2009. The well was producing at a

rate of approximately 1.5 MM/D with a gradually declining flowing tubing pressure; however, there was no assurance regarding the longevity of the gas production on the 52C host platform. Blending with this gas is required to meet pipeline gas quality specifications. Since September 1, 2009, Arena's well has not been producing and as a result, the PNR well is shut-in.

Arena has made several attempts to unload accumulated fluid from the well and return it to production with no results to date. Arena is currently evaluating additional options including economics associated with these options. Arena will advise when they have decided on next steps, if any, to return the well to production.

Under the terms of a farmout agreement between PNR and Woodside, 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 with Woodside 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        Nine Months Ended
                                              September 30,             September 30,
                                             2009        2008        2009         2008
Gross proceeds @ 90%                      $   65,329   $ 157,269   $ 233,902   $   957,123
Operating expenditures @ 90%                       -     (15,024 )         -       (17,073 )
Recoupment of abandonment expenses @
90%                                                -     104,145           -       104,145
Other proceeds @ 90%                               -     112,780           -       112,780
Capital expenditures @ 90%                         -           -           -             -

Net proceeds (deficit)                    $   65,329   $ 359,170   $ 233,902   $ 1,156,975

There are currently three wells producing on this block, and their combined rate is 1.0 MMcf/day and 100 barrels of oil per day.

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. Those properties were sold to Maritech Resources Inc. effective October 1, 2007. Maritech began accounting for the properties on February 1, 2008.

Capital Expenditures

The Trustee has been advised that 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 Partnership's interest in the blocks it believes may be produced economically, retaining an overriding royalty interest for the Partnership.

Abandonment Expenditures

In 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 September 30, 2009, PNR had spent approximately $1.3 million of the $1.4 million estimate. PNR believes all major abandonment charges have been incurred. On December 18, 2008, PNR informed the Trustee that there is no longer a deficit balance due for abandonment accrual for amounts expended and for projected future abandonment expenses for the properties in which the Trust has an interest.

Production and Price Review

Production volumes for natural gas increased to 14,300 Mcf in the third quarter of 2009 as compared with 5,662 Mcf in the third quarter of 2008 primarily due to production increases in West Delta 61. The average sales price received for natural gas in the third quarter of 2009 was $3.87 per

Mcf as compared with $13.85 per Mcf in the third quarter of 2008. Crude oil, condensate and natural gas liquids production volumes decreased to 688 barrels in the third quarter of 2009 as compared to 1,106 barrels in the third quarter of 2008. The average sales price in the third quarter of 2009 for crude oil, condensate and natural gas liquids was $46.34 per barrel as compared to $96.78 per barrel in the third quarter of 2008. Production volumes for natural gas decreased to 23,783 Mcf for the nine months ended September 30, 2009 as compared with 68,492 Mcf in the first nine months of 2008. The average sales price received for natural gas in the nine months ended September 30, 2009 was $4.74 per Mcf as compared with $8.47 per Mcf in the first nine months of 2008. Crude oil, condensate and natural gas liquids production volumes decreased to 3,114 barrels in the nine months ended September 30, 2009 as compared to 4,919 barrels in the first nine months of 2008. The average sales price in the nine months ended September 30, 2009 for crude oil, condensate and natural gas liquids was $47.89 per barrel as compared to $64.30 per barrel in the first nine months of 2008.

Termination of the Trust

The Trust Indenture provides that the Trust will liquidate 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 insufficient 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 had previously taken steps to begin the process of liquidating the Trust; however, the legal proceedings described herein directly challenged whether the Termination Threshold had in fact been met and thus affected the liquidation process, such that the Trustee initially delayed the sale of the Partnership's oil and gas assets in efforts to investigate and resolve the claims. However, due to the continuation of the litigation for more than four years, the related cost to the Trust, the threat that the properties might soon revert back to the MMS, and the opportunity to realize greater proceeds for the benefit of the Trust estate, the Trustee concluded that a public auction of the Partnership's oil and gas assets was in the best interest of the Trust, and the Court had allowed a public auction of these assets to go forward. The Trustee therefore instructed Pioneer to proceed with a public auction of the Partnership's assets on March 18, 2009, and Pioneer complied; but there were no bids submitted at the auction, in the face of the pending litigation by the Plaintiffs described in Part I, Item I, Financial Statements, Note 2. The Trustee then provided notice of another public auction of the Partnership's oil and gas assets, to be held on August 12, 2009. However, this public auction did not go forward, based on a judgment dated August 6, 2009, in which the Court approved the parties' settlement agreement (as detailed in "-Legal Proceedings" below), but held that there was an outstanding procedural issue that needed to be addressed prior to entry of final judgment. The parties to the settlement agreement therefore decided to postpone the sale of the Partnership's oil and gas assets until the Court entered final judgment resolving all issues in the litigation, which took place on September 14, 2009. In accordance with the final judgment and the settlement agreement, the Trustee instructed Pioneer to proceed with a public auction of the Partnership's assets on November 11, 2009. At the November 11, 2009 auction, the highest bidder for the Partnership's assets in the West Delta 61 Block was Emerald Energy, with a sales price of $700,000. The assets of the Partnership and Pioneer in the Brazos A-39 Block did not receive any bids in the auction. Pioneer is entitled to dispose of the Brazos A-39 Block assets in any manner it sees fit, and the Trustee is currently awaiting Pioneer's determination regarding how it will dispose of these assets and the timing for such dispositions, including potentially electing to plug and abandon the property. Any resulting sales proceeds will be remitted to the Trust as part of the wind-down process. The Trustee, which has no

authority or discretionary control over the timing of expenditures, production or income on the Royalty Properties, has no control over 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 assets of the Partnership. The Trust Indenture provides that such properties must be sold for cash and not for any other consideration. 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.

Assets and Liabilities in the Process of Liquidation

As a result of the triggering of the Termination Threshold effective January 1, 2005, the Trust is in the process of liquidation. After a Final Settlement Agreement was approved and Final Judgment was entered by the Court in the Lawsuit, the Trustee directed Pioneer to sell the Partnership assets (along with the Pioneer Settlement Interests), consistent with the terms contained in the Term Sheet and as approved by the Court, at public auction and any resulting sales proceeds will be remitted to the Trust as part of the wind-down process. See "-Legal Proceedings" below. The below table presents the assets of the Trust at their estimated fair value:

                             ASSETS
   Cash and short term investments                               $        47,584
   Net overriding royalty interest in oil and gas properties             700,000

        Total assets                                             $       747,584

                           LIABILITIES
   Reserve for Trust expenses                                    $        47,584
   Trust expenses payable                                                382,741
   Interest Payable                                                      410,676
   Note and advances payable-JPMorgan                                  5,260,198

        Total liabilities                                              6,101,199

   Net liabilities in process of liquidation                     $    (5,353,615 )

The net overriding royalty interest in oil and gas properties at September 30, 2009 reflect the Trustee's estimate of value (in the absence of third-party appraisals or evaluations) based on the price received at auction on November 11, 2009.

Legal Proceedings

On April 11, 2005, MOSH Holding, L.P. ("MOSH") filed an Original Petition in the District Court of Travis County, Texas, 250th Judicial District, against PNRC; PNR (together with PNRC, "Pioneer");

Woodside Energy (USA), Inc. ("Woodside"); and JPMorgan, as Trustee of the Mesa Offshore Trust (Case No. GN501113) (the "Lawsuit"). The Lawsuit was pending before the 334th Judicial District of Harris Country, Texas (the "Court"). MOSH's Original Petition alleged 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 drilled thereon, (3) fraudulent accounting practices by Pioneer, (4) breach of fiduciary duty by Pioneer, (5) aiding and . . .