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 2007, 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 and nine months ended September 30, 2008 and 2007:

                                       Three Months Ended        Nine Months Ended
                                         September 30,             September 30,
                                        2008        2007          2008         2007
    Gross oil and gas proceeds @     $  198,416   $   5,664   $  1,050,465   $  29,547
    90%
    Operating expenditures @ 90%        (14,509 )   (70,832 )      (16,801 )   (82,105 )
    Recoupment of abandonment           104,145           -        104,145           -
    expenses @ 90%
    Other proceeds @ 90%                112,780           -        112,780           -

    Net proceeds (deficit)           $  400,832   $ (65,168 ) $  1,250,589   $ (52,558 )
    Increase (decrease) in deficit     (400,832 )    65,168     (1,250,589 )    52,558

    Net proceeds after deficit       $        -   $       -   $          -   $       -
    recovery

    Royalty Income (99.99%)          $        -   $       -   $          -   $       -

                                       Three Months Ended         Nine Months Ended
                                          September 30,             September 30,
                                       2008         2007         2008         2007
    Royalty Income                   $       -   $         -   $       -   $         -
    Interest income                          -             -           -         5,080
    General and administrative               -             -           -        (5,080 )
    expenses

    Distributable income             $       -   $         -   $       -   $         -
    Distributable income per unit    $       -   $         -   $       -   $         -
    Accumulated deficit (as of end   $ 226,538   $ 1,470,467   $ 226,538   $ 1,470,467
    of period)

During the three and nine months ended September 30, 2008 and 2007, the Trust had no distributable income. 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 for the three months ended June 30, 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. Interest income and the reserve for Trust expenses were used to pay $350 of the Trust's third quarter 2007 general and administrative expenses of $1,311,522 and $801,855 of the Trust's general and administrative expenses of $2,285,400 for the nine months ended September 30, 2007. The Trust had unpaid expenses of $120,008 and $1,483,545 as of September 30, 2008 and 2007, respectively.

On September 28, 2007 the Trust entered into a Demand Promissory Note with JPMorgan which was amended on December 3, 2007, in which loans will be advanced by the lender from time to time not to exceed $3.0 million. On August 25, 2008, the Trustee executed an amended and restated Demand Note that among other things increased the aggregate principal amount available for borrowing to $4.0 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, 2008, $3,317,679 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            Nine Months Ended
                                       September 30,                September 30,
                                    2008          2007           2008           2007
   General and administrative
   costs incurred during the
   period                        $  535,254   $  1,311,522   $  1,576,015   $  2,285,400
   Expenses paid by JPMorgan
   for prior period                 146,245              -        190,955              -
   (Deductions from) additions
   to reserve for Trust
   expenses                          (1,050 )         (350 )       (2,900 )     (796,775 )
   Total expenses paid by
   JPMorgan during current
   period                          (672,333 )            -     (1,644,062 )            -
   Unpaid Trust expenses             (8,116 )   (1,311,172 )     (120,008 )   (1,483,545 )

   General and administrative
   costs as reported             $        -   $          -   $          -   $      5,080

General and administrative expenses of the Trust for the three months ended September 30, 2008 decreased $776,268 or 59% to $535,254 as compared to $1,311,522 for the same period in 2007. The decrease in general and administrative expenses for the three months ended September 30, 2008 is

primarily due to a decrease in legal fees. General and administrative expenses of the Trust for the nine months ended September 30, 2008 decreased $709,385 to $1,576,015 or 31% compared to $2,285,400 for the first nine months of 2007. The decrease in general and administrative expenses for the nine months ended September 30, 2008 is primarily due to a decrease 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

Pioneer has advised the Trust that during the third quarter of 2008 and 2007 its offshore gas production was marketed under short-term contracts at spot market prices primarily to TOTAL S.A. and that it expects to continue to market its production under short-term contracts for the foreseeable future. Spot market prices for natural gas in the third quarter of 2008 were generally higher than spot market prices in the third quarter of 2007.

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,
                                           2008        2007        2008        2007
     Gross oil and gas proceeds @ 90%    $  41,147   $   5,664    $ 93,342   $  29,547
     Operating expenditures @ 90%              515     (46,870 )       272     (57,898 )
     Other proceeds @ 90%                        -           -           -           -

     Net proceeds (deficit)              $  41,662   $ (41,206 )  $ 93,614   $ (28,351 )

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, 2008, these two blocks had one well capable of producing, the Brazos A-39 #5 which was shut-in during the first quarter of 2007 due to the detection of mercury. The Brazos A-7 No. B-1 well, operated by Newfield, was no longer producing and abandoned in 2007. Pioneer entered into farmout agreements for the Partnership's interest in both of these blocks so that two exploration prospects could be drilled and in which the Trust will retain an overriding royalty interest. The first prospect on Brazos A-7 was drilled during 2003 and was determined to be a dry hole. As such, the well was plugged and abandoned.

The second exploration prospect, the Brazos A-39 #5, was drilled on Brazos A-39, which Pioneer announced as a discovery. A production test was completed in 2005. Pioneer, 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

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 approved by the MMS. The well returned to production in the fourth quarter of 2007 after the installation of the required safety equipment. The well was shut in October 4, 2008 after discovery of corrosion in the production separator on the host platform. Repair or replacement options for the separator are being evaluated. The last producing rate was 1.4 MM/D with 3200 psi flowing tubing pressure. There can be no assurance regarding 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 Pioneer and Woodside Energy (USA) Inc., Pioneer 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. Pioneer 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 Pioneer. Pioneer 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.

Pioneer 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 Pioneer's remaining undivided one-half interest to equalize those parties participation in the well).

Pioneer has noted to the Trustee that the Farmout Agreement enabled the drilling costs of these prospects to be carried on the Partnership's interest in part by Woodside. Pioneer 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 Pioneer. 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 Pioneer 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 Pioneer'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,
                                         2008        2007         2008         2007
    Gross oil and gas proceeds @       $ 157,269   $       -   $   957,123   $       -
    90%
    Operating expenditures @ 90%         (15,024 )   (23,962 )     (17,073 )   (24,205 )
    Recoupment of abandonment            104,145           -       104,145           -
    expenses @ 90%
    Other proceeds @ 90%                 112,780           -       112,780           -

    Net proceeds (deficit)             $ 359,170   $ (23,962 ) $ 1,156,975   $ (24,205 )

Hurricane Katrina struck the Gulf of Mexico in August 2005. The operator of the West Delta properties informed Pioneer 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 Pioneer that production at West Delta resumed production at all four wells in October 2007. There are currently three wells producing on this block and their combined rate is
1.0 MMcf/day of gas and 100 barrels of oil per day.

The Pioneer-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. Pioneer 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

Pioneer does not anticipate any significant capital expenditures on the Royalty Properties in the future. Due to the limited financial capacity of the Trust, Pioneer 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.

Other Proceeds

During the third quarter of 2008, proceeds for salvage value were received on the Matagorda Island Block 624 of $57,335 and $55,445 for the South Marsh Island 155 Block.

Abandonment Expenditures

In 2006, Pioneer exhausted the $348,066 cash reserve established as of December 31, 2005. In the third quarter of 2006, Pioneer 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, 2008, Pioneer had spent approximately $1.3 million of the $1.4 million estimate. Currently Pioneer believes all major abandonment charges have been incurred and is lowering their estimate to $1.3 million from $1.4 million. The Trust is recouping excess abandonment expenses previously taken. No Royalty income will be distributed to the Partnership until Pioneer recoups the Partnership's portion of abandonment expenses from gross proceeds. As of September 30, 2008 approximately $230,000, net to the Trust, remains to be recouped.

Production volumes for natural gas increased to 5,662 Mcf in the third quarter of 2008 as compared with 745 Mcf in the third quarter of 2007 primarily due to resumed production at all four wells on the West Delta properties. The average sales price received for natural gas in the third quarter of 2008 was $13.85 per Mcf as compared with $7.36 per Mcf in the third quarter of 2007. Crude oil, condensate and natural gas liquids production volumes increased to 1,106 barrels in the third quarter of 2008 as compared to 3 barrels in the third quarter of 2007. The average sales price in the third quarter of 2008 for crude oil, condensate and natural gas liquids was $96.78 per barrel as compared to $61.33 per barrel in the third quarter of 2007.

Production volumes for natural gas increased to 68,492 Mcf for the nine months ended September 30, 2008 as compared with 4,198 Mcf for the nine months ended September 30, 2007. The average sales price received for natural gas in the nine months ended September 30, 2008 increased to $8.47 per Mcf compared with $6.79 per Mcf for the nine months ended September 30, 2007. Crude oil, condensate and natural gas liquids production volumes increased to 4,919 barrels for the nine months ended September 30, 2008 as compared with 19 barrels for the nine months ended September 30, 2007. The average sales price for the nine months ended September 30, 2008 for crude oil, condensate and natural gas liquids was $64.30 per barrel as compared with $53.84 per barrel for the nine months ended September 30, 2007.

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 has previously taken steps to begin the process of liquidating the Trust; however, due to the pending Lawsuit that directly challenges whether the Termination Threshold has in fact been met, the Trustee cannot predict the timing of the sale of all or a portion of the Royalty making up the assets of the Partnership as part of the Trust liquidation and termination. See "-Timing of Liquidation" above in Note 2. The Trustee, which has no authority or discretionary control over the timing of expenditures, production or income on the Royalty Properties, has no 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; however, due to the pending litigation, the Trustee cannot predict the timing of the sale of the assets. 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.

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. However, due to the pending Lawsuit that directly challenges whether the Termination Threshold has in fact been met, the Trustee cannot predict the timing of the sale of all or

a portion of the Royalty making up the Partnership assets as part of the Trust liquidation and termination. The below table presents the assets of the Trust at their estimated fair value:

                             ASSETS
   Cash and short term investments                                $           69
   Net overriding royalty interest in oil and gas properties           1,943,237

        Total assets                                              $    1,943,306

                           LIABILITIES
   Reserve for Trust expenses                                     $           69
   Trust expenses payable                                                120,008
   Interest Payable                                                      178,493
   Note payable-JPMorgan                                               3,317,679

        Total liabilities                                              3,616,249

   Net liabilities in process of liquidation                      $   (1,672,943 )

The net overriding royalty interest in oil and gas properties at September 30, 2008 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, 2008. 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:

º •
º The Trust's estimated share of proved oil and gas reserve volumes at September 30, 2008, which were derived from the December 31, 2007 reserve report prepared by DeGolyer and MacNaughton (D&M) and updated for nine months of 2008 production. The working interest owner has not prepared a reserve report as of September 30, 2008, and therefore any revisions in oil and gas reserves during the first nine months of 2008 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 September 30, 2008. The recent decline in commodity prices has decreased the fair value of the net overriding royalty interest in oil and gas properties.

º •
º Includes approximately $230,000 of abandonment costs.

º •
º Discount rate of 10%.

Liquidity and Capital Resources

In accordance with the provisions of the Trust conveyance, generally all revenues received by the Trust, net of Trust administrative expenses and any cash reserves established for the payment of contingent or future obligations of the Trust, are distributed currently to the unitholders. Based on the current general and administrative expenditures being incurred in connection with the litigation and the absence of Royalty income, the Trustee was required to borrow money in accordance with the Trust Indenture to fund Trust expenses. On September 28, 2007, the Trust entered into a Demand Promissory Note agreement with JPMorgan in order to cover portions of its operating expenses. The lender approved an uncommitted line of credit to the Trust in a principal amount not to exceed $3.0 million. As part of that agreement, JPMorgan pays the expenses on behalf of the Trust. JPMorgan may decline to fund any request of the Trust for borrowings at anytime, for any reason, including the event that JPMorgan has reason to believe that the Trust will not be able to satisfy its obligation to repay the

Demand Loans. Interest on the note is calculated at a rate per annum equal to Prime Rate plus two percent (2%), paid annually. The rate effective as of September 30, 2008 was a Prime Rate of 5%, plus 2% for a combined rate of 7%. The Demand Promissory Note is secured by a pledge of the Trust Estate, as that term is defined in the Trust Indenture, including without limitation the 99.99% general partnership interest in the Mesa Offshore Royalty Partnership owned by the Trust, pursuant to a Pledge Agreement dated September 29, 2007, as amended by the First Amendment to Pledge Agreement dated as of December 3, 2007, executed by the Trust for the benefit of the Lender. The Trust may borrow amounts under this Note until such time as JPMorgan makes demand for payment in full or December 31, 2008, whichever is earlier.

On December 3, 2007, JPMorgan, individually and as lender, entered into an Amended and Restated Promissory Note with the Trust as borrower, to amend the Demand Promissory Note to provide for, among other provisions, an extension of the stated maturity date of the Loans made pursuant to the Demand Promissory Note and the Amended and Restated Note until the earlier of (1) December 31, 2009, (2) 31 days after the Trust's receipt of any settlement proceeds, recovery or judgment in connection with the Lawsuit, (3) final liquidation of the Trust's . . .