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 discussion of net production attributable to the Hugoton and San Juan properties represents production volumes that are to a large extent hypothetical as the Trust does not own and is not entitled to any specific production volumes. See Note 7 to the financial statements in the Trust's Annual Report on Form 10-K for the year ended December 31, 2008. Any discussion of "actual" production volumes represents the hydrocarbons that were produced from the properties in which the Trust has an overriding royalty interest.

The Trust is a passive entity whose purposes are limited to: (1) converting the Royalties to cash, either by retaining them and collecting the proceeds of production (until production has ceased or the Royalties are otherwise terminated) or by selling or otherwise disposing of the Royalties; and
(2) distributing such cash, net of amounts for payments of liabilities to the Trust, to the unitholders. The Trust has no sources of liquidity or capital resources other than the revenues, if any, attributable to the Royalties and interest on cash held by the Trustee as a reserve for liabilities or for distribution.

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 the Working Interest Owners have advised the Trust that they believe that the expectations reflected in the forward-looking statements contained herein are reasonable, no assurance can be given that such expectations will prove correct. Important factors that could cause actual results to differ materially from expectations ("Cautionary Statements") are disclosed in this Form 10-Q and in the Trust's Annual Report on Form 10-K for the year ended December 31, 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.

            SUMMARY OF ROYALTY INCOME, PRODUCTION AND AVERAGE PRICES
                                  (Unaudited)

    Royalty income is computed after deducting the Trust's proportionate share
of capital costs, operating costs and interest on any cost carryforward from the
Trust's proportionate share of "Gross Proceeds," as defined in the Conveyance.
The following summary illustrates the net effect of the components of the actual
Royalty computation for the periods indicated:

                                              Three Months Ended September 30,
                                             2009                          2008
                                                     Oil,                          Oil,
                                                  Condensate                    Condensate
                                    Natural      and Natural      Natural      and Natural
                                      Gas        Gas Liquids        Gas        Gas Liquids
The Trust's proportionate share
of Gross Proceeds(1)                 1,061,433        729,413      3,911,028      1,691,366
Less the Trust's proportionate
share of:
     Capital costs recovered           (84,302 )      (74,076 )      (96,995 )      (55,805 )
     Operating costs                  (445,159 )     (254,973 )     (637,544 )     (276,932 )

Net Proceeds                           531,972        400,364      3,176,489      1,358,629

Royalty income(2)                      522,856        400,364      3,176,489      1,358,629

Average sales price               $       2.53    $     27.31   $       9.11    $     65.76

                                     (Mcf)          (Bbls)         (Mcf)          (Bbls)
Net production volumes
attributable to the Royalty
paid(3)                                206,268         14,662        348,675         20,662

                                               Nine Months Ended September 30,
                                             2009                          2008
                                                     Oil,                          Oil,
                                                  Condensate                    Condensate
                                                 and Natural                   and Natural
                                  Natural Gas    Gas Liquids    Natural Gas    Gas Liquids
The Trust's proportionate share
of Gross Proceeds(1)                 3,769,113      2,049,990      9,185,133      4,822,715
Less the Trust's proportionate
share of:
     Capital costs recovered          (458,834 )     (288,594 )     (388,940 )     (230,863 )
     Operating costs                (1,587,447 )     (731,667 )   (1,654,691 )     (837,114 )

Net Proceeds                         1,722,832      1,029,729      7,141,502      3,754,738

Royalty income(2)                    1,773,639      1,029,729      7,141,502      3,754,738

Average sales price               $       3.13    $     26.36   $       7.41    $     60.75

                                     (Mcf)          (Bbls)         (Mcf)          (Bbls)
Net production volumes
attributable to the Royalty
paid(3)                                567,224         39,064        956,096         61,958

º (2)
º As a result of excess production costs incurred in one monthly operating period and then recovered in a subsequent monthly operating period(s), the Royalty income paid to the Trust may not agree to the Trust's royalty interest in the Net Proceeds. Excess production costs related to the San Juan Basin-Colorado properties operated by BP were approximately $50,000 as of September 30, 2009. The excess production costs must be recovered by the Working Interest Owners before any distribution of Royalty income will be made to the Trust.

º (3)
º Net production volumes attributable to the Royalty are determined by dividing Royalty income by the average sales price received.

--------------------------------------------------------------------------------
Three Months Ended September 30, 2009 and 2008

Financial Review

                                                   Three Months Ended
                                                      September 30,
                                                   2009          2008
           Royalty income                       $   923,220   $ 4,535,119
           Interest income                                -        10,840
           General and administrative expense       (60,619 )     (35,801 )

           Distributable income                 $   862,601   $ 4,510,158

           Distributable income per unit        $    0.4629   $    2.4201

           Units outstanding                      1,863,590     1,863,590

The Trust's Royalty income was $923,220 in the third quarter 2009, a decrease of approximately 80% as compared to $4,535,119 in the third quarter of 2008, primarily as a result of lower natural gas and natural gas liquids prices in the third quarter of 2009 as compared to the third quarter of 2008.

The distributable income of the Trust for each period includes the Royalty income received from the working interest owners during such period, plus interest income earned to the date of distribution (if any). Trust administration expenses are deducted in the computation of distributable income. Distributable income for the quarter ended September 30, 2009 was $862,601, representing $.4629 per unit, compared to $4,510,158, representing $2.4201 per unit, for the quarter ended September 30, 2008. Based on 1,863,590 units outstanding for the quarters ended September 30, 2009 and 2008, respectively, the per unit distributions were as follows:

                                         2009       2008
                           April       $ 0.1536   $ 0.7699
                           May           0.1572     0.7889
                           September     0.1521     0.8613

                                       $ 0.4629   $ 2.4201

Operational Review

Hugoton Field

Natural gas and natural gas liquids production attributable to the Royalty from the Hugoton field accounted for approximately 38% of the Royalty income of the Trust during the third quarter of 2009.

PNR has advised the Trust that since June 1, 1995 natural gas produced from the Hugoton field has generally been sold under short-term and multi-month contracts at market clearing prices to multiple purchasers recently including Greely Gas and Oneok Energy Marketing, Inc. PNR has advised the Trust that it expects to continue to market gas production from the Hugoton field under short-term and multi-month contracts. As discussed below, overall market prices received for natural gas from the Hugoton Royalty Properties were significantly lower in the third quarter of 2009 compared to the third quarter of 2008.

Royalty income attributable to the Hugoton Royalty decreased to $352,427 in the third quarter of 2009, as compared to $1,844,490 in the third quarter of 2008. The decrease in Royalty income was primarily due to lower natural gas and natural gas liquid prices. The average price received in the third quarter of 2009 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $3.21 per Mcf and $28.11 per barrel, respectively, compared to $9.73 per Mcf and $65.50 per barrel, respectively, during the same period in 2008. Net production attributable to the Hugoton Royalty was 72,824 Mcf of natural gas and 4,221 barrels of natural gas liquids in the third quarter of 2009 compared to 137,627 Mcf of natural gas and 7,723 barrels of natural gas liquids in the third quarter of 2008. Actual production volumes attributable to the Hugoton properties decreased to 154,594 Mcf of natural and 8,909 barrels of natural gas liquids in the third quarter of 2009 as compared to 164,581 Mcf of natural gas and 9,235 barrels of natural gas liquids for the same period in 2008 as a result of natural production decline.

Capital expenditures on these properties in the third quarter of 2009 were $24,804, compared to $0 in the third quarter of 2008. The increase in capital expenditures is due to 2 new wells being drilled in late 2008. Operating costs were $369,207 in the third quarter of 2009, a decrease of approximately 2% as compared to $375,270 in the third quarter of 2008.

San Juan Basin

Royalty income from the San Juan Basin Royalty Properties is calculated and paid to the Trust on a state-by-state basis. Substantially all of the Royalty income from the San Juan Basin Royalty Properties is attributable to the Royalty Properties located in the state of New Mexico. The Royalty income from the San Juan Basin Royalty Properties located in the state of New Mexico was $570,562 during the third quarter of 2009 as compared with $2,416,644 in the third quarter of 2008. The decrease in royalty income was primarily the result of lower natural gas and natural gas liquid prices. The average price received in the third quarter of 2009 for natural gas sold from the San Juan Basin Royalty Properties located in the state of New Mexico was $2.17 per Mcf and $26.97 per barrel, respectively, compared to $8.85 per Mcf and $65.90 per barrel during the same period in 2008. Net production attributable to the San Juan Basin Royalty located in New Mexico was 133,333 Mcf of natural gas and 10,441 barrels of natural gas liquids in the third quarter of 2009 as compared to 176,766 Mcf of natural gas and 12,939 barrels of natural gas liquids in the third quarter of 2008. Actual production volumes attributable to the San Juan Basin properties located in the state of New Mexico increased to 225,179 Mcf of natural gas and 17,758 barrels of natural gas liquids in the third quarter of 2009 as compared to 224,779 Mcf of natural gas and 16,486 barrels of natural gas liquids for the same period in 2008. The increase in actual production volume for the three month period ended September 30, 2009 compared to the same period 2008 was due to better run times on conventional gathering.

Capital expenditures on the San Juan Basin Royalty Properties located in the state of New Mexico were $133,574 in the third quarter of 2009, a decrease of approximately 20% as compared to $166,650

in the third quarter of 2008. This decrease is due to decreased drilling activity in the third quarter of 2009 compared to the third quarter of 2008. Operating costs were $262,663 in the third quarter of 2009, a decrease of approximately 47% as compared to $491,761 in the third quarter of 2008. The decrease in operating expenses for the three month period ended September 30, 2009 compared to the same period in 2008 was due to a reduction in lease inspections and a reduction in well workover expenses.

Royalty income from the San Juan Basin-Colorado Royalty Properties was $231 during the third quarter of 2009, compared to $273,985 during the third quarter of 2008. The decrease in Royalty income was primarily the result of lower natural gas prices and an increase in excess production costs. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 111 Mcf of natural gas during the third quarter of 2009, compared to 34,283 Mcf of natural gas during the third quarter of 2008. The average price received in the third quarter of 2009 for natural gas sold from the San Juan Basin Colorado Properties was $2.09 compared to $8.28 in the third quarter of 2008. Actual production volumes attributable to the San Juan Basin Colorado Properties decreased to 37,109 Mcf of natural gas in the third quarter of 2009 as compared to 38,807 Mcf of natural gas for the same period in 2008. Royalty income reported from BP is net of pre-main line production costs. These costs were charged to the Trust in error and as a result the Royalty income for previous periods was reduced. Because Royalty income recorded for a month is the amount computed and paid by BP, the additional royalties, if any, will not be recorded until received by the Trust.

Operating costs on these properties were $68,262 in the third quarter of 2009, an increase of approximately 44% as compared to $47,445 in the third quarter of 2008 due to an increase in drilling and workover charges.

Nine Months Ended September 30, 2009 and 2008

Financial Review

                                             Nine Months Ended September 30,
                                                2009                 2008
     Royalty income                        $     2,803,368     $      10,896,240
     Interest income                                   215                36,834
     General and administrative expense           (153,723 )             (96,075 )

     Distributable income                  $     2,649,860     $      10,836,999

     Distributable income per unit         $        1.4219     $          5.8151

     Units outstanding                           1,863,590             1,863,590

The Trust's royalty income was $2,803,368 for the nine months ended September 30, 2009, a decrease of approximately 74% as compared to $10,896,240 for the nine months ended September 30, 2008, primarily as a result of lower natural gas and natural gas liquid prices in the first nine months of 2009 as compared to the first nine months of 2008.

The distributable income of the Trust for each period includes the Royalty income received from the working interest owners during such period, plus interest income earned to the date of distribution. Trust administration expenses are deducted in the computation of distributable income. Distributable income for the nine months ended September 30, 2009 was $2,649,860, representing $1.4219 per unit,

compared to $10,836,999, representing $5.8151 per unit, for the nine months ended September 30, 2008.

Operation Review

Hugoton Field

Natural gas and natural gas liquids revenue from the Hugoton field attributable to the Royalty accounted for approximately 45% of the Royalty income of the Trust during the nine months ended September 30, 2009.

Royalty income attributable to the Hugoton Royalty Properties decreased to $1,271,561 for the nine months ended September 30, 2009 from $4,508,561 for the same period in 2008 primarily due to decreases in prices for both natural gas and natural gas liquids from the Hugoton Royalty Properties. The average price received in the first nine months of 2009 for natural gas and natural gas liquids sold from the Hugoton field was $3.67 per Mcf and $31.12 per barrel, respectively, compared to $7.77 per Mcf and $62.49 per barrel, respectively, during the same period in 2008. Net production attributable to the Hugoton Royalty Properties decreased to 233,304 Mcf of natural gas and 13,346 barrels of natural gas liquids for the nine months ended September 30, 2009 as compared to 399,141 Mcf of natural gas and 22,193 barrels of natural gas liquids for the nine months ended September 30, 2008. Actual production volumes attributable to the Hugoton Royalty Properties decreased to 476,972 Mcf of natural gas and 27,243 barrels of natural gas liquids in the nine months ended September 30, 2009 as compared to 496,003 Mcf of natural gas and 27,563 barrels of natural gas liquids for the same period in 2008. The decrease in natural gas production is a result of natural production decline.

The Hugoton capital expenditures were $199,945 during the nine months ended September 30, 2009, an increase of approximately 6680% as compared to $2,949 during the nine months ended September 30, 2008. The increase in the capital expenditures was primarily due to the drilling of two additional wells. Operating costs were $1,128,247 during the nine months ended September 30, 2009, an increase of approximately 6% as compared to $1,064,250 during the nine months ended September 30, 2008 due to higher rates charged by service providers.

San Juan Basin

The royalty income from the San Juan Basin Royalty Properties located in the state of New Mexico was $1,512,491 for the first nine months of 2009 compared to $5,739,675 in the first nine months of 2008. The decrease in royalty income was due primarily to decreased natural gas and natural gas liquid prices. The average price received in the nine months ended September 30, 2009 for natural gas and natural gas liquids sold from the San Juan Basin Royalty Properties located in the state of New Mexico was $2.75 per Mcf and $23.89 per barrel, respectively, compared to $7.32 per Mcf and $59.82 per barrel, respectively, during the same period in 2008. Net production attributable to the San Juan Basin Royalty located in New Mexico was 326,116 Mcf of natural gas and 25,718 barrels of natural gas liquids for the nine months ended September 30, 2009 as compared to 455,299 Mcf of natural gas and 39,765 barrels of natural gas liquids for the nine months ended September 30, 2008. Actual production volumes attributable to the San Juan Basin Royalty Properties increased to 636,480 Mcf of natural gas and decreased to 50,319 barrels of natural gas liquids in the nine months ended September 30, 2009 as compared to 624,450 Mcf of natural gas and 51,824 barrels of natural gas liquids for the same period in 2008. The increase in natural gas production is due to better run times on conventional gathering.

Royalty income from the San Juan Basin-Colorado Royalty Properties was $19,316 for the nine months ended September 30, 2009, compared to $648,004 received during the same period in 2008. The decrease in royalty income was primarily the result of lower natural gas and natural gas liquid prices and an increase in excess production costs. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 7,804 Mcf of natural gas during the nine months ended September 30, 2009 with 98,829 Mcf of natural gas attributable to the Trust during the same period in 2008. The average price received for the nine months ended September 30, 2009 for natural gas sold from the San Juan Basin Colorado Properties was $2.35, compared to $6.53 received during the same period in 2008. Actual production volumes attributable to the San Juan Basin Colorado Properties decreased to 113,329 Mcf of natural gas for the nine months ended September 30, 2009 as compared to 116,605 Mcf of natural gas for the same period in 2008.

Operating costs on these properties were $297,285 for the nine months ended September 30, 2009, an increase of approximately 163% as compared to $112,870 in the same period in 2008 due to an increase in drilling charges.