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.

The financial statements of the Trust are prepared on the following basis:

(a) Royalty income recorded for a month is the Trust's interest in the amount computed and paid by the working interest owner to the Partnership for such month rather than either the value of a portion of the oil and gas 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, 2007 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.

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 have been shut in since August 27, 2005 due to damage to the platform, the pipeline and the sales terminal. The operator has notified PNR that production at West Delta resumed at all four wells in the fourth quarter of 2007 at a combined production rate of 4.8 MMCFD.

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 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 "Business-Timing of Liquidation" in Item 1 of this Form 10-K. 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.

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 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.

Properties producing as of December 31, 2007

                                                             Estimated
                                   Number of   Estimated      Future
                                   Producing   Productive     Royalty
               Property            wells(1)     Life(1)      Income(2)
               -----------------   ---------   ----------   -----------
               West Delta No. 61           3      7 years   $ 2,567,975
               Brazos A-39                 1      4 years   $   332,264


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

º (2)
º Represents estimated future royalty income from the December 31, 2007 reserve report. Future royalty income was calculated using oil and gas spot prices in effect at December 31, 2007 of $92.52 to $92.63 per barrel and $6.94 to $7.03 per thousand cubic feet.

Properties abandoned or scheduled for abandonment as of December 31, 2007

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 Island 155       Plug and abandonment procedures completed in 2002
South Marsh Island 156       Plug and abandonment procedures completed in 2002
Vermillion 381               Plug and abandonment procedures completed in 1989
South Pelto 12               Plug and abandonment procedures completed in 1986
Matagorda Island 624         Plug and abandonment 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 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 were on the average lower in 2007 than spot market prices in 2006.

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.

                                              2007          2006          2005
                                            ---------   ------------   -----------
     Gross proceeds @ 90%                   $  29,550   $    239,356   $ 2,085,418
     Operating expenditures @ 90%             (88,649 )     (103,476 )    (104,265 )
     Change in abandonment estimate @ 90%           -     (1,400,139 )           -
     Capital expenditures @ 90%(1)                  -         (8,034 )     375,338
                                            ---------   ------------   -----------
     Net proceeds (deficit)                   (59,099 )   (1,272,293 )   2,356,491
     Increase (decrease) in deficit            59,099      1,417,950       (71,349 )
                                            ---------   ------------   -----------
     Net proceeds after deficit recovery            -        145,657     2,285,142
                                            ---------   ------------   -----------
     Royalty income (99.99%)                $       -   $    145,642   $ 2,284,914
                                            ---------   ------------   -----------


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

Below is a summary of distributable income for the years ended December 31, 2007, 2006 and 2005:

                                                    Years Ended December 31,
                                           ------------------------------------------
                                               2007           2006           2005
                                           ------------   ------------   ------------
  Royalty income                           $          -   $    145,642   $  2,284,914
  Interest income                                 5,080         29,293          8,512
  General and administrative expenses            (5,080 )     (174,935 )   (2,293,426 )
                                           ------------   ------------   ------------
  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 2007, 2006 and 2005. Interest income and the reserve for Trust expenses 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, in which loans will be advanced by the lender from time to time not to exceed $3.0 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, 2007, approximately $1,673,617 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:

                                                    Years Ended December 31,
                                            -----------------------------------------
                                                2007           2006          2005
                                            ------------   ------------   -----------
   General and administrative costs
   incurred during the year                 $  2,666,727   $  1,223,271   $   824,691
   (Deductions from) additions to reserve
   for Trust Expenses                           (797,075 )   (1,048,336 )   1,456,428
   Expenses paid through advances from
   JPMorgan Chase Bank via the promissory
   note                                       (1,673,617 )            -             -
   Unpaid Trust Expenses                        (190,955 )            -             -
                                            ------------   ------------   -----------
   General and administrative costs as
   reported                                 $      5,080   $    174,935   $ 2,281,119
                                            ------------   ------------   -----------

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

Brazos A-7 and A-39

                                               2007          2006         2005
                                             ---------   ------------   ---------
      Gross proceeds @ 90%                   $  29,550   $    152,215   $ 156,378
      Operating expenditures @ 90%             (60,705 )      (87,211 )   (83,470 )
      Change in abandonment estimate @ 90%        (373 )   (1,269,806 )         -
      Capital expenditures @ 90%                     -              -       6,750
                                             ---------   ------------   ---------
      Net proceeds (deficit)                 $ (31,528 ) $ (1,204,802 ) $  79,658
                                             ---------   ------------   ---------

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, 2007, these two blocks had one well capable of producing, the Brazos A-39 #5 well. The Brazos A-7 No. B-1 well, operated by Newfield, is no longer producing as of December 31, 2006 and was abandoned in 2007. PNR 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. 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, has informed the Trustee that the lower horizon of the prospect was determined to be non-commercial, while the middle horizon in the Big Hum 4 sand produced at 10,000 Mcf of gas per day during a seventeen hour flow test. This well came on line April 20, 2006. However, this well has been shut in from time to time since then as the operator has encountered and addressed hydrogen sulfide issues. The well has also produced a carbon dioxide content that exceeds pipeline specifications. This higher content requires the operator to mix production at the platform with production from other fields in order to transport the product. Production is being routed to the A-52C platform owned by Coldren Resources LP. That platform is being operated by Arena, which is also serving as the contract operator for the Midway property. The well was shut in July 21, 2006 by Williams Pipeline due to reported detection of mercury in the gas stream. 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. PNR 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 current production rate is 1-2 MMCFD with 4,500 psi flowing tubing pressure. The following tubing pressure continues to gradually decline.

Under the terms of a Farmout Agreement between PNR and Woodside Energy (USA) Inc., PNR farmed out to Woodside the undivided one-half interest previously burdened by the 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 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

                                                 2007         2006         2005
                                               ---------   ----------   -----------
     Gross proceeds @ 90%                      $       -   $   87,141   $ 1,929,040
     Operating expenditures @ 90%                (27,944 )    (16,265 )     (20,795 )
     Change in abandonment expenditures @90%         373     (130,333 )           -
     Capital expenditures @ 90%                        -       (8,034 )           -
                                               ---------   ----------   -----------
     Net proceeds (deficit)                    $ (27,571 ) $  (67,491 ) $ 1,908,245
                                               ---------   ----------   -----------

Hurricane Katrina struck the Gulf of Mexico in August 2005. The operator of the West Delta properties informed PNR that the West Delta properties have been shut in since August 27, 2005 due to damage to the platform, the pipeline and the sales terminal. The operator has notified PNR that production at West Delta resumed at all four wells in the fourth quarter 2007 at a combined production rate of 4.8 MMCFD. 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

In 2005, the Trust received, from PNR, net proceeds of $375,300 related to the sale of the South Marsh Island 155 platform that was abandoned by PNR and for casings related to the PNR platform at Brazos A-39. 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

    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                                         $            -
                                                                   --------------

During the first nine months of 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 December 31, 2007, PNR has spent approximately $1.1 million of the $1.4 million estimate, while approximately $329,000 of PNR's original estimate for total abandonment remains to be spent. As the reserve for future abandonment cost was fully utilized during 2006, the total $1.4 million of the Partnership's interest in estimated repairs will be deducted from any future gross proceeds on the Royalty Properties, which will reduce future Royalty income. No Royalty income will be distributed to the Partnership until PNR recoups the Partnership's portion of abandonment expenses from gross proceeds.

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 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 assets, or (4) the Settlement Agreement is not approved by the Court. Additionally, the amendment provided that the Trust may continue to obtain loans under the note until the maturity date, as long as, the amount borrowed does not exceed $3 million and the loan is not in default. The amendment also provided that interest expense shall be due and payable on the maturity date. As of December 31, 2007, there was outstanding $1,673,617 of principal advanced for payment of Trust expenses together with $31,187 of accrued and unpaid interest expense. At December 31, 2007, the Trust had $1,326,383 available under this facility. Should the Trust fully utilize the funds available under the Demand Promissory Note, the Trustee will attempt to borrow additional money. However, no assurance can be given that the Trustee will be able to borrow money on terms the Trustee considers reasonable or at . . .