• Amortization of the Royalty Interests is calculated on a unit-of-production basis and charged directly to trust corpus.

• Distributions to Unitholders subject to the occurrence of a termination event, are recorded when declared by the Trustee (see Note 5 to "Item 8-Financial Statements and Supplementary Data-Notes to Financial Statements").

• Loss contingencies are recognized in the period in which amounts are paid by the Trust.

The financial statements of the Trust differ from financial statements prepared in accordance with GAAP. For example, royalty income is not accrued in the period of production, amortization of the Royalty Interests is not charged against operating results, and loss contingencies are not charged to operating results until paid. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.
The Trust's financial statements reflect the selection and application of accounting policies that require the Trust to make significant estimates and assumptions. The following are some of the more critical judgment areas in the application of accounting policies that currently affect the Trust's financial condition and results of operations.

Revenue Recognition. Revenues from Royalty Interests are recognized in the period in which amounts are received by the Trust. Royalty income received by the Trust in a given calendar year will generally reflect the proceeds, on an entitlements basis, from natural gas produced for the 12-month period ended September 30th in that calendar year.
Reserve Recognition. Independent petroleum engineers estimate the net proved reserves attributable to the Royalty Interests. In accordance with Statement of Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing Activities," estimates of future net revenues from proved reserves have been prepared using year-end contractual gas prices and related costs. Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and the timing of development of non-producing reserves. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.
Contingencies. Contingencies related to the Underlying Properties that are unfavorably resolved would generally be reflected by the Trust as reductions to future royalty income payments to the Trust with corresponding reductions to cash distributions to Unitholders.
Modernization of Oil & Gas Reporting Requirements The SEC has revised its oil and gas reserves reporting requirements effective for fiscal years ending on or after December 31, 2009, with early adoption prohibited. These changes include:
• Expanding the definition of oil and gas reserves and providing clarification of certain concepts and technologies used in the reserve estimation process.

• Allowing optional disclosure of probable and possible reserves and permitting optional disclosure of price sensitivity analysis.

• Modifying prices used to estimate reserves for SEC disclosure purposes to a 12-month average price instead of a single-day, period-end price.

• Requiring certain additional disclosures around proved undeveloped reserves, internal controls used to ensure objectivity of the estimation process, and qualifications of those preparing and/or auditing the reserves.

Historically, the reserves calculated based on the SEC's reporting requirements were also used to calculate amortization of the royalty interest assets, as required by SFAS 69, "Disclosures about Oil and Gas Producing Activities" (SFAS 69). However, the change in the SEC reporting requirements has not yet been adopted by the Financial Accounting Standards Board ("FASB"). The SEC has announced its intent to discuss potential amendments to SFAS 69 with the FASB so that the reserves disclosed remain consistent with the reserves used to calculate depletion on our producing properties. Any such change would impact our future financial results. The SEC has indicated that it may delay the effective date of the revised reporting requirements if the FASB does not make conforming amendments by December 31, 2009. Liquidity and Capital Resources
As stipulated in the Trust Agreement, the Trust is intended to be passive in nature and neither the Delaware Trustee nor the Trustee has any control over or any responsibility relating to the operation of the Underlying Properties. The Trustee has powers to collect and distribute proceeds received by the Trust and pay Trust liabilities and expenses, and its actions have been limited to those activities. The assets of the Trust are passive in nature, and other than the Trust's ability to periodically borrow money as necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited from engaging in borrowing transactions. As a result, other than such borrowings, if any, the Trust has no source of liquidity or capital resources other than the Royalty Interests.
Royalty income to the Trust is attributable to the sale of depleting assets. All of the Underlying Properties burdened by the Royalty Interests consist of producing properties. Accordingly, the proved reserves attributable to WPC's interest in the Underlying Properties are expected to decline substantially during the term of the Trust and a portion of each cash distribution made by the Trust will, therefore, be analogous to a return of capital. Accordingly, cash yields attributable to the Units are expected to decline over the term of the Trust Additionally, the recent decline in natural gas prices has further lowered the expectation for 2009 distributions compared to those in 2008.
Results of Operations
The Trust makes quarterly cash distributions to Unitholders. The only assets of the Trust, other than cash and cash equivalents being held for the payment of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests. The Royalty Interests owned by the Trust burden the Underlying Properties, which are owned by WPC and not the Trust.
Distributable income of the Trust generally consists of the excess of royalty income plus interest income over the general and administrative expenses of the Trust. Upon receipt by the Trust, royalty income is invested in short-term investments in accordance with the Trust Agreement until its subsequent distribution to Unitholders.
The amount of distributable income of the Trust for any calendar year may differ from the amount of cash available for distribution to Unitholders in such year due to differences in the treatment of the expenses of the Trust in the determination of those amounts. The financial statements of the Trust are prepared on a modified cash basis pursuant to which the expenses of the Trust are recognized when incurred whereas royalty income is recognized when received. Consequently, the reported distributable income of the Trust for any year is determined by deducting from the income received by the Trust the amount of expenses incurred by the Trust during such year. The amount of cash available for distribution to Unitholders, however, is determined in accordance with the provisions of the Trust Agreement and reflects the deduction from the income actually received by the Trust of the amount of expenses actually paid by the Trust and adjustment for changes in reserves for unpaid liabilities. See

Note 5 to "Item 8-Financial Statements and Supplementary Data-Notes to Financial
Statements" for additional information regarding the determination of the amount of cash available for distribution to Unitholders.
For 2008, royalty income received by the Trust amounted to $15,151,993 as compared to $9,496,151 and $13,945,315 for 2007 and 2006, respectively. The increase in royalty income in 2008 compared to 2007 was primarily due to an additional $3.5 million distribution received from WPC from the actualization of the unit expansions effecting the underlying properties. The increase was also the result of higher natural gas prices. These events are not expected to recur in 2009. The decrease in royalty income in 2007 compared to 2006 was primarily due to lower natural gas prices and lower natural gas production. Net production related to the royalty income received by the Trust in 2008 was 3,297,752 MMBtu (exclusive of the above described unit expansion adjustment) as compared to 3,730,887 MMBtu and 4,406,089 MMBtu in 2007 and 2006, respectively. The average net natural gas price received for royalty income in 2008 was $3.05 per MMBtu (exclusive of the above described unit expansion adjustment) as compared to $2.24 MMBtu and $2.63 MMBtu in 2007 and 2006, respectively. Interest income for 2008 was $24,390 as compared to $39,842 and $51,533 for 2007 and 2006. The decrease in interest income for 2008 reflects lower interest rates. The decrease in interest income in 2007 compared to 2006 reflects lower interest rates.
General and administrative expenses for 2008 were $885,692, as compared to $988,693 and $964,784 for 2007 and 2006, respectively. General and administrative expenses in 2008 were lower due to decreased Unitholder reporting costs compared to 2007. General and administrative expenses in 2007 were higher due to increased Unitholder reporting costs compared to 2006.
Distributable income for 2008 was $14,290,691 or $1.47 per Unit, compared to $8,547,300 or $0.88 per Unit for 2007, and $13,032,064 or $1.34 per Unit, for 2006. The increase in distributable income in 2008 compared to 2007 was primarily due to the actualization of various unit expansions, as discussed further in Note 6 to "Item 8 - Financial Statements and Supplementary Data - Notes to Financial Statements" and due to higher gas prices. The decrease in distributable income in 2007 compared to 2006 was primarily due to lower net production from the Underlying Properties and lower gas prices.
Because the Trust incurs administrative expenses throughout a quarter but receives its royalty income only once in a quarter, the Trustee established in the first quarter of 1993 a cash reserve for the payment of expenses and liabilities of the Trust. The Trustee thereafter has adjusted the amount of such reserve in certain quarters as required for the payment of the Trust's expenses and liabilities, in accordance with the provisions of the Trust Agreement. The Trustee anticipates that it will maintain for the foreseeable future a cash reserve that will fluctuate as expenses are paid and royalty income is received.
Royalty income to the Trust is attributable to the sale of depleting assets. All of the Underlying Properties burdened by the Royalty Interests consist of producing properties. Accordingly, the proved reserves attributable to WPC's interest in the Underlying Properties are expected to decline substantially during the term of the Trust and a portion of each cash distribution made by the Trust will, therefore, be analogous to a return of capital. Accordingly, cash yields attributable to the Units are expected to decline over the term of the Trust.
Royalty income received by the Trust in a given calendar year will generally reflect the sum of (i) proceeds from the sale of gas produced from the WI Properties during the first three quarters of that year and the fourth quarter of the preceding calendar year, plus (ii) cash received by WPC with respect to the Farmout Properties during the first three quarters of that year (or in the month immediately following the third quarter, if received by WPC in sufficient time to be paid to the Trust) and the fourth quarter of the preceding calendar year.
Accordingly, the royalty income included in distributable income for the years ended December 31, 2008, 2007 and 2006, was based on production volumes and natural gas prices for the 12 months ended in September 30, 2008, 2007 and 2006, respectively, as shown in the table below. The production volumes included in the table are for production attributable to the Underlying Properties, and not production attributable to the Royalty Interests owned by the Trust, and are net of the amount of production attributable to WPC's royalty obligations to third parties, which are determined by contractual arrangement with such parties.

                                                                       Twelve Months Ended September 30,
                                                                2008                 2007                 2006
Production, Net (MMBtu)(1)(2)
WI Properties                                                 5,279,628            5,008,996            5,904,596
Farmout Properties(3)                                         1,043,121            1,209,149            1,438,886
Average Blanco Hub Spot Price ($/MMBtu)                     $      7.21          $      5.86          $      6.92
Average Net Wellhead Price WI Properties ($/MMBtu)(4)       $      3.05          $      2.24          $      2.63

(1) Million British Thermal Units.

(2) Production volumes for 2008 presented above are exclusive of 6,845,010 MMBtu net production volumes related to the unit expansion adjustment as described in Note 6 to "Item 8 - Financial Statements and Supplementary Data - Notes to Financial Statements."

(3) Includes previously reported estimated amounts for certain months.

(4) Total Gross Proceeds divided by Entitled W.I. Dry MMBtu for
12 months
ending on
September 30.

Production from the WI Properties is generally sold pursuant to the Gas Purchase Contract. For more information regarding the Gas Purchase Contract and the right of WFS Gas Resources to recoup certain Price Credits, see "Item 2 - Properties - The Royalty Interests - Gas Purchase Contract" in this Form 10-K.
The information herein concerning production and prices relating to the Underlying Properties is based on information prepared and furnished by WPC to the Trustee. The Trustee has no control over and no responsibility relating to the operation of the Underlying Properties. Termination and Liquidation of the Trust With respect to the Trust termination provisions as outlined in the Trust Agreement, the net present value of the estimated future net revenues computed in accordance with the Trust Agreement, using an average 2008 index price of $7.21, by the independent petroleum engineers as of December 31, 2008 was approximately $65 million. While the results of this computation will not trigger an early termination of the Trust as of December 31, 2008, future computations are subject to the numerous uncertainties in estimating the future net revenues. The negative commodity price outlook for 2009 has to date negatively impacted actual index prices used in the Trust's termination calculation, which could impact the December 31, 2009 termination evaluation and trigger termination of the Trust in accordance with the provisions of the Trust Agreement. Should the Trust's computed net present value fall below the $30 million stipulated threshold as of December 31, 2009, the Trust will terminate effective March 1, 2010.
Pursuant to the terms of the Trust Agreement, the Trust will terminate no later than December 31, 2012 or upon the first to occur of certain events, including (i) the disposition by the Trust of all Royalty Interests;
(ii) following an affirmative vote in favor of termination of the Trust by the holders of record of more than 50% of the then outstanding Units; (iii) such time as the ratio of cash received by the Trust with respect to the Royalty Interests (excluding the effect on cash distributions received by the Trust in respect of the Royalty Interests of excess capital costs) to administrative costs of the Trust is less than 1.2 to 1.0 for three (3) consecutive calendar quarters; and (iv) March 1 of any calendar year if, based on a reserve report as of December 31 of the prior year, it is determined that, as of such date, the net present value (discounted at 10 percent) of the estimated future net revenues (calculated in accordance with criteria established by the SEC) for proved reserves attributable to the Royalty Interests but using the average monthly Blanco Hub Spot Price for the past calendar year less certain gathering costs is equal to or less than $30 million (the date of the first of such occurrences is referred to herein as the "Termination Date"). Following termination, the Trustee and the Delaware Trustee will continue to act as trustees of the Trust until all remaining Trust assets have been sold and the net proceeds from such sales distributed to Unitholders. Upon the termination of the Trust, the Trustee will use best efforts (as defined in the Trust Agreement) to sell any remaining Royalty Interests for cash pursuant to the procedures described in the Trust Agreement. The Trustee will retain an investment banking firm (the "Advisor") on behalf of the Trust who will assist the Trustee in selling the remaining Royalty Interests then owned by the Trust (the "Remaining Royalty Interests"). WPC has the right, but not the obligation' to make a cash offer to purchase all Remaining Royalty Interests following termination of the Trust as described in the following paragraph. WPC may, within 60 days following the Termination Date, make a cash offer to purchase all of the Remaining Royalty Interests then held by the Trust. In the event such an offer is made by WPC, the Trustee will decide, based on the recommendation of the Advisor, to either (i) accept such offer (in which case no sale to WPC will be made unless a fairness opinion is given by the Advisor that the purchase price is fair to the Trust and Unitholders) or (ii) defer action on such offer. If the Trustee defers action on WPC's offer, the offer will be deemed withdrawn and the Trustee will then use Best Efforts (as defined in the Trust Agreement), assisted by the Advisor to obtain alternative offers for the Remaining Royalty Interests. At the end of a 120-day period following the Termination Date, the Trustee is required to notify WPC of the highest of any other offers (net of any commissions or other fees payable by the Trust), acceptable to the Trustee (which must be an all-cash offer), received during such period (the "Highest Acceptable Offer"). WPC then has the exclusive right (whether or not it made an initial offer), but not the obligation, to purchase all Remaining Royalty Interests for a cash purchase price computed as follows:
(i) if the Highest Acceptable Offer is more than 105 percent of WPC's inital offer (or if WPC did not make an inital offer), the purchase price will be 105 percent of the Highest Acceptable Offer, or (ii) if the Highest Acceptable Offer is equal to or less than 105 percent of WPC's original offer, the purchase price will be equal to the Highest Acceptable Offer. If no other acceptable offers are received for all Remaining Royalty Interests, the Trustee may request WPC to submit another offer for consideration by the Trustee and may accept or reject such offer. Acceptance of an offer by the Trustee shall be conditioned upon the opinion of the Advisor of the fairness of the offer. If a sale of the Remaining Royalty Interests is made or a definitive contract for sale of the Remaining Royalty Interests is entered into within a 150-day period following the Termination Date, the buyer of the Remaining Royalty Interests, and not the Trust or Unitholders, will be entitled to all proceeds of production attributable to the Remaining Royalty Interests following the Termination Date. In the event that WPC does not purchase the Remaining Royalty Interests, the Trustee may accept any offer for all or any part (not more than six parts) of the Remaining Royalty Interests as it deems to be in the best interests of the Trust and Unitholders and may continue, for up to one calendar year after the Termination Date, to attempt to locate a buyer or buyers of the Remaining Royalty Interests in order to sell such interests in an orderly fashion not involving a public auction. If any Remaining Royalty Interests have not been sold or a definitive agreement for sale has not been entered into by the end of such calendar year, the Trustee is required to sell the Remaining Royalty Interests at public auction to the highest cash bidder, which sale may be to WPC or any of its affiliates. Notice of such sale by auction shall be mailed at least 30 days prior to such sale to each Unitholder at his address as it appears on the ownership ledger of the Trustee. WPC's purchase rights, as described, may be exercised by WPC and each of its successors-in-interest and assigns. WPC's purchase rights are fully assignable by WPC to any person. The costs of liquidation, including the fees and expenses of the Advisor, and the Trustee's liquidation fee will be paid by the Trust. The sale of the Remaining Royalty Interests and the termination of the Trust will be taxable events to the Unitholders. Generally, a Unitholder will realize gain or loss equal to the difference between the amount realized on the sale and termination of the Trust and his adjusted basis in such Units. Gain or loss realized by a Unitholder who is not a dealer with respect to such Units and who has a holding period for the Units of more than one year will be treated as long-term capital gain or loss except to the extent of any depletion recapture amount, which must be treated as ordinary income. Each Unitholder should consult his own tax advisor regarding Trust tax compliance matters, including Federal and state tax implications concerning the sale of the Remaining Royalty Interests and the termination of the Trust. Off-Balance Sheet Arrangements
As stipulated in the Trust Agreement, the Trust is intended to be passive in nature and neither the Delaware Trustee nor the Trustee has any control over or any responsibility relating to the operation of the Underlying Properties. The Trustee has powers to collect and distribute proceeds received by the Trust and pay Trust liabilities and expenses, and its actions have been limited to those activities. Therefore, the Trust has not engaged in any off-balance sheet arrangements.
Tabular Disclosure of Contractual Obligations As shown below, the Trust had no obligations and commitments to make future contractual payments as of December 31, 2008.

                                                                        Payments Due by Period
                                                      Less than
                                        Total           1 Year          1 - 3 Years         3-5 Years         More than 5 Years
Contractual Obligations               $  -0-          $    -0-           $     -0-          $    -0-             $        -0-

Forward-Looking Statements
This Annual Report 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, which are intended to be covered by the safe harbor created thereby. All statements other than statements of historical fact included in this Annual Report are forward-looking statements. Such statements include, without limitation, factors affecting the price of oil and natural gas contained in Item 1, "Business"; certain reserve information and other statements contained in Item 2, "Properties"; and certain statements regarding the Trust's financial position, industry conditions and other matters contained in this Item 7. Although the Trustee believes that the expectations reflected in such forward-looking statements are reasonable, such expectations are subject to numerous risks and uncertainties and the Trustee can give no assurance that they will prove correct. There are many factors, none of which is within the Trustee's control, that may cause such expectations not to be realized, including, among other things, factors

identified in this Annual Report affecting oil and gas prices and the recoverability of reserves, general economic conditions, actions and policies of petroleum-producing nations and other changes in the domestic and international energy markets and the factors identified in Item 1A, "Risk Factors". Item 7A. Quantitative and Qualitative Disclosure About Market Risk The only assets of and sources of income to the Trust are the Royalty Interests, which generally entitle the Trust to receive a share of the net profits from natural gas production from the Underlying Properties. Consequently, the Trust's financial results can be significantly affected by fluctuations in natural gas prices and the Trust has commodity price risk exposure associated with the natural gas markets in the United States. The Trust does not engage in any hedging activities to manage its price risk associated with natural gas production from the Underlying Properties. The Royalty Interests do not entitle the Trust to control or influence the operation of the Underlying Properties or the sale of gas produced therefrom. Natural gas produced from the WI Properties, which comprises the majority of production attributable to the Royalty Interests, is currently sold by WPC pursuant to the terms of the Gas Purchase Contract. Although the Trust is not a party to the Gas Purchase Contract, the Gas Purchase Contract may significantly impact revenues to the Trust. Although the Gas Purchase Contract mitigates the risk to the Trust of low gas prices, it also limits the ability of the Trust to benefit from the effects of higher gas prices, particularly to the extent a balance exists in the Price Credit Account. See "Item 2 - Properties - The Royalty Interests - Gas Purchase Contract" for detailed information about the Gas Purchase Contract and its impact on the Trust and Unitholders.
Upon receipt by the Trust, royalty income is invested in short-term investments in accordance with the Trust Agreement until its subsequent distribution to Unitholders. Currently, funds are invested in Bank of America money market accounts which are backed by the good faith of Bank of America, N.A., but are not insured by the FDIC. The Trust does not lend money and has limited ability to borrow money, which the Trustee believes limits the Trust's risk from the current tightening of credit markets. The Trust's future royalty income, however, may be subject to risks relating to the credit worthiness of the operators of the Underlying Properties and WPX Gas Resources and other purchasers of the natural gas produced from the Underlying Properties, as well as risks associated with fluctuations in the price of natural gas. See "Item 1A
- Risk Factors - Funds held by the Trustee are not insured by the Federal Deposit Insurance Corporation, and future royalty income may be subject to risks relating to the creditworthiness of third parties." The market prices of the Units are determined by the buyers and sellers on the New York Stock Exchange. The Trust does not make market on any Units and is not in any position to advise any Unitholder on any market position. Unitholders . . .