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 June 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)                      1,091,899         618,368     2,870,529      1,553,475
Less the Trust's proportionate
share of:
     Capital costs recovered            (126,913 )       (99,248 )    (101,262 )      (55,210 )
     Operating costs                    (602,262 )      (246,282 )    (528,936 )     (261,974 )

Net Proceeds                             362,724         272,838     2,240,331      1,236,291

Royalty income(2)                        472,536         272,838     2,240,331      1,236,291

Average sales price                  $      2.98    $      23.23   $      7.28    $     57.98

                                         (Mcf)          (Bbls)         (Mcf)         (Bbls)
Net production volumes
attributable to the Royalty
paid(3)                                  158,592          11,747       307,282         21,301

                                                    Six Months Ended June 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)                   2,707,681      1,320,575      5,274,113      3,131,348
Less the Trust's proportionate
share of:
     Capital costs recovered            (374,537 )     (214,514 )     (291,959 )     (175,040 )
     Operating costs                  (1,192,243 )     (476,626 )   (1,017,139 )     (560,192 )

Net Proceeds                           1,140,901        629,435      3,965,015      2,396,116

Royalty income(2)                      1,250,713        629,435      3,965,015      2,396,116

Average sales price                 $       3.42    $     26.13   $       6.52    $     58.35

                                        (Mcf)          (Bbls)         (Mcf)          (Bbls)
Net production volumes
attributable to the Royalty
paid(3)                                  365,974         24,093        606,814         41,313

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 $110,000 as of June 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 June 30, 2009 and 2008

Financial Review

                                                   Three Months Ended
                                                        June 30,
                                                   2009          2008
           Royalty income                       $   745,374   $ 3,476,622
           Interest income                               80        11,460
           General and administrative expense       (44,130 )     (33,257 )

           Distributable income                 $   701,324   $ 3,454,825

           Distributable income per unit        $    0.3763   $    1.8539

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

The Trust's Royalty income was $745,374 in the second quarter 2009, a decrease of approximately 79% as compared to $3,476,622 in the second quarter of 2008, primarily as a result of lower natural gas and natural gas liquids prices and reduced production of natural gas and natural gas liquids in the second quarter of 2009 as compared to the second 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. Trust administration expenses are deducted in the computation of distributable income. Distributable income for the quarter ended June 30, 2009 was $701,324, representing $.3763 per unit, compared to $3,454,825, representing $1.8539 per unit, for the quarter ended June 30, 2008. Based on 1,863,590 units outstanding for the quarters ended June 30, 2009 and 2008, respectively, the per unit distributions were as follows:

                                       2009       2008
                             April   $ 0.1413   $ 0.5303
                             May       0.1153     0.6552
                             June      0.1197     0.6684

                                     $ 0.3763   $ 1.8539

Operational Review

Hugoton Field

Natural gas and natural gas liquids production attributable to the Royalty from the Hugoton field accounted for approximately 53% of the Royalty income of the Trust during the second 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 second quarter of 2009 compared to the second quarter of 2008.

In June 1994, PNR entered into a Gas Transportation Agreement ("Gas Transportation Agreement") with Western Resources, Inc. ("WRI") for a primary term of five years commencing June 1, 1995. This contract has renewed on a year-to-year basis since June 1, 2001. PNR extended the contract June 1, 2010. Pursuant to the Gas Transportation Agreement, WRI agreed to compress and transport up to 160 MMcf per day of gas and redeliver such gas to PNR at the inlet of PNR's Satanta Plant. PNR agreed to pay WRI a fee of $0.06 per Mcf escalating 4% annually as of June 1, 1996. This Gas Transportation Agreement was assigned to Kansas Gas Service ("Oneok").

Royalty income attributable to the Hugoton Royalty decreased to $393,656 in the second quarter of 2009, as compared to $1,472,388 in the second 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 second quarter of 2009 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $3.65 per Mcf and $25.82 per barrel, respectively, compared to $7.53 per Mcf and $63.26 per barrel, respectively, during the same period in 2008. Net production attributable to the Hugoton Royalty was 76,747 Mcf of natural gas and 4,397 barrels of natural gas liquids in the second quarter of 2009 compared to 135,263 Mcf of natural gas and 7,186 barrels of natural gas liquids in the second quarter of 2008. Actual production volumes attributable to the Hugoton properties decreased to 152,172 Mcf of natural and 8,861 barrels of natural gas liquids in the second quarter of 2009 as compared to 166,945 Mcf of natural gas and 8,869 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 second quarter of 2009 were $20,527, compared to $0 in the second quarter of 2008. The increase in capital expenditures is due to capital well workovers performed during the period. Operating costs were $369,669 in the second quarter of 2009, an increase of approximately 7% as compared to $345,659 in the second quarter of 2008. The increase in operating costs between the three months ended June 30, 2009 and the three months ended June 30, 2008 is due to higher rates charged by service providers.

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 $345,823 during the second quarter of 2009 as compared with $1,811,524 in the second 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 second quarter of 2009 for natural gas sold from the San Juan Basin Royalty Properties located in the state of New Mexico was $2.34 per Mcf and $21.69 per barrel, respectively, compared to $7.27 per Mcf and $55.37 per barrel during the same period in 2008. Net production attributable to the San Juan Basin Royalty located in New Mexico was 79,536 Mcf of natural gas and 7,350 barrels of natural gas liquids in the second quarter of 2009 as compared to 141,367 Mcf of natural gas and 14,103 barrels of natural gas liquids in the second quarter of 2008. Actual production volumes attributable to the San Juan Basin properties located in the state of New Mexico increased to 196,565 Mcf of natural gas and 17,962 barrels of natural gas liquids in the second quarter of 2009 as compared to 189,010 Mcf of natural gas and 17,922 barrels of natural gas liquids for

the same period in 2008. The increase in actual production volume for the three month period ended June 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 $205,634 in the second quarter of 2009, an increase of approximately 31% as compared to $156,472 in the second quarter of 2008. This increase is due to increased drilling activity in the second quarter of 2009 compared to the second quarter of 2008. Operating costs were $298,099 in the second quarter of 2009, a decrease of approximately 25% as compared to $398,395 in the second quarter of 2008. The decrease in operating expenses for the three month period ended June 30, 2009 compared to the same period in 2008 was due to a reduction in lease inspections and a reduction in well workover expenses.

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 portion of the Fruitland Coal drilling program were recovered in December 2004. However, subsequent earnings after recovery of costs were not remitted to the Trust until December 2006. 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, 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 does not expect to receive any further distributions relating to this issue. Since Royalty income for the Trust is recorded on a cash basis, the earnings for the year ended December 31, 2006 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 $5,895 during the second quarter of 2009, compared to $192,710 during the second quarter of 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 2,309 Mcf of natural gas during the second quarter of 2009, compared to 30,653 Mcf of natural gas during the second quarter of 2008. The average price received in the second quarter of 2009 for natural gas sold from the San Juan Basin Colorado Properties was $2.03 compared to $6.29 in the second quarter of 2008. Actual production volumes attributable to the San Juan Basin Colorado Properties decreased to 37,829 Mcf of natural gas in the second quarter of 2009 as compared to 37,925 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 $180,776 in the second quarter of 2009, an increase of approximately 286% as compared to $46,856 in the second quarter of 2008 due to an increase in drilling and workover charges.

--------------------------------------------------------------------------------
Six Months Ended June 30, 2009 and 2008

Financial Review

                                                    Six Months Ended
                                                        June 30,
                                                   2009          2008
           Royalty income                       $ 1,880,148   $ 6,361,131
           Interest income                              215        25,994
           General and administrative expense       (93,104 )     (60,275 )

           Distributable income                 $ 1,787,259   $ 6,326,850

           Distributable income per unit        $    0.9590   $    3.3950

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

The Trust's Royalty income was $1,880,148 for the six months ended June 30, 2009, a decrease of approximately 70% as compared to $6,361,131 for the six months ended June 30, 2008, primarily as a result of lower natural gas and natural gas liquid prices in the first six months of 2009 as compared to the first six 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 six months ended June 30, 2009 was $1,787,259, representing $0.9590 per unit, compared to $6,326.850, representing $3.3950 per unit, for the six months ended June 30, 2008.

Operation Review

Hugoton Field

Natural gas and natural gas liquids revenue from the Hugoton field attributable to the Royalty accounted for approximately 49% of the Royalty income of the Trust during the six months ended June 30, 2009.

Royalty income attributable to the Hugoton Royalty Properties decreased to $919,133 for the six months ended June 30, 2009 from $2,664,077 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 six months of 2009 for natural gas and natural gas liquids sold from the Hugoton field was $3.90 per Mcf and $32.58 per barrel, respectively, compared to $6.80 per Mcf and $60.97 per barrel, respectively, during the same period in 2008. Net production attributable to the Hugoton Royalty Properties decreased to 159,605 Mcf of natural gas and 9,106 barrels of natural gas liquids for the six months ended June 30, 2009 as compared to 261,589 Mcf of natural gas and 14,478 barrels of natural gas liquids for the six months ended June 30, 2008. Actual production volumes attributable to the Hugoton Royalty Properties decreased to 322,375 Mcf of natural gas and increased to 18,344 barrels of natural gas liquids in the six months ended June 30, 2009 as compared to 331,422 Mcf of natural gas and 18,328 barrels of natural gas liquids for the same period in 2008. The decrease in natural gas production is a result of natural production decline.

San Juan Basin

The Royalty income from the San Juan Basin Royalty Properties located in the state of New Mexico was $941,930 for the first six months of 2009 compared to $3,323,031 in the first six months of 2008. The decrease in Royalty income was due primarily to decreased natural gas and natural gas liquid prices in the first six months of 2009 from the San Juan Basin properties. The average price received in the six months ended June 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 $3.07 per Mcf and $22.21 per barrel, respectively, compared to $6.42 per Mcf and $56.41 per barrel, respectively, during the same period in 2008. Net production attributable to the San Juan Basin Royalty located in New Mexico was 198,300 Mcf of natural gas and 14,987 barrels of natural gas liquids for the six months ended June 30, 2009 as compared to 278,535 Mcf of natural gas and 26,821 barrels of natural gas liquids for the six months ended June 30, 2008. Actual production volumes attributable to the San Juan Basin Royalty Properties increased to 411,300 Mcf of natural gas and decreased to 32,560 barrels of natural gas liquids in the six months ended June 30, 2009 as compared to 399,670 Mcf of natural gas and 35,342 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.

San Juan-New Mexico capital expenditures were $413,909 during the six months ended June 30, 2009, a decrease of approximately 8% as compared to $450,202 during the six months ended June 30, 2008. This decrease is due to less drilling activity during the six months ended June 30, 2009 when compared to the six months ended June 30, 2008. Operating costs were $630,919 during the six months ended June 30, 2009, a decrease of approximately 23% as compared to $822,924 during the six months ended June 30, 2008. The decrease in operating costs is the result of decreased repair and maintenance activity.

Royalty income from the San Juan Basin-Colorado Royalty Properties was $19,085 for the six months ended June 30, 2009, compared to $374,023 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 8,069 Mcf of natural gas during the six months ended June 30, 2009 with 66,690 Mcf of natural gas attributable to the Trust during the same period in 2008. The average price received for the six months ended June 30, 2009 for natural gas sold from the San Juan Basin Colorado Properties was $2.47, compared to $5.56 received during the same period in 2008. Actual production volumes attributable to the San Juan Basin Colorado Properties decreased to 76,130 Mcf of natural gas for the six months ended June 30, 2009 as compared to 77,798 Mcf of natural gas for the same period in 2008.

Operating costs on these properties were $278,910 for the six months ended June 30, 2009, an increase of approximately 326% as compared to $65,427 in the same period in 2008 due to an increase in drilling charges.