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.

Below is a summary of Royalty income received on the Trust properties for the three months and six months ended June 30, 2009 and 2008:

                                            Three Months Ended        Six Months Ended
                                                 June 30,                 June 30,
                                            2009         2008        2009         2008
 Gross proceeds @ 90%                     $ 102,758   $  385,582   $ 174,547   $  852,050
 Operating expenditures @ 90%                  (185 )          3      (3,263 )     (2,291 )
 Expense reserve @ 90%                            -            -           -            -
 Capital expenditures @ 90%                       -            -           -            -

 Net proceeds (deficit)                   $ 102,573   $  385,585   $ 171,284   $  849,759
 Increase (decrease) in deficit                   -     (385,585 )         -     (849,759 )

 Net proceeds after deficit recovery(1)   $ 102,573   $        -   $ 171,284   $        -

 Royalty Income (99.99%)                  $ 102,563   $        -   $ 215,130   $        -

                                       Three Months Ended         Six Months Ended
                                            June 30,                  June 30,
                                        2009         2008         2009         2008
    Royalty income                   $  102,563   $        -   $  215,130   $        -
    Interest income                          25            -           46            -
    General and administrative         (102,588 )          -     (215,176 )          -
    expenses

    Distributable income             $        -   $        -   $        -   $        -
    Distributable income per unit    $        -   $        -   $        -   $        -
    Accumulated deficit (as of end   $        -   $ (627,329 ) $        -   $ (627,329 )
    of period)

During the first and second 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 were used to pay $531,627 of the Trust's general and administrative expenses of $992,557 for the three months ended June 30, 2009 and $79,909 of accrued expenses from the first quarter of 2009. The reserve for Trust expenses and advances under the Demand Promissory Note with JPMorgan were used to pay $1,140,601 of the Trust's general and administrative expenses of $1,695,153 for the six months ended June 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 $168,875 of the Trust's general and administrative expenses of $412,012 for the three months ended June 30, 2008 and $15,000 of accrued expenses from the first quarter of 2008. The reserve for Trust expenses and advances under the Demand Promissory Note with JPMorgan were used to pay $973,579 of the Trust's general and administrative expenses of $1,040,761 for the six months ended June 30, 2008 and $190,955 of accrued expenses from 2007. The Trust had unpaid expenses of $474,644 and $258,137 as of June 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 June 30, 2009, $4,996,125 has been advanced to the Trust to pay Trust expenses.

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

                                     Three Months Ended           Six Months Ended
                                          June 30,                    June 30,
                                      2009         2008          2009          2008
   General and administrative
   costs incurred during the
   period                          $  992,557   $  412,012   $  1,695,153   $ 1,040,761
   (Deductions from) additions
   to reserve for Trust expenses       51,014       (1,750 )      162,551        (1,850 )
   Total expenses paid by
   JPMorgan during current
   period                            (559,961 )   (167,125 )   (1,438,479 )    (971,729 )
   Unpaid trust expenses             (474,644 )   (258,137 )     (474,644 )    (258,137 )
   Unpaid trust expenses from
   prior period                        93,622       15,000        270,595       190,955

   General and administrative
   costs as reported               $  102,588   $        -   $    215,176   $         -

General and administrative expenses of the Trust incurred during the second quarter of 2009 increased $580,545 or 141% to $992,557 as compared to $412,012 for the same period in 2008. The

increase in general and administrative expenses in 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. General and administrative expenses of the Trust for the six months ended June 30, 2009, increased $654,392 or 63% to $1,695,153 compared to $1,040,761 for the first six months of 2008. The increase in general and administrative expenses in the six months ended June 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 second 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 second quarter of 2009 were generally lower than spot market prices in the second 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       Six Months Ended
                                             June 30,                June 30,
                                         2009         2008       2009        2008
       Gross proceeds @ 90%            $   2,605    $ 35,112    $  5,974   $ 52,196
       Operating expenditures @ 90%         (184 )         3      (3,262 )     (245 )
       Capital expenditures @ 90%              -           -           -          -

       Net proceeds (deficit)          $   2,421    $ 35,115    $  2,712   $ 51,951

The Brazos A-39 block continued to experience a decrease in natural gas production due to natural production decline. As of June 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 is currently producing at approximately 1.5 MM/D with a gradually declining flowing tubing pressure. There can be 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.

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       Six Months Ended
                                             June 30,                June 30,
                                         2009        2008        2009        2008
       Gross proceeds @ 90%            $ 100,153   $ 350,470   $ 168,573   $ 799,854
       Operating expenditures @ 90%            -           -           -      (2,046 )
       Capital expenditures @ 90%              -           -           -           -

       Net proceeds (deficit)          $ 100,153   $ 350,470   $ 168,573   $ 797,808

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 June 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 decreased to 5,549 Mcf in the second quarter of 2009 as compared with 30,829 Mcf in the second quarter of 2008 primarily due to the shut-in of the Brazos A-39 #5 well between October 4, 2008 and March 19, 2009. The average sales price received for natural gas in the second quarter of 2009 was $5.12 per Mcf as compared with $9.10 per Mcf in the second quarter of 2008. Crude oil, condensate and natural gas liquids production volumes increased to 1,846 barrels in the second quarter of 2009 as compared to 1,089 barrels in the second quarter of 2008. The average sales price in the second quarter of 2009 for crude oil, condensate and natural gas liquids was $40.26 per barrel as compared to $96.35 per barrel in the second quarter of 2008. Production volumes for natural gas decreased to 9,483 Mcf for the six months ended June 30, 2009 as compared with 62,830 Mcf in the first six months of 2008. The average sales price received for natural gas in the six months ended June 30, 2009 was $6.04 per Mcf as compared with $7.98 per Mcf in the first six months of 2008. Crude oil, condensate and natural gas liquids production volumes decreased to 2,426 barrels in the six months ended June 30, 2009 as compared to 3,813 barrels in the first six months of 2008. The average sales price in the six months ended June 30, 2009 for crude oil, condensate and natural gas liquids was $48.32 per barrel as compared to $91.93 per barrel in the first six 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 challenge whether the Termination Threshold has 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 had previously provided notice of another public auction of the Partnership's oil and gas assets, to be held on August 12, 2009, but this public auction has been postponed. In a judgment dated August 6, 2009, 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 an Agreed Final Judgment. The parties to the settlement agreement have therefore decided to postpone the sale of the Partnership's oil and gas assets until the Agreed Final Judgment is signed by the Court. 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 is approved and an Agreed Final Judgment is entered by the Court in the Lawsuit, the Trustee will direct 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                                $      162,620
   Net overriding royalty interest in oil and gas properties           1,177,541

        Total assets                                              $    1,340,161

                                    LIABILITIES
   Reserve for Trust expenses                                     $      162,620
   Trust expenses payable                                                474,644
   Interest Payable                                                      344,563
   Note payable-JPMorgan                                               4,996,125

        Total liabilities                                              5,977,952

   Net liabilities in process of liquidation                      $   (4,637,791 )

º •
º The Trust's estimated share of proved oil and gas reserve volumes at June 30, 2009, which were derived from the December 31, 2008 reserve report prepared by DeGolyer and MacNaughton (D&M) and updated for first and second quarter 2009 production. The working interest owner has not prepared a reserve report as of June 30, 2009, and therefore any revisions in oil and gas reserves during the first six months of 2009 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.

º •
º Forward strip commodity prices on June 30, 2009 and then escalated 2% thereafter.

º •
º Discount rate of 10%.

º •
º Future income taxes were not taken into account.

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 is currently 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 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, MOSH later added claims against the Trustee for (1) an accounting, and (2) breach of fiduciary duty. The remedies MOSH 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 MOSH 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, . . .