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.

Critical Accounting Policies

The financial statements of the Trust do not include any adjustment as a result of the termination of the Trust as described in notes 1 and 2 and 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 sold by the working interest owner for such month or the amount subsequently determined to be 90% of the net proceeds for such month;

(b) Interest income, interest receivable and distributions payable to unitholders include interest to be earned on short-term investments from the financial statement date through the next date of distribution; and

(c) Trust general and administrative expenses are recorded in the month they accrue and are recoupable from Royalty income. Trust expenses payable and the note payable at December 31, 2008 are reported as a reduction in Trust Corpus.

This basis for reporting distributable 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 sales 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, and accounting principles generally accepted in the United States may require a liquidation basis of accounting.

Status of the Trust

Hurricane Katrina struck the Gulf of Mexico in August 2005. The operator of the West Delta properties informed PNR that the West Delta properties were shut in since August 27, 2005 due to damage to the platform, the pipeline, and the sales terminal, until production at West Delta resumed at all four wells in the fourth quarter of 2007 at a combined production rate of 4.8 MMCFD. There are currently four wells producing on this block, and their combined rate is
1.2 MMCF/day and 200 barrels of oil per day.

The Trust Indenture provides that the Trust will liquidate and terminate if the total amount of cash per year received by the Trust falls below certain levels for each of three successive years. As a result of continued declines in production on Royalty Properties nearing the end of their estimated productive lives, Royalty income received by the Trust in 2002, 2003 and 2004 fell below the Termination Threshold prescribed by the Trust Indenture. The Trustee 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. Now, due to the continuation of the litigation into its fourth year, the related cost to the Trust, the threat that the properties might 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 at this time, and the Court allowed a public auction of these assets to go forward. See "Business-Timing of Liquidation" in Item 1 of this Form 10-K. However, at the public auction conducted on March 18, 2009, there were no bids

submitted. The Trustee is considering its options under the Trust Indenture and in light of the pending litigation. 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 regarding the occurrence of the Termination Threshold or its consequences. However, pursuant to a stipulation announced in open court relating to the public auction, the Trustee has agreed to give 60-days notice before any final wind-up of the Trust.

The Trust Indenture provides the Trustee a two-year period during which it must sell all of the assets of the Partnership; but in light of the pending litigation and the results from the recent public auction, the Trustee cannot predict the timing of the sales 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 any future 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.

Below is additional information regarding the Trust properties provided by D&M:

Properties producing as of December 31, 2008

                                 Number of    Estimated       Estimated
                                 Producing    Productive    Future Royalty
            Property             wells(1)      Life(1)        Income(2)
            West Delta No. 61             4      6 years    $     1,304,858
            Brazos A-39                   1      3 years    $       188,676


          ----------------------------------------------------------------------
             º (1)

º (2)
º Represents estimated future royalty income from the December 31, 2008 reserve report. Future royalty income was calculated using oil and gas spot prices in effect at December 31, 2008 of $44.60 per barrel and $5.71 per thousand cubic feet.

Properties abandoned or scheduled for abandonment as of December 31, 2008

                 Property                      Status
                 Brazos A-7         Abandoned in 2005 (Newfield
                                    platform abandoned in 2007)
                 Brazos A-39        Plug and abandonment
                                    procedures completed in 2005
                                    (excluding Midway prospect)*
                 West Delta 62      Plug and abandonment
                                    procedures completed in 2003
                 South Marsh        Plug and abandonment
                 Island 155         procedures completed in 2002
                 South Marsh        Plug and abandonment
                 Island 156         procedures completed in 2002
                 Vermillion 381     Plug and abandonment
                                    procedures completed in 1989
                 South Pelto 12     Plug and abandonment
                                    procedures completed in 1986
                 Matagorda          Plug and abandonment
                 Island 624         procedures completed in 2003
                 High Island 567    Plug and abandonment
                                    procedures completed in 1992


          ----------------------------------------------------------------------
             º *

Financial and Operational Review

As discussed in Item 1 of this Form 10-K, PNR has advised the Trust that during 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 were on the average higher in 2008 than spot market prices in 2007.

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 each of the years ended December 31, 2008, 2007 and 2006:

                                                2008         2007          2006
     Gross proceeds @ 90%                   $  1,328,010   $  29,550   $    239,356
     Operating expenditures @ 90%                (22,432 )   (88,649 )     (103,476 )
     Change in abandonment estimate @ 90%        102,658           -     (1,400,139 )
     Other proceeds (expenditures) @ 90%         112,780           -         (8,034 )

     Net proceeds (deficit)                    1,521,016     (59,099 )   (1,272,293 )
     Increase (decrease) in deficit           (1,477,149 )    59,099      1,417,950

     Net proceeds after deficit recovery    $     43,867           -        145,657

     Royalty income (99.99%)(1)             $          -   $       -   $    145,642

Below is a summary of distributable income for the years ended December 31, 2008, 2007 and 2006:

                                                    Years Ended December 31,
                                               2008        2007           2006
      Royalty income                           $   -   $          -   $    145,642
      Interest income                              -          5,080         29,293
      General and administrative expenses         (- )       (5,080 )     (174,935 )

      Distributable income                     $   -   $          -   $          -

      Distributable income per unit            $   -   $          -   $          -
      Accumulated deficit (as of period end)   $  (- ) $ (1,477,002 ) $ (1,417,808 )

The Trust had no distributable income in 2008, 2007 and 2006. The reserve for Trust expenses and advances under the Demand Promissory Note with JPMorgan were used to pay $1,886,932 of the Trust's general and administrative expenses of $1,966,572 for the year ended December 31, 2008 and $190,955 of accrued expenses from 2007. The Trust had unpaid expenses of $270,595 as of December 31, 2008 as compared to $190,955 as of December 31, 2007. The reserve for Trust expenses and interest income were used to pay $802,155 of the Trust's general and administrative expenses of

$2,666,727 for the year ended December 31, 2007. The Trust had unpaid expenses of $190,955 as of December 31, 2007. On September 28, 2007 the Trust entered into a Demand Promissory Note with JPMorgan which was amended on December 3, 2007 and August 25, 2008, in which loans will be advanced by the lender from time to time not to exceed $4 million. This Demand Promissory Note will be used to pay any unpaid administrative expenses related to the operation of the Trust. As of December 31, 2008, approximately $3,557,646 has been advanced to the Trust to pay Trust expenses. On January 28, 2009, the Trustee executed and delivered to JPMorgan a Third Amended and Restated Promissory Note, dated as of January 12, 2009, increasing the principal amount available for borrowing, subject to the terms of such note, to $5 million.

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

                                             Years Ended December 31,
                                        2008           2007           2006
         General and
         administrative costs
         incurred during the year   $  1,966,572   $  2,666,727   $  1,223,271
         Expenses paid by
         JPMorgan for prior
         period                          190,955              -              -
         (Deductions from)
         additions to reserve for
         trust expenses                   (2,900 )     (797,075 )   (1,048,336 )
         Total expenses paid by
         JP Morgan during current
         period                       (1,884,032 )   (1,673,617 )            -
         Unpaid trust expenses          (270,595 )     (190,955 )            -

         General and
         administrative costs as
         reported                   $          -   $      5,080   $    174,935

General and administrative expenses of the Trust for 2008 decreased 26% to $1,966,569 for 2008 as compared to $2,666,727 for 2007. The decrease in general and administrative expenses in 2008 is primarily due to a decrease in legal fees in the 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 2007 increased 118% to $2,666,727 for 2007 as compared to $1,223,271 for 2006. The increase in general and administrative expenses in 2007 is primarily due to an increase in legal fees in the pending litigation as described in "Legal Proceedings." The Trust incurred additional expenditures in 2005 for the independent reserve studies performed as of March 31, 2005 and December 31, 2005 and for the independent joint venture auditor to perform a review of certain historical expenditures and revenue receipts on Trust properties.

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

Brazos A-7 and A-39

                                               2008        2007          2006
      Gross proceeds @ 90%                   $ 124,818   $  29,550   $    152,215
      Operating expenditures @ 90%                (748 )   (60,705 )      (87,211 )
      Change in abandonment estimate @ 90%           -        (373 )   (1,269,806 )
      Capital expenditures @ 90%                     -           -              -

      Net proceeds (deficit)                 $ 124,070   $ (31,528 ) $ (1,204,802 )

The Brazos A-7 and A-39 blocks continued to experience a decrease in natural gas production due to natural production decline. As of December 31, 2008, these two blocks had one well capable of

producing, the Brazos A-39 #5 well, which was shut-in during the first quarter of 2007 due to the detection of mercury. The Brazos A-7 No. B-1 well, operated by Newfield, was no longer producing as of December 31, 2006 and was abandoned in 2007. PNR previously entered into farmout agreements in 2003 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. In 2005, PNR performed abandonment procedures at the PNR operated Brazos A-7 and the A-39 blocks, with minor sitework clearance remaining. In 2005, the Trust received a $6,750 credit for casings related to the PNR platform at Brazos A-39. These abandonment procedures were substantially completed during 2006.

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 Mineral 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 1.4-1.7 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

                                                  2008         2007         2006
     Gross proceeds @ 90%                      $ 1,203,192   $       -   $   87,141
     Operating expenditures @ 90%                  (21,684 )   (27,944 )    (16,265 )
     Change in abandonment expenditures @90%       102,658         373     (130,333 )
     Capital expenditures @ 90%                    112,780           -       (8,034 )

     Net proceeds (deficit)                    $ 1,396,946   $ (27,571 ) $  (67,491 )

Hurricane Katrina struck the Gulf of Mexico in August 2005. The operator of the West Delta properties informed PNR that the West Delta properties were shut in since August 27, 2005 due to damage to the platform, the pipeline, and the sales terminal, until production at West Delta resumed at all four wells in the fourth quarter 2007. There are currently four wells producing on this block, and their combined rate is 1.2 MMcf/day and 200 barrels of oil per day. The proceeds for the year ended December 31, 2006 consist of revenue adjustments related to prior periods received by the Trust during 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 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

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.

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

    The below table provides a rollforward of the abandonment and removal costs
cash reserve that PNR has withheld from the Partnership and the Trust since
January 1, 2004:

              Balance, January 1, 2004                  $  2,800,643
              Abandonment cost incurred (Mat.
              Is. 624 & WD 62)                              (124,492 )

              Balance, December 31, 2004                $  2,676,151
              Abandonment cost incurred (Brazos A-7A,
              A-7 #4, A-39A1A, A-2 and A-3A)              (2,328,085 )

              Balance, December 31, 2005                $    348,066
              Abandonment cost incurred (Brazos A-7
              #4, A-39A1A, A-2 and A-3A Matagorda
              Island 624, South Marsh Island 155)           (348,066 )

              Balance, December 31, 2006                $          -

              Balance, December 31, 2007                $          -

              Balance, December 31, 2008                $          -

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 March 31, 2008, PNR had spent approximately $1.3 million of the $1.4 million estimate. Currently 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.

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 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 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