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 to be 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 March 31,
                                              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)               $ 1,615,782    $    702,207   $ 2,403,586    $ 1,577,873
Less the Trust's proportionate
share of:
     Capital costs recovered          (247,624 )      (115,266 )    (190,697 )     (119,833 )
     Operating costs                  (589,981 )      (230,344 )    (488,203 )     (298,218 )

Royalty income                     $   778,177    $    356,597   $ 1,724,686    $ 1,159,822

Average sales price                $      3.88    $      29.01   $      5.79    $     58.71

Net production volumes
attributable to the Royalty paid
(2)                                    200,636          12,294       299,531         20,012

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 March 31, 2009 and 2008

Financial Review

                                                   Three Months Ended
                                                        March 31,
                                                   2009          2008
           Royalty income                       $ 1,134,774   $ 2,884,508
           Interest income                              135        14,534
           General and administrative expense       (48,974 )     (27,018 )

           Distributable income                 $ 1,085,935   $ 2,872,024

           Distributable income per unit        $    0.5827   $    1.5411

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

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 March 31, 2009 was $1,085,935, representing $.5827 per unit, compared to $2,872,024, representing $1.5411 per unit, for the quarter ended March 31, 2008. Based on 1,863,590 units outstanding for the quarters ended March 31, 2009 and 2008, respectively, the per unit distributions were as follows:

                                        2009       2008
                            January    $ .1798   $  .4717
                            February     .2090      .5350
                            March        .1939      .5344

                                       $ .5827   $ 1.5411

Operational Review

Hugoton Field

Natural gas and natural gas liquids production attributable to the Royalty from the Hugoton field accounted for approximately 46% of the Royalty income of the Trust during the first 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 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. As discussed below, overall market prices received for natural gas from the Hugoton Royalty Properties were significantly lower in the first quarter of 2009 compared to the first 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 being effective June 1, 2001. PNR extended the contract to 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 $525,477 in the first quarter of 2009, from $1,191,689 in the first quarter of 2008 primarily due to decreases in natural gas and natural gas liquid prices from the Hugoton Royalty Properties, and increased capital and operating expenditures. The average price received in the first quarter of 2009 for natural gas and natural gas liquids sold from the Hugoton Royalty Properties was $4.12 per Mcf and $38.90 per barrel, respectively, as compared to $6.05 per Mcf and $58.83 per barrel, respectively, in the first quarter of 2008. Net

production of natural gas attributable to the Hugoton Royalty decreased to 83,091 Mcf in the first quarter of 2009 from 126,326 Mcf in the first quarter of 2008. Net production of natural gas liquids attributable to the Hugoton Royalty decreased from 7,288 barrels in the first quarter of 2008 to 4,708 barrels in the first quarter of 2009. Actual production volumes from the Hugoton properties increased to 170,203 Mcf of natural gas and 9,478 barrels of natural gas liquids in the first quarter of 2009 as compared to 164,476 Mcf of natural gas and 9,459 barrels of natural gas liquids for the same period in 2008.

The Hugoton capital expenditures were $154,614 in the first quarter of 2009, an increase of approximately 798% as compared to $17,215 in the first quarter of 2008. The increase in capital expenditures was primarily due to increased drilling activity. Operating costs were $389,371 in the first quarter of 2009, an increase of approximately 13% as compared to $343,320 in the first quarter of 2008. The increase in operating costs was primarily 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 $596,107 during the first quarter of 2009 as compared with Royalty income of $1,511,505 in the first quarter of 2008. The decrease in Royalty income was due primarily to lower natural gas and natural gas liquids prices in the first quarter of 2009 compared to the first quarter of 2008 offset in part by decreased capital and operating costs. Net production attributable to the San Juan Basin Royalty located in New Mexico was 113,027 Mcf of natural gas and 7,586 barrels of natural gas liquids in the first quarter of 2009, as compared to 137,168 Mcf of natural gas and 12,724 barrels of natural gas liquids in the first quarter of 2008. The average price received in the first quarter of 2009 for natural gas and natural gas liquids sold from the San Juan Basin Royalty Properties located in the state of New Mexico was $3.74 per Mcf and $22.86 per barrel, respectively, compared to $5.66 per Mcf and $57.51 per barrel during the same period in 2008. Actual production volumes of natural gas attributable to the San Juan Basin properties located in the state of New Mexico increased to 214,735 Mcf in the first quarter of 2009 as compared to 210,660 Mcf of natural gas for the same period in 2008. Actual production volumes of natural gas liquids attributable to the San Juan Basin properties located in the state of New Mexico decreased to 14,598 barrels in the first quarter of 2009 compared to 17,416 barrels for the same period in 2008.

Capital expenditures on these properties were $208,274 in the first quarter of 2009, a decrease of approximately 29% as compared to $293,316 in the first quarter of 2008, primarily due to decreased developmental drilling. Operating costs were $332,820 in the first quarter 2009, a decrease of approximately 22% as compared to $424,529 in the first quarter of 2008 due to decreased repair and maintenance activity.

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. Substantially all of the natural gas produced from the San Juan Basin is currently being sold on the spot market.

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 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 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 $13,190 during the first quarter of 2009, compared to $181,314 during the first quarter of 2008. The decrease in Royalty income was due to lower commodity prices and higher operating cost in the first quarter of 2009. Net production attributable to the San Juan Basin Royalty Properties located in Colorado was 4,518 Mcf of natural gas during the first quarter of 2009 with 36,037 Mcf of natural gas attributable to the Trust during the first quarter of 2008. The average price received in the first quarter of 2009 for natural gas sold from the San Juan Basin Colorado Properties was $2.85, as compared to average price of $4.88 for the first quarter of 2008. Actual production volumes attributable to the San Juan Basin Colorado Properties decreased to 38,301 Mcf of natural gas in the first quarter of 2009 as compared to 39,873 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 $98,137 in the first quarter of 2009, an increase of approximately 428% as compared to $18,571 in the first quarter of 2008 due to an increase in drilling charges.