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, 2007. 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 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 and in the Trust's Annual Report on Form 10-K for the year ended December 31, 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.

            SUMMARY OF ROYALTY INCOME, PRODUCTION AND AVERAGE PRICES

    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 unaudited summary illustrates the net effect of the components of
the actual Royalty computation for the periods indicated:

                                              Three Months Ended September 30,
                                           2008                               2007
                                             Oil, Condensate                    Oil, Condensate
                               Natural       and Natural Gas      Natural       and Natural Gas
                                 Gas             Liquids            Gas             Liquids
The Trust's proportionate
share of Gross Proceeds(1)   $  3,911,028   $       1,691,366   $  3,034,288   $       1,212,004
Less the Trust's
proportionate share of:
    Capital costs
    recovered                     (96,995 )           (55,805 )     (131,706 )           (51,951 )
    Operating costs              (637,544 )          (276,932 )     (641,806 )          (240,615 )

Royalty income               $  3,176,489   $       1,358,629   $  2,260,776   $         919,438

Average sales price          $       9.11   $           65.76   $       5.95   $           42.54

                                (Mcf)            (Bbls)            (Mcf)            (Bbls)
Net production volumes
attributable to the
Royalty(2)                        348,675              20,662        377,403              21,658

                                               Nine Months Ended September 30,
                                           2008                               2007
                                             Oil, Condensate                    Oil, Condensate
                               Natural       and Natural Gas      Natural       and Natural Gas
                                 Gas             Liquids            Gas             Liquids
The Trust's proportionate
share of Gross Proceeds(1)   $  9,185,133   $       4,822,715   $  8,411,487   $       3,133,703
Less the Trust's
proportionate share of:
    Capital costs
    recovered                    (388,940 )          (230,863 )     (709,147 )           (51,951 )
    Operating costs            (1,654,691 )          (837,114 )   (2,007,776 )          (370,098 )

Royalty income               $  7,141,502   $       3,754,738   $  5,694,564   $       2,711,654

Average sales price          $       7.41   $           60.75   $       5.84   $           38.09

                                (Mcf)            (Bbls)            (Mcf)            (Bbls)
Net production volumes
attributable to the
Royalty(2)                        956,096              61,958        970,988              71,823

º (2)
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, 2008 and 2007

Financial Review

                                                   Three Months Ended
                                                      September 30,
                                                   2008          2007
           Royalty income                       $ 4,535,119   $ 3,180,214
           Interest income                           10,840        24,883
           General and administrative expense       (35,801 )     (18,062 )

           Distributable income                 $ 4,510,158   $ 3,187,035

           Distributable income per unit        $    2.4201   $    1.7102

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

The Trust's Royalty income was $4,535,119 in the third quarter of 2008, an increase of approximately 43% as compared to $3,180,214 in the third quarter of 2007, primarily as a result of increased prices for natural gas and natural gas liquids in the third quarter of 2008 as compared to the third quarter of 2007.

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 quarter ended September 30, 2008 was $4,510,158, representing $2.4201 per unit, compared to $3,187,035, representing $1.7102 per unit, for the quarter ended September 30, 2007. Based on 1,863,590 units outstanding for the quarters ended September 30, 2008 and 2007, respectively, the per unit distributions were as follows:

                                         2008       2007
                           July        $ 0.7699   $ 0.6174
                           August        0.7889     0.5919
                           September     0.8613     0.5009

                                       $ 2.4201   $ 1.7102

Operational Review

Hugoton Field

Natural gas and natural gas liquids production attributable to the Royalty from the Hugoton field accounted for approximately 41% of the Royalty income of the Trust during the third quarter of 2008.

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 Gas 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. Overall market prices received for natural gas from the Hugoton Royalty Properties were higher in the third quarter of 2008 compared to the third quarter of 2007.

Royalty income attributable to the Hugoton Royalty Properties increased to $1,844,490 in the third quarter of 2008, as compared to $1,237,354 in the third quarter of 2007 primarily due to an increase in overall prices received from the Hugoton Royalty Properties. The average price received in the third quarter of 2008 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $9.73 per Mcf and $65.50 per barrel, respectively, compared to $6.66 per Mcf and $46.86 per barrel during the same period in 2007. Net production attributable to the Hugoton Royalty was 137,627 Mcf of natural gas and 7,723 barrels of natural gas liquids in the third quarter of 2008 compared to 135,835 Mcf of natural gas and 6,639 barrels of natural gas liquids in the third quarter of 2007. Actual production volumes attributable to the Hugoton properties decreased to 164,581 Mcf of natural gas and increased to 9,235 barrels of natural gas liquids in the third quarter of 2008 as compared to 188,313 Mcf of natural gas and 9,210 barrels of natural gas liquids for the same period in 2007 as a result of line repairs in the field.

Capital expenditures on these properties were $0. In addition, the Trust received a credit of $13,851 in the third quarter of 2008, as compared to $36,117 in the third quarter of 2007. Operating costs were $375,270 in the third quarter of 2008, a decrease of approximately 13% as compared to $431,634 in the third quarter of 2007. The decrease in operating expenses between the three months ended September 30, 2007 and the three months ended September 30, 2008 is due to efforts to contain costs to offset vendor pricing increases.

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. Royalty income from the San Juan Basin Royalty Properties located in the state of New Mexico was $2,416,644 during the third quarter of 2008 as compared with $1,586,626 in the third quarter of 2007. The increase was primarily due to higher natural gas and natural gas liquids prices offset in part by increased capital costs and operating expenses in the third quarter of 2008. The average price received in the third quarter of 2008 for natural gas sold from the San Juan Basin Royalty Properties was $8.85 per Mcf and $65.90 per barrel, respectively, compared to $5.59 per Mcf and $40.41 per barrel during the same period in 2007. Net production attributable to the San Juan Basin Royalty was 176,766 Mcf of natural gas and 12,939 barrels of natural gas liquids in the third quarter of 2008 as compared to 175,530 Mcf of natural gas and 15,019 barrels of natural gas liquids in the third quarter of 2007. Actual production volumes attributable to the San Juan Basin properties decreased to 224,779 Mcf of natural gas and 16,486 barrels of natural gas liquids in the third quarter of 2008 as compared to 249,146 Mcf of natural gas and 20,196 barrels of natural gas liquids for the same period in 2007. The decrease in actual production volume for the three month period ended September 30, 2008 compared to the same period in 2007 as a result of natural production fluctuations.

The Trust's interest in the San Juan Basin was conveyed from PNR's working interest in 31,328 net producing acres in northwestern New Mexico and southwestern Colorado.

The costs related to the San Juan Basin, Colorado drilling program were recovered in December 2004. However, subsequent earnings were not remitted to the Trust until December 2006 and July 2007. The cumulative earnings, including interest on undistributed earnings, reported to the Trust by the working interest owner through November 2006, totaled $1,280,412. In December 2006, BP remitted $978,349 for payment of undistributed earnings from January 2005 through October 2006 and November 2006 earnings for the San Juan properties it operates. In July 2007, Red Willow remitted $159,497 for payment of undistributed earnings from January 2005 through December 2006 for the properties it operates. BP communicated to the Trust these distributions represent all of the previously unpaid revenues. The Trustee is currently investigating the $142,566 difference in the original estimate of unpaid proceeds of $1,280,412 and the payment of $1,137,846. Since Royalty income for the Trust is recorded on a cash basis, the third quarter 2006 earnings were not recognized as income until the quarters ended December 31, 2006 and September 30, 2007.

Royalty income from the San Juan Basin-Colorado Royalty Properties was $273,985 during the third quarter of 2008, compared to $356,234 received during the third quarter of 2007. Royalty income received in the third quarter of 2007 from Red Willow operated properties relating to undistributed earnings from prior periods totaled $206,836. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 34,283 Mcf of natural gas during the third quarter of 2008 compared to 66,038 Mcf of natural gas attributable to the Trust during the third quarter of 2007. The average price received in the third quarter of 2008 for natural gas sold from the San Juan Basin Colorado Properties was $8.28. The average price received in the third quarter of 2007 for natural gas sold from the San Juan Basin Colorado Properties was $5.39. Actual production volumes attributable to the San Juan Basin Colorado Properties decreased to 38,807 Mcf of natural gas in the third quarter of 2008 as compared to 75,652 Mcf of natural gas for the same period in 2007. 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 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.

Operating costs on these properties were $47,445 in the third quarter of 2008, a decrease of approximately 8% as compared to $51,519 in the third quarter of 2007 attributed to a decrease in maintenance work and lease operating expenses (labor, fuel, electricity, and chemicals).

--------------------------------------------------------------------------------
Nine Months Ended September 30, 2008 and 2007

Financial Review

                                                    Nine Months Ended
                                                      September 30,
                                                    2008          2007
           Royalty income                       $ 10,896,240   $ 8,406,218
           Interest income                            36,834        69,374
           General and administrative expense        (96,075 )     (64,904 )

           Distributable income                 $ 10,836,999   $ 8,410,688

           Distributable income per unit        $     5.8151   $    4.5132

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

The Trust's Royalty income was $10,896,249 for the nine months ended September 30, 2008, an increase of approximately 30% as compared to $8,406,218 for the nine months ended September 30, 2007, primarily as a result of higher natural gas and natural gas liquids prices in the first nine months of 2008 compared with the first nine months of 2007.

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, 2008 was $10,837,008, representing $5.8151 per unit, compared to $8,410,688, representing $4.5132 per unit, for the nine months ended September 30, 2007.

Operational Review

Hugoton Field

Natural gas and natural gas liquids revenue from the Hugoton field attributable to the Royalty accounted for approximately 41% of the Royalty income of the Trust during the nine months ended September 30, 2008.

Royalty income attributable to the Hugoton Royalty Properties increased to $4,508,561 for the nine months ended September 30, 2008 from $3,569,852 for the same period in 2007, due to increases in natural gas and natural gas liquids price from the Hugoton Royalty Properties slightly offset by decreases in natural gas and natural gas liquids production. The average price received in the first nine months of 2008 for natural gas and natural gas liquids sold from the Hugoton field was $7.77 per Mcf and $62.49 per barrel, compared to $6.30 per Mcf and $40.65 per barrel during the same period in 2007. Net production attributable to the Hugoton Royalty Properties decreased to 399,141 Mcf of natural gas and 22,193 barrels of natural gas liquids for the nine months ended September 30, 2008 as compared to 406,791 Mcf of natural gas and 24,701 barrels of natural gas liquids for the nine months ended September 30, 2007. Actual production volumes attributable to the Hugoton Royalty Properties decreased to 496,003 Mcf of natural gas and increased to 27,563 barrels of natural gas liquids for the nine months ended September 30, 2008 as compared to 565,612 Mcf of natural gas and 27,281 barrels of natural gas liquids for the same period in 2007. The decrease in gas production and the increase in the natural gas liquids production for the nine month period ended September 30, 2008 compared to the same period in 2007 was primarily due to the nitrogen rejection unit being down for a portion of

January and February 2007. The shut down of the nitrogen rejection unit increased the gas production while it decreased the natural gas liquids production.

The Hugoton capital expenditures were $2,949 during the nine months ended September 30, 2008, a decrease of approximately 94% as compared to $51,995 during the nine months ended September 30, 2007. The decrease in the capital expenditures was primarily due to fewer capital workovers in 2008. Operating costs were $1,064,250 during the nine months ended September 30, 2008, as compared to $1,066,040 during the nine months ended September 30, 2007.

San Juan Basin

The San Juan-New Mexico Royalty income was $5,739,675 for the first nine months of 2008 compared to $4,098,811 in the first nine months of 2007. The increase in Royalty income was due primarily to higher prices for natural gas and natural gas liquids in the first nine months of 2008 from the San Juan Basin-New Mexico properties. Net production attributable to the San Juan-New Mexico properties increased to 455,299 Mcf of natural gas and decreased to 39,765 barrels of natural gas liquids for the nine months ended September 30, 2008 as compared to 420,338 Mcf of natural gas and 47,122 barrels of natural gas liquids for the nine months ended September 30, 2007. Actual production volumes attributable to the San Juan-New Mexico properties decreased to 624,450 Mcf of natural gas and 51,824 barrels of natural gas liquids in the nine months ended September 30, 2008 as compared to 716,324 Mcf of natural gas and 56,559 barrels of natural gas liquids for the same period in 2007. The decrease in production volume for natural gas and natural gas liquids for the nine month period ended September 30, 2008 compared to the same period 2007 was attributable to the slow recovery of the wells after they were shut down for maintenance and subsequently brought back online following a gas plant fire that occurred during the second quarter of 2008. The average price received in the nine months ended September 30, 2008 for natural gas and natural gas liquids sold from the San Juan-New Mexico properties was $7.32 per Mcf and $59.82 per barrel, respectively, compared to $6.38 per Mcf and $43.49 per barrel during the same period in 2007.

San Juan-New Mexico capital expenditures were $616,854 during the nine months ended September 30, 2008, a decrease of approximately 15% as compared to $709,103 during the nine months ended September 30, 2007. Operating costs were $1,314,683 during the nine months ended September 30, 2008, an increase of approximately 7% as compared to $1,226,650 during the nine months ended September 30, 2007 due to an increase in repair and maintenance activity.

Royalty income from the San Juan Basin-Colorado Royalty Properties was $648,004 for the nine months ended September 30, 2008, compared to $737,555 received during the same period in 2007. Royalty income received in the nine months ended September 30, 2007 from Red Willow operated properties relating to undistributed earnings from prior periods totaled $159,497. The operators did not pay to the Trust amounts received during the first nine months of 2006. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 98,829 Mcf of natural gas during the nine months ended September 30, 2008 with 143,859 Mcf of natural gas volumes attributable to the Trust during the same period in 2007. The average price received for the nine months ended September 30, 2008 for natural gas sold from the San Juan Basin Colorado Properties was $6.53. The average price received for the nine months ended September 30, 2007 for natural gas sold from the San Juan Basin Colorado Properties was $5.13. Actual production volumes attributable to the San Juan Basin Colorado Properties decreased to 116,605 Mcf of natural gas for the nine months ended September 30, 2008 as compared to 160,265 Mcf of natural gas for the same period in 2007 due to the

slow recovery of the wells after they were shut down for maintenance and subsequently brought back online following a gas plant fire that occurred during the second quarter of 2008.

Operating costs on these properties were $112,870 for the nine months ended September 30, 2008, an increase of approximately 33% as compared to $85,184 in the same period in 2007 were due to an increase in drilling and workover charges.