10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

COMMISSION FILE NUMBER: 1-11608

WILLIAMS COAL SEAM GAS ROYALTY TRUST

(Exact name of registrant as specified in its charter)

DELAWARE	75-6437433
(State or other jurisdiction of incorporation or organization)	(I.R.S. employer identification number)

Trust Division
Royalty Trust Group
Bank of America, N.A.
901 Main Street, 17th Floor
Dallas, Texas
(Address of principal executive offices) 75202
(Zip Code)

Registrant’s telephone number, including area code:

(214) 209-2400

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

Title of Each Class	Name of Each Exchange on Which Registered
Units of Beneficial Interest	New York Stock Exchange, Inc.

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT

NONE

     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

                Yes o       Noþ

     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

               Yes o      No þ

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ       No o

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act).

Large accelerated filer o      Accelerated filer þ      Non-accelerated filer o

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o      No þ

     The aggregate market value of the registrant’s units of beneficial interest outstanding (based on the closing sale price on the New York Stock Exchange on June 30, 2005 and the number of shares reported by the Williams Companies Inc. in its Form 4 filed on June 27, 2005) held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $148,322,464.

     At March 1, 2006, there were 9,700,000 units of beneficial interest outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

     Portions of the Prospectus dated January 13, 1993, which constitutes a part of the Registration Statement on Form S-3 of The Williams Companies, Inc. (Registration No. 33-53662) filed in connection with the registration of the units of beneficial interest in the registrant, are incorporated by reference in Part I of this Form 10-K.

TABLE OF CONTENTS

	Page
PART I		1
Item 1. Business		1
GLOSSARY		1
DESCRIPTION OF THE TRUST		4
Creation and Organization of the Trust		5
Assets of the Trust		6
Liabilities of the Trust		6
Duties and Limited Powers of the Trustee		6
Liabilities of the Delaware Trustee and the Trustee		7
Termination and Liquidation of the Trust		7
DESCRIPTION OF UNITS		8
Distributions and Income Computations		9
Transfer of Royalty Interests		9
Possible Divestiture of Units		9
Periodic Reports to Unitholders		10
Voting Rights of Unitholders		10
Liability of Unitholders		11
Transfer Agent		11
Website/SEC Filings		11
FEDERAL INCOME TAXATION		11
Summary of Certain Federal Income Tax Consequences		12
ERISA CONSIDERATIONS		15
STATE TAX CONSIDERATIONS		15
REGULATION AND PRICES		15
Regulation of Natural Gas		15
Environmental Regulation		16
Competition, Markets and Prices		17
Item 1A. Risk Factors		18
Item 1B. Unresolved Staff Comments		23
Item 2. Properties		23
THE ROYALTY INTERESTS		23
The Underlying Properties		24
The NPI		26
Reserve Report		27
Historical Gas Sales Prices and Production		29
NPI Percentage Reduction		29
Gas Purchase Contract		29
Gas Gathering Contract		31
Federal and Indian Lands		32
Sale and Abandonment of Underlying Properties		33
The Infill Wells		34
Royalty Trust Reserves		34
Williams’ Performance Assurances		35
Title to Properties		35
Item 3. Legal Proceedings		36
Item 4. Submission of Matters to a Vote of Security Holders		37
PART II		37
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		37
Item 6. Selected Financial Data		37
Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations		38

	Page
Critical Accounting Policies and Estimates		38
Liquidity and Capital Resources		38
Results of Operations		39
Off-Balance Sheet Arrangements		41
Tabular Disclosure of Contractual Obligations		41
Forward-Looking Statements		41
Item 7A. Quantitative and Qualitative Disclosure About Market Risk		41
Item 8. Financial Statements and Supplementary Data		42
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		51
Item 9A. Controls and Produres		52
Item 9B. Other Information		53
PART III		53
Item 10. Directors and Executive Officers of the Registrant		53
Item 11. Executive Compensation		54
Item 12. Security Ownership of Certain Beneficial Owners and Management		54
Williams’s Voting Authority Over Units		55
Item 13. Certain Relationships and Related Transactions		55
Administrative Services Agreement		55
Potential Conflicts of Interest		55
Item 14. Principal Accounting Fees and Services		56
PART IV		56
Item 15. Exhibits and Financial Statement Schedules		56
Consent of Ernst & Young LLP
Consent of Miller and Lents, Ltd.
Certification by Trustee Pursuant to Rule 13a-14(a)/15d-14(a) and Section 302
Certificate Pursuant to 18 U.S.C. 1350 and Section 906
Reserve Report

Consent of Ernst & Young LLP
Consent of Miller and Lents, Ltd.
Certification Pursuant to Rule 13a-14(a)/15d-14(a)
Certification Pursuant to 18 U.S.C. 1350
Reserve Report

PART I

Item 1. Business.

     The following is a glossary of certain defined terms used in this Annual Report on Form 10-K.

GLOSSARY

     “Administrative Services Agreement” means the Administrative Services Agreement, dated effective December 1, 1992, between Williams and the Trust, a copy of which is filed as an exhibit to this Form 10-K.

     “Bcf” means billion cubic feet of natural gas. Natural gas volumes are stated herein at the legal pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit.

     “Blanco Hub Spot Price” means the posted index price of spot gas delivered to pipelines per MMBtu (dry basis) as published in the first issue of the month during which gas is delivered or such determination is made, as the case may be, in Inside FERC’s Gas Market Report for “El Paso Natural Gas Company, San Juan,” or in the event a Blanco Hub posted index price is at some time in the future reported by Inside FERC’s Gas Market Report, then the Blanco Hub posted index price will be substituted in place of the “El Paso Natural Gas Company, San Juan” posted index price.

     “Btu” means British Thermal Unit, the common unit of gross heating value measurement.

     “Citibank’s Base Rate” means a fluctuating interest rate per annum (compounded quarterly) as shall be in effect from time to time which rate per annum shall at all times be equal to the rate of interest announced publicly by Citibank, N.A. in New York, New York, from time to time, as its base rate.

     “Confirmation Agreement” means the Confirmation Agreement dated effective as of May 1, 1995, by and among WPC, Williams and the Trust, a copy of which is filed as an exhibit to this Form 10-K.

     “Conveyance” means the Net Profits Conveyance dated effective as of October 1, 1992, by and among Williams, WPC, the Trustee and the Delaware Trustee, a copy of which is filed as an exhibit to this Form 10-K.

     “December 31, 2005 Reserve Report” means the Reserve Report, dated January 12, 2006, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests and the Underlying Properties as of December 31, 2005, prepared by Miller and Lents, Ltd., independent petroleum engineers, a copy of which is filed as an exhibit to this Form 10-K.

     “Delaware Code” means the Delaware Business Trust Act, Title 12, Chapter 38 of the Delaware Code, Sections 3801 et seq.

     “Delaware Trustee” means Chase Bank (as successor to Chemical Bank Delaware), in its capacity as a trustee of the Trust.

     “Enhanced recovery or similar operations” means operations conducted for the purpose of maintaining, sustaining or enhancing production from the Underlying Properties. These operations may include additional compression, the injection of carbon dioxide or other gases or hydraulic fracturing.

     “Farmout Properties” means the 5,348 gross acres in La Plata County, Colorado on which WPC owns a 35 percent net profits interest, also referred to as the PLA-9 Properties.

     “Gas Gathering Contract” means the Gas Gathering and Treating Agreement, dated October 1, 1992, between WPX Gas Resources (as successor in interest to WGM) and WFS, as amended by the First Amendment thereto dated as of January 12, 1993, by Amendment #2 effective as of October 1, 1993 and by Amendment #3 thereto dated as of October 1, 1993, a copy of each of which is filed as an exhibit to this Form 10-K.

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     “Gas Purchase Contract” means the Gas Purchase Agreement, dated October 1, 1992, between WPX Gas Resources (as successor in interest to WGM) and WPC, as amended by the First Amendment thereto effective as of January 12, 1993, a copy of each of which is filed as an exhibit to this Form 10-K.

     “Grantor trust” means a trust as to which the grantor is treated as the owner of the trust income and corpus under the IRC.

     “Gross acres” means the total number of surface acres of land without regard to ownership.

     “Gross wells” means the total whole number of gas wells without regard to ownership interest.

     “Index Price” means 97 percent of the Blanco Hub Spot Price as of the date the determination is made.

     “Infill Net Proceeds” consists generally of the aggregate proceeds based on the price at the Wellhead of gas produced from WPC’s net revenue interest in any possible Infill Wells less (a) WPC’s working interest share of property and production taxes on such Infill Wells; (b) WPC’s working interest share of operating costs on such Infill Wells; (c) WPC’s working interest share of capital costs on such Infill Wells, including costs of drilling and completing such Infill Wells and the costs of associated surface facilities; and (d) interest on the unrecovered portion, if any, of the foregoing costs at Citibank’s Base Rate.

     “Infill NPI” refers to one of the net profits interests conveyed to the Trust, consisting of a 20 percent interest in WPC’s Infill Net Proceeds.

     “Infill Wells” means any possible additional well drilled on a producing drilling block when well spacing rules are effectively modified from the existing 320 acre spacing.

     “IRC” means the Internal Revenue Code of 1986, as amended.

     “IRR” means the annual discount rate (compounded quarterly) that equates the present value of the Aftertax Cash Flow per Unit to the initial price to the public of the Units in the Public Offering (which was $20.00 per Unit).

     “Mcf” means thousand cubic feet of natural gas.

     “Minimum Purchase Price” means 97 percent of $1.75 per MMBtu (dry basis).

     “MMBtu” means million Btu.

     “MMcf” means million cubic feet of natural gas.

     “Net profits interest” generally refers to a real property interest entitling the owner to receive a specified percentage of the net proceeds from the sale of production attributable to the properties burdened thereby, the amount of which is based on a revenue formula specified in such net profits interest.

     “NPI” refers to one of the net profits interests conveyed to the Trust, generally entitling the Trust to receive 60 percent (permanently reduced from 81 percent as described below) of the NPI Net Proceeds attributable to (i)WPC’s net revenue interest (working interest less lease burdens) in the WI Properties and (ii) the revenue stream received by WPC attributable to its 35 percent net profits interest in the Farmout Properties. The percentage of the NPI Net Proceeds to which the Trust was originally entitled was generally 81 percent. However, after certain conditions occurred as provided in the Conveyance, the percentage of the NPI Net Proceeds to which the Trust is entitled was permanently reduced from 81 percent to 60 percent beginning in the fourth quarter of 2000 as described under “Item 2—The Royalty Interests—NPI Percentage Reduction.”

     “NPI Net Proceeds” consists generally of the aggregate proceeds attributable to (i) WPC’s net revenue interest based on the sale at the Wellhead of gas produced from the WI Properties and (ii) the revenue stream

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received by WPC from its 35 percent net profits interest in the Farmout Properties, less (a) WPC’s working interest share of property and production taxes on the WI Properties; (b) WPC’s working interest share of actual operating costs on the WI Properties to the extent in excess of those agreed to be paid by WPC as described herein; (c) WPC’s working interest share of capital costs on the WI Properties to the extent in excess of those agreed to be paid by WPC as described herein; and (d) interest on the unrecovered portion, if any, of the foregoing costs at Citibank’s Base Rate.

     “Net wells” and “net acres” are calculated by multiplying gross wells or gross acres by the interest in such wells or acres.

     “October 1, 1992 Reserve Report” means the Reserve Report, dated November 21, 1992, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests and the Underlying Properties as of October 1, 1992, prepared by Miller and Lents, Ltd., independent petroleum engineers, a copy of which is filed as an exhibit to this Form 10-K.

     “Price Credit” means the credit received by WPX Gas Resources from WPC for each MMBtu of natural gas purchased by WFS Gas Resources when the Index Price is less than the Minimum Purchase Price on or after January 1, 1994, equal to the difference between the Minimum Purchase Price and the Index Price.

     “Price Credit Account” means the account established by WPC containing the accrued and unrecouped amount of any Price Credits.

     “Price Differential” means 50 percent of the excess of the Index Price over $1.94 per MMBtu.

     “Public Offering” has the meaning assigned to such term herein under “Item 1—Description of the Trust—Creation and Organization of the Trust.”

     “Public Offering Prospectus” has the meaning assigned to such term herein defined under “Item 1—Federal Income Taxation.”

     “Quatro Finale” means (a) with respect to the period May 1, 1997 until February 28, 2001, Quatro Finale LLC, a Delaware limited liability company (which entity acquired and owned the Underlying Properties from May 1, 1997 until February 1, 2001), and (b) with respect to the period March 1, 2001 until January 1, 2003, Quatro Finale V LLC, a Delaware limited liability company (which entity acquired and owned the Underlying Properties from March 1, 2001 until January 1, 2003).

     “QFIV” means Quatro Finale IV LLC, a Delaware limited liability company and a subsidiary of The Bear Stearns Companies Inc.

     “Royalty Interests” means the NPI and Infill NPI conveyed to the Trust.

     “Section 29 tax credit” means the tax credits for federal income tax purposes pursuant to Section 29 of the IRC to an owner of coal seam gas production, which tax credits were generated upon the sale of such production prior to January 1, 2003.

     “Trust” means Williams Coal Seam Gas Royalty Trust, a Delaware business trust formed pursuant to the Trust Agreement.

     “Trust Agreement” means the Trust Agreement, dated as of December 1, 1992, among Williams, WPC, as grantor, Chase Bank (as successor to Chemical Bank Delaware), as the Delaware Trustee, and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.), as the Trustee, as amended by the First Amendment thereto effective as of December 15, 1992 and by the Second Amendment thereto effective as of January 12, 1993, a copy of each of which is filed as an exhibit to this Form 10-K.

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     “Trustee” means Bank of America, N.A. (as successor to NationsBank, N.A.), in its capacity as a trustee of the Trust.

     “Underlying Properties” means certain proved properties in the Fruitland coal formation in the San Juan Basin of New Mexico and Colorado as specified in the Conveyance in which WPC has certain net revenue interests (working interests less lease burdens) and net profits interests.

     “Units” means the 9,700,000 units of beneficial interest issued by, and evidencing the entire beneficial interest in, the Trust.

     “Wellhead” means at or in the vicinity of the wellhead of gas produced.

     “WFS” means Williams Field Services Company, a wholly-owned indirect subsidiary of Williams Energy Services (formerly known as Williams Energy Group) (a wholly-owned subsidiary of Williams).

     “WGM” means Williams Gas Marketing Company, formerly a wholly-owned subsidiary of Williams Field Services Group, Inc. (a wholly-owned subsidiary of Williams) which has been merged into another affiliate of Williams Field Services Group, Inc.

     “WGM Gas Resources Payment Obligations” has the meaning assigned to such term under “Item 2—The Royalty Interests—Williams’ Performance Assurances.”

     “WHD” means Williams Holdings of Delaware, Inc., a wholly-owned subsidiary of Williams. On July 31, 1999, WHD was merged into Williams and Williams assumed all assets, liabilities and obligations of WHD.

     “Williams” means The Williams Companies, Inc., a Delaware corporation.

     “WI Properties” means the net revenue interests (working interests less lease burdens) of WPC in the Underlying Properties including WPC’s interests in 12 Federal producing units in New Mexico.

     “Working interest” generally refers to a real property interest entitling the owner to receive a specified percentage of the proceeds from the sale of oil and gas production or a percentage of such production, but requiring the owner of such working interest to bear the costs to explore for, develop and produce such oil and gas.

     “WPC” means Williams Production Company, a wholly-owned indirect subsidiary of Williams.

     “WPC Payment Obligations LLC” has the meaning assigned to such term under “Item 2—The Royalty Interests—Williams’ Performance Assurances.”

     “WPX Gas Resources” means WPX Gas Resources Company (formerly known as WFS Gas Resources Company), a Delaware corporation and a wholly-owned subsidiary of WPC and Williams.

DESCRIPTION OF THE TRUST

     Williams Coal Seam Gas Royalty Trust (the “Trust”) was formed as a Delaware business trust under the Delaware Business Trust Act, Title 12, Chapter 38 of the Delaware Code, Sections 3801 et seq. (the “Delaware Code”). The following information is subject to the detailed provisions of (i) the Trust Agreement of Williams Coal Seam Gas Royalty Trust (as amended, the “Trust Agreement”), entered into effective as of December 1, 1992, by and among Williams Production Company, a Delaware corporation (“WPC”), as trustor; The Williams Companies, Inc., a Delaware corporation (“Williams”), as sponsor; Chase Bank (as successor to Chemical Bank Delaware), a Delaware banking corporation (the “Delaware Trustee”); and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.), a national banking association (the “Trustee”) (the “Delaware Trustee” and the “Trustee” are sometimes referred to collectively as the “Trustees”), and (ii) the Net Profits Conveyance (the “Conveyance”) entered into effective as of October 1, 1992, by and among WPC, Williams, the Trustee and the Delaware Trustee. Copies of the Trust Agreement and of the Conveyance are filed as exhibits to this Form 10-K. The provisions

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governing the Trust are complex and extensive, and no attempt has been made below to describe or reference all of such provisions. The following is a general description of the basic framework of the Trust and a summary of the material terms of the Trust Agreement, and detailed provisions concerning the Trust may be found in the Trust Agreement.

Creation and Organization of the Trust

     The Trust was formed effective as of December 1, 1992 under Delaware law pursuant to the terms of the Trust Agreement to acquire and hold certain net profits interests (the “Royalty Interests”) in proved natural gas properties located in the San Juan Basin of New Mexico and Colorado (the “Underlying Properties”). The Royalty Interests were conveyed to the Trust on January 21, 1993, pursuant to the Conveyance, for the benefit of the Unitholders. All of the authorized units of beneficial interest in the Trust (“Units”) were issued to WPC on January 21, 1993. On that date, WPC transferred its Units to its parent, Williams, by dividend. Williams, in turn, sold, by means of a prospectus dated January 13, 1993, 5,200,000 Units on January 21, 1993, and an additional 780,000 Units on February 16, 1993, to the public through various underwriters (the “Public Offering”). In the second quarter of 1993, Williams sold an additional 151,209 Units. During the second quarter of 1995, Williams transferred its Units to Williams Holdings of Delaware, Inc. (“WHD”), a separate holding company for Williams’ non-regulated businesses. Effective July 31, 1999, WHD was merged into Williams, and by operation of the merger, Williams assumed all assets, liabilities and obligations of WHD, including without limitation ownership of WHD’s Units. Effective August 11, 2000, Williams sold its Units to Quatro Finale IV LLC, a Delaware limited liability company (“QFIV”), in a privately-negotiated transaction. Williams retained the voting rights and retained a “call” option on the transferred Units, and QFIV was granted a “put” option on the Units. Through a series of exercises of its call option, Williams reacquired an aggregate of 3,568,791 Units from December 2001 through June 2003. Williams has informed the Trustee that it has subsequently sold 2,779,500 of these Units through March 6, 2006 and owned a remaining 789,291 Units as of such date.

     Except for the commitment by WPC to pay the costs incurred to place into production certain proved nonproducing wells, neither WPC, Quatro Finale nor the operators of the Underlying Properties have any contractual commitment to the Trust to further develop the Underlying Properties, to remain as operator with respect to any of the leases on the Underlying Properties or to maintain their ownership interest in any of the properties. However, WPC retained an interest in each of the Underlying Properties immediately after conveyance of the Royalty Interests to the Trust. As described under “Item 2 —The Royalty Interests,” effective May 1, 1997, WPC sold the Underlying Properties subject to and burdened by the Royalty Interests to Quatro Finale LLC, an unaffiliated Delaware limited liability company. Ownership of the Underlying Properties reverted back to WPC effective February 1, 2001, pursuant to the terms of the May 1, 1997 transaction. Effective March 1, 2001, WPC sold the Underlying Properties subject to and burdened by the Royalty Interests to Quatro Finale V LLC, an unaffiliated Delaware limited liability company. The sale of the Underlying Properties is expressly permitted under the Trust Agreement. Effective January 1, 2003, ownership of the Underlying Properties once again reverted back to WPC after it exercised its right to repurchase interests in the Underlying Properties from Quatro Finale V LLC pursuant to the 2001 Transaction Agreement (as defined in “Item 2—Properties–The Royal Interests”). Unless otherwise dictated by context, references herein to WPC with respect to the ownership of the Underlying Properties for any period from May 1, 1997 through February 28, 2001, and for the period from March 1, 2001 through January 1, 2003, shall be deemed to refer to Quatro Finale. For a description of the Underlying Properties and other information relating to such properties, see “Item 2—Properties—The Royalty Interests.”

     The Trustee has powers to collect and distribute proceeds received by the Trust and to pay Trust liabilities and expenses. The Delaware Trustee has only such powers as are set forth in the Trust Agreement and is not empowered to otherwise manage or take part in the business of the Trust. The Royalty Interests are 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 Delaware Trustee and the Trustee may resign at any time or be removed with or without cause by a vote of not less than a majority of the outstanding Units. Any successor trustee must be a bank or trust company meeting certain requirements, including having capital, surplus and undivided profits of at least $20,000,000, in the case of the Delaware Trustee, and $100,000,000, in the case of the Trustee.

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Assets of the Trust

     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 consist primarily of a net profits interest (the “NPI”) in the Underlying Properties. The NPI generally entitles the Trust to receive 60 percent of the NPI Net Proceeds attributable to (i) gas produced and sold from WPC’s net revenue interests (working interests less lease burdens) in the properties in which WPC has a working interest (the “WI Properties”) and (ii) the revenue stream received by WPC attributable to its 35 percent net profits interest in 5,348 gross acres in La Plata County, Colorado (the “Farmout Properties”).

     The Royalty Interests also include a 20 percent interest in WPC’s Infill Net Proceeds from the sale of production if well spacing rules are effectively modified and additional wells are drilled on producing drilling blocks on the WI Properties (the “Infill Wells”) during the term of the Trust. “Infill Net Proceeds” consists generally of the aggregate proceeds, based on the price at the wellhead, of gas produced from WPC’s net revenue interest in any Infill Wells less certain taxes and costs.

     On October 15, 2002 the New Mexico Oil and Gas Commission (NMOCD) revised the field rules for the Basin Fruitland Coal (Gas) Pool to allow an optional second (infill) well on the standard 320-acre spacing unit in certain designated areas of the pool (the non-fairway wells). On July 17, 2003 the NMOCD further modified the field rules for the Basin Fruitland Coal (Gas) Pool to allow these infill wells on the standard 320-acre spacing unit in all areas of the pool. The WI Properties contain 530 infill locations designated as proved locations according to SEC guidelines. As of December 31, 2005, 316 infill locations are proved developed producing and 214 locations are proved undeveloped. Infill drilling is expected to be substantially completed by the end of 2006.

     As of December 31, 2005, the Infill Net Profit Costs exceed the Infill Net Profit Gross Proceeds by $3,164,100. The Trust will not be liable for such excess costs, and such excess costs will hereafter constitute Excess Infill Net Profit Costs until recovered by WPC. The Trust will not receive its 20 percent interest in WPC’s Infill Net Proceeds until such time as the Infill Net Profits Gross Proceeds exceeds the Infill Net Profit Costs on an aggregate basis.

     The complete definitions of Infill Net Profit Costs, Infill Net Profit Gross Proceeds, Excess Infill Net Profit Costs, NPI Net Proceeds and Infill Net Proceeds are set forth in the Conveyance. See “Item 2—Properties—The Royalty Interests” for more information generally and Note 9 to “Item 8—Financial Statements and Supplementary Data—Notes to Financial Statements” for information regarding the net proved reserves attributable to the Trust.

Liabilities of the Trust

     Because of the passive nature of the Trust assets and the restrictions on the power of the Trustee to incur obligations, the only liabilities the Trust generally incurs are those for routine administrative expenses, such as Trustees’ fees and accounting, engineering, legal and other professional fees and the administrative services fee paid to Williams. However, if a court were to hold that the Trust is taxable as a corporation for Federal income tax purposes, then the Trust would incur substantial Federal income tax liabilities. See “—Federal Income Taxation.”

Duties and Limited Powers of the Trustee

     Under the Trust Agreement, the Trustee receives the payments attributable to the Royalty Interests and pays all expenses, liabilities and obligations of the Trust. With respect to any liability that is contingent or uncertain in amount or that otherwise is not currently due and payable, the Trustee has the discretion to establish a cash reserve for the payment of such liability. The Trustee is also entitled to cause the Trust to borrow money to pay expenses, liabilities and obligations that cannot be paid out of cash held by the Trust. Any such borrowings may be from any source, including from the entity serving as Trustee or Delaware Trustee, provided that the entity serving as Trustee or Delaware Trustee shall not be obligated to lend to the Trust. To secure payment of any such indebtedness (including any indebtedness to the entity serving as Trustee or Delaware Trustee), the Trustee is authorized to (i) mortgage and otherwise encumber the entire Trust estate or any portion thereof; (ii) carve out and convey production payments; (iii) include all terms, powers, remedies, covenants and provisions it deems necessary

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or advisable, including confession of judgment and the power of sale with or without judicial proceedings; and (iv) provide for the exercise of those and other remedies available to a secured lender in the event of a default on such loan. The terms of such indebtedness and security interest, if funds were loaned by the entity serving as Trustee or Delaware Trustee, must be similar to the terms which such entity would grant to a similarly-situated commercial customer with whom it did not have a fiduciary relationship, and such entity shall be entitled to enforce its rights with respect to any such indebtedness and security interest as if it were not then serving as trustee.

     The Trustee is authorized and directed to sell and convey the Royalty Interests without Unitholder approval in certain instances as described in the Trust Agreement, including (i) upon termination of the Trust; (ii) commencing January 1, 2003, if a portion of the NPI ceases to produce or is not capable of producing in commercially paying quantities (see “Item 2—Properties—The Royalty Interests—Sale and Abandonment of Underlying Properties”); and (iii) in connection with payment of a purchase price adjustment for uncompleted wells (see “Item 2—Properties—The Royalty Interests—Purchase Price Adjustments” and “—Title to Properties”). The Trustee is empowered by the Trust Agreement to employ consultants and agents (including WPC and Williams) and to make payments of all fees for services or expenses out of the assets of the Trust. The Trust has no employees. The administrative functions of the Trust are performed by the Trustee.

     The Trust Agreement authorizes the Trustee to take such action as in its judgment is necessary or advisable to achieve the purposes of the Trust. The Trustee is authorized to agree to modifications of the terms of the Conveyance and to settle disputes with respect thereto, so long as such modifications or settlements do not result in treatment of the Trust as an association taxable as a corporation for Federal income tax purposes and such modifications or settlements do not alter the nature of the Royalty Interests as a right to receive a share of the proceeds of production from the Underlying Properties which, with respect to the Trust, are free of any operating rights, expense or cost. The Trust Agreement provides that cash being held by the Trustee as a reserve for liabilities or for distribution at the next distribution date will be placed in demand accounts, U.S. government obligations, repurchase agreements secured by such obligations, or certificates of deposit, but the Trustee is otherwise prohibited from acquiring any asset other than the Royalty Interests or engaging in any business or investment activity of any kind whatsoever. The Trustee may deposit funds awaiting distribution in an account with the Trustee or Delaware Trustee provided the interest paid equals the amount paid by the Trustee or Delaware Trustee on similar deposits.

Liabilities of the Delaware Trustee and the Trustee

     Each of the Delaware Trustee and the Trustee may act in its discretion and shall be personally or individually liable only for fraud or acts or omissions in bad faith or that constitute gross negligence and will not be otherwise liable for any act or omission of any agent or employee unless such trustee has acted in bad faith or with gross negligence in the selection and retention of such agent or employee. Each of the Delaware Trustee and the Trustee will be indemnified from the Trust assets for any liability, expense, claim, damage or other loss incurred in performing its duties, unless resulting from gross negligence, fraud or bad faith (the Delaware Trustee or the Trustee will be indemnified from the Trust assets against its own negligence that does not constitute gross negligence), and will have a first lien upon the assets of the Trust as security for such indemnification and for reimbursements and compensation to which it is entitled. WPC and Williams have agreed to indemnify each of the Delaware Trustee and the Trustee against certain environmental and securities laws liabilities, respectively, provided that the Trustee and Delaware Trustee are generally required to first be indemnified from Trust assets before seeking indemnification from WPC or Williams. Neither the Delaware Trustee nor the Trustee shall be entitled to indemnification from Unitholders (except in connection with lost or destroyed Unit certificates).

Termination and Liquidation of the Trust

     The Trust was not permitted to terminate prior to January 1, 2003, except upon the affirmative vote of the holders of not less than 75 percent of the outstanding Units to liquidate the Trust. On and after January 1, 2003, the Trust will terminate upon the first to occur of (i) an affirmative vote of the holders of not less than a majority of the outstanding Units to liquidate the Trust; (ii) such time as the ratio of the cash amounts received by the Trust from the Royalty Interests (excluding deductions for capital expenditures for enhanced recovery or similar operations on the WI Properties) to administrative costs of the Trust is less than 1.2 to 1.0 for three consecutive calendar quarters; (iii) such time as the Royalty Interests held by the Trust have been sold by the Trust; (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

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present value (discounted at 10 percent) of the estimated future net revenues (calculated in accordance with criteria established by the Securities and Exchange Commission (the “Commission”) but using the average monthly Blanco Hub Spot Price (as defined; see “Item 2—Properties—The Royalty Interests—Gas Purchase Contract”)) of proved reserves attributable to the Royalty Interests is equal to or less than $30 million; and (v) December 31, 2012 (the date of any such occurrence 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. WPC has the right, but not the obligation, 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 the offer for approximately 60 days and seek to locate other buyers for the remaining Royalty Interests. 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 locate other buyers for the 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, acceptable to the Trustee (which must be an all-cash offer), received during such period (the “Highest Offer Price”). WPC then has the 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 Offer Price is more than 105 percent of WPC’s original offer (or if WPC did not make an initial offer), the purchase price will be 105 percent of the Highest Offer Price (net of any commissions or other fees payable by the Trust), or (ii) if the Highest Offer Price is equal to or less than 105 percent of WPC’s original offer, the purchase price will be equal to the Highest Offer Price. 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.

     If a sale of the Royalty Interests is made or a definitive contract for sale of the Royalty Interests is entered into within a 150-day period following the Termination Date, the buyer of the Royalty Interests, and not the Trust or Unitholders, will be entitled to all proceeds of production attributable to the Royalty Interests following the Termination Date.

     In the event that WPC does not purchase the Royalty Interests, the Trustee may accept any offer for all or any part of the 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. If any 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, which sale may be to WPC or any of its affiliates.

     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.

DESCRIPTION OF UNITS

     Each Unit represents an equal undivided share of beneficial interest in the Trust and is evidenced by a transferable certificate issued by the Trustee. Each Unit entitles its holder to the same rights as the holder of any other Unit, and the Trust has no other authorized or outstanding class of equity security. At March 1, 2006, there were 9,700,000 Units outstanding. The Trust may not issue additional Units.

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Distributions and Income Computations

     The Trustee determines for each quarter the amount of cash available for distribution to Unitholders. Such amount (the “Quarterly Distribution Amount”) is equal to the excess, if any, of the cash received by the Trust, on or prior to the last day of the month following the end of each calendar quarter ending prior to the dissolution of the Trust from the Royalty Interests then held by the Trust plus, with certain exceptions, any other cash receipts of the Trust during such quarter (which might include purchase price adjustments paid by WPC, sales proceeds not sufficient in amount to qualify for special distribution as described in the next paragraph, and interest), over the liabilities of the Trust paid during such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for the payment of contingent or future obligations of the Trust. Based on the payment procedures relating to the Royalty Interests, cash received by the Trustee in a particular quarter from the Royalty Interests generally represents the sum of (i) proceeds from the sale of gas produced from the WI Properties during the preceding calendar quarter plus (ii) cash received by WPC with respect to the Farmout Properties either (a) during the preceding calendar quarter or (b) if received in sufficient time to be paid to the Trust, in the month immediately following such preceding calendar quarter. The Trustee distributes the Quarterly Distribution Amount within 60 days after the end of each calendar quarter to each person who was a Unitholder of record on the associated record date (i.e., the 45th day following the end of each calendar quarter or if such day is not a business day, the next business day thereafter), together with interest expected to be earned on such Quarterly Distribution Amount from the date of receipt thereof by the Trustee to the payment date.

     The Royalty Interests may be sold under certain circumstances and will be sold following termination of the Trust. Any purchase price adjustments and the proceeds from sales of the Royalty Interests, less liabilities and expenses of the Trust and amounts used for cash reserves, will be distributed, together with any interest expected to be earned thereon, to Unitholders of record on the record date established for such distribution. A special distribution will be made of undistributed sales proceeds, purchase price adjustments and other amounts received by the Trust aggregating in excess of $9,000,000 (a “Special Distribution Amount”). The record date for a Special Distribution Amount will be the 15th day following receipt of amounts aggregating a Special Distribution Amount by the Trust (unless such day is not a business day in which case the record date will be the next business day thereafter) unless such day is within 10 days of the record date for a Quarterly Distribution Amount in which case the record date will be the date as is established for the next Quarterly Distribution Amount. Distribution to Unitholders will be made no later than 15 days after the Special Distribution Amount record date.

     The terms of the Trust Agreement seek to assure, to the extent practicable, that gross income attributable to cash being distributed will be reported by the Unitholder who receives such distributions assuming that such Unitholder is the owner of record on the applicable record date. In certain circumstances, however, a Unitholder will not receive the cash giving rise to such income. For example, the Trustee maintains a cash reserve and is authorized to borrow money under certain conditions to pay or provide for the payment of Trust liabilities. Income associated with the cash used to increase that reserve or to repay any such borrowings must be reported by the Unitholder, even though that cash is not distributed to him. Likewise, if a portion of a cash distribution is attributable to a reduction in the cash reserve maintained by the Trustee, such cash is treated as a reduction of the Unitholder’s basis in his Units and is not treated as taxable income to such Unitholder (assuming such Unitholder’s basis exceeds the total amount of the cash distribution).

Transfer of Royalty Interests

     WPC or its assigns may, at any time, purchase for cash all Royalty Interests attributable to Underlying Properties that are uneconomical to operate. See “Item 2—Properties—The Royalty Interests—Title to Properties” and “—Sale and Abandonment of Underlying Properties.” Upon termination of the Trust, any remaining Royalty Interests will be sold by the Trust and any such sales may, and under certain circumstances will, be made to WPC or Williams or their respective successors or assigns. See “Item 2—Description of the Trust—Termination and Liquidation of the Trust.”

Possible Divestiture of Units

     The Trust Agreement imposes no restrictions based on nationality or other status of Unitholders. However, the Trust Agreement provides that in the event of certain judicial or administrative proceedings seeking the

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cancellation or forfeiture of any property in which the Trust has an interest, or asserting the invalidity of or otherwise challenging any portion of the Royalty Interests, because of the nationality, citizenship or any other status of any one or more Unitholders, the Trustee will give written notice thereof to each Unitholder whose nationality, citizenship or other status is an issue in the proceeding, which notice will constitute a demand that such Unitholder dispose of his Units within 30 days. If any Unitholder fails to dispose of his Units in accordance with such notice, the Trustee shall have the right to cancel all outstanding certificates issued in the name of such Unitholder, transfer all Units held by such Unitholder to the Trustee and sell such Units (including by private sale). The proceeds of such sale (net of sales expenses), pending delivery of certificates representing the Units, will be held by the Trustee in a non-interest bearing account for the benefit of the Unitholder and paid to the Unitholder upon surrender of such certificates. Cash distributions payable to such Unitholder will also be held in a non-interest bearing account pending disposition by the Unitholder of the Units or cancellation of certificates representing the Units by the Trustee.

Periodic Reports to Unitholders

     Within 60 days following the end of each of the first three calendar quarters of each calendar year, the Trustee mails to each party who was a Unitholder of record (i) on the quarterly record date for such quarter or (ii) on a Special Distribution Amount record date occurring during such quarter (if any), a report that shows in reasonable detail the assets and liabilities and receipts and disbursements of the Trust for such quarter. Unitholders are also furnished with comparable quarterly information with respect to the Underlying Properties. Within 120 days following the end of each fiscal year or such shorter period of time as may be required by the rules of the New York Stock Exchange, the Trustee mails to Unitholders of record as of a date to be selected by the Trustee an annual report containing audited financial statements relating to the Trust and the Underlying Properties.

     The Trustee files such returns for Federal income tax purposes as it is advised are required to comply with applicable law. The Trustee mails to each party who was a Unitholder of record (i) on the quarterly record date for such quarter or (ii) on a Special Distribution Amount record date occurring during such quarter (if any), a report that shows in reasonable detail the information necessary to permit each Unitholder to make all calculations reasonably necessary for tax purposes. The Trustee treats all income, credits and deductions recognized during each quarter as having been recognized by holders of record on the quarterly record date established for the distribution unless otherwise advised by counsel. Available year-end tax information permitting each Unitholder to make all calculations reasonably necessary for tax purposes is distributed by the Trustee to Unitholders no later than March 15 of the following year.

     Each Unitholder and his duly authorized agents and attorneys have the right during reasonable business hours to examine and inspect records of the Trust and the Trustee.

Voting Rights of Unitholders

     Unitholders have only such voting rights as are provided in the Trust Agreement and such rights are more limited than those of stockholders of most corporations. Unitholder approval is, however, required to appoint a successor Trustee or Delaware Trustee. Also, Unitholder approval is required to amend the Trust Agreement (except for changing the name of the Trust and except to correct or cure ambiguities in the Trust Agreement that do not adversely affect Unitholders) and to adopt any amendment to the Gas Gathering Contract relating to production from the Underlying Properties entered into between WFS (a subsidiary of Williams Energy Services) and WPX Gas Resources Company (a subsidiary of WPC (formerly known as WFS Resources Company), “WPX Gas Resources”) as successor-in-interest to WGM (a former subsidiary of Williams Field Services Group, Inc., which has been merged into another affiliate of Williams Field Services Group, Inc.) or to the Gas Purchase Contract relating to production from the Underlying Properties entered into between WPC and WPX Gas Resources (as successor-in-interest to WGM), if such amendment would materially adversely affect revenues of the Trust. Unitholders may also remove the Trustee or Delaware Trustee. Unitholders are not entitled to any rights of appraisal or similar rights in connection with the termination of the Trust.

     The Trust Agreement may be amended, the Delaware Trustee and the Trustee may be removed and the Trust may be terminated by a vote of holders of a majority of the outstanding Units, but no provision of the Trust Agreement may be amended that would (i) increase the power of the Delaware Trustee or the Trustee to engage in

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business or investment activities, or (ii) alter the rights of the Unitholders as among themselves. All other actions may be approved by a majority vote of the Units represented at a meeting at which a quorum, constituting a majority of the outstanding Units, is present or represented (except that amendment of required voting percentages requires approval of at least 80 percent of the outstanding Units). The parties to the Trust Agreement may, without approval of the Unitholders, from time to time, supplement or amend the Trust Agreement in order to cure any ambiguity or to correct or supplement any defective or inconsistent provisions, provided such supplement or amendment is not adverse to the interest of the Unitholders. In addition, Williams may direct the Trustee to change the name of the Trust, which change shall not require approval of the Unitholders.

     Meetings of Unitholders may be called by the Trustee or by Unitholders owning not less than 10 percent in number of the outstanding Units. All such meetings shall be held in Dallas, Texas, and written notice of every such meeting setting forth a time and place of the meeting and the matters proposed to be acted upon shall be given not more than 60 nor less than 20 days before such meeting. Each Unitholder shall be entitled to one vote for each Unit owned by such holder.

Liability of Unitholders

     Consistent with Delaware law, the Trust Agreement provides that the Unitholders will have the same limitation on personal liability as is accorded under the laws of such state to stockholders of a corporation for profit. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

Transfer Agent

     The Trustee has appointed Mellon Investor Services, L.L.C. (as successor to Chemical Shareholder Services Group, Inc.), as transfer agent and registrar for the Units (the “Transfer Agent”).

Website/SEC Filings

     The Trust maintains an Internet Website (www.wtu-williamscoalseamgastrust.com), and as a result provides website access to its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports as soon as reasonably practicable after it electronically files with or furnishes such material to the SEC.

FEDERAL INCOME TAXATION

     THE TAX CONSEQUENCES TO A UNITHOLDER OF THE OWNERSHIP AND SALE OF UNITS WILL DEPEND IN PART ON THE UNITHOLDER’S TAX CIRCUMSTANCES. EACH UNITHOLDER SHOULD THEREFORE CONSULT THE UNITHOLDER’S TAX ADVISOR ABOUT THE FEDERAL, STATE AND LOCAL TAX CONSEQUENCES TO THE UNITHOLDER OF THE OWNERSHIP OF UNITS.

     The sections entitled “Federal Income Tax Consequences” and “Risk Factors—Tax Considerations” appearing in the Prospectus (the “Public Offering Prospectus”) dated January 13, 1993, which constitutes a part of the Registration Statement on Form S-3 of Williams (Registration No. 33-53662) filed in connection with the registration of the Units under the Securities Act of 1933 for offer and sale in the Public Offering, set forth, respectively, a summary of Federal income tax matters of general application that addresses the material tax consequences of the ownership and sale of the Units acquired in the Public Offering and a discussion of certain risk factors associated with matters of Federal income taxation as applied to the Trust and such Unitholders. A copy of such sections of the Public Offering Prospectus is filed as an exhibit to this Form 10-K and is incorporated herein by reference.

     In connection with the registration of the Units for offer and sale in the Public Offering, Williams and the underwriters of the Units received certain opinions of counsel to Williams (upon which the Trustee and the Delaware Trustee were entitled to rely), including, without limitation, opinions as to the material Federal income tax

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consequences of the ownership and sale of the Units acquired in the Public Offering. The opinions of counsel to Williams as to such Federal income tax consequences were based on provisions of the Internal Revenue Code of 1986, as amended (the “IRC”), as of January 21, 1993, the date of the closing of the Public Offering, existing and proposed regulations thereunder and administrative rulings and court decisions as of January 21, 1993, all of which are subject to changes that may or may not be retroactively applied. Some of the applicable provisions of the IRC have not been interpreted by the courts or the Internal Revenue Service (“IRS”). In addition, such opinions of counsel to Williams were based on various representations as to factual matters made by Williams and WPC in connection with the Public Offering. As is typically the case, these opinions were limited in their application to certain investors purchasing Units in the Public Offering and, as a result, provide no assurance to investors purchasing Units following the Public Offering.

     Neither counsel to the Trust, the Trustee nor the Delaware Trustee, respectively, has rendered any opinions with respect to any tax matters associated with the Trust or the Units.

     At the time of the Public Offering, no ruling was requested by Williams, as the sponsor of the Trust, from the IRS with respect to any matter affecting the Trust or Unitholders. No assurance can be provided that the opinions of counsel to Williams (which do not bind the IRS) will not be challenged by the IRS or will be sustained by a court if so challenged.

Summary of Certain Federal Income Tax Consequences

     The following summary of certain Federal income tax consequences of acquiring, owning and disposing of Units is based on the opinions of counsel to Williams on Federal income tax matters, which are set forth in the Public Offering Prospectus, and is qualified in its entirety by express reference to the sections of the Public Offering Prospectus identified in the first paragraph of this “Federal Income Taxation” section. Although the Trust believes that the following summary contains a description of all of the material matters discussed in the opinions referenced above, the summary is not exhaustive and many other provisions of the Federal tax laws may affect individual Unitholders. Furthermore, the summary does not purport to be complete or to address the tax issues potentially affecting Unitholders acquiring Units other than by purchase through the Public Offering. Each Unitholder should consult the Unitholder’s tax advisor with respect to the effects of the Unitholder’s ownership of Units on the Unitholder’s personal tax situation.

     Coal seam gas produced and sold after December 31, 2002, no longer generates Section 29 tax credits under the IRC. Therefore, Unitholders are not entitled to claim Section 29 tax credits for coal seam gas produced and sold after 2002. However, a Unitholder may benefit from unused Section 29 tax credits for alternative minimum tax purposes as discussed below. All discussions of Section 29 tax credits are applicable only to those credits attributable to coal seam gas produced and sold on or before December 31, 2002.

Classification and Taxation of the Trust	The Trust is a grantor trust for Federal tax purposes and not an association taxable as a corporation. As a grantor trust, the Trust is not subject to Federal income tax. There can be no assurance that the IRS will not challenge this treatment. The tax treatment of the Trust and Unitholders would be materially different if the IRS were to successfully challenge this treatment.
Taxation of Unitholders	Each Unitholder is taxed directly on his proportionate share of income, deductions and credits of the Trust attributable to the Royalty Interests consistent with such Unitholder’s taxable year and method of accounting, and without regard to the taxable year or method of accounting employed by the Trust.
Income and Deductions	The income of the Trust consists primarily of a specified share of the proceeds from the sale of coal seam gas produced from the Underlying Properties. During 2005, the Trust earned interest income on funds held for distribution and made adjustments to the cash reserve maintained for the payment of contingent or future

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	obligations of the Trust. The deductions of the Trust consist of severance taxes and administrative expenses. In addition, each Unitholder is entitled to depletion deductions. See “Unitholder’s Depletion Allowance” below.
	Individuals may deduct “miscellaneous” itemized deductions (including, in general, investment expenses) only to the extent that such expenses exceed 2 percent of the individual’s adjusted gross income. Although there are exceptions to the 2 percent limitation, authority suggests that no exceptions apply to expenses passed through from a grantor trust, like the Trust.
Section 29 Tax Credits	Coal seam gas produced and sold after December 31, 2002, no longer generates a Section 29 tax credit under the IRC. Therefore, Unitholders are not entitled to claim Section 29 tax credits for coal seam gas produced and sold after 2002. However, a Unitholder may benefit from unused Section 29 tax credits for alternative minimum tax purposes. Before its expiration, the Section 29 tax credit could be used only to the extent that a Unitholder’s regular tax liability exceeded the Unitholder’s tentative minimum tax liability after the regular tax liability had been reduced by the foreign tax credit and certain nonrefundable personal credits. Any part of the Section 29 tax credit not allowed for the tax year solely because of this alternative minimum tax limitation was subject to certain carryover provisions relating to the alternative minimum tax calculation. These carryover provisions continue to apply for tax years ending before 2006. Therefore, for taxpayers with tax years ending on or before December 31, 2005, the alternative minimum tax limitation is increased by the amount of Section 29 tax credits disallowed in prior years, even though the Section 29 tax credit is no longer allowed for coal seam gas produced and sold after 2002.
Unitholder’s Depletion Allowance	Each Unitholder is entitled to amortize the cost of the Units through cost depletion over the life of the NPI (or if greater, through percentage depletion equal to 15 percent of gross income). If any portion of the NPI is treated as a production payment or is not treated as an economic interest, however, a Unitholder will not be entitled to depletion in respect of such portion.
Depletion Recapture	If a taxpayer disposes of any “section 1254 property” (certain oil, gas, geothermal or other mineral property), and if the adjusted basis of such property includes adjustments for deductions for depletion under Section 611 of the IRC (discussed above), the taxpayer generally must recapture the amount deducted for depletion in ordinary income (to the extent of gain realized on the disposition of the property). This depletion recapture rule applies to any disposition of property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the United States Treasury regulations govern dispositions of property after March 13, 1995. The IRS will likely take the position that a Unitholder who purchases a Unit subsequent to December 31, 1986, must recapture depletion upon the disposition of that Unit.
Non-Passive Activity Income, Credits	The income, credits and expenses of the Trust are not taken into

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and Loss	account in computing the passive activity losses and income under Section 469 of the IRC for a Unitholder who acquires and holds Units as an investment and did not acquire them in the ordinary course of a trade or business.
Unitholder Reporting Information	The Trustee furnishes to Unitholders tax information concerning royalty income, depletion and other relevant tax matters on an annual basis. Year-end tax information is furnished to Unitholders no later than March 15 of the following year. See the second paragraph under “Description of Units—Periodic Reports to Unitholders.”
Tax Shelter Registration	The Trust is registered as a “tax shelter,” and its tax shelter registration number is 92-364000072. Issuance of a tax shelter registration number does not indicate that the investment in Units or the claimed tax benefits have been reviewed, examined or approved by the IRS.

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ERISA CONSIDERATIONS

     The section entitled “ERISA Considerations” appearing in the Public Offering Prospectus sets forth certain information regarding the applicability of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), and the IRC to pension, profit-sharing and other employee benefit plans, and to individual retirement accounts (collectively, “Qualified Plans”). A copy of this section of the Public Offering Prospectus is filed as an exhibit to this Form 10-K and is incorporated herein by reference.

     Due to the complexity of the prohibited transaction rules and the penalties imposed upon persons involved in prohibited transactions, it is important that potential qualified plan investors consult their counsel regarding the consequences under ERISA and the IRC of their acquisition and ownership of Units.

STATE TAX CONSIDERATIONS

     THE FOLLOWING IS INTENDED AS A BRIEF SUMMARY OF CERTAIN INFORMATION REGARDING STATE INCOME TAXES AND OTHER STATE TAX MATTERS AFFECTING THE TRUST AND UNITHOLDERS. UNITHOLDERS SHOULD THEREFORE CONSULT THE UNITHOLDER’S TAX ADVISOR REGARDING STATE INCOME TAX FILING AND COMPLIANCE MATTERS.

     Unitholders should consider state and local tax consequences of holding Units. The Trust owns Royalty Interests burdening gas properties located in New Mexico and Colorado. Both New Mexico and Colorado have income taxes applicable to individuals and corporations (subject to certain exceptions for S corporations). A Unitholder is generally required to file state income tax returns and/or pay taxes in those states and may be subject to penalties for failure to comply with such requirements. In addition, these states may require the Trust to withhold tax from distributions to Unitholders to the extent such distributions are attributable to income from properties located in such states.

     The Trustee will provide information concerning the Units sufficient to identify the income from Units that is allocable to each state. Unitholders should consult their own tax advisors to determine their income tax filing requirements with respect to their share of income of the Trust allocable to states imposing an income tax on such income.

     The Trust has been structured to cause the Units to be treated for certain state law purposes essentially the same as other securities, that is, as interests in intangible personal property rather than as interests in real property. If the Units are held to be real property or an interest in real property under the laws of either or both of such states, a Unitholder, even if not a resident of such state, could be subject to devolution, probate and administration laws, and inheritance or estate and similar taxes, under the laws of such state.

REGULATION AND PRICES

Regulation of Natural Gas

     The production, transportation and sale of natural gas from the Underlying Properties are subject to Federal and state governmental regulation, including regulation of tariffs charged by pipelines, taxes, the prevention of waste, the conservation of gas, pollution controls and various other matters.

     Legislative Proposals. In the past, Congress has been very active in the area of gas regulation. Legislation enacted in recent years has repealed incremental pricing requirements and gas use restraints previously applicable.

     Federal and State Regulation of Gas. The Underlying Properties are subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) and the Department of Energy (“DOE”) with respect to various aspects of gas operations, including marketing and production of gas but not the wellhead price for natural gas. All sales of natural gas produced from the Underlying Properties are considered under the Natural Gas Policy Act of

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1978 (“NGPA”) and the Natural Gas Wellhead Decontrol Act of 1989 to be sold at the wellhead (as opposed to downstream sales or resales) for purposes of pricing and therefore are not subject to federal regulation.

     The transportation of natural gas in interstate commerce is subject to Federal regulation by FERC under the Natural Gas Act (“NGA”) and the NGPA. FERC has initiated a number of regulatory policy initiatives that have affected the transportation of natural gas from the wellhead to the market and may promulgate new regulations that affect the marketing of natural gas. Such initiatives include regulations that are intended to further open access to interstate pipelines by requiring such pipelines to unbundle their transportation services from sales services and allow customers to choose and pay for only the services they require, regardless of whether the customer purchases natural gas from such pipelines or from other suppliers. Although these regulations should generally facilitate the transportation of natural gas produced from the Underlying Properties to natural gas markets, the impact of these regulations on prices and costs related to the marketing production from the Underlying Properties cannot be fully predicted at this time; however, it is possible such impact could be significant. On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the NGA to prohibit natural gas market manipulation by any entity and allows FERC to facilitate market transparency in the market for natural gas.

     Many state jurisdictions have at times imposed limitations on the production of gas by restricting the rate of flow for gas wells from their actual capacity to produce and by imposing acreage limitations for the drilling of a well. State and local jurisdictions have also imposed permitting requirements or other requirements that may delay the drilling of new wells. Most states regulate the exploration for and the subsequent production of gas. These regulations include requirements for obtaining drilling permits, the method of developing new fields, provisions for the unitization or pooling of gas properties, the spacing, operation, plugging and abandonment of wells and the prevention of waste of gas resources. The rate of production may be regulated and the maximum daily production allowable from gas wells may be established on a market demand or conservation basis or both.

     Several states have in past years also enacted or proposed regulations intended to revise significantly current systems of prorationing gas production. The modified rules may decrease the total amount of gas produced and could result in an increase in market prices for gas. The foregoing developments have fostered debate regarding the purpose and effect of the new prorationing rules, with opponents of such rules arguing that the primary purpose thereof is to increase gas prices by withholding supplies from the market.

     At the present time, it is impossible to predict what potential regulatory proposals, if any, might actually be enacted by Congress or the various state legislatures or regulatory entities and what effect, if any, such proposals might have on the Underlying Properties gas or oil prices and the Trust.

Environmental Regulation

     General. Activities on the Underlying Properties are subject to existing Federal, state and local laws (including case law), rules and regulations governing health, safety, environmental quality and pollution control. It is anticipated that, absent the occurrence of an extraordinary circumstance or event, compliance with existing Federal, state and local laws, rules and regulations regulating health, safety, the release of materials into the environment or otherwise relating to the protection of the environment will not have a material adverse effect upon the Trust or Unitholders. The Trustee cannot predict what effect additional regulation or legislation, enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from operations on the Underlying Properties could have on the Trust or Unitholders. However, pursuant to the terms of the Conveyance, any costs or expenses incurred by WPC in connection with environmental liabilities arising out of or relating to activities occurring on, in or in connection with, or conditions existing on or under, the Underlying Properties before October 1, 1992, will be borne by WPC and not the Trust and will not be deducted in calculating NPI Net Proceeds or Infill Net Proceeds. Environmental costs or expenses that are attributable to the Farmout Properties that arise after October 1, 1992, could reduce the revenue paid to WPC and, therefore, the amount of NPI Net Proceeds.

     Solid and Hazardous Waste. The Royalty Interests are carved out of WPC’s interests in certain properties that have produced gas from other formations for many years. WPC, the owner of the Underlying Properties, has acted as operator for only a small number of the coal seam gas wells, and for a relatively short period of time. Williams and WPC have advised the Trustee that to their knowledge, although WPC and the other operators have

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utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other solid or hazardous wastes may have been disposed or released on or under the Underlying Properties by the current or previous operators. Federal, state and local laws applicable to gas-related wastes and properties have become increasingly more stringent. Under these laws, WPC or an operator of the Underlying Properties could be required to remove or remediate previously disposed wastes or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination.

     The operations of the Underlying Properties may generate wastes that are subject to the Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The Environmental Protection Agency (the “EPA”) has limited the disposal options for certain hazardous wastes and may adopt more stringent disposal standards for nonhazardous wastes.

     Superfund. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund” law, imposes liability, regardless of fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the current or previous owner and the current or previous operator of a site and companies that disposed or arranged for the disposal of, the hazardous substance found at a site. CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to the public health or the environment and to seek recovery from such responsible classes of persons of the costs of such action. In the course of their operations, the operators of the Underlying Properties have generated and will generate wastes that may fall within CERCLA’s definition of “hazardous substances.” Quatro Finale (as a previous owner), WPC or an operator of the Underlying Properties may be responsible under CERCLA for all or part of the costs to clean up sites at which such substances have been disposed.

     Air Emissions. The operations of the Underlying Properties are subject to Federal, state and local regulations concerning the control of emissions from sources of air contaminants. Administrative enforcement actions for failure to comply strictly with air regulations or permits are generally resolved by payment of a monetary penalty and correction of any identified deficiencies. Regulatory agencies could require the operators to forego or modify construction or operation of certain air emission sources.

     OSHA/Right-to-know. The operations of the Underlying Properties are subject to the requirements of the Federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and similar state statutes require that information be organized and maintained about hazardous materials used or produced in the operations. Certain of this information must be provided to employees, state and local government authorities and citizens.

     The Minerals Management Service of the United States Department of the Interior amended the natural gas valuation regulations in June 2005 for oil and natural gas produced from federal oil and natural gas leases. The principal effect of the natural gas valuation regulations pertains to the calculation of transportation deductions and changes necessitated by judicial decisions since the regulations were last amended. These changes have not had a significant effect on trust distributions but could have a significant effect on trust distributions in the future.

Competition, Markets and Prices

     The revenues of the Trust and the amount of cash distributions to Unitholders depend upon, among other things, the effect of competition and other factors in the market for natural gas. The gas industry is highly competitive in all of its phases. WPC encounters competition from major oil and gas companies, independent oil and gas concerns, and individual producers and operators. Many of these competitors have greater financial and other resources than WPC. Competition is also potentially presented by alternative fuel sources, including heating oil and other fossil fuels, and non-conventional sources such as wind energy.

     Demand for natural gas has increased recently after spiking up during the winter months. This increase was in response to stronger domestic economic conditions, relatively higher prices for alternative energy sources such as crude oil, and other factors. Increased demand has recently resulted in higher prices for natural gas. In addition, in the recent short term, demand for natural gas production in the United States has generally resulted in increased competitive pressure and significantly higher natural gas prices. The existence or effect of any shortages or excesses of natural gas production capacity as may exist in the future cannot be predicted with certainty. See “Item 2—Properties—The Royalty Interests—Historical Gas Sales Prices and Production.”

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     Demand for natural gas production has historically been seasonal in nature and prices for gas fluctuate accordingly. Consequently, the amount of cash distributions by the Trust may vary substantially on a seasonal basis. Generally, gas production volumes and prices tend to be higher during the first and fourth quarters of the calendar year. Because of the lag between the receipt of revenues related to the Underlying Properties and the dates on which distributions are made to Unitholders, however, any seasonality that affects production and prices generally should be reflected in distributions that are made to Unitholders in later periods. See “—Description of Units—Distributions and Income Computations.”

     Prices for natural gas are subject to wide fluctuations in response to relatively minor changes in supply, market uncertainty and a variety of additional factors that are beyond the control of the Trust, Williams and WPC. These factors include political conditions in the Middle East, the price and quantity of imported oil and gas, the level of consumer product demand, the severity of weather conditions, government regulations, the price and availability of alternative fuels and overall economic conditions. In view of the many uncertainties affecting the supply and demand for natural gas and natural gas prices, the Trust and Williams are unable to make reliable predictions of future gas prices, production, or demand or the overall effect they will have on the Trust.

Item 1A. Risk Factors.

Natural gas prices are volatile and fluctuate in response to a number of factors. Lower prices could reduce the net proceeds payable to the trust and trust distributions.

     The trust’s quarterly distributions are highly dependent upon the prices realized from the sale of natural gas and a material decrease in such prices could reduce the amount of cash distributions paid to Unitholders. Natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust. Factors that contribute to price fluctuation include, among others:

• political conditions in major oil and gas producing regions, especially the Middle East;

• worldwide economic conditions;

• weather conditions;

• the supply and price of domestic and foreign natural gas;

• the level of consumer demand;

• the price and availability of alternative fuels;

• the proximity to, and capacity and cost of, transportation facilities;

• the effect of worldwide energy conservation measures; and

• the nature and extent of governmental regulation and taxation.

     When natural gas prices decline, the Trust is affected in two ways. First, net income from the Royalty Interests is reduced. Second, exploration and development activity on the Underlying Properties may decline as some projects may become uneconomic and are either delayed or eliminated. It is impossible to predict future natural gas price movements, and this reduces the predictability of future cash distributions to Unitholders. Approximately 90 percent of the natural gas produced from the WI Properties, which generates most of the natural gas produced burdened by the Trust’s Royalty Interests, is currently being sold pursuant to the Gas Purchase Contract entered into at the inception of the Trust whereby a subsidiary of Williams purchases the gas in accordance with a contractual pricing mechanism. At present, this contract is year-to-year and may be terminated at the end of any calendar year upon notice, and could be terminated as soon as December 31, 2006. Under this agreement, the adverse impact on trust revenues and, therefore, cash available for distribution to Unitholders, that would otherwise result from low natural gas prices is somewhat mitigated. However, the gas purchase agreement may significantly reduce trust revenues and, therefore, cash available for distribution to Unitholders, that would otherwise result from

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high natural gas prices. There is no assurance that the gas purchase contract will remain in effect after December 31, 2006. If it is terminated, revenues of the Trust and, therefore, cash available for distribution to Unitholders, will become increasingly susceptible to fluctuations resulting from changes in prevailing natural gas prices.

Increased production and development costs attributable to the Royalty Interests will result in decreased Trust distributions unless revenues also increase.

     Production and development costs attributable to the Royalty Interests are deducted in the calculation of the Trust’s share of net proceeds. Accordingly, higher or lower production and development costs will directly decrease or increase the amount received by the Trust from the Royalty Interests.

     If production and development costs attributable to the Royalty Interests exceed the gross proceeds related to production from the Underlying Properties, the Trust will not receive net proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional proceeds to repay the costs.

Trust reserve estimates depend on many assumptions that may prove to be inaccurate, which could cause both estimated reserves and estimated future net revenues to be too high, leading to write-downs of estimated reserves.

     The value of the Units will depend upon, among other things, the reserves attributable to the Royalty Interests in the underlying properties. The calculations of proved reserves included in this Form 10-K are only estimates, and estimating reserves is inherently uncertain. In addition, the estimates of future net revenues are based upon various assumptions regarding future production levels, prices and costs that may prove to be incorrect over time.

     The accuracy of any reserve estimate is a function of the quality of available data, engineering interpretation and judgment, and the assumptions used regarding the quantities of recoverable natural gas and the future prices of natural gas. Petroleum engineers consider many factors and make many assumptions in estimating reserves. Those factors and assumptions include:

• historical production from the area compared with production rates from similar producing areas;

• the effects of governmental regulation;

• assumptions about future commodity prices, production and development costs, taxes, and capital expenditures;

• the availability of enhanced recovery techniques; and

• relationships with landowners, working interest partners, pipeline companies and others.

     Changes in any of these factors and assumptions can materially change reserve and future net revenue estimates. The Trust’s estimate of reserves and future net revenues is further complicated because the Trust holds net profits interests and does not own a specific percentage of the natural gas reserves. Ultimately, actual production, revenues and expenditures for the Underlying Properties, and therefore actual net proceeds payable to the Trust, will vary from estimates and those variations could be material. Results of drilling, testing and production after the date of those estimates may require substantial downward revisions or write-downs of reserves.

The assets of the Trust are depleting assets and, if the other operators developing the Underlying Properties do not perform additional development projects, the assets may deplete faster than expected. Eventually, the assets of the Trust will cease to produce in commercial quantities and the Trust will cease to receive proceeds from such assets. In addition, a reduction in depletion tax benefits may reduce the market value of the Units.

     The net proceeds payable to the Trust are derived from the sale of depleting assets. The reduction in proved reserve quantities is a common measure of depletion. Future maintenance and development projects on the Underlying Properties will affect the quantity of proved reserves and can offset the reduction in proved reserves.

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The timing and size of these projects will depend on the market prices of natural gas. If the operators developing the Underlying Properties do not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by the Trust.

     Because the net proceeds payable to the Trust are derived from the sale of depleting assets, the portion of distributions to Unitholders attributable to depletion may be considered a return of capital as opposed to a return on investment. Distributions that are a return of capital will ultimately diminish the depletion tax benefits available to the Unitholders, which could reduce the market value of the Units over time. Eventually, the Underlying Properties will cease to produce in commercial quantities and the Trust will, therefore, cease to receive any distributions of net proceeds therefrom.

The market price for the Units may not reflect the value of the Royalty Interests held by the Trust.

     The public trading price for the Units tends to be tied to the recent and expected levels of cash distribution on the Units. The amounts available for distribution by the Trust vary in response to numerous factors outside the control of the Trust, including prevailing prices for natural gas produced from the Trust’s Royalty Interests. The market price is not necessarily indicative of the value that the Trust would realize if it sold those Royalty Interests to a third party buyer. In addition, such market price is not necessarily reflective of the fact that since the assets of the Trust are depleting assets, a portion of each cash distribution paid on the Units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. There is no guarantee that distributions made to a Unitholder over the life of these depleting assets will equal or exceed the purchase price paid by the Unitholder.

Operational risks and hazards associated with the development of the Underlying Properties may decrease Trust distributions.

     There are operational risks and hazards associated with the production and transportation of natural gas, including without limitation natural disasters, blowouts, explosions, fires, leakage of natural gas, releases of other hazardous materials, mechanical failures, cratering, and pollution. Any of these or similar occurrences could result in the interruption or cessation of operations, personal injury or loss of life, property damage, damage to productive formations or equipment, damage to the environment or natural resources, or cleanup obligations. The operation of natural gas properties is also subject to various laws and regulations. Non-compliance with such laws and regulations could subject the operator to additional costs, sanctions or liabilities. The uninsured costs resulting from any of the above or similar occurrences could be deducted as a cost of production in calculating the net proceeds payable to the Trust and would therefore reduce Trust distributions by the amount of such uninsured costs.

Terrorism and continued hostilities in the Middle East could decrease Trust distributions or the market price of the Units.

     Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as the military or other actions taken in response, cause instability in the global financial and energy markets. Terrorism, the war in Iraq and other sustained military campaigns could adversely affect Trust distributions or the market price of the Units in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in natural gas prices, or the possibility that the infrastructure on which the operators developing the Underlying Properties rely could be a direct target or an indirect casualty of an act of terror.

Unitholders and the Trustee have no influence over the operations on, or future development of, the Underlying Properties.

     Neither the Trustee nor the Unitholders can influence or control the operations on, or future development of, the Underlying Properties. The failure of an operator to conduct its operations, discharge its obligations, deal with regulatory agencies or comply with laws, rules and regulations, including environmental laws and regulations, in a proper manner could have an adverse effect on the net proceeds payable to the Trust. The current operators developing the Underlying Properties are under no obligation to continue operations on the Underlying Properties. Neither the Trustee nor the Unitholders have the right to replace an operator.

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The operator developing any Underlying Property may transfer its interest in the property without the consent of the Trust or the Unitholders.

     Any operator developing any of the Underlying Properties may at any time transfer all or part of its interest in the Underlying Properties to another party. Neither the Trust nor the Unitholders are entitled to vote on any transfer of the properties underlying the Royalty Interests, and the Trust will not receive any proceeds of any such transfer. Following any transfer, the transferred property will continue to be subject to the Royalty Interests, but the net proceeds from the transferred property will be calculated separately and paid by the transferee. The transferee will be responsible for all of the transferor’s obligations relating to calculating, reporting and paying to the Trust the Royalty Interests from the transferred property, and the transferor will have no continuing obligation to the Trust for that property.

The operator developing any Underlying Property may abandon the property, thereby terminating the Royalty Interests payable to the Trust.

     The operators developing the Underlying Properties, or any transferee thereof, may abandon any well or property without the consent of the Trust or the Unitholders if, in their opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities. This could result in the termination of the Royalty Interests relating to the abandoned well or property.

The Royalty Interests can be sold and the Trust would be terminated.

     The Trust will be terminated and the Trustee must sell the Royalty Interest if (i) the holders of a majority or more of the outstanding Units approve the sale or vote to terminate the Trust; (ii) the ratio of the cash amounts received by the Trust from the Royalty Interests (excluding deductions for capital expenditures for enhanced recovery or similar operations on the WI Properties) to administrative costs of the Trust is less than 1.2 to 1.0 for three consecutive calendar quarters; (iii) such time as the Royalty Interests held by the Trust have been sold by the Trust; (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 Securities and Exchange Commission (the “Commission”) but using the average monthly Blanco Hub Spot Price (as defined; see “Item 2—Properties—The Royalty Interests—Gas Purchase Contract”)) of proved reserves attributable to the Royalty Interests is equal to or less than $30 million; and (v) December 31, 2012 (the date of any such occurrence 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. There is no assurance that any such sale will be on terms acceptable to all Unitholders.

Trust Unitholders have limited voting rights and have limited ability to enforce the trust’s rights against the current or future operators developing the Underlying Properties.

     The voting rights of a Unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Unitholders or for an annual or other periodic re-election of the Trustee. Unlike corporations which are generally governed by boards of directors elected by their equity holders, the Trust is administered by an institutional trustee in accordance with the trust agreement and other organizational documents. The Trustee has extremely limited discretion in its administration of the Trust.

Financial information of the Trust is not prepared in accordance with GAAP.

     The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States, or GAAP. Although this basis of accounting is permitted for royalty trusts by the U.S. Securities and Exchange Commission, the financial statements of the Trust differ from GAAP financial statements because revenues are not accrued in the month of production and cash reserves may be established for specified contingencies and deducted which could not be accrued in GAAP financial statements.

The limited liability of Trust Unitholders is uncertain.

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     Consistent with Delaware law, the Trust Agreement provides that the Unitholders will have the same limitation on personal liability as is accorded under the laws of such state to stockholders of a corporation for profit. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

An increase in payments due to the U.S. Government for gas produced on Federal and Indian lands may result in a reduction of net proceeds from Royalty Interests.

     Approximately 80 percent of the Underlying Properties are burdened by Royalty Interests held by the Federal government or the Southern Ute Indian Tribe. Royalty payments due to the U.S. Government for gas produced from Federal and Indian lands included in the Underlying Properties must be calculated in conformance with its interpretation of regulations issued by the Minerals Management Service (“MMS”), a subagency of the U.S. Department of the Interior that administers and receives revenues from Federal and Indian royalties on behalf of the U.S. Government and as agent for the Indian tribes. The MMS regulations cover both valuation standards, which establish the basis for placing a value on production, and cost allowances, which define those post-production costs that are deductible by the lessee.

     The MMS generally audits royalty payments within a 6-year period. Although WPC calculates royalty payments in accordance with its interpretation of the then applicable MMS regulations, WPC does not know whether the royalty payments made to the U.S. Government are totally in conformity with MMS standards until the payments are audited. If an MMS audit, or any other audit by a Federal or state agency, results in additional royalty charges, together with interest, relating to production since October 1, 1992, in respect of the Underlying Properties, such charges and interest will be deducted in calculating NPI Net Proceeds for the quarter in which the charges are billed and in each quarter thereafter until the full amount of the additional royalty charges and interest have been recovered.

     As described in “Item 3—Legal Proceedings,” in 2001 WPC received an Audit Issue Letter from the State of New Mexico, acting under authority of MMS, followed by an MMS Order to Report and Pay Additional Royalties and Perform Restructured Accounting for the alleged underpayment of royalties, on gas produced from the Underlying Properties due to Federal royalty owners. The MMS order requires WPC (1) to pay additional royalties of $943,964 on production related to the audit period of January 1, 1992 through December 31, 1996; (2) to pay an estimated incremental royalty amount of $991,549 for production covering January 1, 1997 through March 31, 2001; and (3) to perform a restructured accounting and pay an additional royalty for months after March 2001. WPC contested the Audit Issue Letter and the MMS order. Applying the MMS methodology asserted by the State of New Mexico could potentially result in negative adjustments to amounts previously paid to the Trust of approximately $5,400,000, including interest. On November 1, 2004, WPC received notice that its appeal was denied in part by the MMS. On January 14, 2005, WPC filed a Complaint for Review of Agency Action and Declaratory Relief requesting the United States District Court for the District of New Mexico hold unlawful and set aside the Assistant Secretary’s October 2004 decision. If either WPC proceeds with its lawsuit and loses or determines to settle the claims, then this would result in an adjustment to royalty income otherwise payable from WPC to the Trust and a corresponding decrease in distributions to Unitholders, which could eliminate entirely such distributions for one or more future quarterly periods. See “Item 3—Legal Proceedings” for additional information on this royalty dispute.

As more infill wells are drilled, they could cause a reduction in amounts payable to the Trust.

     The Royalty Interests include a 20 percent net profit interest in infill wells. Infill wells may recover a portion of the reserves that would otherwise be produced from wells burdened by the Trust’s net profits interests. Since the Trust is entitled to receive 60 percent of the net proceeds from production burdened by its net profits interests but only 20 percent of the net profits from infill wells the drilling of infill wells may reduce payments to the Trust, and ultimately distributions to Trust Unitholders. See “Item 1—Description of the Trust—Assets of the Trust” and “Item 2—The Royalty Interests—The Infill Wells” for more information.

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Item 1B. Unresolved Staff Comments.

     The Trust has not received any written comments from the Securities and Exchange Commission staff regarding its periodic or current reports under the Act within the 180 days preceding December 31, 2005.

Item 2. Properties.

THE ROYALTY INTERESTS

     The Royalty Interests conveyed to the Trust consist of net profits interests in the Underlying Properties. The Royalty Interests were conveyed to the Trust by means of a single instrument of conveyance. The Conveyance was recorded in the appropriate real property records in each county in New Mexico and Colorado where the Underlying Properties are located so as to give notice of the Royalty Interests to creditors and transferees, who would take an interest in the Underlying Properties subject to the Royalty Interests. The Conveyance was intended to convey the Royalty Interests as real property interests under applicable state law.

     On May 7, 1997, effective as of May 1, 1997, WPC transferred the Underlying Properties to Quatro Finale LLC, a Delaware limited liability company, pursuant to the terms of a Purchase and Sale Agreement dated as of May 1, 1997 (“1997 Transaction”). Prior to the 1997 Transaction, WPC had owned the Underlying Properties, subject to and burdened by the Royalty Interests owned by the Trust, since the inception of the Trust. The sale of the Underlying Properties is expressly permitted under the Trust Agreement. Neither the Trustee nor the Delaware Trustee has any control over or responsibility relating to the operation of the Underlying Properties. Under the terms of the 1997 Transaction, ownership of the Underlying Properties reverted back to WPC effective February 1, 2001. Pursuant to a Purchase and Sale Agreement dated March 14, 2001 (the “2001 Transaction Agreement”) and effective March 1, 2001, WPC transferred the Underlying Properties to Quatro Finale V LLC, a Delaware limited liability company (the “2001 Transaction”). Effective January 1, 2003, ownership of the Underlying Properties once again reverted back to WPC after it exercised its right to repurchase interests in the Underlying Properties from Quatro Finale V LLC pursuant to the 2001 Transaction Agreement. With respect to the ownership of the Underlying Properties for any period from May 1, 1997 through February 28, 2001, and for the period from March 1, 2001 through January 1, 2003, references herein to WPC should be deemed to refer to Quatro Finale.

     Concurrently with the 2001 Transaction, WPC and Quatro Finale entered into a Management Services Agreement dated March 1, 2001 (the “Management Services Agreement”), whereby WPC agreed, among other things, to continue to manage and operate the Underlying Properties and to handle the receipt and payment of funds with respect thereto. Following the 2001 Transaction through January 1, 2003, under the Management Services Agreement, WPC collected all revenues on behalf of Quatro Finale and was obligated to pay to the Trust on behalf of Quatro Finale the amounts payable with respect to the Royalty Interests. Currently, as it did prior to the 2001 Transaction, WPC receives all payments relating to the Underlying Properties and, pursuant to the Conveyance, pays to the Trust the portion thereof attributable to the Royalty Interests.

     Under the Conveyance, the amounts payable with respect to the Royalty Interests are computed with respect to each calendar quarter ending prior to termination of the Trust, and such amounts are to be paid to the Trust not later than the last day of the calendar month next following the end of each calendar quarter. The amount paid to the Trust does not include interest on any amounts payable with respect to the Royalty Interests that are held by WPC prior to payment to the Trust. WPC is entitled to retain any amounts attributable to the Underlying Properties that are not required to be paid to the Trust with respect to the Royalty Interests.

     Concurrently with the 2001 Transaction, WPC, Williams, the Trust and Quatro Finale entered into an Agreement dated March 1, 2001 (the “Performance Acknowledgement Agreement”), pursuant to which (i) the parties acknowledged that, although WPC was selling the Underlying Properties to Quatro Finale, WPC retained all of its duties and obligations under the Trust Agreement, Conveyance and related documents (the “Trust Documents”), subject to the terms and conditions set forth in the 2001 Transaction Agreement and the agreements entered into pursuant to the 2001 Transaction Agreement, (ii) Williams and WPC each confirmed and agreed that, notwithstanding the sale of the Underlying Properties to Quatro Finale, Williams and WPC would continue to perform their respective obligations to the Trust pursuant to the Trust Documents, including without limitation the performance assurances of Williams set forth in the Conveyance, and (iii) Quatro Finale acknowledged and agreed

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that it was purchasing the Underlying Properties burdened by the Royalty Interests owned by the Trust. Accordingly, since the inception of the Trust, WPC and Williams have continuously retained and been subject to all of their duties and obligations under the Trust Documents.

     The following description contains a summary of the material terms of the Conveyance and is subject to and qualified by the more detailed provisions of the Conveyance, a copy of which is filed as an exhibit to this Form 10-K.

The Underlying Properties

     The Royalty Interests were conveyed by WPC to the Trust from its net revenue interest (working interest less lease burdens) in the WI Properties and its net profits interest in the Farmout Properties. Substantially all of the production from the Underlying Properties is from the Fruitland coal formation in the San Juan Basin. The San Juan Basin (the “Basin”), one of the largest gas producing basins in the United States, encompasses approximately 12,000 square miles in northwest New Mexico and southwest Colorado, just east of the common corner of the states of Utah, Arizona, New Mexico and Colorado known as the Four Corners. It covers parts of La Plata and Archuleta counties in Colorado, as well as parts of San Juan, Rio Arriba, McKinley and Sandoval counties in New Mexico. The Basin has been an active area for coal seam gas development within the Fruitland coal formation.

     Williams acquired its interests in the Underlying Properties in 1983 through the acquisition of Northwest Pipeline Corporation (“Northwest”), and such Underlying Properties were transferred to WPC on December 31, 1990. Northwest originally owned working interests that were burdened by overriding royalty interests in the Underlying Properties. The overriding royalty interests resulted in excessive burdens and Northwest negotiated settlements with the owners of the overriding royalty interests. Pursuant to one of these settlements, Northwest and Amoco Production Company (“Amoco”) entered into a joint venture under which Northwest agreed to assign to Amoco certain oil and gas properties in two exploratory areas, one of which (the PLA-9 properties) comprises the Farmout Properties. In consideration for such assignment, Northwest received an overriding royalty interest in the Farmout Properties. Northwest’s rights under the joint venture agreement were subsequently assigned to WPC, which elected, effective as of October 1, 1992, to convert the overriding royalty interest in the Farmout Properties to a 35 percent net profits interest.

     Development of the Fruitland coal formation acreage has resulted in the drilling of 953 gross coal seam gas wells in the Underlying Properties, 22 of which are in the Farmout Properties. WPC owns mineral rights in the Fruitland coal formation under 214 oil and gas leases. Under the terms of these leases, WPC has the right to extract oil and gas from the lease properties. WPC holds either a record title interest, operating right interest or net profits interest in the leases. Record title and operating right interests are commonly referred to as working interests. The Underlying Properties constitute substantially all of WPC’s proved reserves in the Fruitland coal formation. WPC does not operate any of the coal seam gas wells on the Underlying Properties.

     Unitized Areas. Approximately 96 percent of the Fruitland coal formation proved developed coal seam gas wells on the WI Properties are located within the boundaries of New Mexico Federal Units (as defined herein). Pursuant to the Federal Mineral Leasing Act of 1920, as amended, and applicable state regulations, owners of oil and gas leases in New Mexico created large unitized areas consisting of several contiguous sections for the orderly development and conservation of oil and gas reserves. The WI Properties participate in production from the 12 unitized areas in New Mexico referred to in the following table (the “Federal Units”). Operation and development of the Federal Units is governed by unit agreements and unit operating agreements (collectively, the “Unit Agreement”). Under the Unit Agreement and applicable government regulations, the Federal Unit operators request regulatory approval from the New Mexico Commission of Public Lands, the New Mexico Oil Conservation Commission and the Bureau of Land Management to establish or expand participating areas which produce oil and gas in paying quantities from designated formations. The interests of participants in a participating area are based on the surface acreage included in the participating area. Under the terms of the Unit Agreements, the operators, selected by a vote of the respective working interest owners, perform all operating functions.

     In all of the Federal Units, participating areas have been formed for the Fruitland coal formation. After the wells capable of producing gas in paying quantities from the Fruitland coal formation are drilled on the undeveloped drill blocks included within a Federal Unit, such wells are added to the participating area if approved in accordance

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with the appropriate Unit Agreement. A delay of at least 18-36 months is usually incurred after a well is completed and producing before it is added to a participating area. As participating areas are created and expanded, such modification (which will be effective retroactively to the date production commenced from the wells causing such expansion) results in a participant owning undivided interests in all of the producing wells within the participating area. Therefore, WPC’s working interest and net revenue interest in the wells in a Federal Unit or participating area may be modified retroactively, which could affect significantly the amount of NPI Net Proceeds with respect to production since October 1, 1992. If any well(s) that produced or may have produced marketable quantities of coal seam gas prior to 1980 is included in or added to a participating area in which the WI Properties participate, the Conveyance provides that such well(s) will be treated as, and the Trust will own, a separate Net profits interest in such well(s) (the “Pre-80 Production NPI”). The net proceeds for such Pre-80 Production NPI would be calculated in a manner similar to the calculation of Infill Net Proceeds, and the Trust’s share of such net proceeds will be 81 percent, subject to decrease upon the same terms as the NPI.

     The following table reflects certain information from the Reserve Report as of December 31, 2005 prepared by Miller and Lents, Ltd. dated January 12, 2006 (the “December 31, 2005 Reserve Report”) regarding the Federal Units in which the WI Properties participate. At December 31, 2005, the WI Properties covered 894 gross (93.9 net) coal seam gas wells with working interests ranging from .0590 percent to 100 percent, with an average working interest of approximately 10.51 percent. The Royalty Interests participate in each Federal Unit and participating area in which the WI Properties participate based on the acreage containing wells with proved reserves on December 31, 2005.

		Underlying Properties
				Estimated
				Discounted
		Net		Future Net
		Proved		Revenues
		Reserves		(Discounted
Federal Unit	Federal Unit Operator	(Bcf)		at 10%)
				(In Thousands)
San Juan 30-5	Conoco Phillips Petroleum Company		18.4		53,824.8
San Juan 32-7	Conoco Phillips Petroleum Company		14.7		45,050.5
San Juan 32-8	Conoco Phillips Petroleum Company		16.6		52,469.6
San Juan 30-6	Meridian Oil Inc.		9.2		26,171.7
San Juan 31-6	Conoco Phillips Petroleum Company		5.9		15,466.8
San Juan 29-6	Conoco Phillips Petroleum Company		8.5		23,409.4
San Juan 29-7	Meridian Oil Inc.		5.8		14,257.7
San Juan 32-9	Meridian Oil Inc.		2.8		8,625.6
Northeast Blanco	Blackwood & Nichols Co., Ltd.		1.7		5,138.5
Huerfano	Meridian Oil Inc.		2.2		4,988.3
San Juan 29-5	Conoco Phillips Petroleum Company		0.5		1,420.3
San Juan 28-6	Meridian Oil Inc.		0.7		1,283.2
San Juan 28-5	Meridian Oil Inc.		0.1		130.0

     Meridian Oil Inc. is a subsidiary of Burlington Resources Inc. and Blackwood & Nichols Co., Ltd. is a subsidiary of Devon Energy Corporation.

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     Well Count and Acreage Summary. The following table shows as of December 31, 2005, 2004, and 2003, the gross and net wells and acreage by proved producing and nonproducing categories for the WI Properties.

	Number of
	Wells				Acres
	Gross		Net		Gross		Net
December 31,
2005
Producing		953		100.1		150,988		20,681
Nonproducing		0		0		0		0
Total		953		100.1		150,988		20,681
2004
Producing		870		99		150,988		20,681
Nonproducing		0		0		0		0
Total		870		99		150,988		20,681
2003
Producing		680		78		150,988		20,681
Nonproducing		0		0		0		0
Total		680		78		150,988		20,681

     Of the total gross wells described above at December 31, 2005, 894 gross wells are located in unitized areas. In addition to the above, the Farmout Properties have 22 gross wells.

     Properties Outside Unitized Areas. The WI Properties also include interests held by WPC in 38 proved developed Fruitland formation coal seam gas wells held in areas outside of Federal Units that are not reflected in the foregoing table. As of December 31, 2005, WPC’s working interest and net revenue interests in these wells averaged 8.17 percent and 6.67 percent, respectively.

     The Farmout Properties consist of a 35 percent Net profits interest on a property farmed out to Amoco in La Plata County, Colorado. Such properties are not within any Federal Unit boundary. The Farmout Properties are owned, and most of the wells thereon are operated, by Amoco. Neither Williams, WPC, the Delaware Trustee, the Trustee nor the Unitholders are able to influence or control the operation or future development of the Farmout Properties. WPC has advised the Trustee that it believes that a majority of the production from the Farmout Properties is sold by Amoco under short-term marketing arrangements at spot market prices. No assurance can be given, however, that Amoco will not in the future subject production from the Farmout Properties to long-term sales contracts at non-market responsive prices. A portion of the production from the Farmout Properties is gathered by WFS pursuant to a gathering contract at rates and subject to other terms that were negotiated on an arms-length basis. As of December 31, 2005, 22 gross wells had been drilled on the Farmout Properties. For a further description of the Farmout Properties, see “ — The NPI.”

The NPI

     The NPI generally entitles the Trust to receive 60 percent (permanently reduced from 81 percent as described under “—The NPI Percentage Reduction” below) of the NPI Net Proceeds. NPI Net Proceeds consists generally of the aggregate proceeds attributable to (i) WPC’s net revenue interest based on the sale at the Wellhead of gas produced from the WI Properties and (ii) the revenue stream received by WPC from its 35 percent Net profits interest in the Farmout Properties, less (a) WPC’s working interest share of property and production taxes on the WI Properties; (b) WPC’s working interest share of actual operating costs on the WI Properties to the extent in excess of those agreed to be paid by WPC as described herein; (c) WPC’s working interest share of capital costs on the WI Properties to the extent in excess of those agreed to be paid by WPC as described herein; and (d) interest on the unrecovered portion, if any, of the foregoing costs at Citibank’s Base Rate.

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     Most of the wells reflected in the December 31, 2005 Reserve Report were drilled prior to 1994. Significant additional capital expenditures were not incurred during the early years of the production lives of such wells, and it is not anticipated that further significant capital expenditures will be incurred. Consequently, the December 31, 2005 Reserve Report was prepared on the basis that there will be no capital expenditures borne by the Royalty Interests. Nevertheless, the operators and working interest owners of the wells could elect at any time to implement measures to increase the producible reserves. These measures, if implemented, could involve additional compression or enhanced or secondary recovery operations requiring substantial capital expenditures that would be proportionately borne by the Royalty Interests.

     Exhibit B to the Conveyance reflects estimated annual operating expenses for wells on the WI Properties. No operating expenses in respect of the WI Properties will be deducted in calculating NPI Net Proceeds except when the actual cumulative operating expenses attributable to WPC’s working interests in the WI Properties exceed the estimated cumulative operating expenses reflected in Exhibit B to the Conveyance as of the close of a calendar quarter (less the estimated operating costs in such Exhibit that are allocable to two wells that were repurchased effective as of January 1, 1994, by WPC as a purchase price adjustment or to any wells that are reconveyed to WPC as uneconomic). The amount by which such actual cumulative operating expenses exceed estimated cumulative operating expenses reflected in such Exhibit will be deducted in calculating NPI Net Proceeds and, therefore, will reduce the amounts payable to the Trust.

     If, during any period, costs and expenses deductible in calculating the NPI Net Proceeds exceed gross proceeds, neither the Trust nor Unitholders will be liable for such excess, but the Trust will receive no payments for distribution to Unitholders with respect to the NPI until future gross proceeds exceed future costs and expenses plus the cumulative excess of such costs and expenses plus interest thereon at Citibank’s Base Rate. However, if the excess costs are the result of capital costs incurred for enhanced recovery or similar operations on the WI Properties, the Trust will receive no less than 20 percent of the NPI Net Proceeds (calculated before such capital costs are deducted) until such excess costs plus interest thereon at Citibank’s Base Rate are recovered by WPC unless such capital costs are $3,000,000 or more, in which event the Trust will only receive payments equal to the administrative costs of the Trust until such unrecovered costs plus interest thereon at Citibank’s Base Rate are less than $3,000,000.

     The calculation of NPI Net Proceeds includes amounts received by WPC in respect of its 35 percent net profits interest in the Farmout Properties. WPC’s net profits interest in the Farmout Properties is calculated on a total operations basis and is defined as lease revenues less burdens, operating expenses (including overhead as defined in the applicable operating agreement) and all taxes related to the value of reserves, production, property and equipment (e.g., severance and ad valorem taxes).

     WPC has advised the Trustee that the majority of the coal seam gas from the Farmout Properties is sold by Amoco under short-term marketing arrangements at spot market prices and the remainder is marketed by the other operators of the wells in the Farmout Properties. Neither the Gas Purchase Contract nor the Gas Gathering Contract covers the volumes produced from the Farmout Properties.

Reserve Report

     The following table summarizes net proved reserves estimated as of December 31, 2005, and certain related information for the Royalty Interests and Underlying Properties from the December 31, 2005 Reserve Report prepared by Miller and Lents, Ltd., independent petroleum engineers. A summary of the December 31, 2005 Reserve Report is filed as an exhibit to this Form 10-K and incorporated herein by reference. See Note 9 to “Item 8—Financial Statements and Supplementary Data—Notes to Financial Statements” for additional information regarding the net proved reserves of the Trust.

     A Net profits interest does not entitle the Trust to a specific quantity of gas but to a portion of the net proceeds derived therefrom. Ordinarily, and in the case of the Farmout Properties, proved reserves attributable to a Net profits interest are calculated by deducting an amount of gas sufficient, if sold at the prices used in preparing the reserve estimates for such net profits interest, to pay the future estimated costs and expenses deducted in the calculation of the net proceeds of such interest. Because WPC has agreed to pay certain operating and capital costs with respect to the WI Properties, no amount of gas in respect of such costs has been deducted from the amount of reserves attributable to the WI Properties in determining the amount of reserves attributable to the Royalty Interests.

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     Accordingly, the reserves presented for the Royalty Interests reflect quantities of gas that are free of future costs and expenses (other than production, severance and ad valorem taxes in respect of the WI Properties) if the price and cost assumptions set forth in the December 31, 2005 Reserve Report occur. The December 31, 2005 Reserve Report was prepared in accordance with criteria established by the Commission and, accordingly, is based upon a contractual price for gas for December 2005, of $4.78 per MMBtu before transportation charges through 2012. The December 31, 2005 Reserve Report is also based on the percentage share of NPI Net Proceeds payable to the Trust continuing at 60 percent for the remaining life of the reserves. Beginning in year 2013, after which the contract will no longer be in effect, the gas price is $7.56 per MMBtu, based on December 31, 2005 Blanco Hub Index Price. Gathering and transportation charges, taxes, treating, and other costs payable prior to the delivery points were deducted from the index price in order to determine the wellhead price used in this evaluation. These prices and deductions were held constant.

	Royalty		Underlying
	Interests		Properties
Net Proved Gas Reserves (Bcf)(a)(b)		28,606		97,748
Estimated Future Net Revenues (in millions)(c)		93,913		408,330
Discounted Estimated Future Net Revenues (in millions)(c)		54,697		282,646

(a) Although the prices utilized in preparing the estimates in this table are in accordance with criteria established by the Commission, such prices were influenced by seasonal demand for natural gas and other factors and may not be the most representative prices for estimating future net revenues or related reserve data.

(b) The gas reserves were estimated by Miller and Lents, Ltd. by applying decline curve analyses utilizing type curves for the various areas in the Basin. The bases for the consideration of type curves are the production histories, the water and gas production rates and the initial reservoir pressures of the wells in the separate areas.

(c) Estimated future net revenues are defined as the total revenues attributable to the Underlying Properties and Royalty Interests less royalties, severance and ad valorem taxes, operating costs and future capital expenditures in excess of estimated amounts to be paid by WPC. Overhead costs (beyond the standard overhead charges for the nonoperated properties) have not been included, nor have the effects of depreciation, depletion and Federal income tax. Estimated future net revenues and discounted estimated future net revenues are not intended and should not be interpreted as representing the fair market value for the estimated reserves.

     There are many uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the timing of development expenditures. The reserve data set forth herein, although prepared by independent petroleum engineers in a manner customary in the industry, are estimates only, and actual quantities and values of natural gas are likely to differ from the estimated amounts set forth herein. In addition, the reserve estimates for the Royalty Interests will be affected by future changes in sales prices for natural gas produced and costs that are deducted in calculating NPI Net Proceeds and Infill Net Proceeds. Further, the discounted present values shown herein were prepared using guidelines established by the Commission for disclosure of reserves and should not be considered representative of the market value of such reserves or the Units. A market value determination would include many additional factors.

     Information concerning historical changes in net proved reserves attributable to the Underlying Properties, and the calculation of the standardized measure of discounted future net revenues related thereto, are contained in Note 9 to “Item 8—Financial Statements and Supplementary Data—Notes to Financial Statements.” Williams has not filed reserve estimates covering the Underlying Properties with any Federal authority or agency other than the Commission.

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Historical Gas Sales Prices and Production

     The following table sets forth the actual net production volumes from the WI Properties, weighted average lifting costs and information regarding historical gas sales prices for each of the years ended December 31, 2005, 2004 and 2003:

	Year Ended December 31,
	2005		2004		2003
Production from the WI Properties (MMcf)		8,110		10,101		10,943
Weighted average lifting costs (dollars per Mcf)	$	0.60	$	0.37	$	0.32
Weighted average sales price of gas produced from the WI Properties (dollars per Mcf)	$	3.62	$	2.66	$	2.64
Average Blanco Hub Spot Price (dollars per MMBtu)	$	6.92	$	5.21	$	4.42

     The published Blanco Hub Spot Price for December 2005 was $7.56 per MMBtu. Information regarding average wellhead sales prices for production from the Farmout Properties is not available to WPC, although WPC has advised the Trustee that it believes production from such properties is currently sold by Amoco under short-term marketing arrangements at spot market prices. While Williams may, from time to time, enter into hedge instruments to manage their price risk associated with natural gas production from the Underlying Properties, the effects of any such hedge instruments are not used in the determination of the Trust’s royalty income attributable from the Net profits interest in the Underlying Properties. The Trust does not engage in any hedging activities to manage its price risk associated with natural gas production from the Underlying Properties. Production from Farmout Properties (in MMcf) was 1,849, 2,227, and 2,352 in 2005, 2004, and 2003, respectively.

NPI Percentage Reduction

     Prior to 2001, the NPI generally entitled the Trust to receive 81 percent of the NPI Net Proceeds. However, under the terms of the Conveyance, at the point that (i) cumulative gas production since October 1, 1992, from the Underlying Properties has exceeded 178.5 Bcf and (ii) the internal rate of return of the “Aftertax Cash flow per Unit” (as defined below) has equaled or exceeded 12 percent, the percentage of NPI Net Proceeds payable to the Trust in respect of the NPI is automatically and permanently reduced to 60 percent. In such event, WPC’s retained percentage of NPI Net Proceeds is correspondingly increased from 19 percent to 40 percent. For purposes hereof, “Aftertax Cash Flow per Unit” is equal to the sum of the following amounts that a hypothetical purchaser of a Unit in the Public Offering would have received or been allocated if such Unit were held through the date of such determination: (a) total cash distributions per Unit plus (b) total tax credits available per Unit under Section 29 of the IRC less (c) the net taxes payable per Unit (assuming a Federal income tax rate of 31 percent, which at the time of the formation of the Trust was the highest Federal income tax rate applicable to individuals). IRR is the annual discount rate (compounded quarterly) that equates the present value of the Aftertax Cash Flow per Unit to the initial price to the public of the Units in the Public Offering (which was $20.00 per Unit).

     Cumulative production since October 1, 1992, from the Underlying Properties has been in excess of 178.5 Bcf since 1999. The 12 percent internal rate of return of Aftertax Cash Flow per Unit was reached in the fourth quarter of 2000. Consequently, beginning in the fourth quarter of 2000, the percentage of NPI Net Proceeds the Trust is entitled to receive under the NPI was permanently reduced from 81 percent to 60 percent. WPC’s retained percentage of NPI Net proceeds was correspondingly increased from 19 percent to 40 percent.

Gas Purchase Contract

     Under the terms of the Gas Purchase Contract, WPX Gas Resources (as successor in interest to WGM) purchased the natural gas produced from the WI Properties (except for certain small volumes) at the Wellhead. The Gas Purchase Contract commenced October 1, 1992, and expires on the termination of the Trust. The Gas Purchase Contract provides for a pricing mechanism during an initial 5-year period (“Primary Term”), which expired on December 31, 1997. Following the expiration of the Primary Term, the pricing mechanism continues for one or more consecutive additional one-year terms (each such term a “Contract Year”) unless and until WPX Gas Resources exercises its annual option, exercisable 15 days prior to the end of each Contract Year, to discontinue purchasing gas from WPC under the pricing provision of the Gas Purchase Contract and instead purchase gas at a

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monthly price equal to the “Index Price” as described hereafter. For each of the Contract Years 2003, 2004 and 2005, WPX Gas Resources did not exercise this option and therefore the pricing mechanism of the Primary Term remained in effect for each of those past years and will continue to remain in effect through at least December 31, 2006. Under this mechanism, the monthly price to be paid by WPX Gas Resources for natural gas purchased pursuant to the Gas Purchase Contract shall be (a) the $1.70 Minimum Purchase Price, less (b) any costs paid by WPX Gas Resources to gather, treat and process the gas and deliver it to specified delivery points and plus (c) under certain circumstances, additional amounts determined as described below:

(i) If the Index Price (as defined below) in any month during any Contract Year, including 2006, is greater than $1.94 per MMBtu, then WPX Gas Resources will pay WPC an amount for gas purchased equal to $1.94 per MMBtu, less the costs paid by WPX Gas Resources to gather and process such gas and deliver it to specified delivery points, plus 50 percent of the excess of the Index Price over $1.94 per MMBtu (the “Price Differential”), provided WPX Gas Resources has no accrued Price Credits (as defined below) in the Price Credit Account (as defined below). If WPX Gas Resources has accrued Price Credits in the Price Credit Account, then WPX Gas Resources will be entitled to reduce the amount in excess of the Minimum Purchase Price (before deducting gathering and processing costs and costs to deliver the gas to specified delivery points) that otherwise would be payable by any accrued and unrecouped Price Credits in the Price Credit Account, and WPX Gas Resources will not be obligated to pay WPC any amounts in excess of the Minimum Purchase Price until such time as all accrued Price Credits have been recouped and a zero balance exists in the Price Credit Account.

(ii) If the Index Price in any month during any Contract Year, including 2006, is greater than the Minimum Purchase Price but less than or equal to $1.94 per MMBtu, then WPX Gas Resources will pay WPC an amount for each MMBtu purchased equal to the Index Price less the costs paid by WPX Gas Resources to gather and process such gas and deliver it to specified delivery points, provided WPX Gas Resources has no accrued Price Credits in the Price Credit Account. If WPX Gas Resources has accrued Price Credits in the Price Credit Account, then WPX Gas Resources will be entitled to reduce the amount in excess of the Minimum Purchase Price (before deducting, gathering and processing costs and costs to deliver to specified delivery points) that otherwise would be payable by any accrued and unrecouped Price Credits in the Price Credit Account, and WPX Gas Resources will not be obligated to pay WPC any amounts in excess of the Minimum Purchase Price until such time as all accrued Price Credits have been recouped and a zero balance exists in the Price Credit Account.

(iii) If the Index Price in any month during any Contract Year, including 2006, is less than the Minimum Purchase Price, then WPX Gas Resources will pay for each MMBtu of gas purchased the Minimum Purchase Price less the costs paid by WPX Gas Resources to gather and process such gas and deliver it at specified delivery points, and WPX Gas Resources will receive a credit (the “Price Credit”) from WPC for each MMBtu of gas purchased by WPX Gas Resources equal to the difference between the Minimum Purchase Price and the Index Price. WPC is required to establish and maintain the Price Credit Account containing the accrued and unrecouped amount of such Price Credits. No Price Credits were accrued in respect of production purchased by WPX Gas Resources prior to January 1, 1994.

     For the year ended December 31, 2005, which is based on production volumes and natural gas prices for the twelve months ended September 30, 2005, the Index Price exceeded the Minimum Purchase Price for each month during the year. As of December 31, 2005 and 2004, there were no remaining unrecouped Price Credits in the Price Credit Account.

     To the extent there may in the future be a balance in the Price Credit Account, the entitlement to recoup Price Credits means that if and when the Index Price is above the Minimum Purchase Price, future royalty income paid to the Trust would be reduced until such time as such Price Credits have been fully recouped. Corresponding cash distributions to Unitholders would also be reduced.

     Subsequent to the expiration of the Primary Term of the pricing provision of the Gas Purchase Contract, which occurred on December 31, 1997, WPX Gas Resources has an annual option (which can be exercised only once during the term of the Gas Purchase Contract) to discontinue purchasing gas under the pricing provision of the Gas Purchase Contract by giving written notice of its election to pay solely the Index Price (less the costs paid by

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WPX Gas Resources to gather, treat and process such gas and deliver it to specified points). If WPX Gas Resources so elects to discontinue paying under the pricing provision, WPX Gas Resources will no longer be entitled to retain the Price Differential when the Index Price exceeds $1.94 per MMBtu and any accrued and unrecouped Price Credits will be extinguished. Since there is no published price in the San Juan Basin for wellhead deliveries, the wellhead price in the Gas Purchase Contract is determined by utilizing a published price that is inclusive of gathering, treating and processing costs. As used in this “Item 2. Properties — Reserve Report,” “Index Price” means 97 percent of the first of month El Paso Natural Gas Co. — San Juan Spot Price. The El Paso Natural Gas Co. — San Juan Spot Price is a posted index price per MMBtu (dry basis) published in Inside F.E.R.C.’s Gas Market Report, which is a bi-monthly publication by The McGraw-Hill Companies, Inc. The Gas Purchase Contract provides WPX Gas Resources a one-time option to convert the Index Price from the first of month posting of El Paso Natural Gas Co. — San Juan Spot Price to the average of the bi-monthly postings for that same index. The Gas Purchase Contract further provides for an alternative indexing mechanism in the event the Inside F.E.R.C.’s Gas Market Report indices are modified or discontinued. All prices used as index prices are delivered prices at the specified point of delivery and are, therefore, before deducting gathering and/or transportation charges, taxes, treating costs or other costs payable prior to the delivery points. During periods when there is a Price Differential, WPX Gas Resources will absorb a portion of the gathering charges based on a formula specified within the Gas Purchase Contract.

     A small volume of gas produced from the WI Properties (less than 5 percent) is sold by the operators of certain wells under gas purchase contracts with other buyers.

     The prices paid to WPC pursuant to the Gas Purchase Contract are prices payable for the value of gas purchased for production at the Wellhead. Title to the gas purchased pursuant to the Gas Purchase Contract passes to WPX Gas Resources at the Wellhead. WPX Gas Resources is responsible for gathering, treating, processing and marketing all gas purchased pursuant to the Gas Purchase Contract. Approximately 90 percent of the production from the WI Properties is gathered by WPX on behalf of WPX Gas Resources. The balance of the production is gathered on behalf of WPX Gas Resources by third parties. See “—Gas Gathering Contract.” The price paid to WPC pursuant to the Gas Purchase Contract is after deducting the costs incurred by WPX Gas Resources to gather, treat and process such gas (including costs incurred by WPX Gas Resources under the Gas Gathering Contract). Payments to WPC for gas purchased pursuant to the Gas Purchase Contract are made by WPX Gas Resources on or before the last day of the first calendar month next following the end of each calendar quarter.

     NPI Net Proceeds and Infill Net Proceeds are calculated on an entitlements or entitled volume basis, whereby the aggregate proceeds from the sale of gas under applicable gas sales contracts (excluding production from the Farmout Properties) are determined by WPC as if WPC had produced and sold its working interest share of production from the WI Properties, even if the actual volumes delivered to and sold by WPC are different than the entitlement volumes. The effect of such an “entitlements basis” calculation is that NPI Net Proceeds or Infill Net Proceeds and, therefore, the amount thereof paid to the Trust, may include amounts in respect of production not taken by WPC because of a so-called imbalance (that is, where a working interest owner is delivered more or less than the actual share of production to which it is entitled).

     The Gas Purchase Contract may not be amended in a manner that would materially adversely affect the revenues to the Trust without the approval of the holders of a majority of the Units present or represented at a meeting of Unitholders at which a quorum (consisting of a majority of the outstanding Units) is present or represented. As noted elsewhere herein, the Units held by Williams (or an affiliate) immediately after the Public Offering may not be voted on any such amendment nor will such Units be counted for quorum purposes so long as such Units are held by Williams (or an affiliate). A copy of the Gas Purchase Contract is filed as an exhibit to this Form 10-K. The foregoing summary of the material provisions of the Gas Purchase Contract is qualified in its entirety by reference to the terms of such agreement as set forth in such exhibit.

Gas Gathering Contract

     In accordance with the Confirmation Agreement, effective May 1, 1995, WGM assigned to WPX Gas Resources all of its right, title, interest, duties and obligations under the Gas Gathering Contract, and WPX Gas Resources assumed all of WGM’s right, title, interest, duties and obligations thereunder.

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     The Gas Gathering Contract, which will be in effect until December 31, 2022, subject to annual extensions thereafter, covers approximately 90 percent of the production from the WI Properties and commits WFS on behalf of WPX Gas Resources to gather such production (except production from 19 wells in the San Juan 29-7 unit as described below), at rates starting at $.35 per Mcf (plus a fuel reimbursement estimated to be 6.2 percent to 7.3 percent of gathered volumes on a Btu equivalent basis, and subject to increase if the CO₂ content of the gas exceeds 10 percent) and adjusted annually based on average annual price comparisons determined on the basis of the Blanco Hub Spot Price, provided that the gathering rate will be no less than $.35 per Mcf (currently 1.046/Mcf) increased or decreased on the basis of an increase or decrease in a published index measuring the gross domestic product. A significant portion of the gas to be gathered pursuant to the Gas Gathering Contract must first be gathered from the Wellhead to a Federal Unit central delivery point by TEPPCO Partners. L.P. (“TEPPCO”). WPX Gas Resources has been assigned a one-year gathering contract (with a monthly evergreen provision) whereby TEPPCO provides interruptible gathering service at the price of $.44 per Mcf, which escalates annually at $0.015 per year, plus actual fuel used (historically averaging approximately 7 percent). It is anticipated that WPX Gas Resources will be able to extend the term of this agreement.

     The remainder of the production on the WI Properties is not physically connected to the WFS system and is not covered by the Gas Gathering Contract. This gas is gathered either by Burlington Resources Gathering Inc. (“Burlington”) or El Paso Field Services (“EFS”) for delivery at the Blanco Hub or by WFS for delivery at the outlet of the Ignacio Plant in La Plata County, Colorado. WPC has existing long-term gathering agreements with EFS and short-term gathering agreements with Burlington with rates and terms generally comparable to the Gas Gathering Contract.

     The Gas Gathering Contract may not be amended in a manner that would materially adversely affect the revenues to the Trust without the approval of the holders of a majority of the Units present or represented at a meeting of Unitholders at which a quorum (consisting of a majority of the outstanding Units) is present or represented. As noted elsewhere herein, the Units held by Williams (or an affiliate) immediately after the Public Offering may not be voted on any such amendment nor will such Units be counted for quorum purposes so long as such Units are held by Williams (or an affiliate).

     The Gas Gathering Contract was twice amended, each effective as of October 1, 1993, with respect to 19 wells located in the San Juan 29-7 unit. WFS is obligated to gather production from such wells at a rate of $.36 per Mcf (plus a fuel reimbursement of 5.5 percent of the gas received at the Wellhead Receipt Points (as defined)), fixed for a 10-year term. In connection with these amendments to the Gas Gathering Contract, the Trustee received an opinion of counsel to Williams that such amendments need not be submitted for approval by vote of the Unitholders.

     The Gas Gathering Contract was further amended effective as of April 1, 1997, for the purpose of increasing the field rights held by the Trust on the Manzanares gathering system. The increase accommodates incremental gas flow that will occur due to WFS’s expansion and enhancement of gathering facilities.

     A copy of the Gas Gathering Contract and each amendment thereto are filed as exhibits to this Form 10-K. The foregoing summary of the material provisions of the Gas Gathering Contract is qualified in its entirety by reference to the terms of such agreement as set forth in such exhibit.

Federal and Indian Lands

     Approximately 80 percent of the Underlying Properties are burdened by Royalty Interests held by the Federal government or the Southern Ute Indian Tribe. Royalty payments due to the U.S. Government for gas produced from Federal and Indian lands included in the Underlying Properties must be calculated in conformance with its interpretation of regulations issued by the Minerals Management Service (“MMS”), a subagency of the U.S. Department of the Interior that administers and receives revenues from Federal and Indian royalties on behalf of the U.S. Government and as agent for the Indian tribes. The MMS regulations cover both valuation standards, which establish the basis for placing a value on production, and cost allowances, which define those post-production costs that are deductible by the lessee.

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     Where gas is sold by a lessee to a marketing affiliate, such as WPX Gas Resources, the MMS regulations essentially ignore the lessee-affiliate transaction and consider the arm’s-length sale by the affiliate as the point of valuation for royalty purposes. Accordingly, WPC is required to calculate royalty payments based on the price WPX Gas Resources receives when it markets the gas production (“Resale Price”), notwithstanding the price payable by WPX Gas Resources to WPC pursuant to the Gas Purchase Contract. With respect to the Farmout Properties, Amoco pays royalties based on the price it receives for production from such properties as long as the gas is purchased by nonaffiliates. The NPI Net Proceeds, a portion of which is payable to the Trust, reflects the deduction of all royalty and overriding royalty burdens. The ratio of royalties paid on Federal and Indian lands to the NPI Net Proceeds increases as the Resale Price exceeds the price under the Gas Purchase Contract.

     The MMS regulations permit a lessee to deduct from its gross proceeds its reasonable actual costs of transportation and processing to transport the gas from the lease to the point of sale in calculating the market value of its production. Although WPX Gas Resources deducts the gathering charges paid by it to WFS, Burlington, EFS and Northwest in calculating the wellhead price it pays to WPC, the MMS could disallow the deduction of some portion of the gathering charges after review of such charges on audit of WPC’s royalty as discussed below. If some portion of the gathering charges is disallowed, the MMS will likely demand additional royalties plus interest on the amount of the underpayment.

     The MMS generally audits royalty payments within a 6-year period. Although WPC calculates royalty payments in accordance with its interpretation of the then applicable MMS regulations, WPC does not know whether the royalty payments made to the U.S. Government are totally in conformity with MMS standards until the payments are audited. If an MMS audit, or any other audit by a Federal or state agency, results in additional royalty charges, together with interest, relating to production since October 1, 1992, in respect of the Underlying Properties, such charges and interest will be deducted in calculating NPI Net Proceeds for the quarter in which the charges are billed and in each quarter thereafter until the full amount of the additional royalty charges and interest have been recovered.

     As described in “Item 3—Legal Proceedings,” in 2001 WPC received an Audit Issue Letter from the State of New Mexico, acting under authority of MMS, followed by an MMS Order to Report and Pay Additional Royalties and Perform Restructured Accounting for the alleged underpayment of royalties, on gas produced from the Underlying Properties due to Federal royalty owners. The MMS order requires WPC (1) to pay additional royalties of $943,964 on production related to the audit period of January 1, 1992 through December 31, 1996; (2) to pay an estimated incremental royalty amount of $991,549 for production covering January 1, 1997 through March 31, 2001; and (3) to perform a restructured accounting and pay an additional royalty for months after March 2001. WPC contested the Audit Issue Letter and the MMS order. Applying the MMS methodology asserted by the State of New Mexico could potentially result in negative adjustments to amounts previously paid to the Trust of approximately $5,400,000, including interest. On November 1, 2004, WPC received notice that its appeal was denied in part by the MMS. On January 14, 2005, WPC filed a Complaint for Review of Agency Action and Declaratory Relief requesting the United States District Court for the District of New Mexico hold unlawful and set aside the Assistant Secretary’s October 2004 decision. If either WPC proceeds with its lawsuit and loses or determines to settle the claims, then this would result in an adjustment to royalty income otherwise payable from WPC to the Trust and a corresponding decrease in distributions to Unitholders, which could eliminate entirely such distributions for one or more future quarterly periods. See “Item 3—Legal Proceedings” for additional information on this royalty dispute.

Sale and Abandonment of Underlying Properties

     WPC (and any transferees) has the right to abandon any well or working interest included in the Underlying Properties if, in its opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities. Since WPC does not operate any of the wells on the Underlying Properties, WPC does not normally control the timing of plugging and abandoning wells. The Conveyance provides that WPC’s working interest share of the costs of plugging and abandoning uneconomic wells will be deducted in calculating NPI Net Proceeds.

     WPC may sell the Underlying Properties, subject to and burdened by the Royalty Interests, without the consent of Unitholders. Under the Trust Agreement, WPC has certain rights (but not obligations) to purchase the

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Royalty Interests upon termination of the Trust. See “Item 1—Description of the Trust—Termination and Liquidation of the Trust.”

     WPC has retained the right to repurchase from the Trust, commencing January 1, 2003, any portion of the NPI conveyed to the Trust if WPC’s interest in the Underlying Properties burdened by such portion of the NPI ceases to produce or is not capable of producing in commercially paying quantities (ignoring for purposes of such determination the NPI and Infill NPI). The purchase price payable by WPC will be the fair market value at the date of repurchase of the portion of the NPI or Infill NPI so purchased, as established on the basis of an appraisal provided by an independent expert.

The Infill Wells

     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 consist primarily of a net profits interest (the “NPI”) in the Underlying Properties. The NPI generally entitles the Trust to receive 60 percent of the NPI Net Proceeds attributable to (i) gas produced and sold from WPC’s net revenue interests (working interests less lease burdens) in the properties in which WPC has a working interest (the “WI Properties”) and (ii) the revenue stream received by WPC attributable to its 35 percent net profits interest in 5,348 gross acres in La Plata County, Colorado (the “Farmout Properties”).

     The Royalty Interests also include a 20 percent interest in WPC’s Infill Net Proceeds from the sale of production if well spacing rules are effectively modified and additional wells are drilled on producing drilling blocks on the WI Properties (the “Infill Wells”) during the term of the Trust. “Infill Net Proceeds” consists generally of the aggregate proceeds, based on the price at the wellhead, of gas produced from WPC’s net revenue interest in any Infill Wells less certain taxes and costs.

     On October 15, 2002 the New Mexico Oil and Gas Commission (NMOCD) revised the field rules for the Basin Fruitland Coal (Gas) Pool to allow an optional second (infill) well on the standard 320-acre spacing unit in certain designated areas of the pool (the non-fairway wells). On July 17, 2003 the NMOCD further modified the field rules for the Basin Fruitland Coal (Gas) Pool to allow these infill wells on the standard 320-acre spacing unit in all areas of the pool. The WI Properties contain 530 infill locations designated as proved locations according to SEC guidelines. As of December 31, 2005, 316 infill locations are proved developed producing and 214 locations are proved undeveloped. Infill drilling is expected to be substantially completed by the end of 2006.

     As of December 31, 2005, the Infill Net Profit Costs exceed the Infill Net Profit Gross Proceeds by $3,164,100. The Trust will not be liable for such excess costs, and such excess costs will hereafter constitute Excess Infill Net Profit Costs until recovered by WPC. The Trust will not receive its 20 percent interest in WPC’s Infill Net Proceeds until such time as the Infill Net Profits Gross Proceeds exceeds the Infill Net Profit Costs on an aggregate basis.

     The complete definitions of Infill Net Profit Costs, Infill Net Profit Gross Proceeds, Excess Infill Net Profit Costs, NPI Net Proceeds and Infill Net Proceeds are set forth in the Conveyance.

Royalty Trust Reserves

     The reserves for the Royalty Trust were determined by Miller and Lents, Ltd in accordance to SEC guidelines. As of December 31, 2005, total proved reserves were 28,606 MMcf, consisting of 27,710 MMcf proved developed producing and 897 MMcf proved undeveloped.

     As of December 31, 2005 total proved reserves for the 320-acre spaced wells in the Working Interest Properties were 21,565 MMcf, consisting of 21,504 MMcf proved developed producing and 61 MMcf proved undeveloped.

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     As of December 31, 2005 total proved reserves for the infill wells in the Working Interest Properties were 2,822 MMcf, consisting of reserves of 1,986 MMcf proved developed producing and 836 MMcf proved undeveloped.

     As of December 31, 2005, total proved reserves for the Farmout Properties were 4,220 MMcf, all of these reserves are proved developed producing.

Williams’ Performance Assurances

     Pursuant to the Conveyance and the Performance Acknowledgement Agreement, Williams has agreed to pay each of the following when due and payable: (i) all liabilities and operating and capital expenses that WPC is required under the Conveyance to pay as owner of the Underlying Properties, including without limitation WPC’s obligation to pay operating expenses in respect of the WI Properties up to the cumulative amounts specified in Exhibit B to the Conveyance and the capital costs incurred in respect of the WI Properties to the extent specified in the Conveyance, including amounts that WPC is obligated to pay with respect to environmental liabilities; (ii) all NPI Net Proceeds, Infill Net Proceeds and other amounts that WPC is obligated to pay to the Trust under the Conveyance, including amounts that WPC is obligated to pay with respect to environmental liability; and (iii) any proceeds from a sale of any remaining Royalty Interests that WPC may elect to purchase upon termination of the Trust ((i) through (iii) collectively, the “WPC Payment Obligations”). Williams has also agreed, to the extent not paid by WPX Gas Resources when due and payable, to pay all amounts that WPX Gas Resources is required to pay to WPC in respect of production attributable to the Royalty Interests pursuant to the terms of the Gas Purchase Contract between WPC and WPX Gas Resources (the “WPX Gas Resources Payment Obligations”). In the Confirmation Agreement, Williams expressly confirmed that its agreement to cause the WPX Gas Resources Payment Obligations to be paid in full when due shall continue in full force and effect notwithstanding the assignments by WGM of the Gas Purchase Contract and the Gas Gathering Contract.

     In the event and to the extent that WPC does not pay any of the WPC Payment Obligations in full when due and, in the event and to the extent that WPX Gas Resources does not pay any of the WFS Gas Resources Payment Obligations in full when due, the Trustee (but not Unitholders) is entitled, following notice to Williams and demand for payment by the Trustee and after a 10-day cure period, to enforce payment by Williams. Williams’ assurance obligations terminate upon the earlier of (i) dissolution of the Trust; (ii) with respect to the WPC Payment Obligations, upon sale or other transfer by WPC of all or substantially all of the Underlying Properties; (iii) with respect to the WPC Payment Obligations, upon one or more sales or other transfers of a majority or more of Williams’ ownership interests in WPC; and (iv) with respect to the WPX Gas Resources Payment Obligations, upon one or more sales or other transfers of a majority or more of Williams’ ownership interests in WPX Gas Resources; provided that, with respect to (ii), (iii) and (iv) above, only if the transferee has, at the time of transfer, a rating assigned to outstanding unsecured long-term debt from Moody’s Investor Services of at least Baa3 or from Standard & Poor’s Corporation of at least BBB (or an equivalent rating from at least one nationally-recognized statistical rating organization), or such transferee is approved by holders of a majority of outstanding Units, and in any case, the transferee unconditionally agrees in writing, to assume and be bound by Williams’ remaining assurance obligations.

Title to Properties

     Williams has advised the Trustee that it believes that WPC’s title to the Underlying Properties, and the Trust’s title to the Royalty Interests, are good and defensible in accordance with standards generally accepted in the gas industry, subject to exceptions that, in the opinion of Williams, are not so material as to detract substantially from the use or value of such Underlying Properties or Royalty Interests. As is customary in the gas industry, only a perfunctory title examination is performed as a lease is acquired, except leases covering proved reserves. Generally, prior to drilling a well, a more thorough title examination of the drill site tract is conducted and curative work is performed with respect to significant title defects, if any, before proceeding with operations. However, except for the sale and repurchase of the Underlying Properties from Quatro Finale, WPC (or its predecessor) has owned the leases covering the Underlying Properties since 1974, and conventional gas has been produced from formations other than the Fruitland formation covered by all of the leases since the 1950s. Under these circumstances, WPC conducted an internal review of its title records prior to the drilling of the coal seam gas wells within the 12 Federal Units but did not conduct title examinations. In addition to its internal review, WPC, when requested by the

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operator, participated in title examinations prior to the drilling of a few coal seam gas wells located outside the Federal Units.

     The Underlying Properties are typically subject, in one degree or another, to one or more of the following: (i) royalties and other burdens and obligations, expressed and implied, under gas leases; (ii) overriding royalties and other burdens created by WPC or its predecessors in title; (iii) a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles; (iv) liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements; (v) pooling, unitization and communitization agreements, declarations and orders; and (vi) easements, restrictions, rights-of-way and other matters that commonly affect property. To the extent that such burdens and obligations affect WPC’s rights to production and the value of production from the Underlying Properties, they have been taken into account in calculating the Trust’s interests and in estimating the size and value of the reserves attributable to the Royalty Interests. Except as noted below, Williams believes that the burdens and obligations affecting the Underlying Properties and Royalty Interests are conventional in the industry for similar properties, do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially and adversely affect the value of the Royalty Interests.

     Although the matter is not entirely free from doubt, Williams has advised the Trustee that it believes (based upon the opinions of local counsel to WPC with respect to matters of Colorado law and New Mexico law) that the Royalty Interests should constitute real property interests under applicable state law. Consistent therewith, the Conveyance states that the Royalty Interests constitute real property interests and it was recorded in the appropriate real property records of Colorado and New Mexico, the states in which the Underlying Properties are located, in accordance with local recordation provisions. If, during the term of the Trust, WPC becomes involved as a debtor in bankruptcy proceedings, it is not entirely clear that all of the Royalty Interests would be treated as real property interests under the laws of Colorado and New Mexico. If in such a proceeding a determination were made that the Royalty Interests constitute real property interests, the Royalty Interests should be unaffected in any material respect by such bankruptcy proceeding. If in such a proceeding a determination were made that a Royalty Interest constitutes an executory contract (a term used, but not defined, in the United States Bankruptcy Code to refer to a contract under which the obligations of both the debtor and the other party to such contract are so unsatisfied that the failure of either to complete performance would constitute a material breach excusing performance by the other) and not a real property interest under applicable state law, and if such contract were not to be assumed in a bankruptcy proceeding involving WPC, the Trust would be treated as an unsecured creditor of WPC with respect to such Royalty Interest in the pending bankruptcy. Although no assurance is given, Williams has advised the Trustee that it does not believe that the Royalty Interests should be subject to rejection in a bankruptcy proceeding as executory contracts.

Item 3. Legal Proceedings.

     On January 5, 2001, the State of New Mexico, acting under authority of the Minerals Management Service (“MMS”), a subagency of the United States Department of the Interior, presented WPC with an Audit Issue Letter for the alleged underpayment of royalties in the amount of $948,501, on gas produced from the Underlying Properties due to Federal royalty owners during the time period from January 1992 through December 1996. MMS regulations permit a lessee to deduct from its gross proceeds its reasonable actual costs of transportation and processing to transport the gas from the lease to the point of sale in calculating the market value of its production. The State of New Mexico claims that certain costs of removing and transporting carbon dioxide gas are not deductible. On March 22, 2001, WPC responded to the Audit Issue Letter and contested the State of New Mexico’s claim for additional royalties as being contrary to law. In early November 2001, WPC received from the MMS an Order to Report and Pay Additional Royalties and Perform Restructured Accounting on subsequent periods. The order was dated October 30, 2001. The order requires WPC (1) to pay additional royalties of $943,964 on production related to the audit period of January 1, 1992 through December 31, 1996; (2) to pay an estimated incremental royalty amount of $991,549 for production covering January 1, 1997 through March 31, 2001; and (3) to perform a restructured accounting and pay an additional royalty for months after March 2001. On January 30, 2002, WPC filed its Statement of Reasons in support of its earlier appeal of the Audit Issue Letter. Applying the MMS methodology asserted by the State of New Mexico could potentially result in negative adjustments to amounts previously paid to the Trust of approximately $5,400,000, including interest. On November 1, 2004, WPC received

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notice that its appeal was denied in part by the MMS. On January 14, 2005, WPC filed a Complaint for Review of Agency Action and Declaratory Relief requesting the United States District Court for the District of New Mexico hold unlawful and set aside the Assistant Secretary’s October 2004 decision. A separate but similar matter has been determined unfavorably against another major oil and gas producer in the D.C. circuit court. If either WPC proceeds with its lawsuit and loses or determines to settle the claims, then this would result in an adjustment to royalty income otherwise payable from WPC to the Trust and a corresponding decrease in distributions to Unitholders, which could eliminate entirely such distributions for one or more future quarterly periods.

     There are no other material pending proceedings to which the Trust is a party or to which any of its properties is the subject.

Item 4. Submission of Matters to a Vote of Security Holders.

     Not applicable.

PART II

     Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

     The Units are listed and traded on the New York Stock Exchange under the symbol “WTU.” The following table sets forth, for the periods indicated, the high and low sales prices per Unit and the amount of quarterly cash distributions per Unit paid by the Trust.

	Sales Price				Distributions
	High		Low		per Unit
2005
First Quarter	$	18.00	$	15.50	$	.346311
Second Quarter	$	17.20	$	14.00	$	.321706
Third Quarter	$	21.43	$	16.10	$	.357841
Fourth Quarter	$	21.95	$	16.58	$	.379323
2004
First Quarter	$	14.57	$	12.91	$	.329589
Second Quarter	$	16.00	$	12.65	$	.396403
Third Quarter	$	18.95	$	14.51	$	.405316
Fourth Quarter	$	18.10	$	14.50	$	.372400

     At March 1, 2006, there were 9,700,000 Units outstanding and approximately 346 Unitholders of record. The Trust does not maintain any equity compensation plans. The Trust did not sell nor did it repurchase any Units during the period covered by this report.

Item 6. Selected Financial Data.

			Year Ended December 31,
	2005		2004		2003		2002		2001
Royalty Income	$	14,497,187	$	15,375,469	$	14,754,582	$	9,296,774	$	24,864,317
Distributable Income	$	13,565,620	$	14,640,743	$	14,012,292	$	8,634,497	$	24,293,901
Distributable Income per Unit	$	1.40	$	1.51	$	1.44	$	.89	$	2.50
Distributions per Unit	$	1.41	$	1.50	$	1.45	$	.89	$	2.50
Total Assets at Year End	$	10,138,644	$	12,317,821	$	14,731,450	$	18,240,451	$	22,621,529
Total Corpus at Year End	$	10,091,169	$	12,285,070	$	14,638,833	$	18,165,048	$	22,544,752

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Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations.

Critical Accounting Policies and Estimates

     The financial statements of the Trust are prepared on a modified cash basis and are not intended to present financial position and results of operations in conformity with United States Generally Accepted Accounting Principles (“GAAP”). Preparation of the Trust’s financial statements on such basis includes the following:

• Revenues are recognized in the period in which amounts are received by the Trust. General and administrative expenses are recognized on an accrual basis.

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

• Distributions to Unitholders are recorded when declared by the Trustee (see Note 5).

• 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 U.S. Securities and Exchange Commission, 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.

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

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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.

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 2005, royalty income received by the Trust amounted to $14,497,187 as compared to $15,375,469 and $14,754,582 for 2004 and 2003, respectively. The decrease in royalty income in 2005 compared to 2004 was primarily due to lower natural gas production, partially offset by the effect of higher natural gas prices. The increase in royalty income in 2004 compared to 2003 was primarily due to higher natural gas prices. Net production related to the royalty income received by the Trust in 2005 was approximately 5,352,416 MMBtu as compared to 6,373,931 MMBtu and 6,975,001 MMBtu in 2004 and 2003, respectively. Retroactive adjustments in 2005 resulting from unit expansions on certain Federal Units increased the natural gas attributable to the NPI of the Underlying Properties by approximately 335,311 MMbtu’s and that of the Trust by approximately 201,187 MMbtu’s (representing a retroactive adjustment based on actual prices in effect during the year of approximately $530,487 to the Trust). In 2004 similar retroactive adjustments increased the natural gas attributable to the NPI of the Underlying Properties by approximately (77,349) MMbtu’s and that of the Trust by approximately (46,409) MMbtu’s (representing a retroactive adjustment based on actual prices in effect during the year of approximately $413,436). The average net natural gas price received for royalty income in 2005 was $2.35 per MMBtu as compared to $2.16 MMBtu and $2.01 MMBtu in 2004 and 2003, respectively. Interest income for 2005 was $29,173 as compared to $10,518 and $9,125 for 2004 and 2003. The increase in interest income for 2005 reflects higher interest rates. The increase in interest income in 2004 compared to 2003 reflects higher interest rates and an increase in funds available for investment.

     General and administrative expenses for 2005 were $960,740, as compared to $745,244 and $751,415 for 2004 and 2003, respectively. General and administrative expenses in 2005 were higher than 2004. The increase in general and administrative expenses in 2005 compared to 2004 was primarily due to higher administrative expenses relating to Sarbanes-Oxley Act compliance in 2005. General and administrative expenses in 2004 were comparable to 2003.

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     Distributable income for 2005 was $13,565,620 or $1.40 per Unit, compared to $14,640,743 or $1.51 per Unit for 2004, and $14,012,292 or $1.44 per Unit, for 2003. The decrease in distributable income in 2005 compared to 2004 was primarily due to lower net production from the Underlying Properties but offset by higher gas prices. The increase in distributable income in 2004 compared to 2003 was primarily due to higher gas prices and the effect of the retroactive adjustment in 2004 as discussed above.

     Reserve values at December 31, 2005, December 31, 2004 and December 31, 2003 were impacted by significant changes in natural gas prices used to value the reserves. The year end prices required to be utilized in such valuations were $7.56 per Mcf, $ 5.44 per Mcf and $5.61 per Mcf as at December 31, 2005, 2004 and 2003 respectively.

     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, 2005, 2004 and 2003, was based on production volumes and natural gas prices for the 12 months ended in September 30, 2005, 2004 and 2003, 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 (or as applicable Quatro Finale’s) royalty obligations to third parties, which are determined by contractual arrangement with such parties.

	Twelve Months Ended September 30,
	2005		2004		2003
Production, Net (MMBtu)(1)
WI Properties		7,319,114		8,711,628		9,694,064
Farmout Properties(2)		1,601,580		1,911,591		1,930,937
Average Blanco Hub Spot Price ($/MMBtu)(3)	$	5.96	$	4.78	$	4.19
Average Net Wellhead Price WI Properties ($/MMBtu)	$	2.35	$	2.16	$	2.01

(1)	Million British Thermal Units.
(2)	Includes previously reported estimated amounts for certain months.
(3)	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 (on behalf of itself and Quatro Finale) to the Trustee. The Trustee has no control over and no responsibility relating to the operation of the Underlying Properties.

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     Distributable income going forward may be reduced or eliminated entirely in one or more future quarterly periods depending on the final resolution of the State of New Mexico’s claim for additional royalties owed to Federal royalty owners. Applying the MMS methodology asserted by the State of New Mexico for calculating royalties on gas produced from the Underlying Properties could potentially reduce future royalty payments to the Trust and result in negative adjustments to amounts previously paid to the Trust of approximately $5,000,000, including interest. See “Item 3—Legal Proceedings” for additional information on this royalty dispute.

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, 2005.

			Payments Due by Period
									More
			Less than		1 - 3		3-5		than 5
	Total		1 Year		Years		Years		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.

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

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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.

     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. The amount of any such borrowings is unlikely to be material to the Trust. The Trust periodically holds short-term investments acquired with funds held by the Trust pending distribution to Unitholders and funds held in reserve for the payment of Trust expenses and liabilities. Because of the short-term nature of these borrowings and investments and certain limitations upon the types of such investments that may be held by the Trust, the Trustee believes that the Trust is not subject to any material interest rate risk. The Trust does not engage in transactions in foreign currencies that could expose the Trust or Unitholders to any foreign currency related market risk.

Item 8. Financial Statements and Supplementary Data.

     Audited Statements of Assets, Liabilities and Trust Corpus of the Trust as of December 31, 2005 and 2004, and the related Statements of Distributable Income and Changes in Trust Corpus for each of the 3 years in the period ended December 31, 2005, are included in this Form 10-K.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Trustee
Williams Coal Seam Gas Royalty Trust

     We have audited the accompanying statements of assets, liabilities and trust corpus of the Williams Coal Seam Gas Royalty Trust as of December 31, 2005 and 2004, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Trustee’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     As described in Note 2 to the financial statements, these financial statements have been prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles.

     In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust corpus of the Williams Coal Seam Gas Royalty Trust at December 31, 2005 and 2004, and its distributable income and its changes in trust corpus for each of the three years in the period ended December 31, 2005, on the basis of accounting described in Note 2.

     We also have audited, in accordance with the Standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Williams Coal Seam Gas Royalty Trust’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 14, 2006 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma
March 14, 2006

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Financial Statements
Williams Coal Seam Gas Royalty Trust

Statements of Assets, Liabilities and Trust Corpus

	December 31,
	2005		2004
Assets
Current assets — cash and cash equivalents	$	55,586	$	105,497
Royalty interests in oil and gas properties (less accumulated amortization of $128,483,605 and $126,354,339 at December 31, 2005 and 2004, respectively) (Note 2)		10,083,058		12,212,324
Total	$	10,138,644	$	12,317,821
Liabilities and Trust Corpus
Current liabilities:
Other accounts payable	$	47,475	$	32,751
Current liabilities		47,475		32,751
Trust corpus (9,700,000 units of beneficial interest authorized and outstanding) (Note 2)		10,091,169		12,285,070
Total	$	10,138,644	$	12,317,821

Statements of Distributable Income

	Year Ended December 31,
	2005			2004			2003
Royalty income (Note 2)	$	14,497,187		$	15,375,469		$	14,754,582
Interest income		29,173			10,518			9,125
Total		14,526,360			15,385,987			14,763,707
General and administrative expenses (Note 4)		(960,740	)		(745,244	)		(751,415	)
Distributable income	$	13,565,620		$	14,640,743		$	14,012,292
Distributable income per Unit (9,700,000 units) (Note 2)	$	1.40		$	1.51		$	1.44
Distributions per Unit (Note 5)	$	1.41		$	1.50		$	1.45

Statements of Changes in Trust Corpus

	Year Ended December 31,
	2005			2004			2003
Trust corpus, beginning of year	$	12,285,070		$	14,638,833		$	18,165,048
Amortization of royalty interests (Note 2)		(2,129,266	)		(2,408,538	)		( 3,504,538	)
Distributable income		13,565,620			14,640,743			14,012,292
Distributions to Unitholders (Note 5)		(13,630,255	)		(14,585,968	)		(14,033,969	)
Trust corpus, end of year	$	10,091,169		$	12,285,070		$	14,638,833

See accompanying notes

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Notes to Financial Statements

1. Trust Organization and Provisions

     Williams Coal Seam Gas Royalty Trust (the “Trust”) was formed as a Delaware business trust pursuant to the terms of the Trust Agreement of Williams Coal Seam Gas Royalty Trust (as amended, the “Trust Agreement”) entered into effective as of December 1, 1992, by and among Williams Production Company, a Delaware corporation (“WPC”), as trustor; The Williams Companies, Inc., a Delaware corporation (“Williams”), as sponsor; Bank of America, N.A. (as successor to NationsBank of Texas, N.A.), a national banking association (the “Trustee”) and Chase Bank (as successor to Chemical Bank Delaware), a Delaware banking corporation (the “Delaware Trustee”) (the “Trustee” and the “Delaware Trustee” are sometimes referred to collectively as the “Trustees”). The Trustees are independent financial institutions.

     The Trust was formed to acquire and hold certain net profits interests (the “Royalty Interests”) in proved natural gas properties located in the San Juan Basin of New Mexico and Colorado (the “Underlying Properties”) owned by WPC. The Trust was initially created effective as of December 1, 1992, with a $100 contribution by WPC. On January 21, 1993, the Royalty Interests were conveyed to the Trust by WPC pursuant to the Net Profits Conveyance (the “Conveyance”) entered into effective as of October 1, 1992, by and among WPC, Williams, the Trustee and the Delaware Trustee, in consideration for all the 9,700,000 authorized units of beneficial interest in the Trust (“Units”). WPC transferred its Units by dividend to its parent, Williams, which sold an aggregate of 5,980,000 Units to the public through various underwriters in January and February 1993 (the “Public Offering”). Subsequently, Williams sold to the public an additional 151,209 Units. During the second quarter of 1995, Williams transferred its remaining Units to Williams Holdings of Delaware, Inc. (“WHD”), a separate holding company for Williams’ non-regulated businesses. Effective July 31, 1999, WHD was merged into Williams, and by operation of the merger, Williams assumed all assets, liabilities and obligations of WHD, including without limitation ownership of WHD’s Units. Effective August 11, 2000, Williams sold its Units to Quatro Finale IV LLC, a Delaware limited liability company (“QFIV”), in a privately negotiated transaction. Williams retained the voting rights and retained a “call” option on the transferred Units and QFIV was granted a “put” option on the Units. Williams retained the voting rights and retained a “call” option on the transferred Units, and QFIV was granted a “put” option on the Units. Through a series of exercises of its call option, Williams reacquired an aggregate of 3,568,791 Units from December 2001 through June 2003. Williams has informed the Trustee that it has subsequently sold 2,779,500 of these Units through March 6, 2006 and owned a remaining 789,291 Units as of such date.

     Effective May 1, 1997, WPC sold the Underlying Properties subject to and burdened by the Royalty Interests to Quatro Finale LLC, an unaffiliated Delaware limited liability company. Ownership of the Underlying Properties reverted back to WPC effective February 1, 2001, pursuant to the terms of the May 1, 1997 transaction. Effective March 1, 2001, WPC sold the Underlying Properties subject to and burdened by the Royalty Interests to Quatro Finale V LLC, an unaffiliated Delaware limited liability company. The sale of the Underlying Properties is expressly permitted under the Trust Agreement. Effective January 1, 2003, ownership of the Underlying Properties once again reverted back to WPC after it exercised its right to repurchase interests in the Underlying Properties from Quatro Finale V LLC pursuant to the 2001 Transaction Agreement. Unless otherwise dictated by context, references herein to WPC with respect to the ownership of the Underlying Properties for any period from May 1, 1997 through February 1, 2001, and for the period from March 1, 2001 through December 31, 2002, shall be deemed to refer to Quatro Finale.

     The Trustee has the power to collect and distribute the proceeds received by the Trust and to pay Trust liabilities and expenses. The Delaware Trustee has only such powers as are set forth in the Trust Agreement and is not empowered to otherwise manage or take part in the business of the Trust. The Royalty Interests are 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 Trust will terminate no later than December 31, 2012, subject to earlier termination under certain circumstances described in the Trust Agreement (the “Termination Date”). Cancellation of the Trust will occur on or following the Termination Date when all Trust assets have been sold and the net proceeds therefrom distributed to holders of Units in the Trust (“Unitholders”).

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     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 consist primarily of a net profits interest (the “NPI”) in the Underlying Properties. The NPI generally entitles the Trust to receive 60 percent of the NPI Net Proceeds, as defined below, attributable to (i) gas produced and sold from WPC’s net revenue interests (working interests less lease burdens) in the properties in which WPC has a working interest (the “WI Properties”) and (ii) the revenue stream received by WPC attributable to its 35 percent net profits interest in 5,348 gross acres in La Plata County, Colorado (the “Farmout Properties”).

     The Royalty Interests also include a 20 percent interest in WPC’s Infill Net Proceeds from the sale of production since well spacing rules have been effectively modified and additional wells are drilled on producing drilling blocks on the WI Properties (the “Infill Wells”) during the term of the Trust. “Infill Net Proceeds” consists generally of the aggregate proceeds, based on the price at the wellhead, of gas produced from WPC’s net revenue interest in any Infill Wells less certain taxes and costs.

     On October 15, 2002 the New Mexico Oil and Gas Commission (NMOCD) revised the field rules for the Basin Fruitland Coal (Gas) Pool to allow an optional second (infill) well on the standard 320-acre spacing unit in certain designated areas of the pool (the non-fairway wells). On July 17, 2003 the NMOCD further modified the field rules for the Basin Fruitland Coal (Gas) Pool to allow these infill wells on the standard 320-acre spacing unit in all areas of the pool. The WI Properties contain 530 infill locations designated as proved locations according to Securities and Exchange Commission guidelines. As of December 31, 2005, 316 infill locations are proved developed producing and 214 locations are proved undeveloped.

     As of December 31, 2005, the Infill Net Profit Costs exceed the Infill Net Profit Gross Proceeds by $3,164,100. The Trust will not be liable for such excess costs, and such excess costs will hereafter constitute Excess Infill Net Profit Costs until recovered by WPC. The Trust will not receive its 20 percent interest in WPC’s Infill Net Proceeds until such time as the Infill Net Profits Gross Proceeds exceeds the Infill Net Profit Costs on an aggregate basis.

2. Basis of Accounting

     The financial statements of the Trust are prepared on a modified cash basis and are not intended to present financial position and results of operations in conformity with United States Generally Accepted Accounting Principles (“GAAP”). Preparation of the Trust’s financial statements on such basis includes the following:

• Revenues are recognized in the period in which amounts are received by the Trust. General and administrative expenses are recognized on an accrual basis.

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

• Distributions to Unitholders are recorded when declared by the Trustee (see Note 5).

• 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 U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

3. Federal Income Taxes

     The Trust is a grantor trust for Federal income tax purposes. As a grantor trust, the Trust is not required to pay Federal income taxes. Accordingly, no provision for income taxes has been made in these financial statements.

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     Because the Trust is treated as a grantor trust, and because a Unitholder is treated as directly owning an interest in the Royalty Interests, each Unitholder is taxed directly on his per Unit pro rata share of income attributable to the Royalty Interests consistent with the Unitholder’s method of accounting and without regard to the taxable year or accounting method employed by the Trust.

     Coal seam gas produced and sold after December 31, 2002, no longer generates a Section 29 tax credit under the Internal Revenue Code of 1986, as amended (the “IRC”). Therefore, Unitholders are not entitled to claim Section 29 credits for coal seam gas produced and sold after 2002. However, a Unitholder may benefit from unused Section 29 credits for alternative minimum tax purposes. Before its expiration, the Section 29 credit could be used only to the extent that a Unitholder’s regular tax liability exceeded the Unitholder’s tentative minimum tax liability after the regular tax liability had been reduced by the foreign tax credit and certain nonrefundable personal credits. Any part of the Section 29 credit not allowed for the tax year solely because of this alternative minimum tax limitation was subject to certain carryover provisions relating to the alternative minimum tax calculation. These carryover provisions continue to apply for tax years ending before 2006. Therefore, for taxpayers with tax years ending on or before December 31, 2005, the alternative minimum tax limitation is increased by the amount of Section 29 tax credits disallowed in prior years, even though the Section 29 tax credit is no longer allowed for coal seam gas produced and sold after 2002.

4. Related Party Transactions

     Williams provides accounting, bookkeeping and informational services to the Trust in accordance with an Administrative Services Agreement effective December 1, 1992. The fee is $50,000 per quarter, escalating 3 percent each October 1 commencing October 1, 1993. Aggregate fees incurred by the Trust to Williams in 2005, 2004 and 2003 were $285,152, $276,847, and $268,783, respectively. Substantially all production from the WI Properties is sold to a Williams’ subsidiary. Additionally, all royalty income is received from Williams.

     The interests of Williams and its affiliates and the interests of the Trust and the Unitholders with respect to the Underlying Properties could at times be different. As a working interest owner in the WI Properties, WPC could have interests that conflict with the interests of the Trust and Unitholders. For example, such conflicts could be due to a number of factors including, but not limited to, future budgetary considerations and the absence of any contractual obligation on the part of WPC to spend for development of the WI Properties, except as noted herein. Such decisions may have the effect of changing the amount or timing of future distributions to Unitholders. WPC’s interests may also conflict with those of the Trust and Unitholders in situations involving the sale or abandonment of Underlying Properties. WPC has the right at any time to sell any of the Underlying Properties subject to the Royalty Interests and under certain circumstances may abandon any of the WI Properties. Such sales or abandonment may not be in the best interest of the Trust. In addition, WPX Gas Resources has the right, exercisable in its sole discretion, to terminate its Minimum Purchase Price commitment under the Gas Purchase Contract. Williams’ interests could conflict with those of the Trust and Unitholders to the extent the interests of WPX Gas Resources, under the Gas Purchase Contract, or WFS and WPX Gas Resources, under the Gas Gathering Contract, differ from the interests of the Trust and the Unitholders. Except for amendments to the Gas Gathering Contract or Gas Purchase Contract that must be approved by the vote of a majority of the Unitholders present at a meeting at which a quorum is present if such amendment would materially adversely affect Trust revenues, no mechanism or procedure has been included to resolve potential conflicts of interest between the Trust, Williams, WPC or their affiliates.

     Aggregate fees paid by the Trust to the trustees in 2005, 2004 and 2003 were $54,055, $52,660 and $51,306, respectively.

5. Distributions to Unitholders

     The Trustee determines for each quarter the amount of cash available for distribution to Unitholders. Such amount (the “Quarterly Distribution Amount”) is an amount equal to the excess, if any, of the cash received by the Trust, on or prior to the last day of the month following the end of each calendar quarter from the Royalty Interests, plus, with certain exceptions, any other cash receipts of the Trust during such quarter, over the liabilities of the Trust paid during such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for the payment of contingent or future obligations of the Trust.

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     The Trustee distributes the Quarterly Distribution Amount within 60 days after the end of each calendar quarter to each person who was a Unitholder of record on the associated record date (i.e., the 45th day following the end of each calendar quarter or if such day is not a business day, the next business day thereafter), together with interest estimated to be earned on such amount from the date of receipt thereof by the Trustee to the payment date.

     In addition to the regular quarterly distributions, under certain circumstances specified in the Trust Agreement (such as upon a purchase price adjustment, if any, or pursuant to the sale of a Royalty Interest) the Trust would make a special distribution (a “Special Distribution Amount”). A Special Distribution Amount would be made when amounts received by the Trust under such circumstances aggregated in excess of $9,000,000. The record date for a Special Distribution Amount will be the 15th day following receipt of amounts aggregating a Special Distribution Amount by the Trust (unless such day is not a business day in which case the record date will be the next business day thereafter or unless such day is within 10 days of the record date for a Quarterly Distribution Amount in which case the record date will be the date as is established for the next Quarterly Distribution Amount). Distribution to Unitholders of a Special Distribution Amount will be made no later than 15 days after the Special Distribution Amount record date.

6. Contingencies

     WPX Gas Resources Company (“WPX Gas Resources,” as successor in interest to Williams Gas Marketing Company) purchases natural gas produced from the WI Properties (except for certain small volumes) at the wellhead under the terms of a gas purchase contract dated October 1, 1992, as amended (the “Gas Purchase Contract”). The Gas Purchase Contract provides for a pricing mechanism during an initial 5-year period, which expired on December 31, 1997, and continuing for one or more consecutive additional 1-year terms unless and until WPX Gas Resources exercises its annual option, exercisable 15 days prior to the end of each contract year, to discontinue purchasing gas under the pricing mechanism of the Gas Purchase Contract and instead purchase gas at a monthly market-based price. WPX Gas Resources has not exercised this option, and therefore, the pricing mechanism will continue to remain in effect through at least December 31, 2006.

     Under the pricing mechanism of the Gas Purchase Contract, when the market price is less than $1.70 per MMBtu (the “Minimum Purchase Price”), the Trust will be paid the Minimum Purchase Price for the gas and an account (the “Price Credit Account”) will be maintained to identify the accrued and unrecouped amount of payments made to the Trust in excess of the market price. Any amounts in the Price Credit Account are subject to future recoupment when the market price exceeds the Minimum Purchase Price. As of December 31, 2005 and 2004, there were no remaining unrecouped Price Credits in the Price Credit Account. To the extent there may in the future be a balance in the Price Credit Account, the entitlement to recoup Price Credits means that if and when the Index Price is above the Minimum Purchase Price, future royalty income paid to the Trust would be reduced until such time as such Price Credit Account is once again reduced to zero. Corresponding cash distributions to Unitholders would also be reduced.

     While the terms of the Gas Purchase Agreement pricing mechanism remain in place and when the market price for natural gas exceeds $1.94 per MMBtu (as was the case during all months in 2005, 2004 and 2003), the Trust receives only 50 percent of the excess of the market price over the $1.94 price per MMBtu before reduction for gathering, processing and certain other costs.

     The majority of the production attributable to the Trust is within Federal units. Unit participating areas are formed by pooling production from the participating area. Entitlement to the pooled production is based on each party’s acreage in the participating area divided by the total participating acreage. Wells drilled outside the participating area may create an enlargement to the participating area and a revision of the Unit ownership entitlement. The Bureau of Land Management (“BLM”) must approve Unit participating area expansions. The effective date for Unit expansions is retroactive to the date the well creating the expansion was tested. For the 12 month period ended on December 31, 2005, retroactive adjustments were processed on certain Federal Units. These retroactive adjustments resulted in unit expansions on certain Federal Units as well as some nominal net pricing adjustments and adjustments to actualize estimates. The total impact of these adjustments was to increase the natural gas attributable to the NPI of the Underlying Properties by approximately 335,311 MMbtu’s and that of the Trust by approximately 201,187 MMbtu’s (representing a retroactive adjustment based on actual prices in effect

48

during the year of approximately $530,487 to the Trust). In the Prior year, similar retroactive adjustments were processed on certain federal units resulting from unit expansions and actualizing estimates. The total impact of these adjustments was to increase the natural gas attributable to the NPI of the Underlying Properties by approximately (77,349) MMbtu’s and that of the Trust by approximately (46,409) MMbtu’s (representing a retroactive adjustment based on actual prices in effect during the year of approximately $413,436. The revenues presented in the accompanying statements of distributable income are on an entitlement basis and reflect the most recent BLM participating area approvals at December 31, 2005, 2004, and 2003, respectively. There are pending or anticipated applications or approvals for additional participating area enlargements that could impact future results.

     On January 5, 2001, the State of New Mexico, acting under authority of the Minerals Management Service (“MMS”), a subagency of the United States Department of the Interior, presented WPC with an Audit Issue Letter for the alleged underpayment of royalties in the amount of $948,501, on gas produced from the Underlying Properties due to Federal royalty owners during the time period from January 1992 through December 1996. MMS regulations permit a lessee to deduct from its gross proceeds its reasonable actual costs of transportation and processing to transport the gas from the lease to the point of sale in calculating the market value of its production. The State of New Mexico claims that certain costs of removing and transporting carbon dioxide gas are not deductible. On March 22, 2001, WPC responded to the Audit Issue Letter and contested the State of New Mexico’s claim for additional royalties as being contrary to law. In early November 2001, WPC received from the MMS an Order to Report and Pay Additional Royalties and Perform Restructured Accounting on subsequent periods. The order was dated October 30, 2001. The order requires WPC (1) to pay additional royalties of $943,964 on production related to the audit period of January 1, 1992 through December 31, 1996; (2) to pay an estimated incremental royalty amount of $991,549 for production covering January 1, 1997 through March 31, 2001; and (3) to perform a restructured accounting and pay an additional royalty for months after March 2001. On January 30, 2002, WPC filed its Statement of Reasons in support of its earlier appeal of the Audit Issue Letter. Applying the MMS methodology asserted by the State of New Mexico could potentially result in negative adjustments to amounts previously paid to the Trust of approximately $5,400,000, including interest. On November 1, 2004, WPC received notice that its appeal was denied in part by the MMS. On January 14, 2005, WPC filed a Complaint for Review of Agency Action and Declaratory Relief requesting the United States District Court for the District of New Mexico hold unlawful and set aside the Assistant Secretary’s October 2004 decision. A separate but similar matter has been determined unfavorably against another major oil and gas producer in the D.C. circuit court. If either WPC proceeds with its lawsuit and loses or determines to settle the claims, then this would result in an adjustment to royalty income otherwise payable from WPC to the Trust and a corresponding decrease in distributions to Unitholders, which could eliminate entirely such distributions for one or more future quarterly periods.

7. Subsequent Event

     Subsequent to December 31, 2005, the Trust declared the following distribution:

Quarterly Record Date	Payment Date	Distribution per Unit
February 14, 2006	March 1, 2006	$	0.562572

8. Quarterly Financial Data (Unaudited)

     The following table sets forth the royalty income, distributable income and distributions per Unit of the Trust for each quarter in the years ended December 31, 2005 and 2004 (in thousands, except per Unit amounts):

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Calendar Quarter	Royalty Income		Distributable Income		Distributions per Unit
2005
First	$	3,534	$	3,142	$	.346311
Second		3,464		3,277		.321706
Third		3,663		3,491		.357841
Fourth		3,836		3,656		.379323
TOTAL		14,497		13,566		1.405181
2004
First	$	3,331	$	3,057	$	.329589
Second		4,193		3,998		.396403
Third		4,129		3,982		.405316
Fourth		3,723		3,603		.372400
TOTAL	$	15,376	$	14,640	$	1.503708

     Selected 2005 and 2004 fourth quarter data are as follows (in thousands except per Unit amounts):

	2005		2004
Royalty income	$     3,836		$ 3,723
Interest income	11		4
General and administrative expenses	(191	)	(124	)
Distributable income	$     3,655		$ 3,603
Distributable income per Unit (9,700,000 units)	$         .38		$     .37
Distributions per Unit	$         .38		$     .37

9. Supplemental Oil and Gas Information (Unaudited)

     The net proved reserves attributable to the Royalty Interests have been estimated as of December 31, 2005, 2004 and 2003, by independent petroleum engineers. In accordance with Statement of Financial Accounting Standards No. 69, estimates of future net revenues from proved reserves have been prepared using contractual gas prices and related costs. The standardized measure of future net revenues from the gas reserves is calculated based on discounting such future net revenues at an annual rate of 10 percent. The Blanco Hub Spot Price was $7.58, $5.44 and $5.61 per MMBtu, after adjustments for certain costs and provisions of the Gas Purchase Contract, at December 31, 2005, 2004, and 2003, respectively. This resulted in a weighted average wellhead price of $4.78, $3.72 and $3.81 per Mcf at December 31, 2005, 2004, and 2003, respectively. The standardized measure of discounted future net revenues below has been reduced by operating and development costs, which are paid by Williams and are included in computing the royalty income of the Trust. The standardized measure has not been reduced for income taxes as no income taxes are paid by the Trust (see Note 3).

     Numerous uncertainties are inherent in estimating volumes and value of proved reserves and in projecting future production rates and timing of development expenditures. 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.

     The reserve estimates as of December 31, 2005, 2004 and 2003, are based on a percentage share of NPI Net Proceeds payable to the Trust of 60 percent.

	Natural Gas (MMcf)
Proved reserves at January 1, 2003		39,722
Production		(7,977	)
Extensions and revisions of previous estimates		12,618
Proved reserves at December 31, 2003		44,363
Production		(7,402	)

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	Natural Gas (MMcf)
Extensions and revisions of previous estimates		427
Proved reserves at December 31, 2004		37,388
Production		(5,976	)
Extensions and revisions of previous estimates		(2,806	)
Proved reserves at December 31, 2005		28,606
Proved developed reserves at December 31, 2005		27,710

     Proved reserve estimates presented above at January 1, 2003 are proved developed reserves. Proved reserves at December 31, 2004, include 1,861 MMcf of proved undeveloped reserves. Proved reserves at December 31, 2005, include 897 MMcf of proved undeveloped reserves.

     Proved reserves are estimated quantities of natural gas that geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. WPC’s proved undeveloped reserves are the reserves that are expected to be recovered from infill wells on the standard 320-acre spacing unit in certain designated areas of Fruitland coal formation.

     The following table sets forth the standardized measure of discounted future net revenues at December 31, 2005, 2004 and 2003 relating to proved developed reserves (in thousands):

	Year Ended December 31,
	2005			2004			2003
Future cash inflows	$	109,580		$	106,058		$	125,582
Future production taxes		(12,701	)		(11,907	)		(7,565	)
Future development costs		(3,266	)		(2,486	)		(4,334	)
Future net cash flows		93,613			91,665			113,683
10% discount factor		(38,916	)		(36,748	)		(48,357	)
Standardized measure of discounted future net revenues	$	54,697		$	54,917		$	65,326

     Future cash flows do not include Section 29 tax credits, which no longer apply for coal seam gas produced and sold after December 31, 2002, as discussed in Note 3.

     The following table sets forth the changes in the aggregate standardized measure of discounted future net revenues from proved reserves during the years ended December 31, 2005, 2004 and 2003 (in thousands):

	2005			2004			2003
Balance at January 1	$	54,917		$	65,326		$	46,039
Increase (decrease) due to:
Net sales of coal seam gas		(16,298	)		(15,145	)		(15,504	)
Net changes in prices and costs		13,857			862			13,264
Development costs incurred		(278	)		(208	)		(321	)
Changes in estimated future development cost		(1,110	)		(2,211	)		(834	)
Extensions and revisions of previous quantity estimates		(3,714	)		427			18,580
Accretion of discount		5,492			6,533			4,604
Other		1,831			(667	)		(502	)
		(220	)		(10,408	)		19,287
Balance at December 31	$	54,697		$	54,917		$	65,326

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

     None.

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Item 9A. Controls and Procedures.

     Disclosure Controls and Procedures. As of the end of the period covered by this report, the Trustee carried out an evaluation of the effectiveness of the design and operation of the Trust’s disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15. Based upon that evaluation, the Trustee concluded that the Trust’s disclosure controls and procedures are effective in timely alerting the Trustee to material information relating to the Trust required to be included in the Trust’s periodic filings with the Securities and Exchange Commission. In its evaluation of disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on information provided by WPC.

     Changes in Internal Control over Financial Reporting. There has not been any change in the Trust’s internal control over financial reporting during the fourth quarter of 2005 that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.

     Trustee’s Report on Internal Control Over Financial Reporting. The Trustee is responsible for establishing and maintaining adequate control over financial reporting, as such term is defined in Rule 13a-15 promulgated under the Securities Exchange Act of 1934, as amended. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control-Integrated Framework, the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2005. The Trustee’s assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2005 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.

     Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

The Trustee
Williams Coal Seam Gas Royalty Trust

     We have audited the Trustee’s assessment, included in the accompanying Trustee’s Report on Internal Control Over Financial Reporting, that the Williams Coal Seam Gas Royalty Trust (the “Trust”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Management of the Trustee is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the Trustee’s assessment and an opinion on the effectiveness of the Trust’s internal control over financial reporting based on our audit.

     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating the Trustee’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

     A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles (or other comprehensive basis of accounting). A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles (or other comprehensive basis of accounting) and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s

52

assets that could have a material effect on the financial statements.

     Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

     In our opinion, the Trustee’s assessment that the Trust maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the COSO criteria.

     We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statements of assets, liabilities and trust corpus of the Trust as of December 31, 2005 and 2004, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2005 of the Trust and our report dated March 14, 2006 expressed an unqualified opinion on those financial statements.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma
March 14, 2006

Item 9B. Other Information.

     None.

PART III

Item 10. Directors and Executive Officers of the Registrant.

     Directors and Executive Officers. The Trust has no directors or executive officers. Each of the Trustee and the Delaware Trustee is a corporate trustee that may be removed as trustee under the Trust Agreement, with or without cause, at a meeting duly called and held by the affirmative vote of Unitholders of not less than a majority of all the Units then outstanding. Any such removal of the Delaware Trustee shall be effective only at such time as a successor Delaware Trustee fulfilling the requirements of Section 3807(a) of the Delaware Code has been appointed and has accepted such appointment, and any such removal of the Trustee shall be effective only at such time as a successor Trustee has been appointed and has accepted such appointment.

     Code of Ethics. Because the Trust has no employees, it does not have a code of ethics. Employees of the Trustee, Bank of American, N.A., must comply with the bank’s code of ethics, a copy of which will be provided to Unitholders, without charge, upon request made to Bank of America, N.A., Trust Division, Royalty Trust Group, 901 Main Street, 17th Floor, Dallas, Texas 75202, Attention: Ron Hooper.

     Audit Committee. The Trust has no directors and therefore has no audit committee or audit committee financial expert.

     Nominating Committee. The Trust has no directors and therefore has no nominating committee.

53

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

     Section 16(a) of the Securities Exchange Act of 1934 requires the Trust’s directors, officers or beneficial owners of more than 10 percent of a registered class of the Trust’s equity securities to file reports of ownership and changes in ownership with the SEC and to furnish the Trust with copies of all such reports.

     The Trust has no directors or officers, and based solely on its review of the reports received by it, the Trust believes that during the fiscal year of 2005, no person who was a beneficial owner of more than 10 percent the Trust’s Units failed to file on a timely basis any report required by Section 16(a).

Item 11. Executive Compensation.

     The following is a description of certain fees and expenses anticipated to be paid or borne by the Trust, including fees expected to be paid to Williams, the Trustee, the Delaware Trustee, Mellon Investor Service, L.L.C. (as successor to Chemical Shareholder Services Group, Inc.) (the “Transfer Agent”), or their affiliates.

     Ongoing Administrative Expenses. The Trust is responsible for paying all legal, accounting, engineering and stock exchange fees, printing costs and other administrative and out-of-pocket expenses incurred by or at the direction of the Trustee or the Delaware Trustee and the out-of-pocket expenses of the Transfer Agent.

     Compensation of the Trustee, Delaware Trustee and Transfer Agent. The Trust Agreement provides for compensation to the Trustee and the Delaware Trustee for administrative services, out of the Trust assets. The Trustee was paid a 2005 base amount of $47,906, plus an hourly charge for services in excess of a combined total of 300 hours annually at the Trustee’s then standard rate. The Delaware Trustee is paid a fixed annual amount, which was initially set at $5,000. The Trustee and the Delaware Trustee received total compensation for 2005 of $47,906 and $6,149, respectively. The base amount of the Trustee’s fee and the amount of the Delaware Trustee’s fee for administrative services escalate at the rate of 3 percent per year. The Trustee and the Delaware Trustee are each entitled to reimbursement for out-of-pocket expenses. Upon termination of the Trust, the Trustee will receive, in addition to its out-of-pocket expenses, a termination fee in the amount of $8,000.

     The Transfer Agent receives a transfer agency fee of $5.50 annually per account (minimum of $15,000 annually), subject to change each December, based upon the change in the Producers’ Price Index as published by the United States Department of Labor, Bureau of Labor Statistics, plus $1.00 for each certificate issued in excess of 10,000 annually. The total fees paid by the Trust to the Transfer Agent in 2005 were $25,579.

     Fees to Williams. Williams will receive, throughout the term of the Trust, an administrative services fee for accounting, bookkeeping and informational services relating to the Royalty Interests as described below in “Item 13—Administrative Services Agreement.”

Item 12. Security Ownership of Certain Beneficial Owners and Management.

     (a) Security Ownership of Certain Beneficial Owners. The following table sets forth as of March 1, 2006 information with respect to the only Unitholder who was known to the Trustee to be a beneficial owner of more than 5 percent of the outstanding Units.

	Number of Units	Percent
Name and Address of Beneficial Owner	Beneficially Owned	of Class
The Williams Companies, Inc.	789,291	8.14%
One Williams Center
Tulsa, Oklahoma 74172 (1)

(1) This information was provided to the Securities and Exchange Commission and to the Trustee in a Schedule 13D/A filed with the Securities and Exchange Commission on August 4, 2005, on behalf of The Williams Companies, Inc.

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Williams’s Voting Authority Over Units

     Although Williams has the voting authority over the Units it holds, with respect to the vote on any amendment to the Gas Purchase Contract or the Gas Gathering Contract, the Units held by Williams (or its affiliates) immediately after the Public Offering may not be voted nor will such Units be counted for purposes of determining if a quorum is present so long as such Units continue to be held by Williams (or its affiliates). This voting limitation will not be applicable to Units Williams (or its affiliates) may acquire, if any, after the date of the Public Offering.

     In addition, as noted below, certain potential conflicts of interest exist between Williams and its affiliates and the interests of the Trust and the Unitholders (see “Item 13 — Certain Relationships and Related Transactions — Potential Conflicts of Interest”). To the extent that any matters are brought to a vote of Unitholders where the interests of Williams conflict, or potentially conflict, with the interests of the Trust or Unitholders, Williams (or its affiliates) can be expected to vote in its own self-interest and under certain circumstances as noted above, may have sufficient votes to control the outcome.

     (b) Security Ownership of Management. The Trust has no directors or executive officers and does not maintain any equity compensation plans. As of March 1, 2006, Bank of America, N.A., the Trustee, held an aggregate of 28,844 Units in various fiduciary capacities, with no investment or voting powers. As of March 1, 2006, Chase Bank (as successor to Chemical Bank Delaware), the Delaware Trustee, did not beneficially own any Units.

     (c) Changes in Control. Subject to the discussion above in this Item 12 under “Williams’s Voting Authority Over Units,” the Trustee knows of no arrangements the operation of which may at a subsequent date result in a change in control of the Trust.

Item 13. Certain Relationships and Related Transactions.

Administrative Services Agreement

     Pursuant to the Trust Agreement, Williams and the Trust entered into an Administrative Services Agreement effective December 1, 1992. A copy of the Administrative Services Agreement is filed as an exhibit to this Form 10-K.

     The Administrative Services Agreement obligates the Trust to pay to Williams each quarter an administrative services fee for accounting, bookkeeping and informational services relating to the Royalty Interests. The administrative services fee was $50,000 per calendar quarter commencing October 1, 1993, through and including the quarter ended September 30, 1994, and increases 3 percent each October 1. Accordingly, the total of the administrative services fees paid by the Trust to Williams in 2005 was $285,152.

Potential Conflicts of Interest

     The interests of Williams and its affiliates and the interests of the Trust and the Unitholders with respect to the Underlying Properties could at times be different. As a working interest owner in the WI Properties, WPC could have interests that conflict with the interests of the Trust and Unitholders. For example, such conflicts could be due to a number of factors including, but not limited to, future budgetary considerations and the absence of any contractual obligation on the part of WPC to spend for development of the WI Properties, except as noted herein. Such decisions may have the effect of changing the amount or timing of future distributions to Unitholders. WPC’s interests may also conflict with those of the Trust and Unitholders in situations involving the sale or abandonment of Underlying Properties. WPC has the right at any time to sell any of the Underlying Properties subject to the Royalty Interests and under certain circumstances may abandon any of the WI Properties. Such sales or abandonment may not be in the best interest of the Trust. In addition, WPX Gas Resources has the right, exercisable in its sole discretion, to terminate its Minimum Purchase Price commitment under the Gas Purchase Contract. Williams’ interests could conflict with those of the Trust and Unitholders to the extent the interests of WPX Gas Resources, under the Gas Purchase Contract, or WFS and WPX Gas Resources, under the Gas Gathering Contract, differ from the interests of the Trust and the Unitholders. Except for amendments to the Gas Gathering Contract or Gas

55

Purchase Contract that must be approved by the vote of a majority of the Unitholders present at a meeting at which a quorum is present if such amendment would materially adversely affect Trust revenues, no mechanism or procedure has been included to resolve potential conflicts of interest between the Trust, Williams, WPC or their affiliates.

Item 14. Principal Accounting Fees and Services.

     Fees for services performed by Ernst & Young LLP for the years ended December 31, 2005 and 2004 are:

	2005		2004
Audit Fees	$	188,700	$	143,000
Audit-Related Fees	$	0	$	0
Tax Fees	$	0	$	0
All Other Fees	$	0	$	0

     The Trust has no audit committee, and as a result, has no audit committee pre-approval policy with respect to fees paid to Ernst & Young LLP.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

     (a) The following documents are filed as a part of this report:

     1. Financial Statements (included in Item 8 of this report)

	Page In This
	Report
Report of Independent Registered Public Accounting Firm	43
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2005 and 2004	44
Statements of Distributable Income for each of the three years in the period ended December 31, 2005	44
Statements of Changes in Trust Corpus for each of the three years in the period ended December 31, 2005	44
Notes to Financial Statements	45–51

     2. Financial Statement Schedules

     Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the financial statements and notes thereto.

     3. Exhibits

Exhibit
Number		Exhibit
3.1	—	Certificate of Trust of Williams Coal Seam Gas Royalty Trust (filed as Exhibit 3.1 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
4.1	—	Trust Agreement of Williams Coal Seam Gas Royalty Trust effective as of December 1, 1992, by and among Williams Production Company, The Williams Companies, Inc. and Chemical

56

Exhibit
Number		Exhibit
		Bank Delaware and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.), as trustees (filed as Exhibit 4.1 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
4.2	—	First Amendment to the Trust Agreement of Williams Coal Seam Gas Royalty Trust effective as of December 15, 1992, by and among Williams Production Company, The Williams Companies, Inc., Chemical Bank Delaware and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 4.2 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
4.3	—	Second Amendment to the Trust Agreement of Williams Coal Seam Gas Royalty Trust effective as of January 12, 1993, by and among Williams Production Company, The Williams Companies, Inc., Chemical Bank Delaware and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 4.3 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
4.4	—	Net Profits Conveyance effective as of October 1, 1992, by and among Williams Production Company, The Williams Companies, Inc., and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.), and Chemical Bank Delaware (filed as Exhibit 4.4 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
10.1	—	Administrative Services Agreement effective December 1, 1992, by and between The Williams Companies, Inc. and Williams Coal Seam Gas Royalty Trust (filed as Exhibit 10.1 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
10.2	—	Gas Purchase Agreement dated October 1, 1992, by and between Williams Gas Marketing Company and Williams Production Company (filed as Exhibit 10.2 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
10.3	—	First Amendment to the Gas Purchase Agreement effective January 12, 1993, by and between Williams Gas Marketing Company and Williams Production Company (filed as Exhibit 10.3 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
10.4	—	Gas Gathering and Treating Agreement effective October 1, 1992, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.4 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
10.5	—	First Amendment to the Gas Gathering and Treating Agreement effective as of January 12, 1993, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.5 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
10.6	—	Amendment #2 to the Gas Gathering and Treating Agreement dated as of October 1, 1993, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.6 to the Registrant’s Form 10-K for the year ended December 31, 1993 and incorporated herein by reference).
10.7	—	Amendment #3 to the Gas Gathering and Treating Agreement dated as of October 1, 1993, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as

57

Exhibit
Number		Exhibit
		Exhibit 10.7 to the Registrant’s Form 10-K for the year ended December 31, 1993 and incorporated herein by reference).
10.8	—	Confirmation Agreement effective as of May 1, 1995 by and among Williams Production Company, The Williams Companies, Inc. and Williams Coal Seam Gas Royalty Trust (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 1995 and incorporated herein by reference).
23.1	—	Consent of Ernst & Young LLP.
23.2	—	Consent of Miller and Lents, Ltd.
31.1	—	Certification by Ron E. Hooper, Senior Vice President and Administrator of Bank of America, Trustee of Williams Coal Seam Gas Royalty Trust, dated March 15, 2006, and submitted pursuant to Rule 13a-14(a)/15d-14(a) and pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	—	Certificate by Bank of America, Trustee of Williams Coal Seam Gas Royalty Trust, dated March 15, 2006, and submitted pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1	—	The information under the section captioned “Tax Considerations” on pages 20-21, and the information under the sections captioned “Federal Income Tax Consequences” and “ERISA Considerations” on pages 45-52 of the Prospectus dated January 13, 1993, which constitutes a part of the Registration Statement on Form S-3 of The Williams Companies, Inc. (Registration No. 33-53662) (filed as Exhibit 28.1 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
99.2	—	Reserve Report, dated November 21, 1992, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests and the Underlying Properties as of October 1, 1992, prepared by Miller and Lents, Ltd., independent petroleum engineers, included as Exhibit A of the Prospectus dated January 13, 1993, which constitutes a part of the Registration Statement on Form S-3 of The Williams Companies, Inc. (Registration No. 33-53662) (filed as Exhibit 28.1 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
99.3	—	Reserve Report, dated January 12, 2006 estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests and the Underlying Properties as of December 31, 2005, prepared by Miller and Lents, Ltd., independent petroleum engineers.

58

SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Williams Coal Seam Gas Royalty Trust
By:	Bank of America, N.A., Trustee
By:	/s/ Ron E. Hooper
	Ron E. Hooper
	Senior Vice President and Administrator

Date: March 15, 2006

(The Registrant has no directors or executive officers.)

59

INDEX TO EXHIBITS

Exhibit
Number		Description
3.1	___	Certificate of Trust of Williams Coal Seam Gas Royalty Trust (filed as Exhibit 3.1 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
4.1	___	Trust Agreement of Williams Coal Seam Gas Royalty Trust effective as of December 1, 1992, by and among Williams Production Company, The Williams Companies, Inc. and Chemical Bank Delaware and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.), as trustees (filed as Exhibit 4.1 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
4.2	___	First Amendment to the Trust Agreement of Williams Coal Seam Gas Royalty Trust effective as of December 15, 1992, by and among Williams Production Company, The Williams Companies, Inc., Chemical Bank Delaware and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 4.2 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
4.3	___	Second Amendment to the Trust Agreement of Williams Coal Seam Gas Royalty Trust effective as of January 12, 1993, by and among Williams Production Company, The Williams Companies, Inc., Chemical Bank Delaware and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 4.3 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
4.4	___	Net Profits Conveyance effective as of October 1, 1992, by and among Williams Production Company, The Williams Companies, Inc., and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.), and Chemical Bank Delaware (filed as Exhibit 4.4 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
10.1	___	Administrative Services Agreement effective December 1, 1992, by and between The Williams Companies, Inc. and Williams Coal Seam Gas Royalty Trust (filed as Exhibit 10.1 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
10.2	___	Gas Purchase Agreement dated October 1, 1992, by and between Williams Gas Marketing Company and Williams Production Company (filed as Exhibit 10.2 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
10.3	___	First Amendment to the Gas Purchase Agreement effective January 12, 1993, by and between Williams Gas Marketing Company and Williams Production Company (filed as Exhibit 10.3 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
10.4	___	Gas Gathering and Treating Agreement effective October 1, 1992, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.4 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
10.5	___	First Amendment to the Gas Gathering and Treating Agreement effective as of January 12, 1993, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.5 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
10.6	___	Amendment #2 to the Gas Gathering and Treating Agreement dated as of October 1, 1993, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.6 to the Registrant’s Form 10-K for the year ended December 31, 1993 and incorporated herein by reference).

Exhibit
Number		Description
10.7	___	Amendment #3 to the Gas Gathering and Treating Agreement dated as of October 1, 1993, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.7 to the Registrant’s Form 10-K for the year ended December 31, 1993 and incorporated herein by reference).
10.8	___	Confirmation Agreement effective as of May 1, 1995 by and among Williams Production Company, The Williams Companies, Inc. and Williams Coal Seam Gas Royalty Trust (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 1995 and incorporated herein by reference).
23.1	___	Consent of Ernst & Young LLP.
23.2	___	Consent of Miller and Lents, Ltd.
31.1	___	Certification by Ron E. Hooper, Senior Vice President and Administrator of Bank of America, Trustee of Williams Coal Seam Gas Royalty Trust, dated March 15, 2006, and submitted pursuant to Rule 13a-14(a)/15d-14(a) and pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	___	Certificate by Bank of America, Trustee of Williams Coal Seam Gas Royalty Trust, dated March 15, 2006, and submitted pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1	___	The information under the section captioned “Tax Considerations” on pages 20-21, and the information under the sections captioned “Federal Income Tax Consequences” and “ERISA Considerations” on pages 45-52 of the Prospectus dated January 13, 1993, which constitutes a part of the Registration Statement on Form S-3 of The Williams Companies, Inc. (Registration No. 33-53662) (filed as Exhibit 28.1 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
99.2	___	Reserve Report, dated November 21, 1992, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests and the Underlying Properties as of October 1, 1992, prepared by Miller and Lents, Ltd., independent petroleum engineers, included as Exhibit A of the Prospectus dated January 13, 1993, which constitutes a part of the Registration Statement on Form S-3 of The Williams Companies, Inc. (Registration No. 33-53662) (filed as Exhibit 28.1 to the Registrant’s Form 10-K for the year ended December 31, 1992 and incorporated herein by reference).
99.3	___	Reserve Report, dated January 12, 2006, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests and the Underlying Properties as of December 31, 2005, prepared by Miller and Lents, Ltd., independent petroleum engineers.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statement (Form S-3, No. 333-70394-01) of the Williams Coal Seam Gas Royalty Trust and in the related Prospectus of our reports dated March 14, 2006, with respect to the financial statements of the Williams Coal Seam Gas Royalty Trust, the Trustee’s assessment of the effectiveness of internal control over financial reporting, and the effectiveness of internal control over financial reporting of the Williams Coal Seam Gas Royalty Trust included in this Annual Report (Form 10-K) for the year ended December 31, 2005.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma
March 14, 2006

EX-23.2

Exhibit 23.2

CONSENT OF MILLER AND LENTS, LTD.

March 15, 2006

Bank of America, Trustee
Williams Coal Seam Gas Royalty trust
901 Main Street, Suite 1700
Dallas, TX 75283-0650

Re: Williams Coal Seam Gas Royalty Trust Securities and Exchange Commission Form
10-K Annual Report

Gentlemen:

The firm of Miller and Lents, Ltd. consents to the references to Miller and Lents, Ltd. and to the use of its reports listed below regarding the Williams Coal Seam Gas Royalty Trust Proved Reserves and Future Net Income in the Form 10-K Annual Report to be filed by the Williams Coal Seam Gas Royalty Trust with the Securities and Exchange Commission.

1. Report dated November 21, 1992 for reserves as of October 1, 1992.

2. Report dated January 12, 2006 for reserves as of December 31, 2005.

Miller and Lents, Ltd. has no interests in the Williams Coal Seam Gas Royalty Trust or in any of its affiliate companies or subsidiaries and does not receive any such interest as payment for its report. No director, officer, or employee of Miller and Lents, Ltd. is employed by or otherwise connected with the Williams Coal Seam Gas Royalty Trust nor is Miller and Lents, Ltd. employed by the Williams Coal Seam Gas Royalty Trust on a contingent basis.

Very truly yours,

MILLER AND LENTS, LTD.
By:	/s/ Stephen M. Hamburg
	Stephen M. Hamburg

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Ron Hooper, certify that:

1. I have reviewed this Annual Report on Form 10-K of Williams Coal Seam Gas Royalty Trust, for which Bank of America, N.A., acts as Trustee;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, distributable income and changes in trust corpus of the registrant as of, and for, the periods presented in this annual report;

4. I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), or for causing such procedures to be established and maintained, for the registrant and I have:

a)	designed such disclosure controls and procedures, or caused such controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this annual report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervisors, to provided reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this annual report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation;
d)	disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors:

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting; and In giving the certifications in paragraphs 4 and 5 above, I have relied to the extent I consider reasonable on information provided to me by Williams Production Company.

Date: March 15, 2006

By:	/s/ Ron E. Hooper
	Ron E. Hooper
	Senior Vice President and Administrator Bank of America, N.A.

EX-32.1

Exhibit 32.1

Certification Furnished Pursuant to Section 906 of

the Sarbanes-Oxley Act of 2002

     In connection with the Annual Report of Williams Coal Seam Royalty Trust (the “Trust”) on Form 10-K for the annual period ended December 31, 2005, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, not in its individual capacity but solely as the trustee of the Trust, certifies pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to its knowledge:

(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.

	BANK OF AMERICA, N.A., TRUSTEE FOR
	WILLIAMS COAL SEAM GAS ROYALTY TRUST
Date: March 15, 2006	By:	/s/ Ron E. Hooper
		Ron E. Hooper,
		Senior Vice President, Royalty Management
		Bank of America, N.A.

A signed original of this written statement required by Section 906 has been provided to Williams Coal Seam Gas Royalty Trust and will be retained by Williams Coal Seam Gas Royalty Trust and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.3

Exhibit 99.3

Miller And Lents, Ltd.
INTERNATIONAL OIL AND GAS CONSULTANTS
TWENTY-SEVENTH FLOOR
IIOO LOUISIANA
HOUSTON, TEXAS 77OO2-5216
Telephone 713-651-9455
Telefax 713-654-9914
e-mail: mail@millerandlents.com

January 12, 2006

Mr. Ron E. Hooper
Senior Vice President
Bank of America, N.A., Trustee
Williams Coal Seam Gas Royalty Trust
901 Main Street, Suite 1700
Dallas, Texas 75201

Re:	Proved Reserves and Future Net
	Revenues As of December 31, 2005

Dear Mr. Hooper:

     At your request, we estimated the proved reserves and projected the future net revenues from the gas reserves in the Fruitland Coal Formation that are attributable to the subject interests of the Williams Coal Seam Gas Royalty Trust (“WTU”). These interests consist of net profits interests in natural gas properties located in the San Juan Basin in Colorado and New Mexico.

     A summary of the reserves for the Underlying Properties and Royalty Interests (net to the Trust) is as follows:

	Net Gas		Future Net		Present Value
	Reserves,		Revenues,		at 10 Percent
	MMcf		M$		Per Annum, M$
The Underlying Properties
Proved Developed		85,670		370,113		261,245
Proved Undeveloped		12,078		38,217		21,401
Total Proved		97,748		408,330		282,646
The Royalty Interests (Net to the Trust)
Proved Developed		27,710		90,134		53,234
Proved Undeveloped		897		3,479		1,463
Total Proved		28,606		93,613		54,697

Miller and Lents, Ltd.

Mr. Ron E. Hooper	January 12, 2006
Bank of America, N.A., Trustee	Page 2
Williams Coal Seam Gas Royalty Trust

     In order to estimate the reserves to the WTU, it was necessary to estimate the reserves attributable to (i) the “Underlying Properties,” which are certain working interest properties (“Working Interest Properties”) and net profits interests properties (“Farmout Properties”) that are managed by Williams Production Company (“WPC”) and (ii) the “Royalty Interests,” the variable net revenue interest conveyed to WTU by WPC. WTU receives a “Specified Percentage” of “Net Proceeds” from gas produced and sold from the Working Interest Properties and from the revenue stream of the Farmout Properties. Currently, for 320-acre spaced wells in the Working Interest Properties, and all wells in the Farmout Properties, the percentage of net proceeds is 60 percent.

     For the Working Interest Properties, overhead costs (beyond the standard overhead charges for the non-operated properties) have not been included, nor have the effects of depreciation, depletion, and Federal Income Tax. Net Proceeds is defined as revenues derived from the sale of Working Interest Properties gas volumes less severance and ad valorem taxes, lease royalty payments, and operating expenses in excess of the estimates shown in Exhibit B of the Trust Conveyance. The reserves attributable to the Royalty Interests from the Working Interest Properties were computed by multiplying the net gas reserves of the Working Interest Properties by the ratio of (i) the net revenue received by WTU from the Working Interest Properties to (ii) total revenues from the Working Interest Properties after deduction of severance and ad valorem taxes.

     The proved reserves were estimated in accordance with the definitions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10(a). Estimates of future net revenues and discounted future net revenues are not intended and should not be interpreted to represent the fair market value of the estimated reserves.

     The production forecast for the total proved reserves and future net revenues as of December 31, 2005 attributable to the Underlying Properties and to the WTU are shown on Table 1. Forecasts for proved developed reserves and proved undeveloped reserves are shown on Tables 2 and 3. The proved reserves and future net revenues as of December 31, 2005 attributable to the individual Underlying Properties are shown on the attached one-line summary identified as Table 4.

     The gas reserves for the Fruitland Coal were primarily estimated by decline curve analyses utilizing type curves for the various areas in the San Juan Basin. These type curves were developed for each area and were based on production histories and the initial reservoir pressures of the wells in the separate areas.

     In October 2002, the field rules for the Basin Fruitland Coal Gas Pool in New Mexico were revised to allow an optional second (infill) well on the standard 320-acre spacing unit in certain designated areas of the pool. As of July 2003, the field rules were further modified to allow such infill drilling in all areas of the pool. The Working Interest Properties contain 530 infill locations of which 316 have been drilled and 214 additional locations are evaluated as containing proved undeveloped reserves. The Trust provides for an infill NPI, a net profits interest that entitles the Trust to receive 20 percent of the Infill Net Proceeds. Infill Net Proceeds is determined on an aggregate basis, not on a well-by-well basis.

Miller and Lents, Ltd.

Mr. Ron E. Hooper	January 12, 2006
Bank of America, N.A., Trustee	Page 3
Williams Coal Seam Gas Royalty Trust

     The gas prices and deductions for WTU are based upon information provided by WPC. The gas price for the Farmout Properties is $7.560 per MMBtu based on the December 31, 2005 Blanco Hub Index Price. For the Working Interest Properties, the adjusted price of $4.780 per MMBtu was employed as provided for in the Gas Purchase Contract. On December 31, 2012, the WTU terminates and the Gas Purchase Contract is no longer in effect. The gas price reverts to $7.560 per MMBtu, based on the December 31, 2005 Blanco Hub Index Price. Gathering and transportation charges, taxes, treating, and other costs payable prior to the delivery points were deducted from the index price in order to determine the net wellhead price used in this evaluation. These prices and deductions were held constant.

     Deductions for lease royalty and production and ad valorem taxes for the Working Interest Properties were based on the December 31, 2005 index gas price of $7.560 per MMBtu less appropriate deductions as reported by WPC.

     Operating expense estimates were based on expenses incurred during 2005 and were not escalated. Where appropriate, estimated operating expenses which exceeded the operating expenses in Exhibit B to the Conveyance were deducted in calculating Net Proceeds and, therefore, reduced the amounts payable to the WTU.

     In preparation of our estimates, we relied on production histories, accounting and cost data, engineering and geological information supplied by WPC, and data from public records. The ownership interests evaluated herein were provided by WPC and were employed as presented. No independent verification of these interests was made by Miller and Lents, Ltd.

     Capital expenditures to plug and abandon wells are considered to be equal to the salvage values of the wells at the time of abandonment. We did not include any consideration for the future environmental restoration that might be required as such was beyond the scope of our assignment. In our projection of future net revenues, no provisions are made for production prepayments or for the consequences of future production balancing. As instructed, we assumed for purposes of this report that the Trust will continue as long as there is economic production from the contributing properties.

     The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments based on accepted standards of professional investigation but are subject to those generally recognized uncertainties associated with interpretation of geological and engineering information. Government policies and market conditions different from those employed in this study may cause the total quantity of oil or gas to be recovered, actual production rates, prices received, and operating and capital costs to vary from those presented in this report. Minor precision inconsistencies in subtotals or totals may exist in the report due to truncation or rounding of aggregated values.

     Miller and Lents, Ltd. is an independent oil and gas consulting firm. No director, officer, or key employee of Miller and Lents, Ltd. has any financial ownership in WTU or WPC or any related company. Our compensation for the required investigations and preparation of this report is not

Miller and Lents, Ltd.

Mr. Ron E. Hooper	January 12, 2006
Bank of America, N.A., Trustee	Page 4
Williams Coal Seam Gas Royalty Trust

contingent on the results obtained and reported, and we nave not performed other work that would affect our objectivity. Production of this report was supervised by an officer of the firm who is a professionally qualified and licensed Professional Engineer in the State of Texas with more than 20 years of relevant experience in the estimation, assessment, and evaluation of oil and gas reserves.

Very truly yours,
MILLER AND LENTS, LTD.
By	/s/ Stephen M. Hamburg
	Stephen M. Hamburg
	Vice President

SMH/hsd  [SEAL] 

WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMICS AS OF DECEMBER 31, 2005
UNDERLYING PROPERTIES AND TRUST INTERESTS

NON-ESCALATED 12/31/2005 PRICES
TOTAL PROVED RESERVES

	Underlying Properties																				Trust Interests
	Natural Gas, MMCF						Revenue				Net Oper Costs, M$				Future Net Revenue, M$				Tax Credits, M$				Future Net Revenue, M$				Tax Credits, M$
					Price		to Net Intr		Oper		Adv&Sev		Future				Disc			Disc	Net				Disc			Disc
Year	Gross		Net		$/Mcf		M$		Expns		Taxes		Capital		Annual		@10%		Annual	@10%	MMCF		Annual		@10%		Annual	@10%
2006		209,441		17,866		5.404		96,555		6,875		10,106		5,658		73,916		70,630				4,569		11,997		11,434
2007		175,722		14,886		5.407		80,490		5,937		8,439		2,605		63,509		55,135				4,021		10,450		9,025
2008		146,600		12,315		5.409		66,607		5,119		6,992		3,413		51,084		40,310				3,176		8,280		6,481
2009		120,790		10,155		5.410		54,942		4,423		5,772		982		43,765		31,382				2,729		7,067		5,012
2010		100,154		8,382		5.411		45,358		3,846		4,769		1,567		35,176		22,929				2,127		5,536		3,558
2011		80,325		6,704		5.410		36,264		3,271		3,809		20		29,165		17,278				1,848		4,774		2,780
2012		63,258		5,342		5.408		28,886		2,789		3,030		—		23,067		12,424				1,483		3,837		2,025
2013		50,165		4,277		5.406		23,120		2,388		2,422		—		18,310		8,966				1,703		8,206		3,903
2014		40,165		3,448		5.405		18,638		2,083		1,951		—		14,604		6,501				1,375		6,626		2,854
2015		32,310		2,789		5.404		15,070		1,828		1,577		—		11,665		4,721				1,112		5,355		2,089
2016		26,151		2,265		5.403		12,239		1,624		1,280		—		9,335		3,435				900		4,333		1,531
2017		21,247		1,845		5.403		9,968		1,454		1,042		—		7,472		2,500				728		3,506		1,122
2018		17,310		1,505		5.402		8,132		1,307		850		—		5,975		1,817				589		2,834		821
2019		14,117		1,229		5.402		6,637		1,178		693		—		4,765		1,317				475		2,286		600
2020		11,501		1,002		5.401		5,411		1,060		565		—		3,786		953				382		1,839		438
2021		9,303		809		5.401		4,366		926		456		—		2,985		682				306		1,470		317
2022		7,360		642		5.399		3,466		786		361		—		2,318		481				243		1,167		228
2023		5,846		510		5.401		2,754		679		288		—		1,787		339				191		918		162
2024		4,602		403		5.399		2,173		577		227		—		1,370		235				150		722		115
2025		3,558		312		5.397		1,686		472		176		—		1,038		164				117		560		81
AFTER		11,917		1,065		5.405		5,756		1,920		598		—		3,237		446				384		1,849		122
TOTAL		1,151,842		97,748		5.407		528,517		50,540		55,402		14,244		408,330		282,646				28,606		93,613		54,697

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 1

WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMICS AS OF DECEMBER 31, 2005
UNDERLYING PROPERTIES AND TRUST INTERESTS

NON-ESCALATED 12/31/2005 PRICES
TOTAL PROVED DEVELOPED RESERVES

	Underlying Properties																				Trust Interests
	Natural Gas, MMCF						Revenue		Net Oper Costs, M$						Future Net Revenue, M$				Tax Credits, M$				Future Net Revenue, M$				Tax Credits, M$
					Price		to Net Intr		Oper		Adv&Sev		Future				Disc			Disc	Net				Disc			Disc
Year	Gross		Net		$/Mcf		M$		Expns		Taxes		Capital		Annual		@10%		Annual	@10%	MMCF		Annual		@10%		Annual	@10%
2006		199,539		17,173		5.401		92,747		6,592		9,683		—		76,472		73,057				4,569		11,997		11,434
2007		157,081		13,508		5.398		72,914		5,359		7,597		—		59,958		52,070				4,021		10,450		9,025
2008		124,487		10,699		5.396		57,725		4,420		6,004		—		47,300		37,341				3,163		8,251		6,458
2009		99,778		8,572		5.394		46,241		3,712		4,805		—		37,724		27,073				2,633		6,849		4,858
2010		79,893		6,861		5.393		36,997		3,136		3,840		—		30,021		19,586				2,119		5,519		3,548
2011		64,136		5,509		5.391		29,699		2,675		3,079		—		23,945		14,202				1,715		4,471		2,604
2012		51,623		4,436		5.390		23,911		2,298		2,477		—		19,136		10,318				1,385		3,615		1,909
2013		41,696		3,585		5.389		19,318		1,993		2,000		—		15,325		7,512				1,576		7,586		3,609
2014		33,809		2,908		5.388		15,669		1,754		1,621		—		12,294		5,478				1,278		6,148		2,649
2015		27,463		2,365		5.387		12,739		1,556		1,317		—		9,865		3,996				1,036		4,985		1,945
2016		22,366		1,927		5.387		10,383		1,394		1,073		—		7,916		2,915				840		4,042		1,428
2017		18,246		1,573		5.387		8,470		1,251		875		—		6,344		2,125				681		3,275		1,049
2018		14,884		1,284		5.386		6,915		1,123		714		—		5,077		1,546				551		2,650		768
2019		12,141		1,048		5.386		5,647		1,009		583		—		4,054		1,122				445		2,142		562
2020		9,900		856		5.385		4,608		903		476		—		3,229		813				359		1,726		411
2021		8,004		690		5.384		3,715		780		383		—		2,552		584				288		1,382		298
2022		6,377		550		5.383		2,960		658		305		—		1,997		415				229		1,102		215
2023		5,158		446		5.387		2,400		582		248		—		1,569		298				182		874		154
2024		4,163		360		5.388		1,941		509		201		—		1,231		211				144		693		111
2025		3,283		285		5.386		1,537		427		159		—		952		150				113		544		79
AFTER		11,618		1,037		5.403		5,601		1,867		581		—		3,152		434				381		1,833		119
TOTAL		995,644		85,670		5.394		462,136		43,999		48,024		—		370,113		261,245				27,710		90,134		53,234

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 2

WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMICS AS OF DECEMBER 31, 2005
UNDERLYING PROPERTIES AND TRUST INTERESTS

NON-ESCALATED 12/31/2005 PRICES
TOTAL PROVED UNDEVELOPED RESERVES

	Underlying Properties																								Trust Interests
	Natural Gas, MMCF						Revenue		Net Oper Costs, M$						Future Net Revenue, M$						Tax Credits, M$				Future Net Revenue, M$				Tax Credits, M$
					Price		to Net Intr		Oper		Adv&Sev		Future					Disc				Disc	Net				Disc			Disc
Year	Gross		Net		$/Mcf		M$		Expns		Taxes		Capital		Annual			@10%			Annual	@10%	MMCF		Annual		@10%		Annual	@10%
2006		9,901		693		5.496		3,809		283		423		5,658		(2,556	)		(2,427	)				—		—		—
2007		18,641		1,379		5.496		7,577		578		842		2,605		3,551			3,065					—		—		—
2008		22,114		1,616		5.496		8,883		699		987		3,413		3,784			2,969					13		29		23
2009		21,012		1,583		5.496		8,701		711		967		982		6,042			4,310					96		218		154
2010		20,261		1,521		5.496		8,361		709		929		1,567		5,156			3,343					7		17		11
2011		16,189		1,195		5.496		6,565		596		730		20		5,219			3,077					133		303		175
2012		11,635		905		5.496		4,975		491		553		—		3,931			2,107					97		222		116
2013		8,469		692		5.496		3,803		395		423		—		2,984			1,454					127		620		294
2014		6,356		540		5.496		2,969		329		330		—		2,310			1,023					98		478		205
2015		4,847		424		5.495		2,331		272		259		—		1,800			725					76		371		144
2016		3,785		338		5.495		1,856		230		206		—		1,420			520					60		291		102
2017		3,001		272		5.496		1,497		203		166		—		1,128			375					47		230		73
2018		2,426		222		5.495		1,217		184		135		—		898			272					37		183		53
2019		1,977		180		5.498		990		169		110		—		711			195					30		145		38
2020		1,601		146		5.494		803		156		89		—		557			140					23		114		27
2021		1,299		119		5.495		651		145		72		—		434			99					18		88		19
2022		983		92		5.495		506		128		56		—		322			66					13		65		13
2023		688		64		5.498		354		96		39		—		218			41					9		44		7
2024		439		42		5.493		232		67		26		—		139			24					6		28		4
2025		276		27		5.507		149		46		17		—		86			14					3		17		3
AFTER		299		28		5.496		155		53		17		—		85			12					3		16		2
TOTAL		156,198		12,078		5.496		66,381		6,541		7,379		14,244		38,217			21,401					897		3,479		1,463

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 3

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

												REVENUE		OPER.						BFIT NET		10% DISC
						LIFE		GROSS GAS		NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		TAXES M$		M$		M$		M$		NUM
STATE: COLORADO
PROVED DEVELOPED RESERVES
HENDRICKSON GU B #1 (NPI)	13385	NON-UNIT	32N10W20		1		22		1,319		404		1,726		0		0		0		1,726		1,178		12
SO UTE TRIBAL I 2 (NPI)	13389	NON-UNIT	32N10W07		1		17		1,262		386		1,652		0		0		0		1,652		1,228		17
SO UTE TRIBAL J #2 (NPI)	13390	NON-UNIT	32N10W07		1		21		999		306		1,307		0		0		0		1,307		889		22
TOTAL PROVED DEVELOPED: 160-Acre Colorado					3				3,579		1,096		4,685		0		0		0		4,685		3,295
CARTER UTE #101 (NPI)	14449	NON-UNIT	32N10W12		1		21		1,726		66		282		0		0		0		282		200		6
CARTER UTE #106 (NPI)	13397	NON-UNIT	32N10W11		1		22		2,253		173		737		0		0		0		737		520		16
CARTER UTE #107(NPI)	13398	NON-UNIT	32N10W13		1		13		702		67		287		0		0		0		287		223		14
CLARK CUMMINS GU A #1 (NPI)	13383	NON-UNIT	32N10W19		1		31		2,639		798		3,412		0		0		0		3,412		2,126		13
HENDRICKSON GU A #1 (NPI)	13384	NON-UNIT	32N10W20		1		15		614		186		794		0		0		0		794		584		11
J B GARDNER GU A #1 (NPI)	13386	NON-UNIT	32N10W22		1		25		2,315		481		2,055		0		0		0		2,055		1,399		18
MONTGOMERY, M H #9 (NPI)	15248	NON-UNIT	32N10W12		1		28		3,543		678		2,899		0		0		0		2,899		1,928		15
ROBIN FRAZIER GU A #1 (NPI)	13387	NON-UNIT	32N10W23		1		17		1,137		226		965		0		0		0		965		715		19
SO UTE 10-3, 32-10 (NPI)	13399	NON-UNIT	32N10W10		1		25		2,564		393		1,678		0		0		0		1,678		1,151		21
SO UTE 15-3, 32-10 (NPI)	13400	NON-UNIT	32N10W15		1		32		3,459		265		1,132		0		0		0		1,132		711		9
SO UTE 16-2, 32-10 (NPI)	13401	NON-UNIT	32N10W16		1		22		2,153		247		1,057		0		0		0		1,057		746		10
SO UTE TRIBAL H #2 (NPI)	13388	NON-UNIT	32N10W18		1		18		972		298		1,272		0		0		0		1,272		915		2
SO UTE TRIBAL KK #1 (NPI)	13391	NON-UNIT	32N10W07		1		20		888		272		1,163		0		0		0		1,163		791		3
SO UTE TRIBAL LL #1 (NPI)	13392	NON-UNIT	32N10W08		1		19		1,118		342		1,464		0		0		0		1,464		1,041		4
SO UTE TRIBAL MM #1 (NPI)	13393	NON-UNIT	32N10W08		1		23		1,558		477		2,040		0		0		0		2,040		1,392		7
SO UTE TRIBAL NN #1 (NPI)	13394	NON-UNIT	32N10W17		1		17		919		281		1,203		0		0		0		1,203		876		5
SO UTE TRIBAL OO #1 (NPI)	13395	NON-UNIT	32N10W18		1		16		688		211		900		0		0		0		900		651		8
SO UTE TRIBAL SS #1 (NPI)	13396	NON-UNIT	32N10W21		1		23		1,555		476		2,036		0		0		0		2,036		1,368		20
TOTAL PROVED DEVELOPED: 320-Acre Colorado					18				30,803		5,936		25,377		0		0		0		25,377		17,337
TOTAL PROVED DEVELOPED: COLORADO					21				34,382		7,033		30,063		0		0		0		30,063		20,632
TOTAL PROVED RESERVES: COLORADO					21				34,382		7,033		30,063		0		0		0		30,063		20,632
STATE: NEW MEXICO
PROVED DEVELOPED RESERVES
BLANCO #201A	5609	NON-UNIT	31N08W35		1		16		700		103		568		66		63		0		439		311		1168
BLANCO #202A	5607	NON-UNIT	31N08W26		1		8		319		47		258		31		29		0		199		170		1166
BLANCO #203A	5610	NON-UNIT	31N08W35		1		16		488		72		396		53		44		0		299		220		1233
BLANCO #204A	5608	NON-UNIT	31N08W26		1		12		366		54		297		41		33		0		224		175		1165
BLANCO #330S	5559	NON-UNIT	31N08W05		1		20		1,495		109		600		58		67		0		476		342		1132
DECKER GAS COM A #1S	5840	NON-UNIT	32N10W17		1		13		245		18		98		17		11		0		70		53		1133
EAGLE #750S	5995	NON-UNIT	32N09W16		1		16		665		13		69		8		8		0		54		38		1179

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 1 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

												REVENUE		OPER.						BFIT NET		10% DISC
						LIFE		GROSS GAS		NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		TAXES M$		M$		M$		M$		NUM
HUERFANO UNIT #258S	2326	HUERFANO	27N10W36		1		14		277		39		215		35		24		0		156		116		1191
HUERFANO UNIT #79	12186	HUERFANO	27N10W31		1		18		952		134		739		75		82		0		582		405		1268
MOORE, WAYNE COM #2S (BPO)	5268	NON-UNIT	31N09W16		1		9		157		8		44		8		5		0		31		25		1034
NE BLANCO UNIT #403A	5191	NEBU	30N07W09		1		16		561		4		24		3		3		0		19		14		767
NE BLANCO UNIT #406A	5192	NEBU	31N07W22		1		1		4		0		0		0		0		0		0		0		1008
NE BLANCO UNIT #407A	17895	NEBU	30N07W21		1		12		242		2		10		2		1		0		8		6		695
NE BLANCO UNIT #408A	5196	NEBU	31N07W20		1		0		0		0		0		0		0		0		0		0		1215
NE BLANCO UNIT #410A	17897	NEBU	31N07W09		1		17		1,641		13		70		5		8		0		57		44		668
NE BLANCO UNIT #413A	17899	NEBU	30N07W20		1		9		251		2		11		1		1		0		8		7		692
NE BLANCO UNIT #418A	5210	NEBU	31N07W28		1		16		1,378		11		59		5		7		0		48		36		1217
NE BLANCO UNIT #422A	5146	NEBU	31N07W20		1		10		467		4		20		2		2		0		16		13		1011
NE BLANCO UNIT #426A	5231	NEBU	31N06W06		1		19		1,160		9		50		4		6		0		40		28		1219
NE BLANCO UNIT #428A	6018	NEBU	31N07W24		1		17		1,136		9		49		4		5		0		39		28		1048
NE BLANCO UNIT #430A	5245	NEBU	30N07W05		1		17		701		5		30		3		3		0		24		17		1013
NE BLANCO UNIT #433A	1000	NEBU	30N07W19		1		15		449		3		19		2		2		0		15		11		1208
NE BLANCO UNIT #434A	6017	NEBU	31N07W23		1		7		452		4		19		2		2		0		16		14		1045
NE BLANCO UNIT #435A	4894	NEBU	30N08W01		1		21		1,626		13		70		6		8		0		56		40		999
NE BLANCO UNIT #436A	1149	NEBU	31N06W19		1		20		1,855		14		79		6		9		0		64		47		1004
NE BLANCO UNIT #437A	5251	NEBU	30N08W12		1		18		925		7		40		4		4		0		31		23		1015
NE BLANCO UNIT #438A	1160	NEBU	31N06W18		1		14		676		5		29		3		3		0		23		18		1000
NE BLANCO UNIT #440A	709	NEBU	31N07W11		1		19		1,992		16		85		7		9		0		69		51		1207
NE BLANCO UNIT #441A	1545	NEBU	30N08W24		1		15		942		7		40		4		4		0		32		25		735
NE BLANCO UNIT #442A	17900	NEBU	31N07W11		1		22		2,452		19		105		8		12		0		85		61		666
NE BLANCO UNIT #445A	5250	NEBU	31N08W25		1		14		751		6		32		3		4		0		26		20		1017
NE BLANCO UNIT #447A	5248	NEBU	31N08W36		1		15		984		8		42		4		5		0		34		26		1018
NE BLANCO UNIT #448A	5181	NEBU	31N07W32		1		12		308		2		13		2		1		0		10		8		1019
NE BLANCO UNIT #449A	5183	NEBU	31N07W19		1		19		1,580		12		68		5		8		0		55		40		1020
NE BLANCO UNIT #457A	5189	NEBU	31N07W30		1		17		1,784		14		76		6		8		0		62		47		1022
NE BLANCO UNIT #458A	5247	NEBU	31N07W13		1		13		1,474		11		63		5		7		0		51		41		1023
NE BLANCO UNIT #460A	1810	NEBU	31N06W07		1		19		1,848		14		79		6		9		0		64		48		753
NE BLANCO UNIT #462A	5246	NEBU	31N07W01		1		17		747		6		32		3		4		0		25		18		1025
NE BLANCO UNIT #463A	5170	NEBU	30N07W18		1		12		432		3		18		2		2		0		14		11		1213
NE BLANCO UNIT #464A	17898	NEBU	31N07W10		1		15		932		7		40		4		4		0		32		24		667
NE BLANCO UNIT #468A	5163	NEBU	31N07W35		1		20		1,392		11		60		5		7		0		48		34		772
NE BLANCO UNIT #478A	5212	NEBU	31N07W21		1		13		471		4		20		2		2		0		16		12		1218
NE BLANCO UNIT #480A	5209	NEBU	31N07W14		1		16		591		5		25		3		3		0		20		14		1029
NE BLANCO UNIT #482A	4895	NEBU	31N07W15		1		16		1,187		9		51		4		6		0		41		31		1002
NE BLANCO UNIT #483A	5149	NEBU	31N07W36		1		16		544		4		23		3		3		0		18		13		774
NE BLANCO UNIT #484A	4896	NEBU	31N07W16		1		16		1,347		10		58		5		6		0		47		36		1003
NE BLANCO UNIT #486A	1150	NEBU	31N06W19		1		17		1,749		14		75		6		8		0		61		46		717
NE BLANCO UNIT #487A	5201	NEBU	31N07W35		1		6		409		3		17		2		2		0		14		12		1030
NE BLANCO UNIT #490A	5198	NEBU	31N07W14		1		16		588		5		25		3		3		0		20		14		1216
NE BLANCO UNIT #491A	5147	NEBU	31N07W25		1		19		985		8		42		4		5		0		34		24		1212

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 2 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

												REVENUE		OPER.						BFIT NET		10% DISC
						LIFE		GROSS GAS		NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		TAXES M$		M$		M$		M$		NUM
NE BLANCO UNIT #492A	5795	NEBU	31N07W12		1		6		389		3		17		1		2		0		13		12		1038
NE BLANCO UNIT #495A	1068	NEBU	31N06W30		1		12		396		3		17		2		2		0		13		10		754
NE BLANCO UNIT #496A	1161	NEBU	31N06W18		1		19		1,457		11		62		5		7		0		50		36		720
NE BLANCO UNIT #497A	1110	NEBU	31N06W30		1		14		480		4		21		2		2		0		16		12		713
NE BLANCO UNIT #498A	5193	NEBU	31N07W13		1		21		1,571		12		67		6		7		0		54		39		1214
NE BLANCO UNIT #499A	1152	NEBU	31N06W20		1		19		2,558		20		109		8		12		0		89		68		731
NE BLANCO UNIT #500A	1157	NEBU	31N06W20		1		14		733		6		31		3		3		0		25		19		1209
NE BLANCO UNIT #504A	1163	NEBU	31N07W16		1		8		586		5		25		2		3		0		20		17		738
PAYNE #201S	4128	NON-UNIT	32N10W20		1		19		1,030		19		104		11		12		0		82		59		743
QUINN #336S	5596	NON-UNIT	31N08W17		1		18		952		70		384		41		43		0		300		209		1135
SAN JUAN 28-6 UNIT #418S	19353	SJ 28-6	28N06W28		1		9		90		5		28		8		3		0		17		13		639
SAN JUAN 29-6 UNIT #201A	5403	SJ 29-6	29N06W06		1		14		469		57		312		40		35		0		237		179		740
SAN JUAN 29-6 UNIT #202A	5404	SJ 29-6	29N06W06		1		6		60		7		40		11		4		0		24		20		739
SAN JUAN 29-6 UNIT #203A	5406	SJ 29-6	29N06W07		1		14		754		91		501		52		56		0		393		303		816
SAN JUAN 29-6 UNIT #204A	5405	SJ 29-6	29N06W07		1		16		567		69		377		47		42		0		288		211		745
SAN JUAN 29-6 UNIT #205A	6095	SJ 29-6	29N06W21		1		17		1,378		167		916		82		102		0		732		558		926
SAN JUAN 29-6 UNIT #207A	5555	SJ 29-6	29N06W02		1		18		966		117		642		67		71		0		504		364		817
SAN JUAN 29-6 UNIT #208A	5551	SJ 29-6	29N06W17		1		11		173		21		115		23		13		0		79		61		995
SAN JUAN 29-6 UNIT #209A	5552	SJ 29-6	29N06W17		1		12		566		69		377		41		42		0		294		234		994
SAN JUAN 29-6 UNIT #210A	6093	SJ 29-6	29N06W20		1		16		1,297		157		863		79		96		0		688		525		924
SAN JUAN 29-6 UNIT #214A	5407	SJ 29-6	29N06W03		1		18		865		105		575		62		64		0		449		325		818
SAN JUAN 29-6 UNIT #215A	5408	SJ 29-6	29N06W03		1		21		1,641		199		1,091		100		121		0		870		623		775
SAN JUAN 29-6 UNIT #216A	5410	SJ 29-6	29N06W04		1		18		940		114		625		66		69		0		489		354		742
SAN JUAN 29-6 UNIT #217A	5411	SJ 29-6	29N06W05		1		12		340		41		226		31		25		0		170		134		741
SAN JUAN 29-6 UNIT #218A	5412	SJ 29-6	29N06W05		1		2		19		2		13		3		1		0		8		8		905
SAN JUAN 29-6 UNIT #220A	6081	SJ 29-6	29N06W11		1		16		1,279		155		850		77		94		0		678		519		912
SAN JUAN 29-6 UNIT #221A	6082	SJ 29-6	29N06W11		1		13		290		35		193		31		21		0		141		105		911
SAN JUAN 29-6 UNIT #236A	5553	SJ 29-6	29N06W18		1		8		188		23		125		20		14		0		91		76		819
SAN JUAN 29-6 UNIT #237A	5110	SJ 29-6	29N06W01		1		14		368		44		244		36		27		0		182		135		757
SAN JUAN 29-6 UNIT #238A	5033	SJ 29-6	29N06W01		1		7		142		17		94		16		10		0		68		58		734
SAN JUAN 29-6 UNIT #239A	5616	SJ 29-6	29N06W02		1		16		490		59		326		43		36		0		247		182		903
SAN JUAN 29-6 UNIT #240A	6078	SJ 29-6	29N06W18		1		7		222		27		148		19		16		0		113		98		921
SAN JUAN 29-6 UNIT #241A	6091	SJ 29-6	29N06W19		1		13		1,120		136		745		66		83		0		596		479		922
SAN JUAN 29-6 UNIT #242A	5554	SJ 29-6	29N06W19		1		15		955		116		635		62		71		0		502		386		820
SAN JUAN 29-6 UNIT #245A	5413	SJ 29-6	29N06W08		1		15		467		57		311		41		35		0		235		173		776
SAN JUAN 29-6 UNIT #72A	6098	SJ 29-6	29N06W22		1		7		68		10		55		16		6		0		33		27		1241
SAN JUAN 29-7 UNIT #176	707	SJ 29-7	29N07W22		1		13		147		15		82		19		9		0		53		39		684
SAN JUAN 29-7 UNIT #187	832	SJ 29-7	29N07W03		1		3		20		2		11		4		1		0		6		5		696
SAN JUAN 29-7 UNIT #188	18165	SJ 29-7	29N07W06		1		5		34		3		19		7		2		0		10		8		748
SAN JUAN 29-7 UNIT #189	8020	SJ 29-7	29N07W14		1		11		192		126		694		122		77		0		494		382		694
SAN JUAN 29-7 UNIT #191	945	SJ 29-7	29N07W22		1		4		28		3		15		5		2		0		9		8		749
SAN JUAN 29-7 UNIT #507S	6070	SJ 29-7	29N07W13		1		16		665		67		369		41		41		0		287		203		894
SAN JUAN 29-7 UNIT #521S	6069	SJ 29-7	29N07W13		1		16		654		66		362		41		40		0		282		200		895

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 3 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

												REVENUE		OPER.						BFIT NET		10% DISC
						LIFE		GROSS GAS		NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		TAXES M$		M$		M$		M$		NUM
SAN JUAN 29-7 UNIT #545S	6068	SJ 29-7	29N07W12		1		19		1,140		115		632		61		70		0		501		360		892
SAN JUAN 29-7 UNIT #563S	1195	SJ 29-7	29N07W24		1		15		856		375		2,059		198		229		0		1,632		1,259		693
SAN JUAN 29-7 UNIT #565S	6074	29-7	29N07W26		1		16		676		444		2,440		267		271		0		1,901		1,348		1332
SAN JUAN 30-5 UNIT #201A	5722	SJ 30-5	30N05W19		1		16		717		122		672		75		75		0		523		387		969
SAN JUAN 30-5 UNIT #202A	1551	SJ 30-5	30N05W06		1		15		2,115		314		1,726		140		192		0		1,394		1,111		947
SAN JUAN 30-5 UNIT #203A	9785	SJ 30-5	30N05W06		1		19		1,832		312		1,716		148		191		0		1,378		1,023		644
SAN JUAN 30-5 UNIT #206A	5721	SJ 30-5	30N05W18		1		14		312		53		293		46		33		0		215		159		967
SAN JUAN 30-5 UNIT #207A	5034	SJ 30-5	30N05W18		1		6		120		20		113		20		13		0		80		69		756
SAN JUAN 30-5 UNIT #208A	5723	SJ 30-5	30N05W19		1		18		1,014		173		950		97		106		0		747		542		968
SAN JUAN 30-5 UNIT #209A	5781	SJ 30-5	30N05W30		1		1		5		1		4		2		0		0		2		2		984
SAN JUAN 30-5 UNIT #210A	5780	SJ 30-5	30N05W30		1		12		233		40		219		37		24		0		157		121		985
SAN JUAN 30-5 UNIT #212A	5782	SJ 30-5	30N05W31		1		10		120		21		113		26		13		0		74		58		987
SAN JUAN 30-5 UNIT #213A	17901	SJ 30-5	30N05W05		1		16		1,081		184		1,013		96		113		0		805		618		643
SAN JUAN 30-5 UNIT #214A	8013	SJ 30-5	30N05W05		1		17		1,026		175		961		96		107		0		758		560		642
SAN JUAN 30-5 UNIT #215A	5702	SJ 30-5	30N05W08		1		16		597		522		2,871		328		319		0		2,224		1,653		993
SAN JUAN 30-5 UNIT #216A	5731	SJ 30-5	30N05W20		1		4		102		17		96		15		11		0		70		64		971
SAN JUAN 30-5 UNIT #217A	5734	SJ 30-5	30N05W21		1		14		556		95		521		62		58		0		402		304		1239
SAN JUAN 30-5 UNIT #218A	5720	SJ 30-5	30N05W17		1		12		349		59		327		44		36		0		247		194		965
SAN JUAN 30-5 UNIT #219A	5108	SJ 30-5	30N05W16		1		12		399		68		374		48		42		0		284		222		730
SAN JUAN 30-5 UNIT #223A	5733	SJ 30-5	30N05W20		1		1		8		1		7		3		1		0		4		4		1238
SAN JUAN 30-5 UNIT #229A	5735	SJ 30-5	30N05W21		1		17		813		139		762		83		85		0		594		433		972
SAN JUAN 30-5 UNIT #230A	5112	SJ 30-5	30N05W32		1		0		0		0		0		0		0		0		0		0		737
SAN JUAN 30-5 UNIT #231A	5139	SJ 30-5	30N05W32		1		3		19		3		17		6		2		0		10		9		736
SAN JUAN 30-5 UNIT #234A	5737	SJ 30-5	30N05W22		1		12		338		58		317		43		35		0		239		188		975
SAN JUAN 30-5 UNIT #237A	5052	SJ 30-5	30N05W16		1		13		619		317		1,740		184		193		0		1,362		1,065		725
SAN JUAN 30-5 UNIT #240A	5738	SJ 30-5	30N05W22		1		14		621		106		582		64		65		0		453		352		974
SAN JUAN 30-5 UNIT #243A	5718	SJ 30-5	30N05W15		1		4		117		20		110		14		12		0		83		76		963
SAN JUAN 30-5 UNIT #260A	9786	SJ 30-5	30N05W09		1		19		2,498		426		2,341		189		260		0		1,892		1,419		646
SAN JUAN 30-5 UNIT #263A	12144	30-5	30N05W13		1		7		476		81		446		42		50		0		354		310		1352
SAN JUAN 30-5 UNIT #264A	5710	SJ 30-5	30N05W09		1		21		1,834		313		1,718		152		191		0		1,375		989		956
SAN JUAN 30-5 UNIT #265A	5711	SJ 30-5	30N05W10		1		19		3,189		544		2,988		231		332		0		2,425		1,839		957
SAN JUAN 30-5 UNIT #266A	8017	SJ 30-5	30N05W10		1		19		2,634		449		2,468		196		274		0		1,998		1,517		645
SAN JUAN 30-6 UNIT #400S	6042	SJ 30-6	30N07W14		1		15		417		21		114		16		13		0		86		63		845
SAN JUAN 30-6 UNIT #401S	6041	SJ 30-6	30N07W13		1		16		513		26		141		18		16		0		107		79		876
SAN JUAN 30-6 UNIT #404S	5516	SJ 30-6	30N07W23		1		12		359		18		99		13		11		0		74		58		778
SAN JUAN 30-6 UNIT #405S	5436	SJ 30-6	30N06W09		1		14		437		22		120		15		13		0		91		69		779
SAN JUAN 30-6 UNIT #408S	19395	SJ 30-6	30N06W16		1		18		802		40		220		25		24		0		171		123		685
SAN JUAN 30-6 UNIT #410S	5539	SJ 30-6	30N06W26		1		16		759		38		208		23		23		0		162		116		864
SAN JUAN 30-6 UNIT #411S	1258	SJ 30-6	30N07W27		1		6		131		7		36		5		4		0		26		23		648
SAN JUAN 30-6 UNIT #412S	996	SJ 30-6	30N07W24		1		13		498		25		137		16		15		0		105		82		781
SAN JUAN 30-6 UNIT #413S	5508	SJ 30-6	30N07W23		1		17		555		28		152		19		17		0		116		84		782
SAN JUAN 30-6 UNIT #414S	1260	SJ 30-6	30N07W35		1		8		75		4		21		6		2		0		12		10		651
SAN JUAN 30-6 UNIT #415S	5077	SJ 30-6	30N07W26		1		16		561		28		154		19		17		0		118		86		761

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 4 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

												REVENUE		OPER.						BFIT NET		10% DISC
						LIFE		GROSS GAS		NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		TAXES M$		M$		M$		M$		NUM
SAN JUAN 30-6 UNIT #419S	6028	SJ 30-6	30N07W11		1		11		186		9		51		10		6		0		36		27		842
SAN JUAN 30-6 UNIT #420S	6039	SJ 30-6	30N07W12		1		16		733		37		201		22		22		0		157		112		844
SAN JUAN 30-6 UNIT #422S	1261	SJ 30-6	30N07W27		1		16		497		25		136		18		15		0		103		76		690
SAN JUAN 30-6 UNIT #424S	1723	30-6	30N07W33		1		16		665		33		182		21		20		0		141		100		1272
SAN JUAN 30-6 UNIT #425S	1322	SJ 30-6	30N07W33		1		14		731		36		200		21		22		0		157		121		652
SAN JUAN 30-6 UNIT #426S	1271	SJ 30-6	30N07W34		1		9		249		12		68		10		8		0		51		42		650
SAN JUAN 30-6 UNIT #427S	1203	SJ 30-6	30N07W35		1		1		2		0		1		0		0		0		0		0		687
SAN JUAN 30-6 UNIT #430S	5447		30N06W08		1		12		356		18		27		0		0		0		27		20		1260
SAN JUAN 30-6 UNIT #431S	5450	SJ 30-6	30N06W10		1		15		387		19		106		15		12		0		79		59		1221
SAN JUAN 30-6 UNIT #432S	5448	SJ 30-6	30N06W10		1		7		148		7		41		7		5		0		30		25		1220
SAN JUAN 30-6 UNIT #433S	11700	30-6	30N06W11		1		16		733		37		201		22		22		0		157		112		1266
SAN JUAN 30-6 UNIT #434S	5469	SJ 30-6	30N06W12		1		16		966		48		265		26		29		0		209		159		1222
SAN JUAN 30-6 UNIT #435S	5484	SJ 30-6	30N06W13		1		14		321		16		88		13		10		0		65		48		789
SAN JUAN 30-6 UNIT #436S	5525	SJ 30-6	30N06W15		1		16		746		37		205		22		23		0		159		114		848
SAN JUAN 30-6 UNIT #437S	5504	SJ 30-6	30N06W11		1		18		833		42		228		25		25		0		178		129		790
SAN JUAN 30-6 UNIT #438S	5468	SJ 30-6	30N06W12		1		12		389		19		107		14		12		0		81		63		791
SAN JUAN 30-6 UNIT #442S	5485	SJ 30-6	30N06W14		1		12		372		19		102		13		11		0		77		61		1223
SAN JUAN 30-6 UNIT #443S	1206	SJ 30-6	30N06W36		1		15		429		21		118		16		13		0		89		65		649
SAN JUAN 30-6 UNIT #444S	19402	SJ 30-6	30N06W36		1		0		0		0		0		0		0		0		0		0		647
SAN JUAN 30-6 UNIT #445S	5479	SJ 30-6	30N06W13		1		16		493		25		135		18		15		0		103		75		794
SAN JUAN 30-6 UNIT #446S	5502	SJ 30-6	30N06W35		1		14		708		35		194		21		22		0		152		117		795
SAN JUAN 30-6 UNIT #450S	5437	SJ 30-6	30N06W07		1		10		141		7		39		8		4		0		26		20		796
SAN JUAN 30-6 UNIT #451S	5430	SJ 30-6	30N06W07		1		5		141		7		39		5		4		0		29		26		763
SAN JUAN 30-6 UNIT #452S	5438	SJ 30-6	30N06W08		1		16		510		25		140		18		16		0		106		78		797
SAN JUAN 30-6 UNIT #454S	5529	SJ 30-6	30N06W17		1		16		759		38		208		23		23		0		162		116		850
SAN JUAN 30-6 UNIT #455S	5530	SJ 30-6	30N06W18		1		16		759		38		208		23		23		0		162		116		853
SAN JUAN 30-6 UNIT #457S	5257	SJ 30-6	30N06W19		1		21		954		48		262		29		29		0		204		141		764
SAN JUAN 30-6 UNIT #460S	5487	SJ 30-6	30N06W20		1		17		706		35		194		22		22		0		150		109		798
SAN JUAN 30-6 UNIT #461S	5503	SJ 30-6	30N07W11		1		15		482		24		132		17		15		0		100		74		799
SAN JUAN 30-6 UNIT #462S	6040	SJ 30-6	30N07W12		1		16		642		32		176		20		20		0		136		97		843
SAN JUAN 30-6 UNIT #463S	5505	SJ 30-6	30N07W13		1		3		37		2		10		3		1		0		7		6		800
SAN JUAN 30-6 UNIT #468S	5117	SJ 30-6	30N07W36		1		5		67		3		18		4		2		0		12		11		759
SAN JUAN 30-6 UNIT #471S	5488	SJ 30-6	30N06W21		1		9		357		18		98		12		11		0		76		63		803
SAN JUAN 30-6 UNIT #473S	5535	SJ 30-6	30N06W22		1		16		746		37		205		22		23		0		159		114		858
SAN JUAN 30-6 UNIT #475S	5493	SJ 30-6	30N06W27		1		18		647		32		177		22		20		0		136		96		804
SAN JUAN 30-6 UNIT #476S	5541	SJ 30-6	30N06W28		1		18		808		40		222		24		25		0		173		125		863
SAN JUAN 30-6 UNIT #477S	5130	SJ 30-6	30N06W28		1		17		1,508		75		414		36		46		0		332		253		760
SAN JUAN 30-6 UNIT #478S	5137	SJ 30-6	30N06W29		1		7		221		11		61		8		7		0		46		40		746
SAN JUAN 30-6 UNIT #479S	5542	SJ 30-6	30N06W29		1		16		759		38		208		23		23		0		162		116		869
SAN JUAN 30-6 UNIT #481S	5431	SJ 30-6	30N06W30		1		14		603		30		165		19		18		0		128		99		765
SAN JUAN 30-6 UNIT #483S	5500	SJ 30-6	30N06W34		1		18		1,000		50		274		28		30		0		216		157		806
SAN JUAN 30-6 UNIT #484S	5499	SJ 30-6	30N06W34		1		19		1,040		52		285		29		32		0		224		162		807
SAN JUAN 30-6 UNIT #485S	5116	SJ 30-6	30N07W36		1		10		197		10		54		9		6		0		39		31		996

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 5 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

												REVENUE		OPER.						BFIT NET		10% DISC
						LIFE		GROSS GAS		NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		TAXES M$		M$		M$		M$		NUM
SAN JUAN 30-6 UNIT #486S	5143	SJ 30-6	30N06W23		1		8		152		8		42		7		5		0		30		25		766
SAN JUAN 30-6 UNIT #488S	5490	SJ 30-6	30N06W24		1		11		177		9		49		9		5		0		34		26		808
SAN JUAN 30-6 UNIT #489S	5489	SJ 30-6	30N06W24		1		14		343		17		94		14		10		0		70		52		809
SAN JUAN 30-6 UNIT #490S	5492	SJ 30-6	30N06W25		1		13		305		15		84		13		9		0		61		46		810
SAN JUAN 30-6 UNIT #491S	5491	SJ 30-6	30N06W25		1		14		318		16		87		13		10		0		64		48		811
SAN JUAN 30-6 UNIT #493S	5131	SJ 30-6	30N06W32		1		1		14		1		4		1		0		0		2		2		744
SAN JUAN 30-6 UNIT #495S	5497	SJ 30-6	30N06W33		1		17		800		40		220		24		24		0		172		122		813
SAN JUAN 30-6 UNIT #496S	5501	SJ 30-6	30N06W35		1		10		401		20		110		13		12		0		85		69		814
SAN JUAN 30-6 UNIT #497S	1778	30-6	30N07W29		1		16		665		33		182		21		20		0		141		100		1277
SAN JUAN 30-6 UNIT COM #467S	6049	NEBU	30N07W22		1		16		759		22		119		13		13		0		93		66		822
SAN JUAN 31-6 UNIT #201A	1813	SJ 31-6	30N06W01		1		21		1,064		114		626		67		70		0		490		343		706
SAN JUAN 31-6 UNIT #202A	1812	SJ 31-6	30N06W01		1		3		84		9		50		8		6		0		37		34		1211
SAN JUAN 31-6 UNIT #203A	1819	SJ 31-6	30N06W03		1		18		687		74		404		49		45		0		310		220		718
SAN JUAN 31-6 UNIT #204A	1817	SJ 31-6	30N06W03		1		13		516		55		303		36		34		0		233		181		707
SAN JUAN 31-6 UNIT #205A	1821	SJ 31-6	30N06W04		1		1		3		0		2		1		0		0		1		1		712
SAN JUAN 31-6 UNIT #206A	1820	SJ 31-6	30N06W04		1		9		139		15		82		16		9		0		57		46		708
SAN JUAN 31-6 UNIT #210A	1816	SJ 31-6	30N06W02		1		16		673		72		396		45		44		0		307		230		719
SAN JUAN 31-6 UNIT #211A	1815	SJ 31-6	30N06W02		1		16		1,133		121		667		64		74		0		528		400		710
SAN JUAN 31-6 UNIT #212A	5613	SJ 31-6	30N06W05		1		15		424		45		249		35		28		0		187		138		935
SAN JUAN 31-6 UNIT #213A	5612	SJ 31-6	30N06W05		1		15		459		49		270		37		30		0		203		150		936
SAN JUAN 31-6 UNIT #214A	1360	SJ 31-6	31N06W36		1		16		742		79		437		49		49		0		339		253		702
SAN JUAN 31-6 UNIT #215A	1361	SJ 31-6	31N06W36		1		11		653		70		384		39		43		0		302		246		653
SAN JUAN 31-6 UNIT #217A	1363	SJ 31-6	31N06W35		1		13		404		43		238		32		26		0		180		138		703
SAN JUAN 31-6 UNIT #223A	1377	SJ 31-6	31N06W32		1		7		119		13		70		14		8		0		49		41		654
SAN JUAN 31-6 UNIT #229A	1386	SJ 31-6	31N06W28		1		20		1,212		130		713		71		79		0		563		404		715
SAN JUAN 31-6 UNIT #230A	1383	SJ 31-6	31N06W27		1		20		1,353		145		796		77		88		0		630		453		705
SAN JUAN 31-6 UNIT #231A	1384	SJ31-6	31N06W27		1		5		100		11		59		10		7		0		42		38		704
SAN JUAN 31-6 UNIT #234A	1385	SJ 31-6	31N06W29		1		13		462		50		272		34		30		0		208		160		688
SAN JUAN 32-7 UNIT #203A	5109	SJ 32-7	32N07W22		1		16		1,182		197		1,083		102		120		0		860		659		664
SAN JUAN 32-7 UNIT #204A	4126	SJ 32-7	32N07W36		1		10		128		21		117		27		13		0		78		61		1176
SAN JUAN 32-7 UNIT #206A	719	SJ 32-7	32N07W27		1		20		1,615		269		1,479		136		164		0		1,179		855		722
SAN JUAN 32-7 UNIT #207A	5812	SJ 32-7	32N07W27		1		13		827		138		758		75		84		0		598		475		1174
SAN JUAN 32-7 UNIT #208A	970	SJ 32-7	32N07W34		1		15		826		317		1,741		181		193		0		1,366		1,052		670
SAN JUAN 32-7 UNIT #209A	1207	SJ 32-7	32N07W35		1		18		1,422		237		1,302		120		145		0		1,037		773		672
SAN JUAN 32-7 UNIT #210A	4125	SJ 32-7	32N07W36		1		20		1,112		185		1,018		105		113		0		800		571		1177
SAN JUAN 32-7 UNIT #211A	648	SJ 32-7	32N07W35		1		20		1,391		232		1,274		123		142		0		1,010		725		721
SAN JUAN 32-7 UNIT #213A	12143	32-7	31N07W18		1		19		1,609		169		931		84		103		0		743		528		1351
SAN JUAN 32-7 UNIT #214A	5804	SJ 32-7	32N07W34		1		5		194		74		409		51		45		0		312		280		1178
SAN JUAN 32-7 UNIT #215A	1210	SJ 32-7	32N07W32		1		16		1,395		232		1,278		116		142		0		1,020		779		671
SAN JUAN 32-7 UNIT #216A	6120	SJ 32-7	31N07W04		1		11		414		69		379		46		42		0		291		236		1242
SAN JUAN 32-7 UNIT #217A	655	SJ 32-7	31N07W04		1		6		307		51		281		30		31		0		219		195		716
SAN JUAN 32-7 UNIT #218A	1208	SJ 32-7	31N07W07		1		17		1,565		261		1,434		127		159		0		1,148		878		662
SAN JUAN 32-7 UNIT #219A	6122	SJ 32-7	31N07W05		1		16		1,657		276		1,518		130		169		0		1,219		953		1243

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 6 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

												REVENUE		OPER.						BFIT NET		10% DISC
						LIFE		GROSS GAS		NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		TAXES M$		M$		M$		M$		NUM
SAN JUAN 32-7 UNIT #221A	694	SJ 32-7	31N07W08		1		11		283		47		259		38		29		0		192		152		711
SAN JUAN 32-7 UNIT #222A	6008	SJ 32-7	32N07W20		1		17		1,158		175		960		92		107		0		761		552		1180
SAN JUAN 32-7 UNIT #224A	4795	SJ 32-7	32N07W21		1		11		885		116		636		56		71		0		509		422		659
SAN JUAN 32-7 UNIT #228A	12142	32-7	31N07W07		1		19		1,609		137		753		68		84		0		601		427		1350
SAN JUAN 32-7 UNIT #229A	4893	SJ 32-7	31N07W09		1		7		212		35		194		26		22		0		147		127		714
SAN JUAN 32-7 UNIT #230A	5798	SJ 32-7	31N07W17		1		0		0		0		0		0		0		0		0		0		1171
SAN JUAN 32-7 UNIT #231A	1323	SJ 32-7	31N07W17		1		8		187		31		171		27		19		0		125		105		663
SAN JUAN 32-7 UNIT #232A	4127	SJ 32-7	31N07W08		1		15		1,016		169		930		90		103		0		737		570		709
SAN JUAN 32-7 UNIT #234A	1229	SJ 32-7	32N07W32		1		8		185		31		169		26		19		0		124		104		661
SAN JUAN 32-7 UNIT #235A	5811	SJ 32-7	32N07W29		1		19		1,552		259		1,421		130		158		0		1,133		806		1175
SAN JUAN 32-7 UNIT #238A	1211	SJ 32-7	32N07W29		1		19		3,143		524		2,878		227		320		0		2,332		1,768		674
SAN JUAN 32-7 UNIT #242A	1212	SJ 32-7	32N07W33		1		13		853		142		781		77		87		0		617		491		669
SAN JUAN 32-7 UNIT #246	740	SJ 32-7	32N07W18		1		19		1,700		283		1,557		139		173		0		1,244		883		1172
SAN JUAN 32-8 UNIT #202A	1495	SJ 32-8	32N08W27		1		18		1,930		220		1,211		103		135		0		973		741		698
SAN JUAN 32-8 UNIT #203A	1213	SJ 32-8	32N08W33		1		7		332		38		208		24		23		0		162		140		686
SAN JUAN 32-8 UNIT #204A	5142	SJ 32-8	32N08W34		1		23		3,103		354		1,946		158		216		0		1,572		1,135		732
SAN JUAN 32-8 UNIT #205A	1504	SJ 32-8	32N08W34		1		16		1,868		213		1,172		98		130		0		943		737		680
SAN JUAN 32-8 UNIT #208A	4275	SJ 32-8	32N08W29		1		19		3,313		378		2,078		162		231		0		1,685		1,277		726
SAN JUAN 32-8 UNIT #213A	6003	SJ 32-8	32N08W22		1		20		1,830		209		1,148		102		128		0		919		647		1154
SAN JUAN 32-8 UNIT #218A	1514	SJ 32-8	32N08W35		1		21		2,457		280		1,541		129		171		0		1,241		910		691
SAN JUAN 32-8 UNIT #219A	1529	SJ 32-8	32N08W35		1		19		1,573		180		987		90		110		0		787		579		678
SAN JUAN 32-8 UNIT #220A	5602	SJ 32-8	31N08W24		1		15		874		100		549		56		61		0		432		332		1232
SAN JUAN 32-8 UNIT #221A	5583	SJ 32-8	31N08W09		1		6		283		32		178		20		20		0		138		122		1140
SAN JUAN 32-8 UNIT #222A	5584	SJ 32-8	31N08W09		1		22		2,024		231		1,270		112		141		0		1,016		725		1139
SAN JUAN 32-8 UNIT #223A	5588	SJ 32-8	31N08W10		1		16		2,048		234		1,285		105		143		0		1,036		815		1142
SAN JUAN 32-8 UNIT #224A	5589	SJ 32-8	31N08W10		1		14		1,354		155		849		74		94		0		681		542		1141
SAN JUAN 32-8 UNIT #225A	5592	SJ 32-8	31N08W15		1		15		922		105		578		58		64		0		456		351		1227
SAN JUAN 32-8 UNIT #226A	5593	SJ 32-8	31N08W15		1		15		882		101		554		56		62		0		436		335		1228
SAN JUAN 32-8 UNIT #227A	5594	SJ 32-8	31N08W16		1		14		663		76		416		46		46		0		324		250		1148
SAN JUAN 32-8 UNIT #228A	5595	SJ 32-8	31N08W16		1		12		727		83		456		46		51		0		359		288		1147
SAN JUAN 32-8 UNIT #229A	1204	SJ 32-8	32N08W20		1		20		2,178		249		1,367		116		152		0		1,099		815		660
SAN JUAN 32-8 UNIT #230A	1544	SJ 32-8	32N08W28		1		23		2,387		272		1,497		128		166		0		1,203		856		697
SAN JUAN 32-8 UNIT #231A	1541	SJ 32-8	32N08W28		1		22		3,382		386		2,122		169		236		0		1,717		1,255		677
SAN JUAN 32-8 UNIT #232A	972	SJ 32-8	32N08W29		1		17		1,670		191		1,047		92		116		0		839		640		665
SAN JUAN 32-8 UNIT #233A	5675	SJ 32-8	32N08W30		1		19		1,645		188		1,032		92		115		0		825		613		1237
SAN JUAN 32-8 UNIT #234A	4904	SJ 32-8	31N08W21		1		12		555		63		348		38		39		0		271		218		1150
SAN JUAN 32-8 UNIT #235A	5597	SJ 32-8	31N08W21		1		9		360		41		226		27		25		0		174		146		1149
SAN JUAN 32-8 UNIT #236A	5599	SJ 32-8	31N08W22		1		17		736		84		462		53		51		0		357		260		1229
SAN JUAN 32-8 UNIT #237A	5601	SJ 32-8	31N08W23		1		16		648		74		406		47		45		0		314		235		1231
SAN JUAN 32-8 UNIT #238A	5600	SJ 32-8	31N08W23		1		13		729		83		457		47		51		0		359		285		1230
SAN JUAN 32-8 UNIT #239A	5670	SJ 32-8	32N08W30		1		9		214		24		134		20		15		0		99		82		1161
SAN JUAN 32-8 UNIT #240A	5047	SJ 32-8	31N08W03		1		15		1,352		154		848		76		94		0		678		531		997
SAN JUAN 32-8 UNIT #241A	5558	SJ 32-8	31N08W04		1		14		1,707		195		1,071		89		119		0		863		693		1224

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 7 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

												REVENUE		OPER.						BFIT NET		10% DISC
						LIFE		GROSS GAS		NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		TAXES M$		M$		M$		M$		NUM
SAN JUAN 32-8 UNIT #242A	5557	SJ 32-8	31N08W04		1		11		338		39		212		29		24		0		160		126		1138
SAN JUAN 32-8 UNIT #243A	1884	SJ 32-8	31N08W11		1		16		1,137		130		713		68		79		0		566		434		679
SAN JUAN 32-8 UNIT #244A	5591	SJ 32-8	31N08W14		1		15		923		105		579		58		64		0		457		351		1226
SAN JUAN 32-8 UNIT #245A	5590	SJ 32-8	31N08W14		1		13		978		112		613		57		68		0		488		391		1225
SAN JUAN 32-8 UNIT #247A	5999	SJ 32-8	32N08W19		1		15		1,077		123		676		65		75		0		536		413		1199
SAN JUAN 32-8 UNIT #248A	1885	SJ 32-8	31N08W11		1		12		498		57		312		36		35		0		241		191		676
SAN JUAN 32-8 UNIT #249R	11696	32-8	31N08W03		1		20		1,830		209		1,148		102		128		0		919		647		1265
SAN JUAN 32-8 UNIT #250A	5048	SJ 32-8	32N08W33		1		15		2,256		258		1,415		114		157		0		1,144		908		723
SAN JUAN 32-8 UNIT #253A	1887	SJ 32-8	32N08W27		1		20		1,850		211		1,161		102		129		0		929		683		699
SAN JUAN 32-8 UNIT #254A	12149	32-8	32N08W23		1		20		1,965		224		1,233		108		137		0		988		695		1355
SAN JUAN 32-8 UNIT #255A	1867	SJ 32-8	32N08W24		1		17		1,560		178		979		87		109		0		783		598		701
SAN JUAN 32-8 UNIT #256A	1888	SJ 32-8	32N08W25		1		17		1,659		189		1,040		91		116		0		834		634		700
SAN JUAN 32-8 UNIT #257A	6000	SJ 32-8	32N08W19		1		4		160		18		101		12		11		0		78		71		1200
SAN JUAN 32-9 UNIT #201S	5935	SJ 32-9	31N09W02		1		12		224		5		27		5		3		0		19		15		1076
SAN JUAN 32-9 UNIT #202S	5939	SJ 32-9	31N09W02		1		19		1,061		23		129		13		14		0		101		73		1075
SAN JUAN 32-9 UNIT #217S	5994	32-9	32N09W16		1		7		476		9		50		5		6		0		40		35		1322
SAN JUAN 32-9 UNIT #226S	5970	SJ 32-9	32N09W32		1		7		500		11		61		6		7		0		48		42		1119
SAN JUAN 32-9 UNIT #228S	5978	SJ 32-9	32N09W36		1		15		440		10		53		7		6		0		40		30		1127
SAN JUAN 32-9 UNIT #235S	5979	SJ 32-9	32N09W36		1		15		466		10		57		7		6		0		43		32		1126
SAN JUAN 32-9 UNIT #250S	5945	SJ 32-9	31N09W04		1		14		1,396		31		169		14		19		0		136		109		1240
SAN JUAN 32-9 UNIT #253S	5952	SJ 32-9	31N09W05		1		7		476		11		58		5		6		0		46		40		1079
SAN JUAN 32-9 UNIT #254S	5953	SJ 32-9	31N09W06		1		10		395		9		48		6		5		0		37		30		1082
SAN JUAN 32-9 UNIT #257S	5957	SJ 32-9	31N09W08		1		10		128		3		16		3		2		0		10		8		1083
SAN JUAN 32-9 UNIT #261S	5961	SJ 32-9	31N09W10		1		16		1,209		27		147		14		16		0		117		89		1087
SAN JUAN 32-9 UNIT #270S	5991	SJ 32-9	32N09W18		1		6		409		9		50		5		6		0		39		34		1103
SAN JUAN 32-9 UNIT #271S	1351	SJ 32-9	32N09W18		1		13		1,051		23		128		12		14		0		102		82		733
SAN JUAN 32-9 UNIT #273S	5980	SJ 32-9	32N09W19		1		6		430		9		52		5		6		0		41		36		1104
SAN JUAN 32-9 UNIT #274S	5962	SJ 32-9	32N09W28		1		13		1,040		23		126		12		14		0		101		80		1113
SAN JUAN 32-9 UNIT #275S	5965	SJ 32-9	32N09W29		1		13		824		18		100		10		11		0		79		63		1114
SAN JUAN 32-9 UNIT #276S	5964	SJ 32-9	32N09W27		1		13		363		8		44		6		5		0		33		25		1112
SAN JUAN 32-9 UNIT #277S	5966	SJ 32-9	32N09W30		1		22		2,252		50		273		23		30		0		220		157		1115
SAN JUAN 32-9 UNIT #279S	5968	SJ 32-9	32N09W31		1		7		476		11		58		5		6		0		46		40		1116
SAN JUAN 32-9 UNIT #281S	5974	SJ 32-9	32N09W32		1		7		452		10		55		5		6		0		44		38		1118
SAN JUAN 32-9 UNIT #282S	5975	SJ 32-9	32N09W33		1		18		1,374		30		167		15		19		0		133		98		1121
SAN JUAN 32-9 UNIT #283S	5976	SJ 32-9	32N09W33		1		12		221		5		27		5		3		0		19		15		1120
SAN JUAN 32-9 UNIT #284S	1357	SJ 32-9	32N10W13		1		9		800		18		97		9		11		0		78		66		998
SAN JUAN 32-9 UNIT #286S	5914	SJ 32-9	32N10W14		1		6		430		9		52		5		6		0		41		36		1098
SAN JUAN 32-9 UNIT #287S	5915	SJ 32-9	32N10W14		1		7		452		10		55		5		6		0		44		38		1097
SAN JUAN 32-9 UNIT #289S	5918	SJ 32-9	32N10W23		1		6		430		9		52		5		6		0		41		36		1105
SAN JUAN 32-9 UNIT #291S	5402	SJ 32-9	32N10W24		1		8		494		11		60		6		7		0		47		41		728
SAN JUAN 32-9 UNIT #293S	5927	SJ 32-9	32N10W25		1		15		959		21		116		11		13		0		92		71		1108
SAN JUAN 32-9 UNIT #294S	5930	SJ 32-9	32N10W26		1		1		5		0		1		0		0		0		0		0		1111
SAN JUAN 32-9 UNIT #295S	5931	SJ 32-9	32N10W26		1		17		1,612		36		196		17		22		0		157		120		1110

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 8 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

										REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
					LIFE	GROSS GAS		NET GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS	YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$		NUM
SAN JUAN 32-9 UNIT #300S	5856	SJ 32-9	32N10W11	1	3		84		2		10		2		1		0		8		7		1092
SAN JUAN 32-9 UNIT #301S	5857	SJ 32-9	32N10W12	1	7		406		9		49		5		5		0		39		34		1095
SAN JUAN 32-9 UNIT #302S	747	32-9	32N09W09	1	7		476		11		58		5		6		0		46		40		1263
STATE COM FC #20A	6006	NON-UNIT	30N08W02	1	9		141		3		14		3		2		0		10		8		1069
NE BLANCO UNIT #306 POW	4897	NEBU	31N07W26	1	10		500		4		21		2		2		0		17		11		727
SAN JUAN 29-6 UNIT #44A	5623	SJ 29-6	29N06W26	1	21		900		102		562		59		62		0		440		233		1234
SAN JUAN 29-6 UNIT #45A	5637	SJ 29-6	29N06W27	1	21		900		109		598		63		67		0		469		244		1235
SAN JUAN 29-6 UNIT #63A	5638	SJ 29-6	29N06W30	1	21		900		109		598		63		67		0		469		244		1236
TOTAL PROVED DEVELOPED: 160- Acre New Mexico				316			254,554		23,810		130,790		12,970		14,536		0		103,284		77,517
BARNES GAS COM F #1	14369	NON-UNIT	32N11W26	1	9		53		3		16		7		2		0		7		5		474
BLANCO #201	13592	NON-UNIT	31N08W35	1	22		1,044		154		847		94		94		0		659		452		413
BLANCO #202	13651	NON-UNIT	31N08W26	1	30		2,631		388		2,134		194		237		0		1,703		1,091		509
BLANCO #203	13649	NON-UNIT	31N08W35	1	15		647		96		525		61		58		0		406		306		498
BLANCO #204R	14451	NON-UNIT	31N08W26	1	20		841		124		682		79		76		0		527		369		591
BLANCO #330	14219	NON-UNIT	31N08W05	1	27		3,038		222		1,219		105		136		0		979		662		547
BONDS COM #100 (APO)	14220	NON-UNIT	32N10W15	1	31		5,110		254		1,397		107		155		0		1,135		754		455
DECKER GAS COM A #1	14370	NON-UNIT	32N10W17	1	19		1,688		123		678		61		75		0		542		401		477
EAGLE #750 (BPO)	14375	NON-UNIT	32N09W16	1	24		1,419		28		154		15		17		0		122		82		495
FC BARNES #1	14371	NON-UNIT	32N11W15	1	34		616		11		59		15		7		0		38		20		418
FC FEE COM #2	14277	NON-UNIT	32N11W30	1	8		48		1		5		3		1		0		1		1		497
FC STATE COM #19	14276	NON-UNIT	30N09W36	1	22		207		4		22		6		2		0		14		8		541
FC STATE COM #20	12651	NON-UNIT	30N08W02	1	19		1,635		29		161		15		18		0		128		94		466
FEDERAL G #4 COM.PI	4755	NON-UNIT	31N07W10	1	21		977		41		224		25		25		0		174		120		467
GRASSY CANYON UNIT #3	4762	SJ 32-7	32N07W31	1	25		2,195		142		779		70		87		0		622		423		580
HEIZER #100	14203	NON-UNIT	32N10W15	1	18		2,376		1		6		1		1		0		5		4		378
HUBBARD GAS COM A #1	14250	NON-UNIT	32N11W30	1	16		124		4		24		11		3		0		10		7		496
HUERFANO UNIT #12	14215	HUERFANO	26N10W04	1	0		0		0		0		0		0		0		0		0		352
HUERFANO UNIT #138	17003	HUERFANO	26N09W22	1	6		43		6		33		12		4		0		17		14		350
HUERFANO UNIT #14R	14218	HUERFANO	26N10W05	1	22		296		42		230		49		26		0		155		95		362
HUERFANO UNIT #18 COM	16974	HUERFANO	27N10W32	1	0		0		0		0		0		0		0		0		0		355
HUERFANO UNIT #182	17019	HUERFANO	26N09W28	1	0		0		0		0		0		0		0		0		0		360
HUERFANO UNIT #19	14221	HUERFANO	26N10W05	1	2		9		1		7		3		1		0		3		3		354
HUERFANO UNIT #22	14216	HUERFANO	27N10W33	1	29		439		62		341		67		38		0		236		129		356
HUERFANO UNIT #223	14004	HUERFANO	26N10W04	1	19		271		38		211		43		23		0		144		94		363
HUERFANO UNIT #231	17004	HUERFANO	26N09W06	1	23		440		62		342		58		38		0		246		153		364
HUERFANO UNIT #237	17005	HUERFANO	26N09W17	1	23		341		48		265		54		29		0		182		108		365
HUERFANO UNIT #24	14222	HUERFANO	27N10W29	1	10		120		17		93		22		10		0		61		47		357
HUERFANO UNIT #255	17006	HUERFANO	27N09W31	1	40		1,190		168		924		122		103		0		699		352		369
HUERFANO UNIT #257	17007	HUERFANO	27N10W36	1	39		939		133		729		108		81		0		541		271		367
HUERFANO UNIT #259	13989	HUERFANO	26N10W06	1	5		25		4		19		9		2		0		9		7		368
HUERFANO UNIT #282	14512	HUERFANO	27N10W31	1	18		341		48		265		45		29		0		191		130		372
HUERFANO UNIT #286	14202	HUERFANO	27N10W35	1	40		918		130		713		109		79		0		525		251		374
HUERFANO UNIT #46	13951	HUERFANO	26N09W23	1	23		475		67		369		60		41		0		268		168		349

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 9 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

										REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
					LIFE	GROSS GAS		NET GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS	YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$		NUM
HUERFANO UNIT #501	17009	HUERFANO	26N09W20	1	28		674		95		524		77		58		0		389		228		599
HUERFANO UNIT #502	17010	HUERFANO	26N09W21	1	0		0		0		0		0		0		0		0		0		602
HUERFANO UNIT #503	13987	HUERFANO	26N09W21	1	5		40		6		31		10		3		0		18		16		601
HUERFANO UNIT #504	17011	HUERFANO	26N09W22	1	3		19		3		15		5		2		0		8		7		608
HUERFANO UNIT #505	17012	HUERFANO	26N09W30	1	40		924		131		718		109		80		0		529		259		600
HUERFANO UNIT #507	17013	HUERFANO	26N09W27	1	22		393		56		305		55		34		0		217		134		604
HUERFANO UNIT #508	13985	HUERFANO	26N09W26	1	40		974		138		756		111		84		0		561		274		605
HUERFANO UNIT #509	13999	HUERFANO	27N10W30	1	18		252		36		196		41		22		0		133		86		607
HUERFANO UNIT #518	17014	HUERFANO	26N09W16	1	30		473		67		367		70		41		0		256		138		609
HUERFANO UNIT #520	17015	HUERFANO	26N09W17	1	24		368		52		286		56		32		0		198		118		610
HUERFANO UNIT #521	17016	HUERFANO	27N10W35	1	40		1,265		179		983		126		109		0		748		361		612
HUERFANO UNIT #522	17017	HUERFANO	27N09W31	1	36		1,131		160		879		113		98		0		668		359		611
HUERFANO UNIT #523	14008	HUERFANO	26N09W23	1	23		435		61		338		57		38		0		243		151		613
HUERFANO UNIT #528	12464	HUERFANO	26N10W06	1	26		363		51		282		58		31		0		192		110		620
HUERFANO UNIT #549	13950	HUERFANO	27N10W33	1	15		205		29		159		34		18		0		108		75		598
HUERFANO UNIT #55	14223	HUERFANO	26N09W27	1	19		275		39		214		44		24		0		146		93		347
HUERFANO UNIT #550	17018	HUERFANO	27N10W29	1	23		257		36		199		49		22		0		128		75		606
HUERFANO UNIT #59	13952	HUERFANO	26N09W26	1	10		69		10		53		18		6		0		29		22		348
HUERFANO UNIT #6	14377	HUERFANO	27N10W31	1	15		129		18		101		29		11		0		60		40		359
HUERFANO UNIT #600	706	HUERFANO	27N10W32	1	6		66		9		52		13		6		0		32		27		673
HUERFANO UNIT #70	14224	HUERFANO	26N10W08	1	8		78		11		61		17		7		0		37		29		351
HUERFANO UNIT #74	13988	HUERFANO	27N10W19	1	2		11		2		9		4		1		0		3		3		358
HUERFANO UNIT COM #118	4765	HUERFANO	27N10W30	1	9		106		8		41		10		5		0		27		21		366
HUERFANO UNIT COM #551	4766	HUERFANO	26N09W16	1	10		124		7		36		8		4		0		24		18		626
JACQUEZ #331	14343	NON-UNIT	31N08W06	1	31		3,288		251		1,379		111		153		0		1,115		715		530
KEYS GAS COM G #1R	14212	NON-UNIT	32N10W27	1	19		915		1		7		1		1		0		6		4		375
MOORE, WAYNE COM #2	14442	NON-UNIT	31N09W16	1	25		1,099		41		224		26		25		0		174		113		578
NE BLANCO UNIT #400R	14350	NEBU	31N06W07	1	24		2,646		21		113		9		13		0		92		64		550
NE BLANCO UNIT #401	14278	NEBU	30N07W09	1	15		675		5		29		3		3		0		23		17		34
NE BLANCO UNIT #402	13561	NEBU	30N07W05	1	25		2,142		17		92		7		10		0		74		51		376
NE BLANCO UNIT #403R	14279	NEBU	30N07W09	1	28		2,185		17		93		8		10		0		75		49		189
NE BLANCO UNIT #404R	14280	NEBU	31N07W34	1	16		1,534		12		66		5		7		0		53		41		561
NE BLANCO UNIT #406	13560	NEBU	31N07W22	1	24		1,864		14		80		7		9		0		64		44		377
NE BLANCO UNIT #407	14281	NEBU	30N07W21	1	28		1,562		12		67		6		7		0		53		34		36
NE BLANCO UNIT #408	13562	NEBU	31N07W20	1	18		905		7		39		4		4		0		31		22		406
NE BLANCO UNIT #409	14282	NEBU	30N07W10	1	16		933		7		40		4		4		0		32		24		35
NE BLANCO UNIT #410	14283	NEBU	31N07W09	1	18		1,679		13		72		6		8		0		58		43		421
NE BLANCO UNIT #411	14284	NEBU	30N07W10	1	26		1,566		12		67		6		7		0		54		35		78
NE BLANCO UNIT #412	14285	NEBU	31N07W29	1	15		1,052		8		45		4		5		0		36		28		408
NE BLANCO UNIT #413R	14286	NEBU	30N07W20	1	19		996		8		43		4		5		0		34		24		257
NE BLANCO UNIT #414	13569	NEBU	31N07W30	1	15		857		7		37		3		4		0		29		23		403
NE BLANCO UNIT #415	14287	NEBU	30N07W02	1	24		1,332		10		57		5		6		0		45		30		71
NE BLANCO UNIT #416	13563	NEBU	31N07W21	1	22		817		6		35		4		4		0		27		18		395

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 10 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

										REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
					LIFE	GROSS GAS		NET GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS	YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$		NUM
NE BLANCO UNIT #417	14288	NEBU	30N07W02	1	31		2,852		22		122		10		14		0		99		63		72
NE BLANCO UNIT #418	14289	NEBU	31N07W28	1	13		872		7		37		3		4		0		30		24		410
NE BLANCO UNIT #419	14290	NEBU	30N07W03	1	22		1,764		14		75		6		8		0		61		43		77
NE BLANCO UNIT #420	13564	NEBU	31N07W28	1	2		8		0		0		0		0		0		0		0		394
NE BLANCO UNIT #421R	14291	NEBU	30N07W04	1	20		1,842		14		79		6		9		0		64		46		151
NE BLANCO UNIT #422	13570	NEBU	31N07W20	1	15		335		3		14		2		2		0		11		8		397
NE BLANCO UNIT #423R	14292	NEBU	30N07W08	1	19		1,717		13		73		6		8		0		59		44		286
NE BLANCO UNIT #424	14293	NEBU	30N07W04	1	24		2,385		19		102		8		11		0		83		58		385
NE BLANCO UNIT #425R	14294	NEBU	30N07W08	1	27		2,653		21		113		9		13		0		92		61		169
NE BLANCO UNIT #426	14262	NEBU	31N06W06	1	25		2,115		16		90		7		10		0		73		49		440
NE BLANCO UNIT #427R	14295	NEBU	30N07W16	1	17		884		7		38		4		4		0		30		22		194
NE BLANCO UNIT #428	13571	NEBU	31N07W24	1	19		1,472		11		63		5		7		0		51		37		420
NE BLANCO UNIT #429R	14296	NEBU	30N07W17	1	5		86		1		4		1		0		0		3		2		226
NE BLANCO UNIT #430	13565	NEBU	30N07W05	1	16		678		5		29		3		3		0		23		17		398
NE BLANCO UNIT #431	14297	NEBU	30N07W17	1	32		2,459		19		105		9		12		0		85		52		74
NE BLANCO UNIT #432	13566	NEBU	30N07W07	1	22		1,839		14		79		6		9		0		64		45		399
NE BLANCO UNIT #433	14298	NEBU	30N07W19	1	13		234		2		10		2		1		0		7		5		76
NE BLANCO UNIT #434	14299	NEBU	31N07W23	1	21		2,323		18		99		7		11		0		81		59		423
NE BLANCO UNIT #435	14300	NEBU	30N08W01	1	23		1,064		8		46		4		5		0		36		24		383
NE BLANCO UNIT #436	13572	NEBU	31N06W19	1	21		1,179		9		50		5		6		0		40		28		425
NE BLANCO UNIT #437	14301	NEBU	30N08W12	1	26		1,119		9		48		5		5		0		38		24		382
NE BLANCO UNIT #438	14361	NEBU	31N06W18	1	25		1,078		8		46		5		5		0		36		24		452
NE BLANCO UNIT #439	14302	NEBU	30N08W13	1	26		2,383		19		102		8		11		0		83		56		380
NE BLANCO UNIT #440	13573	NEBU	31N07W11	1	22		1,490		12		64		5		7		0		51		36		431
NE BLANCO UNIT #441R	14303	NEBU	30N08W24	1	32		1,681		13		72		7		8		0		57		34		475
NE BLANCO UNIT #442	14304	NEBU	31N07W11	1	23		1,628		13		70		6		8		0		56		39		436
NE BLANCO UNIT #443	14305	NEBU	30N08W24	1	30		1,420		11		61		6		7		0		48		29		381
NE BLANCO UNIT #444	14362	NEBU	31N07W23	1	16		1,433		11		61		5		7		0		50		38		461
NE BLANCO UNIT #445	14306	NEBU	31N08W25	1	30		2,036		16		87		7		10		0		70		44		388
NE BLANCO UNIT #446	14307	NEBU	31N07W33	1	20		637		5		27		3		3		0		21		14		400
NE BLANCO UNIT #447	14308	NEBU	31N08W36	1	19		1,186		9		51		5		6		0		41		29		379
NE BLANCO UNIT #448	13567	NEBU	31N07W32	1	17		827		6		35		3		4		0		28		21		384
NE BLANCO UNIT #449	14309	NEBU	31N07W19	1	23		1,039		8		44		4		5		0		35		24		391
NE BLANCO UNIT #450	14310	NEBU	31N07W32	1	15		588		5		25		3		3		0		20		15		389
NE BLANCO UNIT #451	14311	NEBU	30N07W06	1	25		1,521		12		65		6		7		0		52		35		405
NE BLANCO UNIT #452	13574	NEBU	31N07W15	1	18		790		6		34		3		4		0		27		19		422
NE BLANCO UNIT #453	14312	NEBU	30N07W06	1	27		1,750		14		75		7		8		0		60		39		390
NE BLANCO UNIT #454	14313	NEBU	31N07W33	1	20		984		8		42		4		5		0		33		23		409
NE BLANCO UNIT #455	14314	NEBU	31N07W31	1	30		3,675		29		157		12		17		0		128		84		387
NE BLANCO UNIT #456	13575	NEBU	31N07W26	1	8		229		2		10		1		1		0		8		6		417
NE BLANCO UNIT #457	14315	NEBU	31N07W31	1	20		1,217		9		52		5		6		0		42		29		392
NE BLANCO UNIT #458	13576	NEBU	31N07W13	1	16		751		6		32		3		4		0		25		19		416
NE BLANCO UNIT #459	14316	NEBU	31N07W19	1	30		3,449		27		147		11		16		0		120		78		415

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 11 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

										REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
					LIFE	GROSS GAS		NET GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS	YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$		NUM
NE BLANCO UNIT #460	14351	NEBU	31N06W07	1	24		2,377		18		102		8		11		0		82		57		424
NE BLANCO UNIT #461	14317	NEBU	30N07W07	1	22		1,069		8		46		4		5		0		36		24		543
NE BLANCO UNIT #462	14318	NEBU	31N07W01	1	25		2,717		21		116		9		13		0		94		65		428
NE BLANCO UNIT #463	14319	NEBU	30N07W18	1	23		968		8		41		4		5		0		33		21		411
NE BLANCO UNIT #464	13577	NEBU	31N07W10	1	17		825		6		35		3		4		0		28		20		429
NE BLANCO UNIT #465	14320	NEBU	30N08W01	1	19		1,403		11		60		5		7		0		48		36		404
NE BLANCO UNIT #466	14321	NEBU	31N07W34	1	17		1,235		10		53		4		6		0		42		32		462
NE BLANCO UNIT #467	14322	NEBU	30N08W12	1	18		570		4		24		3		3		0		19		13		407
NE BLANCO UNIT #468	14323	NEBU	31N07W35	1	22		1,791		14		77		6		9		0		62		43		457
NE BLANCO UNIT #469	14324	NEBU	30N08W13	1	27		2,888		22		123		9		14		0		100		68		393
NE BLANCO UNIT #470	14352	NEBU	31N07W27	1	20		794		6		34		4		4		0		27		19		438
NE BLANCO UNIT #471	14325	NEBU	31N08W25	1	26		2,385		19		102		8		11		0		83		56		402
NE BLANCO UNIT #472	14326	NEBU	31N07W29	1	14		676		5		29		3		3		0		23		18		401
NE BLANCO UNIT #473	14327	NEBU	31N08W36	1	24		1,903		15		81		7		9		0		66		45		396
NE BLANCO UNIT #474	14353	NEBU	31N07W26	1	13		471		4		20		2		2		0		16		12		437
NE BLANCO UNIT #475	14328	NEBU	30N07W19	1	16		511		4		22		3		2		0		17		12		298
NE BLANCO UNIT #476	14329	NEBU	31N07W22	1	23		1,858		14		79		6		9		0		64		44		435
NE BLANCO UNIT #477	14379	NEBU	30N07W29	1	11		333		3		14		2		2		0		11		9		93
NE BLANCO UNIT #478	14330	NEBU	31N07W21	1	20		1,377		11		59		5		7		0		47		34		386
NE BLANCO UNIT #479R	13942	NEBU	30N07W20	1	26		1,350		10		58		5		6		0		46		30		334
NE BLANCO UNIT #480	14332	NEBU	31N07W14	1	24		1,773		14		76		6		8		0		61		42		463
NE BLANCO UNIT #481	14333	NEBU	31N07W36	1	16		745		6		32		3		4		0		25		19		86
NE BLANCO UNIT #482	14334	NEBU	31N07W15	1	24		2,520		20		108		8		12		0		88		61		439
NE BLANCO UNIT #483	14335	NEBU	31N07W36	1	13		534		4		23		2		3		0		18		14		85
NE BLANCO UNIT #484	14336	NEBU	31N07W16	1	14		370		3		16		2		2		0		12		9		430
NE BLANCO UNIT #485	14337	NEBU	30N07W03	1	16		900		7		38		4		4		0		31		23		131
NE BLANCO UNIT #486	14338	NEBU	31N06W19	1	21		2,251		18		96		7		11		0		78		56		472
NE BLANCO UNIT #487	14339	NEBU	31N07W35	1	30		2,968		23		127		10		14		0		103		66		464
NE BLANCO UNIT #488	14340	NEBU	31N07W24	1	19		2,214		17		95		7		11		0		77		57		458
NE BLANCO UNIT #489	14364	NEBU	31N07W12	1	12		293		2		13		2		1		0		9		7		456
NE BLANCO UNIT #490	14363	NEBU	31N07W14	1	18		1,215		9		52		4		6		0		42		31		434
NE BLANCO UNIT #491	14368	NEBU	31N07W25	1	17		678		5		29		3		3		0		23		16		152
NE BLANCO UNIT #492	14354	NEBU	31N07W12	1	21		1,465		11		63		5		7		0		50		36		453
NE BLANCO UNIT #493	14380	NEBU	31N07W25	1	17		770		6		33		3		4		0		26		19		143
NE BLANCO UNIT #494	14341	NEBU	31N07W27	1	22		1,030		8		44		4		5		0		35		24		465
NE BLANCO UNIT #495	14381	NEBU	31N06W30	1	20		1,113		9		48		4		5		0		38		27		144
NE BLANCO UNIT #496	14355	NEBU	31N06W18	1	16		1,237		10		53		4		6		0		43		32		459
NE BLANCO UNIT #497	14382	NEBU	31N06W30	1	22		1,113		9		48		5		5		0		38		26		146
NE BLANCO UNIT #498	14365	NEBU	31N07W13	1	19		1,467		11		63		5		7		0		51		37		460
NE BLANCO UNIT #499	14383	NEBU	31N06W20	1	28		1,738		14		74		7		8		0		59		38		179
NE BLANCO UNIT #500	14356	NEBU	31N06W20	1	27		1,755		14		75		7		8		0		60		39		454
NE BLANCO UNIT #504	14342	NEBU	31N07W16	1	20		1,289		10		55		5		6		0		44		32		513
NE BLANCO UNIT #505	14384	NEBU	30N07W21	1	28		1,580		12		68		6		8		0		54		34		319

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 12 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

										REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
					LIFE	GROSS GAS		NET GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS	YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$		NUM
NORDHAUS #716	14360	NON-UNIT	31N09W13	1	26		2,051		149		820		77		91		0		652		435		549
PAYNE #201	14225	NON-UNIT	32N10W20	1	19		1,078		20		109		11		12		0		85		61		546
QUINN #336	14226	NON-UNIT	31N08W17	1	11		586		43		236		25		26		0		185		151		451
SAN JUAN 28-5 UNIT #219	13793	SJ 28-5	28N05W30	1	22		182		75		412		135		46		0		232		130		245
SAN JUAN 28-5 UNIT #223	13740	SJ 28-5	28N05W34	1	0		0		0		0		0		0		0		0		0		246
SAN JUAN 28-6 UNIT #400	13883	SJ 28-6	28N06W09	1	25		248		14		77		21		9		0		47		26		98
SAN JUAN 28-6 UNIT #404	14227	SJ 28-6	28N06W13	1	12		67		28		154		68		17		0		69		47		124
SAN JUAN 28-6 UNIT #405	13884	SJ 28-6	28N06W18	1	15		171		10		53		13		6		0		34		23		153
SAN JUAN 28-6 UNIT #406	13885	SJ 28-6	28N06W19	1	26		311		18		97		23		11		0		63		35		112
SAN JUAN 28-6 UNIT #410	14228	SJ 28-6	28N06W13	1	1		3		1		6		4		1		0		2		2		214
SAN JUAN 28-6 UNIT #414	13886	SJ 28-6	28N06W08	1	21		227		13		70		18		8		0		44		26		260
SAN JUAN 28-6 UNIT #418	13757	SJ 28-6	28N06W28	1	7		46		3		14		5		2		0		7		6		297
SAN JUAN 28-6 UNIT #421	13758	SJ 28-6	28N06W33	1	16		221		12		69		15		8		0		46		31		247
SAN JUAN 28-6 UNIT #436	14347	SJ 28-6	28N06W16	1	23		271		15		84		20		9		0		54		32		277
SAN JUAN 28-6 UNIT #437	14456	SJ 28-6	28N06W28	1	19		193		11		60		16		7		0		37		23		309
SAN JUAN 28-6 UNIT #438	14348	SJ 28-6	28N06W15	1	17		138		21		115		36		13		0		67		43		293
SAN JUAN 28-6 UNIT #439	14388	SJ 28-6	28N06W29	1	18		188		58		319		84		36		0		200		129		248
SAN JUAN 28-6 UNIT #440	13759	SJ 28-6	28N06W16	1	4		20		1		6		3		1		0		3		3		276
SAN JUAN 28-6 UNIT #441	14389	SJ 28-6	28N06W17	1	30		452		26		140		29		16		0		96		51		296
SAN JUAN 28-6 UNIT #448	13760	SJ 28-6	28N06W15	1	0		0		0		0		0		0		0		0		0		228
SAN JUAN 28-6 UNIT #449	13761	SJ 28-6	27N06W02	1	11		78		8		44		16		5		0		23		17		218
SAN JUAN 28-6 UNIT #455	13719	SJ 28-6	28N06W17	1	19		157		24		131		42		15		0		75		45		278
SAN JUAN 28-6 UNIT #456	14229	SJ 28-6	28N06W19	1	10		90		14		75		21		8		0		46		35		243
SAN JUAN 28-6 UNIT #457	13720	SJ 28-6	28N06W20	1	19		139		21		116		41		13		0		62		36		279
SAN JUAN 28-6 UNIT #458	14263	SJ 28-6	28N06W20	1	22		313		18		97		20		11		0		66		41		231
SAN JUAN 28-6 UNIT #459	13733	SJ 28-6	28N06W21	1	40		1,124		64		349		48		39		0		262		119		280
SAN JUAN 28-6 UNIT #460	13721	SJ 28-6	28N06W21	1	24		307		17		95		22		11		0		63		36		294
SAN JUAN 28-6 UNIT #461	13762	SJ 28-6	28N06W22	1	33		376		57		315		77		35		0		203		100		266
SAN JUAN 28-6 UNIT #462	13732	SJ 28-6	28N06W22	1	23		266		40		222		54		25		0		144		84		295
SAN JUAN 28-6 UNIT #467	13724	SJ 28-6	28N06W34	1	34		674		38		210		35		23		0		151		79		282
SAN JUAN 28-6 UNIT #474	13723	SJ 28-6	28N06W27	1	30		323		18		100		26		11		0		63		32		281
SAN JUAN 28-6 UNIT #475	13887	SJ 28-6	28N06W29	1	24		428		24		133		24		15		0		94		56		289
SAN JUAN 29-5 UNIT #203	13547	SJ 29-5	29N05W06	1	17		874		113		620		65		69		0		486		362		122
SAN JUAN 29-5 UNIT #213	13597	SJ 29-5	29N05W22	1	38		760		98		540		91		60		0		389		193		136
SAN JUAN 29-5 UNIT #219	14398	SJ 29-5	29N05W04	1	23		510		66		362		57		40		0		264		167		304
SAN JUAN 29-5 UNIT #223	13653	SJ 29-5	29N05W33	1	3		13		2		9		4		1		0		4		4		241
SAN JUAN 29-5 UNIT #225	14391	SJ 29-5	29N05W06	1	14		246		32		175		32		19		0		124		91		305
SAN JUAN 29-5 UNIT #226	14392	SJ 29-5	29N05W07	1	27		744		96		528		74		59		0		396		240		302
SAN JUAN 29-5 UNIT #230	14405	SJ 29-5	29N05W05	1	26		1,051		136		746		87		83		0		576		364		326
SAN JUAN 29-5 UNIT #231	14393	SJ 29-5	29N05W05	1	0		1		0		0		0		0		0		0		0		301
SAN JUAN 29-6 UNIT #201	13589	SJ 29-6	29N06W06	1	26		2,205		267		1,466		132		163		0		1,171		780		132
SAN JUAN 29-6 UNIT #202	13654	SJ 29-6	29N06W06	1	18		759		92		504		57		56		0		391		284		235
SAN JUAN 29-6 UNIT #203	13684	SJ 29-6	29N06W07	1	17		1,030		125		685		68		76		0		540		400		180

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 13 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

										REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
					LIFE	GROSS GAS		NET GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS	YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$		NUM
SAN JUAN 29-6 UNIT #204	13655	SJ 29-6	29N06W07	1	6		84		10		56		12		6		0		38		33		207
SAN JUAN 29-6 UNIT #205	13685	SJ 29-6	29N06W21	1	22		1,331		161		885		88		98		0		698		480		250
SAN JUAN 29-6 UNIT #206	13548	SJ 29-6	29N06W04	1	26		1,057		128		703		82		78		0		542		341		117
SAN JUAN 29-6 UNIT #207	13549	SJ 29-6	29N06W02	1	17		1,011		122		672		67		75		0		530		394		115
SAN JUAN 29-6 UNIT #208	13587	SJ 29-6	29N06W17	1	20		1,389		168		924		87		103		0		734		529		133
SAN JUAN 29-6 UNIT #209	13588	SJ 29-6	29N06W17	1	18		807		98		537		59		60		0		418		302		126
SAN JUAN 29-6 UNIT #210	14394	SJ 29-6	29N06W20	1	30		2,698		326		1,794		157		199		0		1,437		925		182
SAN JUAN 29-6 UNIT #211	14395	SJ 29-6	29N06W20	1	27		1,224		148		814		90		90		0		634		401		174
SAN JUAN 29-6 UNIT #213	13590	SJ 29-6	29N06W30	1	11		92		11		61		18		7		0		36		27		127
SAN JUAN 29-6 UNIT #214	13595	SJ 29-6	29N06W03	1	6		146		18		97		15		11		0		72		63		137
SAN JUAN 29-6 UNIT #215	13599	SJ 29-6	29N06W03	1	16		561		68		373		46		41		0		285		209		175
SAN JUAN 29-6 UNIT #216	13596	SJ 29-6	29N06W04	1	14		459		56		305		39		34		0		233		178		138
SAN JUAN 29-6 UNIT #217	13612	SJ 29-6	29N06W05	1	26		2,531		306		1,683		145		187		0		1,351		919		193
SAN JUAN 29-6 UNIT #218	13605	SJ 29-6	29N06W05	1	12		524		63		348		39		39		0		271		216		181
SAN JUAN 29-6 UNIT #219	13593	SJ 29-6	29N06W10	1	22		1,048		127		697		75		77		0		544		373		139
SAN JUAN 29-6 UNIT #220	13600	SJ 29-6	29N06W11	1	18		497		60		331		47		37		0		247		171		165
SAN JUAN 29-6 UNIT #221	13601	SJ 29-6	29N06W11	1	20		916		111		609		67		68		0		474		333		159
SAN JUAN 29-6 UNIT #222	13718	SJ 29-6	29N06W12	1	32		1,253		152		833		99		93		0		642		371		183
SAN JUAN 29-6 UNIT #223	13611	SJ 29-6	29N06W12	1	28		1,585		192		1,054		107		117		0		830		524		160
SAN JUAN 29-6 UNIT #224	13696	SJ 29-6	29N06W13	1	0		0		0		0		0		0		0		0		0		184
SAN JUAN 29-6 UNIT #225R	13947	SJ 29-6	29N06W13	1	1		4		1		3		2		0		0		1		1		332
SAN JUAN 29-6 UNIT #226	14396	SJ 29-6	29N06W14	1	35		4,077		493		2,711		224		301		0		2,186		1,354		154
SAN JUAN 29-6 UNIT #227	13765	SJ 29-6	29N06W14	1	0		0		0		0		0		0		0		0		0		155
SAN JUAN 29-6 UNIT #229	13766	SJ 29-6	29N06W35	1	19		243		29		162		37		18		0		106		67		162
SAN JUAN 29-6 UNIT #230	13602	SJ 29-6	29N06W35	1	19		210		8		43		11		5		0		27		17		140
SAN JUAN 29-6 UNIT #231	13594	SJ 29-6	29N06W36	1	4		19		3		16		7		2		0		7		6		141
SAN JUAN 29-6 UNIT #233	13767	SJ 29-6	29N06W26	1	16		225		26		140		30		16		0		95		64		176
SAN JUAN 29-6 UNIT #235	14513	SJ 29-6	29N06W34	1	33		471		57		313		65		35		0		213		108		208
SAN JUAN 29-6 UNIT #236	13694	SJ 29-6	29N06W18	1	25		1,149		139		764		84		85		0		595		385		177
SAN JUAN 29-6 UNIT #237	13674	SJ 29-6	29N06W01	1	19		708		86		471		57		52		0		362		252		197
SAN JUAN 29-6 UNIT #238	13675	SJ 29-6	29N06W01	1	14		448		54		298		38		33		0		227		173		198
SAN JUAN 29-6 UNIT #239	13676	SJ 29-6	29N06W02	1	15		647		78		430		49		48		0		334		252		170
SAN JUAN 29-6 UNIT #240	13686	SJ 29-6	29N06W18	1	23		1,531		185		1,018		98		113		0		807		554		251
SAN JUAN 29-6 UNIT #241	13687	SJ 29-6	29N06W19	1	31		1,817		220		1,208		121		134		0		953		583		252
SAN JUAN 29-6 UNIT #242	13688	SJ 29-6	29N06W19	1	27		1,420		172		944		99		105		0		740		470		178
SAN JUAN 29-6 UNIT #243	13768	SJ 29-6	29N06W31	1	22		197		7		40		12		4		0		24		14		255
SAN JUAN 29-6 UNIT #245	13667	SJ 29-6	29N06W08	1	21		1,063		129		707		75		79		0		554		386		242
SAN JUAN 29-6 UNIT #246	14397	SJ 29-6	29N06W08	1	5		35		4		23		9		3		0		12		10		209
SAN JUAN 29-6 UNIT #247R	13814	SJ 29-6	29N06W10	1	17		392		47		261		41		29		0		191		134		338
SAN JUAN 29-6 UNIT #249	13796	SJ 29-6	29N06W22	1	8		50		6		33		13		4		0		17		13		323
SAN JUAN 29-6 UNIT #251	13803	SJ 29-6	29N06W23	1	8		42		6		34		16		4		0		15		11		317
SAN JUAN 29-6 UNIT #257R	13815	SJ 29-6	29N06W09	1	25		1,082		131		719		82		80		0		558		358		339
SAN JUAN 29-6 UNIT #258	13695	SJ 29-6	29N06W16	1	25		1,710		207		1,137		108		126		0		902		607		186

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 14 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

										REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
					LIFE	GROSS GAS		NET GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS	YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$		NUM
SAN JUAN 29-6 UNIT #259	14399	SJ 29-6	29N06W09	1	11		273		33		181		27		20		0		134		106		185
SAN JUAN 29-6 UNIT #260	14400	SJ 29-6	29N06W16	1	16		276		33		184		33		20		0		130		91		187
SAN JUAN 29-6 UNIT #262	14401	SJ 29-6	29N06W21	1	30		2,122		257		1,411		133		157		0		1,121		704		307
SAN JUAN 29-6 UNIT #263	13802	SJ 29-6	29N06W22	1	6		48		7		39		14		4		0		21		17		320
SAN JUAN 29-6 UNIT #264	13841	SJ 29-6	29N06W27	1	9		56		7		37		15		4		0		18		14		341
SAN JUAN 29-7 UNIT #507R	12667	SJ 29-7	29N07W13	1	31		1,867		188		1,036		100		115		0		821		503		330
SAN JUAN 29-7 UNIT #520	12524	SJ 29-7	29N07W08	1	16		229		23		127		26		14		0		87		59		342
SAN JUAN 29-7 UNIT #521	12653	SJ 29-7	29N07W13	1	26		1,554		157		862		84		96		0		682		443		221
SAN JUAN 29-7 UNIT #530	13882	SJ 29-7	29N07W34	1	26		401		41		223		43		25		0		155		89		195
SAN JUAN 29-7 UNIT #532	14349	SJ 29-7	29N07W02	1	16		306		31		170		29		19		0		122		85		145
SAN JUAN 29-7 UNIT #533	14464	SJ 29-7	29N07W03	1	9		140		14		78		14		9		0		55		45		196
SAN JUAN 29-7 UNIT #534	12668	SJ 29-7	29N07W09	1	16		454		46		252		34		28		0		189		136		327
SAN JUAN 29-7 UNIT #537	12669	SJ 29-7	29N07W22	1	7		91		9		51		11		6		0		34		28		290
SAN JUAN 29-7 UNIT #538	14402	SJ 29-7	29N07W26	1	23		454		46		252		42		28		0		182		113		200
SAN JUAN 29-7 UNIT #540	12654	SJ 29-7	29N07W10	1	14		253		25		140		24		16		0		101		74		284
SAN JUAN 29-7 UNIT #543	12655	SJ 29-7	29N07W03	1	35		1,081		109		599		76		67		0		456		249		299
SAN JUAN 29-7 UNIT #544	12656	SJ 29-7	29N07W04	1	31		2,321		234		1,287		116		143		0		1,028		637		283
SAN JUAN 29-7 UNIT #545	12657	SJ 29-7	29N07W12	1	30		2,337		236		1,296		116		144		0		1,036		652		210
SAN JUAN 29-7 UNIT #547	14403	SJ 29-7	29N07W07	1	26		597		60		331		50		37		0		244		145		291
SAN JUAN 29-7 UNIT #548	14372	SJ 29-7	29N07W07	1	37		636		64		353		63		39		0		250		122		300
SAN JUAN 29-7 UNIT #550	12659	SJ 29-7	29N07W11	1	18		769		78		426		46		47		0		333		241		215
SAN JUAN 29-7 UNIT #552	12652	SJ 29-7	29N07W12	1	21		1,781		180		988		86		110		0		792		566		314
SAN JUAN 29-7 UNIT #553	12661	SJ 29-7	29N07W14	1	25		2,450		247		1,359		113		151		0		1,095		756		234
SAN JUAN 29-7 UNIT #554	12662	SJ 29-7	29N07W14	1	20		459		301		1,656		244		184		0		1,228		821		201
SAN JUAN 29-7 UNIT #559	14404	SJ 29-7	29N07W22	1	16		180		18		100		24		11		0		64		43		244
SAN JUAN 29-7 UNIT #562	12664	SJ 29-7	29N07W24	1	26		1,833		185		1,017		93		113		0		810		534		239
SAN JUAN 29-7 UNIT #563	12665	SJ 29-7	29N07W24	1	5		37		16		90		29		10		0		51		44		285
SAN JUAN 29-7 UNIT #565	14231	SJ 29-7	29N07W26	1	15		94		62		339		126		38		0		176		114		203
SAN JUAN 29-7 UNIT #577	14232	SJ 29-7	29N07W35	1	9		75		6		30		10		3		0		17		13		275
SAN JUAN 29-7 UNIT #580	14465	SJ 29-7	29N07W01	1	12		617		62		342		35		38		0		269		215		219
SAN JUAN 29-7 UNIT #582	12666	SJ 29-7	29N07W02	1	18		1,548		156		858		74		95		0		689		513		211
SAN JUAN 29-7 UNIT #583	12670	SJ 29-7	29N07W06	1	13		230		23		128		23		14		0		91		67		329
SAN JUAN 29-7 UNIT #92R	12025	SJ 29-7	29N07W16	1	4		38		4		21		5		2		0		14		12		1248
SAN JUAN 30-5 UNIT #201	13550	SJ 30-5	30N05W19	1	27		1,956		333		1,833		171		204		0		1,458		956		123
SAN JUAN 30-5 UNIT #202	13551	SJ 30-5	30N05W06	1	22		1,726		256		1,409		131		157		0		1,121		790		116
SAN JUAN 30-5 UNIT #203	13607	SJ 30-5	30N05W06	1	3		19		3		18		6		2		0		9		9		156
SAN JUAN 30-5 UNIT #204	13726	SJ 30-5	30N05W07	1	20		425		72		398		65		44		0		289		190		163
SAN JUAN 30-5 UNIT #205	13772	SJ 30-5	30N05W07	1	13		282		48		264		43		29		0		191		143		148
SAN JUAN 30-5 UNIT #206	13711	SJ 30-5	30N05W18	1	21		869		148		814		94		91		0		630		428		166
SAN JUAN 30-5 UNIT #207	13727	SJ 30-5	30N05W18	1	16		860		147		806		83		90		0		633		475		192
SAN JUAN 30-5 UNIT #208	13665	SJ 30-5	30N05W19	1	19		1,672		285		1,566		137		174		0		1,255		931		199
SAN JUAN 30-5 UNIT #209	13606	SJ 30-5	30N05W30	1	20		1,187		202		1,112		111		124		0		877		624		167
SAN JUAN 30-5 UNIT #210	13682	SJ 30-5	30N05W30	1	15		565		96		529		63		59		0		408		307		264

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 15 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

											REVENUE		OPER.						BFIT NET		10% DISC
						LIFE	GROSS GAS		NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		TAXEX M$		M$		M$		M$		NUM
SAN JUAN 30-5 UNIT #211	13683	SJ 30-5	30N05W31		1	18		703		120		659		78		73		0		508		360		172
SAN JUAN 30-5 UNIT #212	13617	SJ 30-5	30N05W31		1	18		672		115		629		76		70		0		484		344		173
SAN JUAN 30-5 UNIT #213R	16986	SJ 30-5	30N05W05		1	14		687		117		644		70		72		0		503		385		624
SAN JUAN 30-5 UNIT #214	16987	SJ 30-5	30N05W05		1	16		1,244		212		1,165		107		130		0		929		711		638
SAN JUAN 30-5 UNIT #215	13660	SJ 30-5	30N05W08		1	23		1,545		1,352		7,430		680		826		0		5,924		4,093		190
SAN JUAN 30-5 UNIT #216R	13943	SJ 30-5	30N05W20		1	14		438		75		410		54		46		0		310		233		335
SAN JUAN 30-5 UNIT #217	13614	SJ 30-5	30N05W21		1	24		1,523		260		1,427		139		159		0		1,130		761		217
SAN JUAN 30-5 UNIT #218	13659	SJ 30-5	30N05W17		1	21		2,407		410		2,255		186		251		0		1,819		1,335		191
SAN JUAN 30-5 UNIT #219R	17250	SJ 30-5	30N05W16		1	9		298		51		279		35		31		0		213		178		625
SAN JUAN 30-5 UNIT #220R	15532	SJ 30-5	30N05W08		1	20		833		142		780		88		87		0		605		425		635
SAN JUAN 30-5 UNIT #223	13677	SJ 30-5	30N05W20		1	23		1,444		246		1,353		133		150		0		1,070		726		236
SAN JUAN 30-5 UNIT #224	12576	SJ 30-5	30N05W17		1	17		520		89		487		64		54		0		369		263		237
SAN JUAN 30-5 UNIT #225	14406	SJ 30-5	30N05W29		1	14		316		54		297		46		33		0		218		162		306
SAN JUAN 30-5 UNIT #226	13670	SJ 30-5	30N05W29		1	16		817		139		766		81		85		0		600		447		261
SAN JUAN 30-5 UNIT #226A	5772	SJ 30-5	30N05W29		1	17		744		127		697		78		77		0		541		396		983
SAN JUAN 30-5 UNIT #227	13672	SJ 30-5	30N05W28		1	23		924		158		866		101		96		0		669		441		232
SAN JUAN 30-5 UNIT #228	14407	SJ 30-5	30N05W28		1	15		411		70		385		54		43		0		289		213		310
SAN JUAN 30-5 UNIT #229	13673	SJ 30-5	30N05W21		1	29		2,026		345		1,898		178		211		0		1,509		967		270
SAN JUAN 30-5 UNIT #230	14366	SJ 30-5	30N05W32		1	7		197		34		185		26		21		0		138		117		238
SAN JUAN 30-5 UNIT #231	14409	SJ 30-5	30N05W32		1	21		551		94		516		73		57		0		386		257		233
SAN JUAN 30-5 UNIT #232	14408	SJ 30-5	30N05W33		1	6		57		10		54		15		6		0		33		27		321
SAN JUAN 30-5 UNIT #233	14443	SJ 30-5	30N05W33		1	24		784		134		735		94		82		0		559		358		322
SAN JUAN 30-5 UNIT #234	14410	SJ 30-5	30N05W22		1	34		3,387		577		3,174		271		353		0		2,549		1,565		318
SAN JUAN 30-5 UNIT #235	14411	SJ 30-5	30N05W27		1	16		513		87		481		61		53		0		366		269		311
SAN JUAN 30-5 UNIT #236	14412	SJ 30-5	30N05W27		1	7		258		44		242		30		27		0		185		159		303
SAN JUAN 30-5 UNIT #237	14413	SJ 30-5	30N05W16		1	0		0		0		0		0		0		0		0		0		308
SAN JUAN 30-5 UNIT #237R	6123	SJ 30-5	30N05W16		1	7		452		232		1,272		117		141		0		1,014		886		1201
SAN JUAN 30-5 UNIT #238	14414	SJ 30-5	30N05W34		1	12		406		69		380		49		42		0		290		225		312
SAN JUAN 30-5 UNIT #239	13949	SJ 30-5	30N05W15		1	12		380		65		356		46		40		0		270		212		315
SAN JUAN 30-5 UNIT #240	14415	SJ 30-5	30N05W22		1	29		2,493		425		2,336		207		260		0		1,870		1,214		324
SAN JUAN 30-5 UNIT #241	14416	SJ 30-5	30N05W23		1	15		336		57		314		50		35		0		229		164		325
SAN JUAN 30-5 UNIT #242	14444	SJ 30-5	30N05W34		1	4		41		7		39		11		4		0		23		21		316
SAN JUAN 30-5 UNIT #243	14069	SJ 30-5	30N05W15		1	32		1,895		323		1,775		178		197		0		1,400		839		346
SAN JUAN 30-5 UNIT #246	13948	SJ 30-5	30N05W26		1	18		615		105		576		72		64		0		441		313		331
SAN JUAN 30-5 UNIT #249	14068	SJ 30-5	30N05W23		1	17		771		131		723		79		80		0		563		414		632
SAN JUAN 30-5 UNIT #255	13842	SJ 30-5	30N05W14		1	21		936		160		877		98		97		0		681		464		340
SAN JUAN 30-5 UNIT #257	14025	SJ 30-5	30N05W11		1	22		1,766		301		1,655		149		184		0		1,322		938		345
SAN JUAN 30-5 UNIT #258	14026	SJ 30-5	30N05W14		1	31		3,307		564		3,099		261		344		0		2,493		1,591		344
SAN JUAN 30-5 UNIT #259	8011	SJ 30-5	30N05W13		1	18		854		146		800		87		89		0		625		452		630
SAN JUAN 30-5 UNIT #260	12646	SJ 30-5	30N05W09		1	10		1,241		212		1,163		94		129		0		939		802		633
SAN JUAN 30-5 UNIT #261	5424	SJ 30-5	30N05W11		1	20		1,020		174		956		101		106		0		748		525		682
SAN JUAN 30-5 UNIT #262	8012	SJ 30-5	30N05W12		1	9		422		72		396		43		44		0		309		260		631
SAN JUAN 30-5 UNIT #263	5425	SJ 30-5	30N05W13		1	16		837		143		784		81		87		0		616		467		683

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 16 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

											REVENUE		OPER.						BFIT NET		10% DISC
						LIFE	GROSS GAS		NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		TAXEX M$		M$		M$		M$		NUM
SAN JUAN 30-5 UNIT #264	12619	SJ 30-5	30N05W09		1	20		2,507		427		2,349		191		261		0		1,897		1,408		634
SAN JUAN 30-5 UNIT #265	15533	SJ 30-5	30N05W10		1	19		2,943		502		2,758		215		307		0		2,236		1,696		637
SAN JUAN 30-5 UNIT #266	15534	SJ 30-5	30N05W10		1	22		3,056		521		2,863		227		318		0		2,318		1,691		636
SAN JUAN 30-5 UNIT #267	5046	SJ 30-5	30N05W24		1	12		560		95		525		57		58		0		409		325		1246
SAN JUAN 30-5 UNIT #268	10177	SJ 30-5	30N05W24		1	15		557		95		522		64		58		0		400		297		1247
SAN JUAN 30-6 UNIT #467COM FRT.	4496	NEBU	30N07W22		1	13		459		13		72		9		8		0		55		43		105
SAN JUAN 30-6 UNIT #400	14164	SJ 30-6	30N07W14		1	19		1,475		74		405		37		45		0		323		237		23
SAN JUAN 30-6 UNIT #401R	14165	SJ 30-6	30N07W13		1	10		310		15		85		11		9		0		65		53		79
SAN JUAN 30-6 UNIT #403	13648	SJ 30-6	30N06W09		1	27		2,253		113		618		56		69		0		494		325		171
SAN JUAN 30-6 UNIT #404R	14459	SJ 30-6	30N07W23		1	24		2,561		128		703		59		78		0		566		395		328
SAN JUAN 30-6 UNIT #405	13580	SJ 30-6	30N06W09		1	18		696		35		191		23		21		0		147		105		128
SAN JUAN 30-6 UNIT #406R	14167	SJ 30-6	30N07W15		1	19		1,026		51		281		29		31		0		221		159		108
SAN JUAN 30-6 UNIT #407	13559	SJ 30-6	30N06W16		1	24		1,931		96		530		48		59		0		423		289		120
SAN JUAN 30-6 UNIT #408	13558	SJ 30-6	30N06W16		1	24		1,720		86		472		44		52		0		375		256		119
SAN JUAN 30-6 UNIT #409	14168	SJ 30-6	30N07W25		1	24		2,607		130		715		60		80		0		576		402		30
SAN JUAN 30-6 UNIT #410	14211	SJ 30-6	30N06W26		1	19		946		47		260		28		29		0		203		145		135
SAN JUAN 30-6 UNIT #411	14169	SJ 30-6	30N07W27		1	11		272		14		75		11		8		0		55		44		33
SAN JUAN 30-6 UNIT #412	14170	SJ 30-6	30N07W24		1	25		2,523		126		692		59		77		0		556		382		24
SAN JUAN 30-6 UNIT #413R	14171	SJ 30-6	30N07W23		1	24		1,905		95		523		47		58		0		417		288		84
SAN JUAN 30-6 UNIT #414	14172	SJ 30-6	30N07W35		1	11		267		13		73		11		8		0		54		43		25
SAN JUAN 30-6 UNIT #415	14173	SJ 30-6	30N07W26		1	25		1,989		99		546		49		61		0		436		297		32
SAN JUAN 30-6 UNIT #416	14174	SJ 30-6	30N07W24		1	25		2,968		148		814		67		91		0		657		459		28
SAN JUAN 30-6 UNIT #417	14175	SJ 30-6	30N07W25		1	21		1,523		76		418		39		46		0		333		238		29
SAN JUAN 30-6 UNIT #418	14176	SJ 30-6	30N07W26		1	28		2,697		135		740		64		82		0		594		395		31
SAN JUAN 30-6 UNIT #419	14177	SJ 30-6	30N07W11		1	14		503		25		138		17		15		0		106		81		26
SAN JUAN 30-6 UNIT #420	14178	SJ 30-6	30N07W12		1	21		859		43		236		27		26		0		182		125		27
SAN JUAN 30-6 UNIT #421	14179	SJ 30-6	30N07W34		1	2		9		0		2		1		0		0		1		1		37
SAN JUAN 30-6 UNIT #422	14264	SJ 30-6	30N07W27		1	23		915		46		251		29		28		0		194		128		59
SAN JUAN 30-6 UNIT #423	14462	SJ 30-6	30N07W28		1	6		81		4		22		5		2		0		15		13		95
SAN JUAN 30-6 UNIT #424	14463	SJ 30-6	30N07W33		1	16		460		23		126		17		14		0		95		70		56
SAN JUAN 30-6 UNIT #425	14385	SJ 30-6	30N07W33		1	19		1,095		55		301		30		33		0		237		171		47
SAN JUAN 30-6 UNIT #426	14180	SJ 30-6	30N07W34		1	11		207		10		57		10		6		0		41		32		54
SAN JUAN 30-6 UNIT #427	14181	SJ 30-6	30N07W35		1	15		647		32		178		20		20		0		138		104		60
SAN JUAN 30-6 UNIT #428	14358	SJ 30-6	30N07W28		1	28		1,445		72		396		42		44		0		311		195		82
SAN JUAN 30-6 UNIT #429	14359	SJ 30-6	30N07W32		1	7		102		5		28		6		3		0		19		16		67
SAN JUAN 30-6 UNIT #430	13543	SJ 30-6	30N06W08		1	16		1,050		52		288		27		32		0		229		175		38
SAN JUAN 30-6 UNIT #431	13544	SJ 30-6	30N06W10		1	12		769		38		211		21		23		0		167		134		40
SAN JUAN 30-6 UNIT #432	13545	SJ 30-6	30N06W10		1	26		1,625		81		446		43		50		0		353		233		39
SAN JUAN 30-6 UNIT #433	14182	SJ 30-6	30N06W11		1	19		1,052		53		289		29		32		0		227		165		48
SAN JUAN 30-6 UNIT #434	14183	SJ 30-6	30N06W12		1	21		1,556		78		427		40		47		0		340		242		58
SAN JUAN 30-6 UNIT #435	14184	SJ 30-6	30N06W13		1	22		1,177		59		323		33		36		0		254		175		70
SAN JUAN 30-6 UNIT #436	14185	SJ 30-6	30N06W15		1	20		1,497		75		411		38		46		0		327		238		41
SAN JUAN 30-6 UNIT #437	14186	SJ 30-6	30N06W11		1	30		2,275		114		624		57		69		0		498		316		62

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 17 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

											REVENUE		OPER.						BFIT NET		10% DISC
						LIFE	GROSS GAS		NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		TAXEX M$		M$		M$		M$		NUM
SAN JUAN 30-6 UNIT #438	14187	SJ 30-6	30N06W12		1	22		1,835		92		504		45		56		0		403		287		68
SAN JUAN 30-6 UNIT #439	14188	SJ 30-6	30N06W14		1	24		1,287		64		353		37		39		0		277		185		49
SAN JUAN 30-6 UNIT #440	14189	SJ 30-6	30N06W15		1	6		75		4		21		5		2		0		14		12		50
SAN JUAN 30-6 UNIT #441	14190	SJ 30-6	30N06W31		1	2		25		1		7		2		1		0		4		4		53
SAN JUAN 30-6 UNIT #442	13568	SJ 30-6	30N06W14		1	23		1,726		86		474		44		53		0		377		260		96
SAN JUAN 30-6 UNIT #443	13532	SJ 30-6	30N06W36		1	4		23		1		6		3		1		0		3		3		69
SAN JUAN 30-6 UNIT #444	14208	SJ 30-6	30N06W36		1	29		1,637		82		449		45		50		0		354		222		66
SAN JUAN 30-6 UNIT #445	14209	SJ 30-6	30N06W13		1	23		1,530		76		420		40		47		0		333		228		73
SAN JUAN 30-6 UNIT #446	14204	SJ 30-6	30N06W35		1	23		2,157		108		592		51		66		0		475		333		129
SAN JUAN 30-6 UNIT #447	14206	SJ 30-6	30N07W31		1	14		377		19		103		15		11		0		77		57		147
SAN JUAN 30-6 UNIT #450	13536	SJ 30-6	30N06W07		1	22		1,407		70		386		37		43		0		306		214		43
SAN JUAN 30-6 UNIT #451	13534	SJ 30-6	30N06W07		1	20		1,709		85		469		42		52		0		375		273		42
SAN JUAN 30-6 UNIT #452	13535	SJ 30-6	30N06W08		1	20		1,249		62		343		33		38		0		271		195		61
SAN JUAN 30-6 UNIT #453	14191	SJ 30-6	30N06W17		1	21		1,176		59		323		33		36		0		254		177		57
SAN JUAN 30-6 UNIT #454	14192	SJ 30-6	30N06W17		1	25		2,092		104		574		51		64		0		459		313		44
SAN JUAN 30-6 UNIT #455	14161	SJ 30-6	30N06W18		1	21		1,153		58		316		33		35		0		249		172		52
SAN JUAN 30-6 UNIT #456	13537	SJ 30-6	30N06W18		1	23		2,357		118		647		55		72		0		520		368		51
SAN JUAN 30-6 UNIT #457	14193	SJ 30-6	30N06W19		1	23		2,034		102		558		49		62		0		447		311		45
SAN JUAN 30-6 UNIT #458	14194	SJ 30-6	30N06W19		1	19		1,016		51		279		29		31		0		219		156		63
SAN JUAN 30-6 UNIT #459	14195	SJ 30-6	30N06W20		1	24		1,678		84		460		43		51		0		366		250		64
SAN JUAN 30-6 UNIT #460	14162	SJ 30-6	30N06W20		1	20		1,445		72		396		37		44		0		315		227		55
SAN JUAN 30-6 UNIT #461	14251	SJ 30-6	30N07W11		1	17		613		31		168		21		19		0		129		93		80
SAN JUAN 30-6 UNIT #462	14196	SJ 30-6	30N07W12		1	31		1,640		82		450		47		50		0		353		213		83
SAN JUAN 30-6 UNIT #463	14197	SJ 30-6	30N07W13		1	11		304		15		83		12		9		0		63		50		81
SAN JUAN 30-6 UNIT #464	14198	SJ 30-6	30N07W14		1	21		806		40		221		26		25		0		171		117		46
SAN JUAN 30-6 UNIT #465	14199	SJ 30-6	30N07W15		1	21		1,230		61		338		34		38		0		266		187		65
SAN JUAN 30-6 UNIT #466	14200	SJ 30-6	30N07W22		1	14		559		28		153		18		17		0		119		92		75
SAN JUAN 30-6 UNIT #468	14252	SJ 30-6	30N07W36		1	29		2,843		142		780		67		87		0		626		407		91
SAN JUAN 30-6 UNIT #470	14253	SJ 30-6	30N06W21		1	22		1,449		72		398		38		44		0		315		220		102
SAN JUAN 30-6 UNIT #471	14254	SJ 30-6	30N06W21		1	20		1,374		69		377		36		42		0		299		215		113
SAN JUAN 30-6 UNIT #472	14255	SJ 30-6	30N06W22		1	20		632		32		173		22		19		0		132		90		107
SAN JUAN 30-6 UNIT #473	14256	SJ 30-6	30N06W22		1	18		907		45		249		27		28		0		195		141		106
SAN JUAN 30-6 UNIT #474	14257	SJ 30-6	30N06W27		1	26		2,210		110		607		54		67		0		485		325		97
SAN JUAN 30-6 UNIT #475	14258	SJ 30-6	30N06W27		1	30		3,153		157		865		73		96		0		696		453		109
SAN JUAN 30-6 UNIT #476	14163	SJ 30-6	30N06W28		1	23		1,592		79		437		41		49		0		347		240		100
SAN JUAN 30-6 UNIT #477	14210	SJ 30-6	30N06W28		1	28		2,686		134		737		64		82		0		591		389		111
SAN JUAN 30-6 UNIT #478	14205	SJ 30-6	30N06W29		1	24		2,031		101		557		50		62		0		446		307		101
SAN JUAN 30-6 UNIT #479	14259	SJ 30-6	30N06W29		1	24		1,554		78		426		41		47		0		338		230		134
SAN JUAN 30-6 UNIT #480	14260	SJ 30-6	30N06W30		1	17		866		43		238		25		26		0		186		137		110
SAN JUAN 30-6 UNIT #481	14261	SJ 30-6	30N06W30		1	28		2,813		140		772		66		86		0		620		409		99
SAN JUAN 30-6 UNIT #482	14266	SJ 30-6	30N06W31		1	29		2,663		133		731		64		81		0		586		379		142
SAN JUAN 30-6 UNIT #483	14207	SJ 30-6	30N06W34		1	20		870		43		239		27		27		0		185		128		104
SAN JUAN 30-6 UNIT #484	14249	SJ 30-6	30N06W34		1	20		802		40		220		25		24		0		170		119		103

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 18 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

											REVENUE		OPER.						BFIT NET		10% DISC
						LIFE	GROSS GAS		NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		TAXEX M$		M$		M$		M$		NUM
SAN JUAN 30-6 UNIT #485	14233	SJ 30-6	30N07W36		1	18		1,259		63		345		32		38		0		275		205		204
SAN JUAN 30-6 UNIT #486	14234	SJ 30-6	30N06W23		1	23		1,782		89		489		45		54		0		390		270		271
SAN JUAN 30-6 UNIT #487	14235	SJ 30-6	30N06W23		1	24		1,767		88		485		45		54		0		386		262		292
SAN JUAN 30-6 UNIT #488	14236	SJ 30-6	30N06W24		1	16		455		23		125		17		14		0		94		67		222
SAN JUAN 30-6 UNIT #489	14237	SJ 30-6	30N06W24		1	18		1,118		56		307		30		34		0		242		177		249
SAN JUAN 30-6 UNIT #490	14238	SJ 30-6	30N06W25		1	14		569		28		156		18		17		0		121		92		223
SAN JUAN 30-6 UNIT #491	14239	SJ 30-6	30N06W25		1	19		1,153		58		316		31		35		0		250		180		224
SAN JUAN 30-6 UNIT #492	14240	SJ 30-6	30N06W26		1	14		513		26		141		17		16		0		108		82		230
SAN JUAN 30-6 UNIT #493	14241	SJ 30-6	30N06W32		1	14		595		30		163		19		18		0		127		97		205
SAN JUAN 30-6 UNIT #494	14242	SJ 30-6	30N06W33		1	31		3,438		172		943		79		105		0		760		486		212
SAN JUAN 30-6 UNIT #495	14243	SJ 30-6	30N06W33		1	25		1,769		88		485		45		54		0		386		261		213
SAN JUAN 30-6 UNIT #496	14244	SJ 30-6	30N06W35		1	18		594		30		163		21		18		0		124		87		225
SAN JUAN 30-6 UNIT #497	14245	SJ 30-6	30N07W29		1	27		776		39		213		29		24		0		160		98		259
SAN JUAN 30-6 UNIT #498R	13946	SJ 30-6	30N07W30		1	5		38		6		31		11		3		0		16		14		336
SAN JUAN 30-6 UNIT #499	14247	SJ 30-6	30N07W30		1	1		4		0		1		1		0		0		0		0		258
SAN JUAN 30-6 UNIT #500	14417	SJ 30-6	30N07W31		1	21		306		45		249		53		28		0		168		104		240
SAN JUAN 30-6 UNIT #501	14248	SJ 30-6	30N06W32		1	20		1,285		64		353		34		39		0		279		199		206
SAN JUAN 31 FED 3 #2	14418	NON-UNIT	31N09W03		1	26		1,618		240		1,321		132		147		0		1,042		688		559
SAN JUAN 31-6 UNIT #201	13540	SJ 31-6	30N06W01		1	25		1,057		113		622		72		69		0		481		311		130
SAN JUAN 31-6 UNIT #202	13552	SJ 31-6	30N06W01		1	33		2,640		283		1,554		144		173		0		1,238		756		118
SAN JUAN 31-6 UNIT #203	13539	SJ 31-6	30N06W03		1	13		337		36		198		29		22		0		147		113		88
SAN JUAN 31-6 UNIT #204	13541	SJ 31-6	30N06W03		1	22		1,599		171		941		90		105		0		747		521		90
SAN JUAN 31-6 UNIT #205R	12574	SJ 31-6	30N06W04		1	4		40		4		24		6		3		0		15		13		343
SAN JUAN 31-6 UNIT #206	13542	SJ 31-6	30N06W04		1	10		437		47		257		29		29		0		199		164		92
SAN JUAN 31-6 UNIT #207	13533	SJ 31-6	30N06W06		1	20		707		76		416		52		46		0		318		219		94
SAN JUAN 31-6 UNIT #208	14213	SJ 31-6	30N06W06		1	17		422		45		248		38		28		0		183		128		89
SAN JUAN 31-6 UNIT #209	14214	SJ 31-6	30N07W01		1	10		225		24		132		21		15		0		97		78		87
SAN JUAN 31-6 UNIT #210	13618	SJ 31-6	30N06W02		1	20		1,365		146		803		78		89		0		636		458		168
SAN JUAN 31-6 UNIT #211	13553	SJ 31-6	30N06W02		1	26		1,977		212		1,164		109		129		0		925		616		114
SAN JUAN 31-6 UNIT #212	13615	SJ 31-6	30N06W05		1	12		630		68		371		40		41		0		290		230		164
SAN JUAN 31-6 UNIT #213	13554	SJ 31-6	30N06W05		1	17		855		92		503		55		56		0		393		289		121
SAN JUAN 31-6 UNIT #214	13646	SJ 31-6	31N06W36		1	14		445		48		262		34		29		0		199		151		254
SAN JUAN 31-6 UNIT #215	13616	SJ 31-6	31N06W36		1	21		857		92		504		59		56		0		389		268		150
SAN JUAN 31-6 UNIT #216	13647	SJ 31-6	31N06W35		1	22		786		84		463		58		51		0		353		236		287
SAN JUAN 31-6 UNIT #217	13609	SJ 31-6	31N06W35		1	11		263		28		155		23		17		0		114		91		157
SAN JUAN 31-6 UNIT #218	13671	SJ 31-6	31N06W34		1	16		453		48		266		37		30		0		199		144		265
SAN JUAN 31-6 UNIT #219	13608	SJ 31-6	31N06W34		1	31		1,894		203		1,115		112		124		0		879		538		158
SAN JUAN 31-6 UNIT #220R	18278	SJ 31-6	31N06W33		1	1		4		0		3		1		0		0		1		1		641
SAN JUAN 31-6 UNIT #221	13656	SJ 31-6	31N06W33		1	26		902		97		531		67		59		0		405		254		253
SAN JUAN 31-6 UNIT #222	13666	SJ 31-6	31N06W32		1	9		175		19		103		18		11		0		74		60		220
SAN JUAN 31-6 UNIT #223	13613	SJ 31-6	31N06W32		1	27		1,614		173		950		96		106		0		749		487		149
SAN JUAN 31-6 UNIT #224	13691	SJ 31-6	31N06W31		1	13		396		42		233		32		26		0		176		135		274
SAN JUAN 31-6 UNIT #225R	13697	SJ 31-6	31N06W31		1	25		1,168		125		687		76		76		0		535		350		263

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 19 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

											REVENUE		OPER.						BFIT NET		10% DISC
						LIFE	GROSS GAS		NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		TAXEX M$		M$		M$		M$		NUM
SAN JUAN 31-6 UNIT #228	14419	SJ 31-6	31N06W28		1	16		684		73		403		46		45		0		312		233		272
SAN JUAN 31-6 UNIT #229R	18279	SJ 31-6	31N06W28		1	15		469		50		276		37		31		0		208		153		640
SAN JUAN 31-6 UNIT #230	13555	SJ 31-6	31N06W27		1	27		1,546		166		910		93		101		0		716		463		125
SAN JUAN 31-6 UNIT #231R	17256	SJ 31-6	31N06W27		1	12		354		38		209		29		23		0		156		121		627
SAN JUAN 31-6 UNIT #232	13692	SJ 31-6	30N07W01		1	8		185		20		109		17		12		0		80		66		262
SAN JUAN 31-6 UNIT #233	13693	SJ 31-6	31N06W29		1	21		589		63		346		49		39		0		259		173		227
SAN JUAN 31-6 UNIT #234R	14007	SJ 31-6	31N06W29		1	7		97		10		57		12		6		0		38		33		337
SAN JUAN 32-7 UNIT #203R	12467	SJ 32-7	32N07W22		1	27		2,248		375		2,059		188		229		0		1,642		1,078		621
SAN JUAN 32-7 UNIT #204	13546	SJ 32-7	32N07W36		1	28		2,684		447		2,458		215		273		0		1,969		1,305		412
SAN JUAN 32-7 UNIT #206	12647	SJ 32-7	32N07W27		1	16		931		155		853		86		95		0		672		511		656
SAN JUAN 32-7 UNIT #207	13698	SJ 32-7	32N07W27		1	28		3,397		566		3,111		259		346		0		2,507		1,683		468
SAN JUAN 32-7 UNIT #208	13710	SJ 32-7	32N07W34		1	24		2,684		1,030		5,659		483		629		0		4,547		3,166		469
SAN JUAN 32-7 UNIT #209	13640	SJ 32-7	32N07W35		1	12		1,153		192		1,056		93		117		0		845		690		476
SAN JUAN 32-7 UNIT #210	13598	SJ 32-7	32N07W36		1	20		1,647		274		1,508		138		168		0		1,202		869		433
SAN JUAN 32-7 UNIT #211R	12642	SJ 32-7	32N07W35		1	20		1,214		202		1,112		111		124		0		878		631		618
SAN JUAN 32-7 UNIT #214	13717	SJ 32-7	32N07W34		1	10		214		82		451		75		50		0		326		260		551
SAN JUAN 32-7 UNIT #215	13700	SJ 32-7	32N07W32		1	21		1,562		260		1,431		134		159		0		1,138		815		481
SAN JUAN 32-7 UNIT #216	14422	SJ 32-7	31N07W04		1	7		109		18		100		21		11		0		68		57		581
SAN JUAN 32-7 UNIT #217	13701	SJ 32-7	31N07W04		1	13		342		57		314		45		35		0		234		179		570
SAN JUAN 32-7 UNIT #218	13702	SJ 32-7	31N07W05		1	25		1,422		237		1,302		134		145		0		1,023		675		571
SAN JUAN 32-7 UNIT #219	13703	SJ 32-7	31N07W05		1	22		1,655		276		1,516		141		169		0		1,206		852		572
SAN JUAN 32-7 UNIT #221	13704	SJ 32-7	31N07W08		1	22		1,281		213		1,173		119		130		0		924		641		552
SAN JUAN 32-7 UNIT #222 (APO)	14423	SJ 32-7	32N07W20		1	20		1,299		196		1,077		104		120		0		853		613		588
SAN JUAN 32-7 UNIT #228 FRT.PI	4816	SJ 32-7	31N07W07		1	16		1,643		140		769		66		85		0		617		481		617
SAN JUAN 32-7 UNIT #229	13729	SJ 32-7	31N07W09		1	22		1,290		215		1,181		121		131		0		929		637		566
SAN JUAN 32-7 UNIT #230	12620	SJ 32-7	31N07W17		1	23		1,724		287		1,579		148		176		0		1,255		868		616
SAN JUAN 32-7 UNIT #231	13664	SJ 32-7	31N07W17		1	18		415		69		380		60		42		0		278		191		567
SAN JUAN 32-7 UNIT #232	13705	SJ 32-7	31N07W08		1	15		529		88		485		62		54		0		370		274		556
SAN JUAN 32-7 UNIT #233	14452	SJ 32-7	32N07W20		1	25		2,194		366		2,009		180		223		0		1,606		1,103		592
SAN JUAN 32-7 UNIT #234	14425	SJ 32-7	32N07W32		1	20		1,765		294		1,616		145		180		0		1,292		941		583
SAN JUAN 32-7 UNIT #235	14426	SJ 32-7	32N07W29		1	20		2,632		439		2,410		197		268		0		1,945		1,450		589
SAN JUAN 32-7 UNIT #238	14455	SJ 32-7	32N07W29		1	27		3,457		576		3,166		260		352		0		2,554		1,742		593
SAN JUAN 32-7 UNIT #242	12643	SJ 32-7	32N07W33		1	20		2,187		364		2,003		171		223		0		1,609		1,181		657
SAN JUAN 32-7 UNIT #246A	12147	32-7	32N07W18		1	19		1,669		278		1,529		137		170		0		1,221		867		1354
SAN JUAN 32-7 UNIT COM #213 FRT.	4832	SJ 32-7	31N07W07		1	27		1,535		162		888		92		99		0		697		445		573
SAN JUAN 32-7 UNIT COM #220 FRT.	4835	SJ 32-7	31N07W05		1	25		2,174		317		1,741		156		194		0		1,392		954		619
SAN JUAN 32-7 UNIT COM #224 FRT.	4792	SJ 32-7	32N07W21		1	28		3,018		377		2,073		177		230		0		1,666		1,108		582
SAN JUAN 32-7 UNIT COM #227 FRT.	4843	SJ 32-7	31N07W18		1	21		1,176		154		844		83		94		0		667		468		574
SAN JUAN 32-8 UNIT #202	13657	SJ 32-8	32N08W27		1	28		3,775		431		2,368		193		263		0		1,912		1,289		432
SAN JUAN 32-8 UNIT #203	14507	SJ 32-8	32N08W33		1	22		2,127		243		1,334		117		148		0		1,069		762		584
SAN JUAN 32-8 UNIT #204	14508	SJ 32-8	32N08W34		1	23		2,478		283		1,554		132		173		0		1,249		889		585
SAN JUAN 32-8 UNIT #205	14511	SJ 32-8	32N08W34		1	23		2,524		288		1,584		134		176		0		1,273		906		590
SAN JUAN 32-8 UNIT #206	14445	SJ 32-8	31N08W24		1	13		478		55		300		37		33		0		230		179		548

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 20 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

											REVENUE		OPER.						BFIT NET		10% DISC
						LIFE	GROSS GAS		NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		TAXEX M$		M$		M$		M$		NUM
SAN JUAN 32-8 UNIT #207	13591	SJ 32-8	31N08W22		1	24		1,922		219		1,206		111		134		0		961		664		414
SAN JUAN 32-8 UNIT #208	13557	SJ 32-8	32N08W29		1	29		3,048		348		1,912		164		213		0		1,535		1,008		419
SAN JUAN 32-8 UNIT #213	12648	SJ 32-8	32N08W22		1	22		1,388		158		870		87		97		0		687		473		614
SAN JUAN 32-8 UNIT #218	14509	SJ 32-8	32N08W35		1	19		1,201		137		753		75		84		0		595		430		586
SAN JUAN 32-8 UNIT #219	14510	SJ 32-8	32N08W35		1	27		2,972		339		1,865		158		207		0		1,499		1,010		587
SAN JUAN 32-8 UNIT #220	13706	SJ 32-8	31N08W24		1	15		739		84		463		50		52		0		362		276		544
SAN JUAN 32-8 UNIT #221	13642	SJ 32-8	31N08W09		1	16		920		105		577		58		64		0		454		346		499
SAN JUAN 32-8 UNIT #222	13658	SJ 32-8	31N08W09		1	26		1,716		196		1,076		106		120		0		851		558		500
SAN JUAN 32-8 UNIT #223	13643	SJ 32-8	31N08W10		1	22		1,064		121		668		72		74		0		521		358		488
SAN JUAN 32-8 UNIT #224	13644	SJ 32-8	31N08W10		1	28		2,304		263		1,445		133		161		0		1,152		746		486
SAN JUAN 32-8 UNIT #225	14427	SJ 32-8	31N08W15		1	21		1,590		182		998		94		111		0		793		562		517
SAN JUAN 32-8 UNIT #226	13707	SJ 32-8	31N08W15		1	18		1,230		140		772		75		86		0		611		450		487
SAN JUAN 32-8 UNIT #227	14428	SJ 32-8	31N08W16		1	17		856		98		537		57		60		0		420		311		473
SAN JUAN 32-8 UNIT #228	14429	SJ 32-8	31N08W16		1	20		899		103		564		64		63		0		437		304		471
SAN JUAN 32-8 UNIT #229	13708	SJ 32-8	32N08W20		1	26		3,127		357		1,962		163		218		0		1,580		1,084		501
SAN JUAN 32-8 UNIT #230	13716	SJ 32-8	32N08W28		1	19		2,895		330		1,816		145		202		0		1,469		1,115		510
SAN JUAN 32-8 UNIT #231	13715	SJ 32-8	32N08W28		1	22		2,371		271		1,487		128		165		0		1,194		851		511
SAN JUAN 32-8 UNIT #232	13709	SJ 32-8	32N08W29		1	26		2,413		275		1,514		134		168		0		1,212		818		502
SAN JUAN 32-8 UNIT #233	13712	SJ 32-8	32N08W30		1	23		3,484		398		2,185		174		243		0		1,768		1,271		512
SAN JUAN 32-8 UNIT #234	14430	SJ 32-8	31N08W21		1	15		1,011		115		634		62		70		0		502		385		565
SAN JUAN 32-8 UNIT #235	14431	SJ 32-8	31N08W21		1	14		552		63		346		42		38		0		266		202		564
SAN JUAN 32-8 UNIT #236	14432	SJ 32-8	31N08W22		1	18		1,000		114		627		65		70		0		493		363		577
SAN JUAN 32-8 UNIT #237	13645	SJ 32-8	31N08W23		1	18		868		99		545		60		61		0		424		305		539
SAN JUAN 32-8 UNIT #238	13652	SJ 32-8	31N08W23		1	18		1,512		173		949		86		105		0		757		564		538
SAN JUAN 32-8 UNIT #239	13714	SJ 32-8	32N08W30		1	20		1,389		159		871		84		97		0		691		496		569
SAN JUAN 32-8 UNIT #240	13725	SJ 32-8	31N08W03		1	15		1,039		119		652		63		72		0		516		396		553
SAN JUAN 32-8 UNIT #241	13713	SJ 32-8	31N08W04		1	17		1,248		142		783		74		87		0		622		471		554
SAN JUAN 32-8 UNIT #242	14433	SJ 32-8	31N08W04		1	21		1,259		144		790		79		88		0		623		439		576
SAN JUAN 32-8 UNIT #243	14434	SJ 32-8	31N08W11		1	21		1,307		149		820		81		91		0		647		458		555
SAN JUAN 32-8 UNIT #244	13730	SJ 32-8	31N08W14		1	24		2,058		235		1,291		116		144		0		1,031		714		562
SAN JUAN 32-8 UNIT #245	14435	SJ 32-8	31N08W14		1	14		769		88		483		50		54		0		379		294		563
SAN JUAN 32-8 UNIT #247	12555	SJ 32-8	32N08W19		1	24		3,721		425		2,334		186		259		0		1,889		1,339		1195
SAN JUAN 32-8 UNIT #248	759	SJ 32-8	31N08W11		1	18		1,229		140		771		75		86		0		610		448		568
SAN JUAN 32-8 UNIT #249	14437	SJ 32-8	31N08W03		1	19		1,520		173		954		88		106		0		759		556		557
SAN JUAN 32-8 UNIT #250	13731	SJ 32-8	32N08W33		1	21		1,857		212		1,165		105		129		0		931		665		558
SAN JUAN 32-8 UNIT #253	12649	SJ 32-8	32N08W27		1	19		1,031		118		647		68		72		0		507		362		615
SAN JUAN 32-8 UNIT #254	14084	SJ 32-8	32N08W23		1	16		422		48		265		38		29		0		197		143		622
SAN JUAN 32-8 UNIT #255	1874	SJ 32-8	32N08W24		1	8		245		28		154		21		17		0		116		97		1196
SAN JUAN 32-8 UNIT #256	19424	SJ 32-8	32N08W25		1	7		618		70		387		35		43		0		310		275		628
SAN JUAN 32-8 UNIT #257	16981	SJ 32-8	32N08W19		1	22		1,984		226		1,245		111		138		0		996		711		1197
SAN JUAN 32-8 UNIT #259A	5043	SJ 32-8	32N08W22		1	16		962		110		604		61		67		0		475		357		724
SAN JUAN 32-8 UNIT #261	17021	SJ 32-8	32N08W17		1	14		477		54		299		38		33		0		228		174		1198
SAN JUAN 32-8 UNIT #267A	10123	SJ 32-8	32N08W23		1	20		1,965		224		1,233		108		137		0		988		695		1345

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 21 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

											REVENUE		OPER.						BFIT NET		10% DISC
						LIFE	GROSS GAS		NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		TAXES M$		M$		M$		M$		NUM
SAN JUAN 32-8 UNIT #36	15041	SJ 32-8	32N08W25		1	15		200		23		125		29		14		0		83		57		371
SAN JUAN 32-9 UNIT #104	14466	SJ 32-9	32N10W24		1	24		2,391		53		290		25		32		0		233		161		426
SAN JUAN 32-9 UNIT #105	14467	SJ 32-9	31N09W08		1	13		390		9		47		6		5		0		36		27		427
SAN JUAN 32-9 UNIT #201	14438	SJ 32-9	31N09W02		1	12		266		6		32		5		4		0		24		18		441
SAN JUAN 32-9 UNIT #202	14439	SJ 32-9	31N09W02		1	15		831		18		101		10		11		0		79		60		442
SAN JUAN 32-9 UNIT #209	14273	SJ 32-9	31N10W02		1	9		104		2		13		3		1		0		8		6		443
SAN JUAN 32-9 UNIT #210	14274	SJ 32-9	31N10W02		1	14		193		18		100		22		11		0		67		47		444
SAN JUAN 32-9 UNIT #215	14468	SJ 32-9	32N09W10		1	19		990		22		120		12		13		0		94		68		503
SAN JUAN 32-9 UNIT #217 (APO)	14275	SJ 32-9	32N09W16		1	20		1,263		24		132		13		15		0		105		75		482
SAN JUAN 32-9 UNIT #220	14000	SJ 32-9	31N10W11		1	30		3,571		79		433		36		48		0		350		229		594
SAN JUAN 32-9 UNIT #221	12458	SJ 32-9	31N10W11		1	6		38		1		5		2		1		0		2		2		595
SAN JUAN 32-9 UNIT #222	12556	SJ 32-9	31N10W12		1	2		11		0		1		1		0		0		1		1		596
SAN JUAN 32-9 UNIT #223	12459	SJ 32-9	31N10W12		1	9		132		3		16		3		2		0		11		9		597
SAN JUAN 32-9 UNIT #226	14469	SJ 32-9	32N09W32		1	15		873		19		106		11		12		0		84		65		445
SAN JUAN 32-9 UNIT #228	14440	SJ 32-9	32N09W36		1	27		3,573		79		434		35		48		0		350		237		446
SAN JUAN 32-9 UNIT #229	14267	SJ 32-9	32N10W36		1	20		1,705		38		207		18		23		0		165		120		447
SAN JUAN 32-9 UNIT #230	14470	SJ 32-9	32N10W36		1	19		436		10		53		8		6		0		39		26		448
SAN JUAN 32-9 UNIT #235	14450	SJ 32-9	32N09W36		1	15		945		21		115		11		13		0		91		70		449
SAN JUAN 32-9 UNIT #250	14268	SJ 32-9	31N09W04		1	20		1,937		43		235		20		26		0		189		139		531
SAN JUAN 32-9 UNIT #251	14269	SJ 32-9	31N09W04		1	26		3,004		66		364		30		41		0		294		201		478
SAN JUAN 32-9 UNIT #252	14471	SJ 32-9	31N09W05		1	19		1,446		32		175		16		19		0		140		102		479
SAN JUAN 32-9 UNIT #253	14472	SJ 32-9	31N09W05		1	15		1,036		23		126		12		14		0		100		77		504
SAN JUAN 32-9 UNIT #254	14473	SJ 32-9	31N09W06		1	15		879		19		107		11		12		0		84		65		483
SAN JUAN 32-9 UNIT #255	14474	SJ 32-9	31N09W06		1	18		1,256		28		152		14		17		0		121		89		489
SAN JUAN 32-9 UNIT #257	14475	SJ 32-9	31N09W08		1	22		767		17		93		12		10		0		71		47		545
SAN JUAN 32-9 UNIT #258	14476	SJ 32-9	31N09W09		1	25		1,652		36		200		19		22		0		159		105		506
SAN JUAN 32-9 UNIT #259	14477	SJ 32-9	31N09W09		1	22		1,037		23		126		14		14		0		98		66		490
SAN JUAN 32-9 UNIT #260	14270	SJ 32-9	31N09W10		1	15		926		20		112		11		12		0		89		68		484
SAN JUAN 32-9 UNIT #261	14271	SJ 32-9	31N09W10		1	5		83		2		10		2		1		0		7		6		491
SAN JUAN 32-9 UNIT #262	14478	SJ 32-9	31N09W15		1	23		685		15		83		11		9		0		63		41		492
SAN JUAN 32-9 UNIT #263	14479	SJ 32-9	31N09W15		1	21		660		15		80		11		9		0		61		40		485
SAN JUAN 32-9 UNIT #264	14480	SJ 32-9	31N09W17		1	24		737		16		89		12		10		0		68		43		514
SAN JUAN 32-9 UNIT #268	14482	SJ 32-9	31N10W01		1	17		808		18		98		11		11		0		77		57		535
SAN JUAN 32-9 UNIT #269	14483	SJ 32-9	31N10W01		1	15		530		12		64		8		7		0		49		37		518
SAN JUAN 32-9 UNIT #270	14484	SJ 32-9	32N09W18		1	24		2,358		52		286		25		32		0		230		159		519
SAN JUAN 32-9 UNIT #271	14485	SJ 32-9	32N09W18		1	31		5,647		125		685		52		76		0		557		373		520
SAN JUAN 32-9 UNIT #273	14486	SJ 32-9	32N09W19		1	10		858		19		104		9		12		0		83		70		521
SAN JUAN 32-9 UNIT #274	14272	SJ 32-9	32N09W28		1	18		1,354		30		164		15		18		0		131		98		575
SAN JUAN 32-9 UNIT #275	14487	SJ 32-9	32N09W29		1	22		1,485		33		180		17		20		0		143		100		536
SAN JUAN 32-9 UNIT #276	14344	SJ 32-9	32N09W27		1	19		1,416		31		172		16		19		0		137		101		579
SAN JUAN 32-9 UNIT #277	14488	SJ 32-9	32N09W30		1	17		1,321		29		160		15		18		0		128		97		516
SAN JUAN 32-9 UNIT #278	14489	SJ 32-9	32N09W31		1	21		1,556		34		189		17		21		0		150		107		515
SAN JUAN 32-9 UNIT #279	14490	SJ 32-9	32N09W31		1	20		1,639		36		199		18		22		0		159		115		528

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 22 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

										REVENUE		OPER.						BFIT NET		10% DISC
						LIFE	GROSS GAS	NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF	MMCF		M$		M$		TAXES M$		M$		M$		M$		NUM
SAN JUAN 32-9 UNIT #281	14491	SJ 32-9	32N09W32		1	29	1,953		43		237		23		26		0		188		120		470
SAN JUAN 32-9 UNIT #282	14345	SJ 32-9	32N09W33		1	23	1,719		38		209		19		23		0		166		116		522
SAN JUAN 32-9 UNIT #283	14346	SJ 32-9	32N09W33		1	26	2,723		60		330		28		37		0		266		179		480
SAN JUAN 32-9 UNIT #284	14492	SJ 32-9	32N10W13		1	18	2,269		50		275		22		31		0		222		168		523
SAN JUAN 32-9 UNIT #285	14493	SJ 32-9	32N10W13		1	17	2,176		48		264		21		29		0		213		165		537
SAN JUAN 32-9 UNIT #286	14494	SJ 32-9	32N10W14		1	19	2,048		45		248		21		28		0		200		149		493
SAN JUAN 32-9 UNIT #287	14495	SJ 32-9	32N10W14		1	20	2,386		53		290		24		32		0		234		173		533
SAN JUAN 32-9 UNIT #288	14496	SJ 32-9	32N10W23		1	15	1,799		40		218		18		24		0		176		139		534
SAN JUAN 32-9 UNIT #289	14497	SJ 32-9	32N10W23		1	28	3,615		80		439		35		49		0		354		239		524
SAN JUAN 32-9 UNIT #291	14498	SJ 32-9	32N10W24		1	19	1,574		35		191		17		21		0		153		113		505
SAN JUAN 32-9 UNIT #292	14499	SJ 32-9	32N10W25		1	25	2,688		59		326		27		36		0		263		181		525
SAN JUAN 32-9 UNIT #293	14500	SJ 32-9	32N10W25		1	16	1,292		29		157		14		17		0		125		96		494
SAN JUAN 32-9 UNIT #294	14501	SJ 32-9	32N10W26		1	21	1,614		36		196		18		22		0		156		112		529
SAN JUAN 32-9 UNIT #295	14502	SJ 32-9	32N10W26		1	20	1,449		32		176		16		20		0		140		102		526
SAN JUAN 32-9 UNIT #296	13928	SJ 32-9	32N10W35		1	11	492		11		60		7		7		0		46		37		560
SAN JUAN 32-9 UNIT #297	13929	SJ 32-9	32N10W35		1	4	69		2		8		2		1		0		6		5		527
SAN JUAN 32-9 UNIT #300	14503	SJ 32-9	32N10W11		1	27	4,129		91		501		39		56		0		406		278		507
SAN JUAN 32-9 UNIT #301	14504	SJ 32-9	32N10W12		1	30	3,871		85		470		38		52		0		379		249		508
SAN JUAN 32-9 UNIT #302 (APO)	15548	SJ 32-9	32N09W09		1	18	902		20		109		12		12		0		86		62		658
SAN JUAN 32-9 UNIT #303 FRT.PI	12172		31N10W14		1	32	820		11		17		0		0		0		17		9		1261
SEYMOUR #720	14357	NON-UNIT	31N09W23		1	20	1,319		96		530		53		59		0		418		300		540
STATE GAS COM AA #1	14441	NON-UNIT	30N08W36		1	23	1,202		24		130		13		14		0		102		69		542
YAGER N COM #5 FRT.PI	4873	NON-UNIT	31N07W03		1	16	644		13		74		9		8		0		57		42		450
TOTAL PROVED DEVELOPED: 320-Acre New Mexico					616		706,708		54,827		301,283		31,028		33,489		0		236,766		163,095
TOTAL PROVED DEVELOPED: NEW MEXICO					932		961,262		78,638		432,073		43,999		48,024		0		340,050		240,612
PROVED UNDEVELOPED RESERVES
BONDS COM #100S	5140	NON-UNIT	32N10W15		1	18	1,000		50		273		28		30		38		178		110		1006
FC FEE COM #2A	5319	NON-UNIT	32N11W30		1	22	1,000		18		99		14		11		23		50		19		1182
FC STATE COM #19A	10781	NON-UNIT	30N09W36		1	22	1,000		20		108		11		12		20		66		27		1346
FEDERAL G #4A COM.PI	5796	SJ 32-7	31N07W10		1	25	2,000		333		1,832		160		204		158		1,310		583		1129
FEDERAL G COM #5	6009	NON-UNIT	31N07W03		1	19	1,400		29		160		15		18		22		105		64		1128
FRT 18-30N-7W (160-ACRE)	6048	NEBU	30N07W18		1	18	800		6		34		3		4		7		21		11		1062
FRT 26-32N-10W	10780	NON-UNIT	32N11W26		1	22	1,200		67		367		36		41		53		238		106		1204
FRT 28-28N-6W (160-ACRE)	6102	28-6	28N06W28		1	15	500		28		155		19		17		46		74		38		1344
FRT 28-31N-6W	1806	31-6	31N06W28		1	22	1,400		150		824		77		92		115		541		240		1289
FRT 29-31N-6W	1805	31-6	31N06W29		1	22	1,400		150		824		77		92		115		541		240		1288
FRT 30-30N-7W (160-ACRE)	1779	30-6	30N07W30		1	20	800		119		653		72		73		123		385		177		1278
FRT 32-31N-6W	1803	31-6	31N06W32		1	22	1,400		150		824		77		92		115		541		240		1287
GRASSY CANYON UNIT #3A	5809	SJ 32-7	32N07W31		1	21	1,500		97		532		49		59		61		363		181		1130
HEIZER #100S	5114	NON-UNIT	32N10W15		1	18	1,000		0		3		0		0		0		2		1		1005

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 23 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

										REVENUE		OPER.						BFIT NET		10% DISC
						LIFE	GROSS GAS	NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF	MMCF		M$		M$		TAXES M$		M$		M$		M$		NUM
HUBBARD GAS COM A #1S	5323	NON-UNIT	32N11W30		1	22	1,000		35		191		27		21		45		97		37		1183
JACQUEZ #331S	5582	NON-UNIT	31N08W07		1	9	300		23		126		15		14		52		45		25		1136
NE BLANCO UNIT #400A	1809	NEBU	31N06W07		1	12	500		4		21		2		2		7		11		5		1290
NE BLANCO UNIT #401A	5317	NEBU	30N07W09		1	7	500		4		21		2		2		6		11		9		834
NE BLANCO UNIT #402A	5145	NEBU	30N07W05		1	7	500		4		21		2		2		5		13		10		1007
NE BLANCO UNIT #404A	6026	NEBU	31N07W34		1	8	500		4		21		2		2		7		11		7		1060
NE BLANCO UNIT #409A	5273	NEBU	30N07W10		1	9	500		4		21		2		2		6		11		7		835
NE BLANCO UNIT #411A	5200	NEBU	30N07W10		1	7	500		4		21		2		2		4		13		11		768
NE BLANCO UNIT #412A	5802	NEBU	31N07W29		1	7	500		4		21		2		2		6		11		9		1310
NE BLANCO UNIT #414A	6023	NEBU	31N07W30		1	8	500		4		21		2		2		7		11		7		1054
NE BLANCO UNIT #415A	5207	NEBU	30N07W02		1	11	500		4		21		2		2		4		13		8		769
NE BLANCO UNIT #416A	5282	NEBU	31N07W21		1	9	500		4		21		2		2		7		11		7		1063
NE BLANCO UNIT #417A	5274	NEBU	30N07W02		1	8	500		4		21		2		2		7		11		8		832
NE BLANCO UNIT #419A	6031	NEBU	30N07W03		1	9	500		4		21		2		2		7		11		7		824
NE BLANCO UNIT #420A	5279	NEBU	31N07W28		1	10	500		4		21		2		2		7		11		6		1065
NE BLANCO UNIT #421A	6033	NEBU	30N07W04		1	10	500		4		21		2		2		7		11		6		825
NE BLANCO UNIT #423A	6037	NEBU	30N07W08		1	10	500		4		21		2		2		7		11		6		827
NE BLANCO UNIT #424A	6034	NEBU	30N07W04		1	10	500		4		21		2		2		7		11		6		1035
NE BLANCO UNIT #425A	6038	NEBU	30N07W08		1	12	500		4		21		2		2		7		11		5		826
NE BLANCO UNIT #427A	5148	NEBU	30N07W16		1	10	500		4		21		2		2		5		13		8		770
NE BLANCO UNIT #429A	5150	NEBU	30N07W17		1	10	500		4		21		2		2		5		13		8		771
NE BLANCO UNIT #431A	6046	NEBU	30N07W17		1	11	500		4		21		2		2		7		11		6		829
NE BLANCO UNIT #432A	5160	NEBU	30N07W07		1	10	500		4		21		2		2		5		13		8		1014
NE BLANCO UNIT #439A	5169	NEBU	30N08W13		1	10	500		4		21		2		2		5		13		8		1016
NE BLANCO UNIT #444A	6016	NEBU	31N07W23		1	9	500		4		21		2		2		7		11		7		1046
NE BLANCO UNIT #446A	6024	NEBU	31N07W33		1	11	500		4		21		2		2		7		11		6		1058
NE BLANCO UNIT #450A	5801	NEBU	31N07W32		1	7	500		4		21		2		2		6		11		9		1056
NE BLANCO UNIT #451A	6035	NEBU	30N07W06		1	12	500		4		21		2		2		7		11		5		1037
NE BLANCO UNIT #452A	5797	NEBU	31N07W15		1	11	500		4		21		2		2		7		11		6		1041
NE BLANCO UNIT #453A	6036	NEBU	30N07W06		1	8	500		4		21		2		2		7		11		8		1036
NE BLANCO UNIT #454A	6025	NEBU	31N07W33		1	7	500		4		21		2		2		6		11		9		1057
NE BLANCO UNIT #455A	5190	NEBU	31N07W31		1	9	500		4		21		2		2		5		13		8		1021
NE BLANCO UNIT #456A	6015	NEBU	31N07W26		1	9	500		4		21		2		2		7		11		7		1049
NE BLANCO UNIT #457	6022	NEBU	31N07W30		1	8	500		4		21		2		2		7		11		8		1066
NE BLANCO UNIT #457A	6014	NEBU	31N07W31		1	10	500		4		21		2		2		7		11		6		1055
NE BLANCO UNIT #459A	5800	NEBU	31N07W19		1	10	500		4		21		2		2		7		11		6		1043
NE BLANCO UNIT #461A	5182	NEBU	30N07W07		1	11	500		4		21		2		2		5		13		7		1024
NE BLANCO UNIT #465A	5243	NEBU	30N08W01		1	11	500		4		21		2		2		4		13		7		1027
NE BLANCO UNIT #466A	6027	NEBU	31N07W34		1	8	500		4		21		2		2		6		11		8		1059
NE BLANCO UNIT #467A	5269	NEBU	30N08W12		1	9	500		4		21		2		2		7		11		7		1061
NE BLANCO UNIT #469A	6007	NEBU	30N08W13		1	10	500		4		21		2		2		7		11		6		1040
NE BLANCO UNIT #470A	6021	NEBU	31N07W27		1	10	500		4		21		2		2		7		11		6		1050
NE BLANCO UNIT #471A	5272	NEBU	31N08W25		1	11	500		4		21		2		2		6		11		6		1064

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 24 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

										REVENUE		OPER.						BFIT NET		10% DISC
						LIFE	GROSS GAS	NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF	MMCF		M$		M$		TAXES M$		M$		M$		M$		NUM
NE BLANCO UNIT #472A	5803	NEBU	31N07W29		1	8	500		4		21		2		2		7		11		8		1052
NE BLANCO UNIT #473A	5281	NEBU	31N08W36		1	11	500		4		21		2		2		7		11		6		1067
NE BLANCO UNIT #475A	1787	NEBU	30N07W19		1	9	500		4		21		2		2		7		11		7		837
NE BLANCO UNIT #476A	5799	NEBU	31N07W22		1	12	500		4		21		2		2		7		11		5		1044
NE BLANCO UNIT #477S	1777	NEBU	30N07W29		1	9	500		4		21		2		2		6		12		8		1276
NE BLANCO UNIT #479A	1785	NEBU	30N07W20		1	9	500		4		21		2		2		7		11		7		839
NE BLANCO UNIT #481A	5153	NEBU	31N07W36		1	11	500		4		21		2		2		5		13		7		773
NE BLANCO UNIT #485A	6032	NEBU	30N07W03		1	8	500		4		21		2		2		7		11		8		823
NE BLANCO UNIT #488A	6019	NEBU	31N07W24		1	8	500		4		21		2		2		7		11		8		1047
NE BLANCO UNIT #489A	5792	NEBU	31N07W12		1	9	500		4		21		2		2		7		11		7		1039
NE BLANCO UNIT #493A	6012	NEBU	31N07W25		1	12	500		4		21		2		2		7		11		5		830
NE BLANCO UNIT #494A	6020	NEBU	31N07W27		1	9	500		4		21		2		2		7		11		7		1051
NE BLANCO UNIT #505A	1784	NEBU	30N07W21		1	9	500		4		21		2		2		7		11		7		838
NORDHAUS #716S	5839	NON-UNIT	31N09W13		1	21	800		58		320		36		36		70		179		72		1131
SAN JUAN 28-6 UNIT #400	6101	28-6	28N06W09		1	15	500		28		155		19		17		46		74		38		1343
SAN JUAN 28-6 UNIT #414S	6100	28-6	28N06W08		1	14	500		28		155		19		17		46		74		38		1342
SAN JUAN 29-6 UNIT #206A	5409	SJ 29-6	29N06W04		1	20	900		109		598		63		67		127		341		162		904
SAN JUAN 29-6 UNIT #211A	6094	SJ 29-6	29N06W20		1	18	900		109		598		63		67		127		341		187		923
SAN JUAN 29-6 UNIT #219A	6079	SJ 29-6	29N06W10		1	20	900		109		598		63		67		127		341		155		910
SAN JUAN 29-6 UNIT #222A	6083	SJ 29-6	29N06W12		1	20	900		109		598		63		67		127		341		154		914
SAN JUAN 29-6 UNIT #223A	6084	SJ 29-6	29N06W12		1	20	900		109		598		63		67		127		341		167		913
SAN JUAN 29-6 UNIT #224A	6085	SJ 29-6	29N06W13		1	22	900		109		598		63		67		127		341		134		916
SAN JUAN 29-6 UNIT #226A	6088	SJ 29-6	29N06W14		1	22	900		109		598		63		67		127		341		134		917
SAN JUAN 29-6 UNIT #257A	5645	SJ 29-6	29N06W09		1	20	900		109		598		63		67		127		341		155		907
SAN JUAN 29-6 UNIT #258A	6089	SJ 29-6	29N06W16		1	22	900		109		598		63		67		127		341		134		920
SAN JUAN 29-6 UNIT #262A	6096	SJ 29-6	29N06W21		1	20	900		109		598		63		67		127		341		166		925
SAN JUAN 29-7 UNIT #519S	6063	29-7	29N07W08		1	18	700		71		388		43		43		80		223		112		1327
SAN JUAN 29-7 UNIT #520S	6062	SJ 29-7	29N07W08		1	17	700		71		388		43		43		80		223		126		888
SAN JUAN 29-7 UNIT #530S	6076	29-7	29N07W34		1	19	700		71		388		43		43		80		223		103		1334
SAN JUAN 29-7 UNIT #532S	1866	29-7	29N07W02		1	18	700		71		388		43		43		80		223		109		1292
SAN JUAN 29-7 UNIT #533S	1550	29-7	29N07W03		1	19	700		71		388		43		43		80		223		104		1270
SAN JUAN 29-7 UNIT #534S	6064	29-7	29N07W09		1	17	700		71		388		43		43		80		223		130		1328
SAN JUAN 29-7 UNIT #538S	6075	29-7	29N07W26		1	19	700		71		388		43		43		80		223		103		1333
SAN JUAN 29-7 UNIT #540S	6065	29-7	29N07W10		1	18	700		71		388		43		43		80		223		111		1329
SAN JUAN 29-7 UNIT #544S	6053	SJ 29-7	29N07W04		1	17	700		71		388		43		43		80		223		126		884
SAN JUAN 29-7 UNIT #546S	6054	29-7	29N07W04		1	18	700		71		388		43		43		80		223		113		1324
SAN JUAN 29-7 UNIT #547S	6061	29-7	29N07W07		1	18	700		71		388		43		43		80		223		110		1326
SAN JUAN 29-7 UNIT #548S	6055	29-7	29N07W07		1	17	700		71		388		43		43		80		223		130		1325
SAN JUAN 29-7 UNIT #551S	6066	29-7	29N07W11		1	17	700		230		1,263		137		140		295		691		364		1330
SAN JUAN 29-7 UNIT #552S	6067	SJ 29-7	29N07W12		1	17	700		71		388		43		43		80		223		124		893
SAN JUAN 29-7 UNIT #553S	1546	SJ 29-7	29N07W14		1	17	700		71		388		43		43		80		223		125		901
SAN JUAN 29-7 UNIT #560S	6072	29-7	29N07W23		1	17	700		290		1,593		175		177		376		866		454		1331
SAN JUAN 29-7 UNIT #562S	6071	SJ 29-7	29N07W24		1	17	700		71		388		43		43		80		223		123		896

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 25 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

										REVENUE		OPER.						BFIT NET		10% DISC
						LIFE	GROSS GAS	NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF	MMCF		M$		M$		TAXES M$		M$		M$		M$		NUM
SAN JUAN 29-7 UNIT #577S	12177	SJ 29-7	29N07W35		1	16	700		52		286		33		32		66		155		88		1206
SAN JUAN 29-7 UNIT #580S	6052	SJ 29-7	29N07W01		1	17	700		71		388		43		43		80		223		124		881
SAN JUAN 29-7 UNIT #582S	1864	29-7	29N07W02		1	18	700		71		388		43		43		80		223		113		1291
SAN JUAN 29-7 UNIT #585S	12212	29-7	29N07W15		1	18	700		71		388		43		43		80		223		110		1357
SAN JUAN 30-5 UNIT #204A	5685	30-5	30N05W07		1	10	500		85		468		43		52		179		194		110		1303
SAN JUAN 30-5 UNIT #205A	5678	30-5	30N05W07		1	7	500		85		468		43		52		179		194		139		1302
SAN JUAN 30-5 UNIT #211A	5783	SJ 30-5	30N05W31		1	9	500		85		468		43		52		179		194		122		986
SAN JUAN 30-5 UNIT #220A	8014	SJ 30-5	30N05W08		1	8	500		85		468		43		52		179		194		135		1203
SAN JUAN 30-5 UNIT #224A	5719	SJ 30-5	30N05W17		1	9	500		85		468		43		52		179		194		121		966
SAN JUAN 30-5 UNIT #227A	5744	SJ 30-5	30N05W28		1	9	500		85		468		43		52		179		194		114		981
SAN JUAN 30-5 UNIT #228A	5745	SJ 30-5	30N05W28		1	9	500		85		468		43		52		179		194		115		980
SAN JUAN 30-5 UNIT #232A	5786	30-5	30N05W33		1	10	500		85		468		43		52		179		194		103		1307
SAN JUAN 30-5 UNIT #233A	5787	SJ 30-5	30N05W33		1	9	500		85		468		43		52		179		194		114		988
SAN JUAN 30-5 UNIT #235A	5743	30-5	30N05W27		1	10	500		85		468		43		52		179		194		111		1306
SAN JUAN 30-5 UNIT #236A	5742	30-5	30N05W27		1	10	500		85		468		43		52		179		194		111		1305
SAN JUAN 30-5 UNIT #238A	5789	30-5	30N05W34		1	11	500		85		468		43		52		179		194		102		1309
SAN JUAN 30-5 UNIT #239A	5716	SJ 30-5	30N05W15		1	7	500		85		468		43		52		210		164		116		964
SAN JUAN 30-5 UNIT #241A	5739	30-5	30N05W23		1	7	500		85		468		43		52		179		194		138		1304
SAN JUAN 30-5 UNIT #242A	5788	30-5	30N05W34		1	10	500		85		468		43		52		179		194		112		1308
SAN JUAN 30-5 UNIT #246A	5741	SJ 30-5	30N05W26		1	9	500		85		468		43		52		179		194		122		978
SAN JUAN 30-5 UNIT #248A	11693	30-5	30N05W35		1	7	500		75		411		39		46		159		167		118		1347
SAN JUAN 30-5 UNIT #249A	5740	SJ 30-5	30N05W23		1	8	500		85		468		43		52		179		194		134		976
SAN JUAN 30-5 UNIT #255A	5714	SJ 30-5	30N05W14		1	7	500		85		468		43		52		184		189		142		962
SAN JUAN 30-5 UNIT #257A	5712	SJ 30-5	30N05W11		1	8	500		85		468		43		52		187		186		126		959
SAN JUAN 30-5 UNIT #258A	5715	SJ 30-5	30N05W14		1	7	500		85		468		43		52		186		187		140		961
SAN JUAN 30-5 UNIT #259A	12145	30-5	30N05W13		1	7	500		85		468		43		52		188		185		129		1353
SAN JUAN 30-5 UNIT #261A	5713	SJ 30-5	30N05W11		1	7	500		85		468		43		52		187		187		136		958
SAN JUAN 30-5 UNIT #262A	5791	SJ 30-5	30N05W12		1	9	500		85		468		43		52		179		194		115		960
SAN JUAN 30-5 UNIT #267A	11794	30-5	30N05W24		1	7	500		85		468		43		52		179		194		137		1348
SAN JUAN 30-5 UNIT #268A	11795	30-5	30N05W24		1	7	500		85		468		43		52		189		184		127		1349
SAN JUAN 30-6 UNIT #403S	5435	SJ 30-6	30N06W09		1	16	700		35		192		22		21		39		110		65		777
SAN JUAN 30-6 UNIT #406S	6043	SJ 30-6	30N07W15		1	16	700		35		192		22		21		35		115		71		861
SAN JUAN 30-6 UNIT #407S	5527	SJ 30-6	30N06W16		1	18	700		35		192		22		21		41		108		56		849
SAN JUAN 30-6 UNIT #409S	5521	SJ 30-6	30N07W25		1	17	700		35		192		22		21		29		120		74		780
SAN JUAN 30-6 UNIT #416S	5519	SJ 30-6	30N07W24		1	17	700		35		192		22		21		33		116		70		783
SAN JUAN 30-6 UNIT #417S	5429	SJ 30-6	30N07W25		1	17	700		35		192		22		21		29		120		74		762
SAN JUAN 30-6 UNIT #418S	5522	SJ 30-6	30N07W26		1	16	700		35		192		22		21		31		118		74		784
SAN JUAN 30-6 UNIT #421S	1622	30-6	30N07W34		1	19	700		35		192		22		21		41		108		50		1271
SAN JUAN 30-6 UNIT #423S	1782	30-6	30N07W28		1	18	700		35		192		22		21		41		108		53		1280
SAN JUAN 30-6 UNIT #428S	1783	30-6	30N07W28		1	19	700		35		192		22		21		41		108		50		1281
SAN JUAN 30-6 UNIT #429S	1773	30-6	30N07W32		1	16	700		35		192		22		21		33		116		73		1273
SAN JUAN 30-6 UNIT #439S	5524	SJ 30-6	30N06W14		1	18	700		35		192		22		21		41		108		56		846
SAN JUAN 30-6 UNIT #440S	5526	SJ 30-6	30N06W15		1	18	700		35		192		22		21		41		108		56		847

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 26 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

										REVENUE		OPER.						BFIT NET		10% DISC
						LIFE	GROSS GAS	NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF	MMCF		M$		M$		TAXES M$		M$		M$		M$		NUM
SAN JUAN 30-6 UNIT #441S	5495	SJ 30-6	30N06W31		1	16	700		35		192		22		21		34		115		71		792
SAN JUAN 30-6 UNIT #447S	1776	30-6	30N07W31		1	18	700		35		192		22		21		41		108		55		1275
SAN JUAN 30-6 UNIT #453S	5528	SJ 30-6	30N06W17		1	18	700		35		192		22		21		41		108		55		851
SAN JUAN 30-6 UNIT #456S	5531	SJ 30-6	30N06W18		1	17	700		35		192		22		21		41		108		61		852
SAN JUAN 30-6 UNIT #458S	5532	SJ 30-6	30N06W19		1	18	700		35		192		22		21		41		108		55		854
SAN JUAN 30-6 UNIT #459S	5533	SJ 30-6	30N06W20		1	17	700		35		192		22		21		41		108		61		855
SAN JUAN 30-6 UNIT #464S	5506	SJ 30-6	30N07W14		1	16	700		35		192		22		21		29		120		76		801
SAN JUAN 30-6 UNIT #465S	5507	SJ 30-6	30N07W15		1	16	700		35		192		22		21		29		120		76		802
SAN JUAN 30-6 UNIT #466S	6051	SJ 30-6	30N07W22		1	16	700		35		192		22		21		33		116		71		859
SAN JUAN 30-6 UNIT #470S	5534	SJ 30-6	30N06W21		1	17	700		35		192		22		21		41		108		61		856
SAN JUAN 30-6 UNIT #472S	5536	SJ 30-6	30N06W22		1	18	700		35		192		22		21		41		108		55		857
SAN JUAN 30-6 UNIT #474S	5540	SJ 30-6	30N06W27		1	17	700		35		192		22		21		41		108		60		866
SAN JUAN 30-6 UNIT #480S	5543	SJ 30-6	30N06W30		1	17	700		35		192		22		21		41		108		60		862
SAN JUAN 30-6 UNIT #482S	5494	SJ 30-6	30N06W31		1	16	700		35		192		22		21		34		115		71		805
SAN JUAN 30-6 UNIT #487S	5537	SJ 30-6	30N06W23		1	17	700		35		192		22		21		41		108		61		860
SAN JUAN 30-6 UNIT #492S	5538	30-6	30N06W26		1	18	700		35		192		22		21		47		103		48		1296
SAN JUAN 30-6 UNIT #494S	5498	SJ 30-6	30N06W33		1	16	700		35		192		22		21		32		117		73		812
SAN JUAN 30-6 UNIT #499S	1780	30-6	30N07W30		1	19	700		35		192		22		21		41		108		50		1279
SAN JUAN 30-6 UNIT #500S	1775	30-6	30N07W31		1	18	700		104		571		66		64		123		319		158		1274
SAN JUAN 30-6 UNIT #501SR	5496	SJ 30-6	30N06W32		1	17	700		35		192		22		21		41		108		61		815
SAN JUAN 31 FED 3 #2A	5942	NON-UNIT	31N09W03		1	18	1,500		223		1,224		113		136		168		807		526		1169
SAN JUAN 31-6 UNIT #207A	5615	SJ 31-6	30N06W06		1	20	1,400		150		824		77		92		115		541		305		937
SAN JUAN 31-6 UNIT #208A	5614	SJ 31-6	30N06W06		1	20	1,400		150		824		77		92		115		541		295		938
SAN JUAN 31-6 UNIT #209A	6030	SJ 31-6	30N07W01		1	18	1,400		150		824		77		92		94		561		377		933
SAN JUAN 31-6 UNIT #216A	1788	31-6	31N06W35		1	19	1,400		150		824		77		92		115		541		330		1282
SAN JUAN 31-6 UNIT #218A	1790	31-6	31N06W34		1	19	1,400		150		824		77		92		115		541		330		1284
SAN JUAN 31-6 UNIT #219A	1789	31-6	31N06W34		1	19	1,400		150		824		77		92		115		541		330		1283
SAN JUAN 31-6 UNIT #220A	1791	31-6	31N06W33		1	22	1,400		150		824		77		92		115		541		242		1285
SAN JUAN 31-6 UNIT #221A	1801	31-6	31N06W33		1	22	1,400		150		824		77		92		115		541		240		1286
SAN JUAN 31-6 UNIT #224A	708	SJ 31-6	31N06W31		1	20	1,400		150		824		77		92		115		541		295		1164
SAN JUAN 31-6 UNIT #225A	5611	SJ 31-6	31N06W31		1	20	1,400		150		824		77		92		115		541		302		1163
SAN JUAN 31-6 UNIT #232A	6029	SJ 31-6	30N07W01		1	18	1,400		150		824		77		92		93		562		375		934
SAN JUAN 32-7 UNIT #220A	6011	SJ 32-7	31N07W06		1	20	1,700		248		1,362		122		151		156		933		570		1170
SAN JUAN 32-7 UNIT #233A	5819	SJ 32-7	32N07W20		1	20	1,700		283		1,557		139		173		178		1,066		662		1173
SAN JUAN 32-8 UNIT #206A	5603	SJ 32-8	31N08W24		1	21	2,000		228		1,255		109		139		115		891		572		1158
SAN JUAN 32-8 UNIT #259	6004	SJ 32-8	32N08W22		1	22	2,000		228		1,255		109		139		122		884		491		1153
SAN JUAN 32-8 UNIT #261A	6507	SJ 32-8	32N08W17		1	21	2,000		228		1,255		109		139		122		884		549		1202
SAN JUAN 32-8 UNIT #267	6005	32-8	32N08W23		1	21	2,000		228		1,255		109		139		122		884		532		1323
SAN JUAN 32-9 UNIT #104S	5911	SJ 32-9	32N10W24		1	7	500		11		61		6		7		18		30		23		1107
SAN JUAN 32-9 UNIT #105S	5956	SJ 32-9	31N09W08		1	8	500		11		61		6		7		18		30		22		1084
SAN JUAN 32-9 UNIT #209S	5862	32-9	31N10W02		1	9	500		11		61		6		7		18		30		20		1316
SAN JUAN 32-9 UNIT #210S	5865	32-9	31N10W02		1	9	500		10		55		5		6		16		28		18		1317
SAN JUAN 32-9 UNIT #215S	5992	SJ 32-9	32N09W10		1	7	500		11		61		6		7		18		30		23		1089

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 27 of 28

WILLIAMS PRODUCTION CO.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2005

										REVENUE		OPER.								BFIT NET		10% DISC
						LIFE	GROSS GAS	NET GAS		TO INT.		EXPENSE		ADV&SEV		CAPITAL		REVENUE		REVENUE		SEQ
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF	MMCF		M$		M$		TAXES M$		M$		M$		M$		NUM
SAN JUAN 32-9 UNIT #220S	5897	SJ 32-9	31N10W11		1	7	500		11		61		6		7		18		30		23		1090
SAN JUAN 32-9 UNIT #221S	5890	SJ 32-9	31N10W11		1	7	500		11		61		6		7		18		30		23		1091
SAN JUAN 32-9 UNIT #222S	5910	32-9	31N10W12		1	9	500		11		61		6		7		18		30		20		1319
SAN JUAN 32-9 UNIT #223S	5902	32-9	31N10W12		1	9	500		11		61		6		7		18		30		20		1318
SAN JUAN 32-9 UNIT #229S	5933	SJ 32-9	32N10W36		1	7	500		11		61		6		7		18		30		23		1125
SAN JUAN 32-9 UNIT #230S	5934	32-9	32N10W36		1	7	500		11		61		6		7		18		31		24		1320
SAN JUAN 32-9 UNIT #251S	5947	32-9	31N09W04		1	8	500		11		61		6		7		21		27		18		1321
SAN JUAN 32-9 UNIT #252S	5949	SJ 32-9	31N09W05		1	7	500		11		61		6		7		21		27		21		1080
SAN JUAN 32-9 UNIT #255S	5955	SJ 32-9	31N09W06		1	7	500		11		61		6		7		18		30		23		1081
SAN JUAN 32-9 UNIT #258S	5958	SJ 32-9	31N09W09		1	7	500		11		61		6		7		18		30		23		1086
SAN JUAN 32-9 UNIT #259S	5959	SJ 32-9	31N09W09		1	7	500		11		61		6		7		21		27		21		1085
SAN JUAN 32-9 UNIT #260S	5960	SJ 32-9	31N09W10		1	7	500		11		61		6		7		18		30		23		1088
SAN JUAN 32-9 UNIT #262S	5834	SJ 32-9	31N09W15		1	7	500		11		61		6		7		18		30		23		1099
SAN JUAN 32-9 UNIT #263S	5831	32-9	???		1	7	500		11		61		6		7		18		30		23		1311
SAN JUAN 32-9 UNIT #264S	5835	32-9	???		1	7	500		11		61		6		7		18		30		23		1312
SAN JUAN 32-9 UNIT #266S	5836	32-9	???		1	7	500		11		61		6		7		18		30		23		1313
SAN JUAN 32-9 UNIT #268S	5859	32-9	31N10W01		1	9	500		11		61		6		7		18		31		20		1314
SAN JUAN 32-9 UNIT #269S	5860	32-9	31N10W01		1	9	500		11		61		6		7		18		30		20		1315
SAN JUAN 32-9 UNIT #272S	726	SJ 32-9	32N09W21		1	7	500		11		61		6		7		18		30		23		1262
SAN JUAN 32-9 UNIT #278S	5967	SJ 32-9	32N09W31		1	7	500		11		61		6		7		18		30		23		1117
SAN JUAN 32-9 UNIT #285S	5855	SJ 32-9	32N10W13		1	7	500		11		61		6		7		21		27		20		1096
SAN JUAN 32-9 UNIT #288S	5916	SJ 32-9	32N10W23		1	7	500		11		61		6		7		21		27		20		1106
SAN JUAN 32-9 UNIT #292S	5925	SJ 32-9	32N10W25		1	7	500		11		61		6		7		18		30		23		1109
SAN JUAN 32-9 UNIT #296S	5853	SJ 32-9	32N10W35		1	7	500		11		61		6		7		18		30		23		1123
SAN JUAN 32-9 UNIT #297S	5854	SJ 32-9	32N10W35		1	7	500		11		61		6		7		17		31		24		1122
SEYMOUR #720S	12603	NON-UNIT	31N09W23		1	17	800		58		321		36		36		53		197		125		1134
STATE GAS COM AA #1A	10782	NON-UNIT	30N08W36		1	23	1,100		22		119		11		13		18		77		33		1205
SUTER #4A	5348	NON-UNIT	32N11W15		1	19	1,000		17		96		14		11		9		62		39		1293
TOTAL PROVED UNDEVELOPED: 160-Acre New Mexico					214		152,498		11,703		64,321		6,348		7,150		13,790		37,034		20,701
FRT 18-30N-7W	6047	NEBU	30N07W18		1	21	800		6		34		3		4		7		21		9		1042
SAN JUAN 29-7 UNIT #585	12211	29-7	29N07W15		1	17	700		71		388		43		43		80		223		121		1356
SAN JUAN 30-5 UNIT #225A	5773	SJ 30-5	30N05W29		1	11	500		85		468		43		52		179		194		99		982
SAN JUAN 32-7 UNIT #227A	6010	SJ 32-7	31N07W18		1	19	1,700		213		1,170		105		130		189		746		471		1162
TOTAL PROVED UNDEVELOPED: 320-Acre New Mexico					4		3,700		375		2,061		194		229		454		1,183		699
TOTAL PROVED UNDEVELOPED: NEW MEXICO					218		156,198		12,078		66,382		6,541		7,379		14,244		38,217		21,401
TOTAL PROVED RESERVES: NEW MEXICO					1150		1,117,460		90,716		498,454		50,540		55,403		14,244		378,267		262,013
TOTAL PROVED RESERVES					1171		1,151,842		97,748		528,517		50,540		55,403		14,244		408,330		282,646

DATE: 12/31/2005 This page is a part of a Miller and Lents, Ltd. report dated 01/12/2006 and should not be used independently of the report. TABLE 4
Page 28 of 28