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, 2004

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	(I.R.S. employer identification number)
incorporation or organization)
Trust Division	75202
Royalty Trust Group	(Zip Code)
Bank of America, N.A.
901 Main Street, 17th Floor
Dallas, Texas
(Address of principal executive offices)

Registrant’s telephone number, including area code:
(214) 209-2400

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

	Name of Each Exchange
Title of Each Class	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 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 an accelerated filer (as defined in Rule 12b-2 of the Securities and Exchange Act of 1934). Yes þ No o

     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, 2004 and the number of shares reported by the Williams Companies Inc. in its Form 4 filed on April 14, 2004) 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 $120,371,092.

     At March 1, 2005, 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 2. Properties	18
THE ROYALTY INTERESTS	18
The Underlying Properties	19
The NPI	21
Reserve Report	22
Historical Gas Sales Prices and Production	24
NPI Percentage Reduction	24
Gas Purchase Contract	24
Gas Gathering Contract	26
Federal and Indian Lands	27
Sale and Abandonment of Underlying Properties	28
The Infill Wells	29
Royalty Trust Reserves	29
Williams’ Performance Assurances	29
Title to Properties	30
Item 3. Legal Proceedings	31
Item 4. Submission of Matters to a Vote of Security Holders	32
PART II	32
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
Item 6. Selected Financial Data	32
Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations	32
Critical Accounting Policies and Estimates	32
Liquidity and Capital Resources	33
Results of Operations	33
Off-Balance Sheet Arrangements	35

	Page
Tabular Disclosure of Contractual Obligations	35
Forward-Looking Statements	35
Item 7A. Quantitative and Qualitative Disclosure About Market Risk	36
Item 8. Financial Statements and Supplementary Data	36
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	45
Item 9A. Controls and Procedures	45
Item 9B. Other Information	46
PART III	46
Item 10. Directors and Executive Officers of the Registrant	46
Item 11. Executive Compensation	46
Item 12. Security Ownership of Certain Beneficial Owners and Management	47
Williams’s Voting Authority Over Units	47
Item 13. Certain Relationships and Related Transactions	48
Administrative Services Agreement	48
Potential Conflicts of Interest	48
Item 14. Principal Accounting Fees and Services	48
PART IV	49
Item 15. Exhibits and Financial Statement Schedules	49
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, 2004 Reserve Report” means the Reserve Report, dated January 5, 2005, 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, 2004, 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 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.

1

     “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

2

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, 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.

3

     “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

4

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 2,633,700 of these Units through March 9, 2005 and owned a remaining 935,091 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.

5

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 450 infill locations designated as proved locations according to SEC guidelines. As of December 31, 2004, 249 infill locations are proved developed producing and 201 locations are proved undeveloped. Infill drilling is expected to be substantially completed by the end of 2006.

     As of December 31, 2004, the Infill Net Profit Costs exceed the Infill Net Profit Gross Proceeds by $7,561,581. 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

6

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

7

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.

     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, 2005, there were 9,700,000 Units outstanding. The Trust may not issue additional Units.

8

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 Quatro Finale 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

9

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

10

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

11

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 2004, 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

12

	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. Except for the foregoing, there were no other IRC provisions that allowed for the carryback or carryforward of Section 29 tax credits. As the carryforward of unused Section 29 tax credits is related to the alternative minimum tax calculation for succeeding years, carryforwards should continue to be allowed, even though the Section 29 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.

13

Non-Passive Activity Income, Credits and Loss	The income, credits and expenses of the Trust are not taken into 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.

14

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

15

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 marketing production from the Underlying Properties cannot be fully predicted at this time; however, it is possible such impact could be significant.

     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 jurisdictions have also imposed permitting 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 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

16

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.

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 presented by alternative fuel sources, including heating oil and other fossil fuels.

     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 after spiking up during the winter months. 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.”

     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

17

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 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

18

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 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 627 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

19

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 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, 2004 prepared by Miller and Lents, Ltd. dated January 5, 2005 (the “December 31, 2004 Reserve Report”) regarding the Federal Units in which the WI Properties participate. At December 31, 2004, the WI Properties covered 797 gross (86.2 net) coal seam gas wells with working interests ranging from .0490 percent to 100 percent, with an average working interest of approximately 10.80 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, 2004.

		Underlying Properties
				Estimated
				Discounted
				Future Net
		Net Proved		Revenues
		Reserves		(Discounted
Federal Unit	Federal Unit Operator	(Bcf)		at 10%)
				(In Thousands)
San Juan 30-5	Conoco Phillips Petroleum Company		26.4	$	54,653.5
San Juan 32-7	Conoco Phillips Petroleum Company		17.3		36,672.2
San Juan 32-8	Conoco Phillips Petroleum Company		12.1		38.161.3
San Juan 30-6	Meridian Oil Inc.		12.7		25,064.2
San Juan 31-6	Conoco Phillips Petroleum Company		5.4		10,957.9
San Juan 29-6	Conoco Phillips Petroleum Company		9.5		18,527.9
San Juan 29-7	Meridian Oil Inc.		3.7		6,715.5
San Juan 32-9	Meridian Oil Inc.		3.7		7,431.5
Northeast Blanco	Blackwood & Nichols Co., Ltd.		2.1		4,138.3
Huerfano	Meridian Oil Inc.		2.4		3,724.0
San Juan 29-5	Conoco Phillips Petroleum Company		0.7		1,174.2
San Juan 28-6	Meridian Oil Inc.		0.7		1,008.2
San Juan 28-5	Meridian Oil Inc.		0.1		127.8

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

20

     Well Count and Acreage Summary. The following table shows as of December 31, 2004, 2003, and 2002, 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,
2004
Producing		870		99		150,988		20,681
Nonproducing		—		—		—		—
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
2002
Producing		627		72		150,988		20,681
Nonproducing		0		0		0		0
Total		627		72		150,988		20,681

     Of the total gross wells described above at December 31, 2004, 819 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 29 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, 2004, WPC’s working interest and net revenue interests in these wells averaged 0.05889 percent and 18 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, 2004, 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.

     Most of the wells reflected in the December 31, 2004 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, 2004 Reserve Report was prepared on the basis that there will be no capital expenditures borne by the

21

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, 2004, and certain related information for the Royalty Interests and Underlying Properties from the December 31, 2004 Reserve Report prepared by Miller and Lents, Ltd., independent petroleum engineers. A summary of the December 31, 2004 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. 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, 2004 Reserve Report occur. The December 31, 2004 Reserve Report was prepared in accordance with criteria established by the Commission and, accordingly, is based upon a

22

contractual price for gas for December 2004, of $3.72 per MMBtu before transportation charges through 2012. The December 31, 2004 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 $5.21 per MMBtu, based on December 31, 2004 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)		37,388		113,752
Estimated Future Net Revenues (in millions)(c)	$	91,665	$	345,157
Discounted Estimated Future Net Revenues (in millions)(c)	$	54,917	$	237,989

(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.

23

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, 2004, 2003 and 2002:

	Year Ended December 31,
	2004		2003		2002
Production from the WI Properties (MMcf)		10,101		10,943		11,992
Weighted average lifting costs (dollars per Mcf)	$	0.37	$	0.32	$	0.31
Weighted average sales price of gas produced from the WI Properties (dollars per Mcf)	$	2.66	$	2.64	$	1.56
Average Blanco Hub Spot Price (dollars per MMBtu)	$	5.21	$	4.42	$	2.58

     The published Blanco Hub Spot Price for December 2004 was $5.95 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 2,227, 2,352, and 2,265 in 2004, 2003, and 2002, 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 monthly price equal to the “Index Price” as described hereafter. For each of the Contract Years 2002, 2003 and 2004, 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, 2005. 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:

24

(i) If the Index Price (as defined below) in any month during any Contract Year, including 2005, 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 2005, 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 2005, 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, 2004, which is based on production volumes and natural gas prices for the twelve months ended September 30, 2004, the Index Price exceeded the Minimum Purchase Price for each month during the year. As of December 31, 2004 and 2003, 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 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

25

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.

     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

26

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 Duke Energy Field Services (“Duke”). WPX Gas Resources has been assigned a one-year gathering contract (with a monthly evergreen provision) whereby Duke 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.

     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.

27

     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 $4,000,000, plus interest. On November 1, 2004, WPC received notice that its appeal was denied in part by the MMS. WPC is currently evaluating the necessary course of action to defend against the claims asserted by the MMS. If WPC does not successfully appeal the MMS decision, 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 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.

28

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 450 infill locations designated as proved locations according to SEC guidelines. As of December 31, 2004, 249 infill locations are proved developed producing and 201 locations are proved undeveloped. Infill drilling is expected to be substantially completed by the end of 2006.

     As of December 31, 2004, the Infill Net Profit Costs exceed the Infill Net Profit Gross Proceeds by $7,561,581. 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, 2004, total proved reserves were 37,388 MMcf, consisting of 35,527 MMcf proved developed producing and 1,861 MMcf proved undeveloped.

     As of December 31, 2004 total proved reserves for the 320-acre spaced wells in the Working Interest Properties were 27,804 MMcf, consisting of 27,395 MMcf proved developed producing and 409 MMcf proved undeveloped.

     As of December 31, 2004 total proved reserves for the infill wells in the Working Interest Properties were 4,746 MMcf, consisting of reserves of 3,294 MMcf proved developed producing and 1,452 MMcf proved undeveloped.

     As of December 31, 2004, total proved reserves for the Farmout Properties were 4,838 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

29

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 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

30

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 Services (“MMS”), 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 $4,000,000, plus interest. On November 1, 2004, WPC received notice that its appeal was denied in part by the MMS. WPC is currently evaluating the necessary course of action to defend against the claims asserted by the MMS. A separate but similar matter is currently under appeal by another major oil and gas producer in the D.C. circuit court. If the D.C. circuit court upholds the lower court ruling, the Trustee has been advised that it is likely that WPC would not appeal the MMS decision. 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.

31

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
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
2003
First Quarter	$	11.65	$	8.68	$	.211473
Second Quarter	$	14.30	$	9.50	$	.378438
Third Quarter	$	13.27	$	11.25	$	.415848
Fourth Quarter	$	13.29	$	8.73	$	.441042

     At March 1, 2005, there were 9,700,000 Units outstanding and approximately 390 Unitholders of record. The Trust does not maintain any equity compensation plans. The Trust did sell nor did it repurchase any Units during the period covered by this report.

Item 6. Selected Financial Data.

	Year Ended December 31,
	2004		2003		2002		2001		2000
Royalty Income	$	15,375,469	$	14,754,582	$	9,296,774	$	24,864,317	$	16,817,935
Distributable Income	$	14,640,744	$	14,012,292	$	8,634,497	$	24,293,901	$	16,319,731
Distributable Income per Unit	$	1.51	$	1.44	$	.89	$	2.50	$	1.68
Distributions per Unit	$	1.50	$	1.45	$	.89	$	2.50	$	1.68
Total Assets at Year End	$	12,317,821	$	14,731,450	$	18,240,451	$	22,621,529	$	30,743,274
Total Corpus at Year End	$	12,285,070	$	14,638,833	$	18,165,048	$	22,544,752	$	30,670,266

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 because 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

32

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 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 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 2004, royalty income received by the Trust amounted to $15,375,469 as compared to $14,754,582 and $9,296,774 for 2003 and 2002, respectively. The increase in royalty income in 2004 compared to 2003 was primarily due to higher natural gas prices. The increase in royalty income in 2003 compared to 2002 was primarily due to higher natural gas prices. Net production related to the royalty income received by the Trust in 2004 was approximately 6,373,931 MMBtu as compared to 6,975,001 MMBtu and 8,271,271 MMBtu in 2003 and 2002,

33

respectively. Retroactive adjustments in 2004 resulting from unit expansions on certain Federal Units increased the natural gas attributable to the NPI of the Underlying Properties by approximately 394,712 MMbtu’s and that of the Trust by approximately 236,827 MMbtu’s (representing a retroactive adjustment based on actual prices in effect during the production period of approximately $680,990 to the Trust). In 2003 similar retroactive adjustments reduced the natural gas attributable to the NPI of the Underlying Properties by approximately 500,000 MMbtu’s and that of the Trust by approximately 300,000 MMbtu’s (representing a retroactive adjustment based on actual prices in effect during the production period of approximately $357,000). The average net natural gas price received for royalty income in 2004 was $2.16 per MMBtu as compared to $2.01 MMBtu and $1.12 MMBtu in 2003 and 2002, respectively. Interest income for 2004 was $10,518 as compared to $9,125 and $7,807 for 2003 and 2002. The increase in interest income for 2004 reflects higher interest rates and an increase in funds available for investment. The increase in interest income in 2003 compared to 2002 reflects lower interest rates but offset by an increase in funds available for investment.

     General and administrative expenses for 2004 were $745,243, as compared to $751,415 and $670,084 for 2003 and 2002, respectively. General and administrative expenses in 2004 were comparable to 2003. The increase in general and administrative expenses in 2003 compared to 2002 was primarily due to higher administrative expenses relating to Sarbanes-Oxley Act compliance in 2003.

     Distributable income for 2004 was $14,640,744 or $1.51 per Unit, compared to $14,012,292 or $1.44 per Unit for 2003, and $8,634,497, or $0.89 per Unit, for 2002. The increase in distributable income in 2004 compared to 2003 was primarily due to higher gas prices but offset by lower net production from the Underlying Properties. The increase in distributable income in 2003 compared to 2002 was primarily due to higher gas prices.

     Reserve values at 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 $5.44 per Mcf, $5.61 per Mcf and $3.125 per Mcf as at December 31, 2004, 2003 and 2002 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, 2004, 2003 and 2002, was based on production volumes and natural gas prices for the 12 months ended in September 30, 2004, 2003 and 2002, 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,
	2004		2003		2002
Production, Net (MMBtu)(1)
WI Properties		8,711,628		9,694,064		11,625,265
Farmout Properties(2)		1,911,591		1,930,937		2,160,187
Average Blanco Hub Spot Price ($/MMBtu)(3)	$	4.78	$	4.19	$	2.31
Average Net Wellhead Price WI Properties ($/MMBtu)	$	2.16	$	2.01	$	1.12

(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.

34

     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.

     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 $4,000,000, plus 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, 2004.

	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 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.

35

Item 7A. Quantitative and Qualitative Disclosure About Market Risk

     The only assets of and sources of income to the Trust are the Royalty Interests, which generally entitle the Trust to receive a share of the net profits from natural gas production from the Underlying Properties. Consequently, the Trust’s financial results can be significantly affected by fluctuations in natural gas prices and the Trust has commodity price risk exposure associated with the natural gas markets in the United States. The Trust does not engage in any hedging activities to manage its price risk associated with natural gas production from the Underlying Properties. The Royalty Interests do not entitle the Trust to control or influence the operation of the Underlying Properties or the sale of gas produced therefrom. Natural gas produced from the WI Properties, which comprises the majority of production attributable to the Royalty Interests, is currently sold by WPC pursuant to the terms of the Gas Purchase Contract. Although the Trust is not a party to the Gas Purchase Contract, the Gas Purchase Contract may significantly impact revenues to the Trust. Although the Gas Purchase Contract mitigates the risk to the Trust of low gas prices, it also limits the ability of the Trust to benefit from the effects of higher gas prices, particularly to the extent a balance exists in the Price Credit Account. See “Item 2 — Properties — The Royalty Interests — Gas Purchase Contract” for detailed information about the Gas Purchase Contract and its impact on the Trust and Unitholders.

     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, 2004 and 2003, and the related Statements of Distributable Income and Changes in Trust Corpus for each of the 3 years in the period ended December 31, 2004, are included in this Form 10-K.

36

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, 2004 and 2003, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2004. 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, 2004 and 2003, and its distributable income and its changes in trust corpus for each of the three years in the period ended December 31, 2004, on the basis of accounting described in Note 2.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma
March 11, 2005

37

Financial Statements
Williams Coal Seam Gas Royalty Trust

Statements of Assets, Liabilities and Trust Corpus

	December 31,
	2004		2003
Assets
Current assets – cash and cash equivalents	$	105,497	$	110,588
Royalty interests in oil and gas properties (less accumulated amortization of $126,354,339 and $123,945,801 at December 31, 2004 and 2003, respectively) (Note 2)		12,212,324		14,620,862
Total	$	12,317,821	$	14,731,450
Liabilities and Trust Corpus
Current liabilities:
Payable to The Williams Companies, Inc. (Note 4)	$	—	$	67,914
Other accounts payable		32,751		24,703
Current liabilities		32,751		92,617
Trust corpus (9,700,000 units of beneficial interest authorized and outstanding) (Note 2)		12,285,070		14,638,833
Total	$	12,317,821	$	14,731,450

Statements of Distributable Income

	Year Ended December 31,
	2004			2003			2002
Royalty income (Note 2)	$	15,375,469		$	14,754,582		$	9,296,774
Interest income		10,518			9,125			7,807
Total	$	15,385,987		$	14,763,707		$	9,304,581
General and administrative expenses (Note 4)		(745,244	)		(751,415	)		(670,084	)
Distributable income	$	14,640,743		$	14,012,292		$	8,634,497
Distributable income per Unit (9,700,000 units) (Note 2)	$	1.51		$	1.44		$	.89
Distributions per Unit (Note 5)	$	1.50		$	1.45		$	.89

Statements of Changes in Trust Corpus

	Year Ended December 31,
	2004			2003			2002
Trust corpus, beginning of year	$	14,638,833		$	18,165,048		$	22,544,752
Amortization of royalty interests (Note 2)		(2,408,538	)		(3,504,538	)		(4,404,637	)
Distributable income		14,640,743			14,012,292			8,634,497
Distributions to Unitholders (Note 5)		(14,585,968	)		(14,033,969	)		(8,609,564	)
Trust corpus, end of year	$	12,285,070		$	14,638,833		$	18,165,048

See accompanying notes

38

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 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 2,633,700 of these Units through March 9, 2005 and owned a remaining 935,091 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 28, 2001, and for the period from March 1, 2001 through January 1, 2003, 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”).

39

     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 450 infill locations designated as proved locations according to SEC guidelines. As of December 31, 2004, 249 infill locations are proved developed producing and 201 locations are proved undeveloped. Infill drilling is expected to be substantially completed by the end of 2006.

     As of December 31, 2004, the Infill Net Profit Costs exceed the Infill Net Profit Gross Proceeds by $7,561,581. 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 because 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.

40

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.

     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. Except for the foregoing, there are no IRC provisions that allow for the carryback or carryforward of Section 29 tax credits in any other circumstances. As the carryforward of unused Section 29 tax credits is related to the alternative minimum tax calculation for succeeding years, carryforwards should be allowed even though the Section 29 tax credit is no longer allowed for coal seam gas produced and sold.

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 2004, 2003 and 2002 were $276,847, $268,783 and $260,955, 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 2004, 2003 and 2002 were $52,660, $51,306 and $48,452, 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.

     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

41

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, 2005.

     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, 2004 and 2003, 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 no balance exists in the Price Credit Account at December 31, 2004, when the market price for natural gas exceeds $1.94 per MMBtu (as was the case during all months in 2004, 2003 and 2002), 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, 2004, 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. The total impact of these adjustments was to increase the natural gas attributable to the NPI of the Underlying Properties by approximately 394,712 MMbtu’s and that of the Trust by approximately 236,827 MMbtu’s (representing a retroactive adjustment based on actual prices in effect during the production period of approximately $680,990 to the Trust). In the Prior year, similar retroactive adjustments were processed on certain federal units resulting from a payout determination and unit expansion. The total impact of these adjustments was to reduce the natural gas attributable to the NPI of the Underlying Properties by approximately 500,000 MMbtu’s and that of the Trust by approximately 300,000 MMbtu’s (representing a retroactive adjustment based on actual prices in effect during the production period of approximately $357,000). 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, 2004, 2003, and 2002, respectively. There are pending or anticipated applications or approvals for additional participating area enlargements that could impact future results.

42

     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 $4,000,000, plus interest. On November 1, 2004, WPC received notice that its appeal was denied in part by the MMS. WPC is currently evaluating the necessary course of action to defend against the claims asserted by the MMS. A separate but similar matter is currently under appeal by another major oil and gas producer in the D.C. circuit court. If the D.C. circuit court upholds the lower court ruling, the Trustee has been advised that it is likely that WPC would not appeal the MMS decision. 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, 2004, the Trust declared the following distribution:

Quarterly Record Date	Payment Date	Distribution per Unit
February 14, 2005	March 1, 2005	$0.346311

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, 2004 and 2003 (in thousands, except per Unit amounts):

Calendar Quarter	Royalty Income		Distributable Income		Distributions per Unit
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
2003
First	$	2,240	$	1,977	$	.211473
Second		3,888		3,705		.378438
Third		4,191		4,028		.415848
Fourth		4,436		4,302		.441042
TOTAL	$	14,755	$	14,012	$	1.446801

43

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

Royalty income	$	3,723
Interest income	$	4
General and administrative expenses	$	(124	)
Distributable income	$	3,603
Distributable income per Unit (9,700,000 units)	$	.37
Distributions per Unit	$	.37

9. Supplemental Oil and Gas Information (Unaudited)

     The net proved reserves attributable to the Royalty Interests have been estimated as of December 31, 2004, 2003 and 2002, 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 $5.440, $5.61 and $4.25 per MMBtu, after adjustments for certain costs and provisions of the Gas Purchase Contract, at December 31, 2004, 2003, and 2002, respectively. This resulted in a weighted average wellhead price of $3.27, $4.16 and $2.89 per Mcf at December 31, 2004, 2003, and 2002, 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, 2004, 2003 and 2002, 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, 2002		45,339
Production		(8,136	)
Extensions and revisions of previous estimates		2,519
Proved reserves at December 31, 2002		39,722
Production		(7,977	)
Extensions and revisions of previous estimates		12,618
Proved reserves at December 31, 2003		44,363
Production		(7,402	)
Extensions and revisions of previous estimates		427
Proved reserves at December 31, 2004		37,388
Proved developed reserves at December 31, 2004		35,527

     Proved reserve estimates presented above at January 1, 2002 are proved developed reserves. Proved reserves at December 31, 2003, include 2,490 MMcf of proved undeveloped reserves. Proved reserves at December 31, 2004, include 1,861 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

44

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, 2004, 2003 and 2002 relating to proved developed reserves (in thousands):

	Year Ended December 31,
	2004			2003			2002
Future cash inflows	$	106,058		$	125,582		$	78,299
Future production taxes		(11,907	)		(7,565	)		(9,549	)
Future development costs		(2,486	)		(4,334	)		(3,441	)
Future net cash flows		91,665			113,683			65,309
10% discount factor		(36,748	)		(48,357	)		(19,270	)
Standardized measure of discounted future net revenues	$	54,917		$	65,326		$	46,039

     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, 2004, 2003 and 2002 (in thousands):

	2004			2003			2002
Balance at January 1	$	65,326		$	46,039		$	34,438
Increase (decrease) due to:
Net sales of coal seam gas		(15,145	)		(15,504	)		(10,299	)
Net changes in prices and costs		862			13,264			15,503
Development costs incurred		(208	)		(321	)		(629	)
Changes in estimated future development cost		(2,211	)		(834	)		(2,812	)
Extensions and revisions of previous quantity estimates		427			18,580			2,915
Accretion of discount		6,533			4,604			3,444
Other		(667	)		(502	)		3,479
		10,408			19,287			11,601
Balance at December 31	$	54,917		$	65,326		$	46,039

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

     None.

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.

     Trustee’s Report on Internal Control Over Reporting. As permitted by the Order Under Section 36 of the Securities Exchange Act of 1934 Granting an Exemption from Specified Provisions of Exchange Act Rules 13a-1 and 15d-1 issued by the SEC on November 30, 2004, the Trustee will file the Trustee’s Report on Internal Control Over Financial Reporting and the related Attestation Report of Ernst & Young LLP, an independent registered public accounting firm, by April 30, 2005 through an amendment to this annual report on Form 10-K.

45

     There has not been any change in the Trust’s internal control over financial reporting during the fourth quarter of 2004 that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.

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.

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 2004, 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

46

Trustee was paid a 2004 base amount of $46,511, 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 2004 of $46,511 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 2004 were $20,970.

     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 9, 2005 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.(1)		935,091		9.64	%
One Williams Center
Tulsa, Oklahoma 74172

(1) This information was provided to the Securities and Exchange Commission and to the Trustee in a Schedule Form 4 filed with the Securities and Exchange Commission on March 11, 2005, on behalf of The Williams Companies, Inc.

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, 2005, Bank of America, N.A., the Trustee, held an aggregate of 9,144 Units in various fiduciary capacities, with no investment or voting powers. As of March 1, 2004, Chase Bank (as successor to Chemical Bank Delaware), the Delaware Trustee, did not beneficially own any Units.

47

     (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 2004 was $276,847.

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 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, 2003 and 2002 are:

	2004		2003
Audit Fees	$	90,500	$	81,900
Audit-Related Fees	$	0	$	0
Tax Fees	$	0	$	0
All Other Fees	$	0	$	0

     As referenced in Item 10, above, 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.

48

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		37
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2004 and 2003		38
Statements of Distributable Income for each of the three years in the period ended December 31, 2004		38
Statements of Changes in Trust Corpus for each of the three years in the period ended December 31, 2004		38
Notes to Financial Statements		39-45

     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 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).

49

Exhibit
Number		Exhibit
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 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 16, 2005, and submitted pursuant to Rule 13a-14(a)/15d-14(a) and pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

50

Exhibit
Number		Exhibit
32.1	—	Certificate by Bank of America, Trustee of Williams Coal Seam Gas Royalty Trust, dated March 16, 2005, 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 5, 2005 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, 2004, prepared by Miller and Lents, Ltd., independent petroleum engineers.

51

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 16, 2005

(The Registrant has no directors or executive officers.)

52

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).

53

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 16, 2005, 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 16, 2005, 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 5, 2005, 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, 2004, prepared by Miller and Lents, Ltd., independent petroleum engineers.

54

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 report dated March 11, 2005, with respect to the financial statements of the Williams Coal Seam Gas Royalty Trust included in this Annual Report (Form 10-K) for the year ended December 31, 2004.

	/s/ ERNST & YOUNG LLP
Tulsa, Oklahoma
March 11, 2005

EX-23.2

Exhibit 23.2

CONSENT OF MILLER AND LENTS, LTD.

March 15, 2005

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 5, 2005 for reserves as of December 31, 2004.

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)), 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)	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;
c)	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 16, 2005

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, 2004, 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 16, 2005	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

January 5, 2005

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, 2004

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		99,091		309,731		217,300
Proved Undeveloped		14,661		35,426		20,689
Total Proved		113,752		345,157		237,989
The Royalty Interests (Net to the Trust)
Proved Developed		35,527		87,222		52,705
Proved Undeveloped		1,861		4,442		2,212
Total Proved		37,388		91,665		54,917

      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.

Mr. Ron E. Hooper	January 5, 2005
Bank of America, N.A., Trustee	Page 2
Williams Coal Seam Gas Royalty Trust

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, 2004 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, 2004 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 450 infill locations of which 249 have been drilled and 201 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.

      The gas price of $5.440 per MMBtu used in these projections for the Farmout Properties is based on the December 31, 2004 Blanco Hub Index Price reported by WPC. For the Working Interest Properties, the adjusted price of $3.720 per MMBtu was employed as provided for in the Gas Purchase Contract. Beginning in year 2013, after which the contract will no longer be in effect, the gas price is $5.440 per MMBtu, based on the December 31, 2004 Blanco Hub Index Price. Gathering and transportation charges, taxes, treating, and other costs payable prior to the delivery points were deducted

Mr. Ron E. Hooper	January 5, 2005
Bank of America, N.A., Trustee	Page 3
Williams Coal Seam Gas Royalty Trust

from the index price in order to determine the 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, 2004 index gas price of $5.440 per MMBtu less appropriate deductions as reported by WPC.

      Operating expense estimates were based on expenses incurred during 2004 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

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

WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMICS AS OF DECEMBER 31, 2004
UNDERLYING PROPERTIES AND TRUST INTERESTS

NON-ESCALATED 12/31/2004 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%
2005		236,961		20,731		3.830		79,399		5,154		8,189		6,499		59,557		57,187				6,106		12,678		12,079
2006		205,210		17,916		3.829		68,605		4,584		7,103		2,315		54,604		47,603				5,353		11,009		9,505
2007		174,080		14,551		3.829		55,722		3,840		5,763		506		45,612		36,078				4,528		9,276		7,257
2008		144,168		11,699		3.830		44,804		3,200		4,626		42		36,937		26,503				3,719		7,622		5,403
2009		116,207		9,384		3.830		35,941		2,677		3,703				29,561		19,238				3,000		6,166		3,962
2010		93,497		7,548		3.831		28,912		2,261		2,973				23,678		13,975				2,434		5,014		2,919
2011		75,423		6,090		3.831		23,330		1,930		2,395				19,005		10,173				1,987		4,100		2,163
2012		60,991		4,928		3.831		18,879		1,665		1,935				15,279		7,417				1,619		3,347		1,601
2013		49,426		3,997		3.831		15,313		1,450		1,567				12,296		5,413				1,660		6,228		2,685
2014		40,129		3,248		3.832		12,446		1,272		1,272				9,902		3,952				1,348		5,060		1,975
2015		32,633		2,646		3.832		10,139		1,127		1,035				7,977		2,887				1,096		4,114		1,455
2016		26,601		2,162		3.832		8,283		1,012		844				6,427		2,109				892		3,347		1,072
2017		21,682		1,767		3.832		6,771		911		690				5,170		1,538				725		2,722		790
2018		17,693		1,447		3.832		5,544		825		564				4,154		1,120				589		2,213		582
2019		14,424		1,182		3.833		4,531		744		460				3,327		813				478		1,795		428
2020		11,742		962		3.833		3,686		661		374				2,651		587				387		1,452		313
2021		9,444		774		3.833		2,969		575		300				2,094		420				311		1,168		228
2022		7,408		614		3.834		2,354		486		237				1,631		296				248		933		163
2023		5,669		476		3.835		1,824		397		183				1,245		205				197		739		118
2024		4,144		340		3.838		1,306		280		129				898		133				151		570		83
AFTER		14,014		1,292		3.834		4,954		1,308		493				3,153		343				562		2,113		137
TOTAL		1,361,543		113,752		3.830		435,712		36,359		44,835		9,361		345,157		237,989				37,388		91,665		54,917

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 1

WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMICS AS OF DECEMBER 31, 2004
UNDERLYING PROPERTIES AND TRUST INTERESTS

NON-ESCALATED 12/31/2004 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%
2005		225,612		19,705		3.831		75,483		4,884		7,754		—		62,844		60,459				6,106		12,678		12,079
2006		179,036		15,657		3.831		59,986		3,980		6,145		—		49,862		43,512				5,265		10,854		9,371
2007		141,979		12,403		3.832		47,524		3,250		4,852		—		39,422		31,192				4,260		8,804		6,889
2008		113,151		9,879		3.832		37,860		2,686		3,854		—		31,320		22,468				3,452		7,152		5,071
2009		90,547		7,906		3.833		30,302		2,244		3,076		—		24,981		16,247				2,781		5,781		3,716
2010		72,732		6,352		3.833		24,348		1,895		2,466		—		19,988		11,784				2,259		4,706		2,742
2011		58,617		5,123		3.834		19,637		1,618		1,984		—		16,035		8,570				1,848		3,855		2,035
2012		47,386		4,145		3.834		15,890		1,397		1,603		—		12,891		6,245				1,509		3,152		1,509
2013		38,412		3,363		3.834		12,894		1,217		1,298		—		10,379		4,557				1,526		5,733		2,472
2014		31,212		2,735		3.835		10,487		1,067		1,054		—		8,366		3,329				1,241		4,663		1,821
2015		25,411		2,231		3.835		8,553		945		859		—		6,749		2,434				1,010		3,796		1,343
2016		20,752		1,825		3.835		7,000		849		702		—		5,449		1,781				824		3,094		992
2017		16,944		1,495		3.835		5,732		764		574		—		4,394		1,301				671		2,521		732
2018		13,854		1,226		3.835		4,702		690		470		—		3,542		950				546		2,054		540
2019		11,316		1,004		3.836		3,850		619		385		—		2,847		692				444		1,671		398
2020		9,233		818		3.836		3,138		546		313		—		2,279		502				360		1,355		292
2021		7,460		662		3.836		2,539		471		252		—		1,816		362				291		1,094		214
2022		5,975		534		3.837		2,049		403		203		—		1,443		260				235		882		156
2023		4,753		424		3.838		1,626		337		160		—		1,128		185				188		707		114
2024		3,709		320		3.840		1,227		254		120		—		853		126				148		558		81
AFTER		13,854		1,287		3.836		4,937		1,302		492		—		3,143		342				561		2,110		137
TOTAL		1,131,945		99,091		3.833		379,763		31,415		38,617		—		309,731		217,300				35,527		87,222		52,705

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 2

WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMICS AS OF DECEMBER 31, 2004
UNDERLYING PROPERTIES AND TRUST INTERESTS

NON-ESCALATED 12/31/2004 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%
2005		11,348		1,026		3.816		3,916		270		435		6,499		(3,288	)		(3,272	)				—		—		—
2006		26,174		2,259		3.816		8,619		604		958		2,315		4,742			4,090					88		155		134
2007		32,101		2,148		3.816		8,198		590		911		506		6,191			4,886					268		471		367
2008		31,017		1,820		3.816		6,944		514		772		42		5,616			4,035					267		470		332
2009		25,660		1,478		3.816		5,640		433		627		—		4,580			2,991					218		384		246
2010		20,766		1,196		3.816		4,564		366		507		—		3,690			2,191					175		307		178
2011		16,807		968		3.816		3,693		312		411		—		2,970			1,603					139		245		128
2012		13,605		783		3.816		2,989		269		332		—		2,388			1,172					110		194		92
2013		11,014		634		3.816		2,420		233		269		—		1,917			855					133		496		213
2014		8,918		513		3.816		1,959		205		218		—		1,536			623					107		397		154
2015		7,222		416		3.816		1,586		182		176		—		1,228			453					85		318		112
2016		5,849		336		3.816		1,283		163		143		—		978			328					68		253		81
2017		4,738		272		3.816		1,039		148		116		—		776			237					54		201		58
2018		3,838		221		3.816		842		136		94		—		613			170					43		159		42
2019		3,108		178		3.816		680		125		76		—		480			121					34		125		29
2020		2,508		144		3.816		548		116		61		—		372			85					26		97		21
2021		1,984		113		3.816		430		104		48		—		278			58					20		73		14
2022		1,433		80		3.816		305		83		34		—		188			36					14		51		7
2023		916		52		3.816		199		60		22		—		117			20					9		32		4
2024		435		21		3.816		80		26		9		—		45			7					3		11		1
AFTER		160		5		3.816		17		6		1		—		10			2					1		2		0
TOTAL		229,599		14,661		3.816		55,950		4,944		6,219		9,361		35,426			20,689					1,861		4,442		2,212

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report 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, 2004

														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
STATE: COLORADO
PROVED DEVELOPED RESERVES
HENDRICKSON GU B #1 (NPI)		13385	NON-UNIT		32N10W20		1		23		1,677		282		1,131		0		0		0		1,131		770		12
SO UTE TRIBAL I 2 (NPI)		13389	NON-UNIT		32N10W07		1		19		1,917		322		1,293		0		0		0		1,293		947		17
SO UTE TRIBAL J #2 (NPI)		13390	NON-UNIT		32N10W07		1		26		1,545		260		1,042		0		0		0		1,042		671		22
TOTAL PROVED DEVELOPED 160-Acre Colorado							3				5,138		863		3,466		0		0		0		3,466		2,388
CARTER UTE #101 (NPI)		14449	NON-UNIT		32N10W12		1		26		2,774		466		1,871		0		0		0		1,871		1,264		6
CARTER UTE #106 NPI		13397	NON-UNIT		32N10W11		1		26		3,458		581		2,332		0		0		0		2,332		1,594		16
CARTER UTE #107(NPI)		13398	NON-UNIT		32N10W13		1		21		1,656		278		1,117		0		0		0		1,117		794		14
CLARK CUMMINS GU A #1 (NPI)		13383	NON-UNIT		32N10W19		1		32		3,082		518		2,079		0		0		0		2,079		1,294		13
HENDRICKSON GU A #1 (NPI)		13384	NON-UNIT		32N10W20		1		20		1,090		183		735		0		0		0		735		508		11
J B GARDNER GU A #1 (NPI)		13386	NON-UNIT		32N10W22		1		26		2,828		475		1,908		0		0		0		1,908		1,297		18
MONTGOMERY, M H #9 (NPI)		15248	NON-UNIT		32N10W12		1		29		4,273		718		2,882		0		0		0		2,882		1,915		15
ROBIN FRAZIER GU A #1 (NPI)		13387	NON-UNIT		32N10W23		1		24		2,314		389		1,561		0		0		0		1,561		1,075		19
SO UTE 10-3, 32-10 (NPI)		13399	NON-UNIT		32N10W10		1		26		3,147		529		2,123		0		0		0		2,123		1,454		21
SO UTE 15-3, 32-10 (NPI)		13400	NON-UNIT		32N10W15		1		33		4,056		681		2,736		0		0		0		2,736		1,717		9
SO UTE 16-2, 32-10 (NPI)		13401	NON-UNIT		32N10W16		1		27		3,234		543		2,181		0		0		0		2,181		1,468		10
SO UTE TRIBAL H #2 (NPI)		13388	NON-UNIT		32N10W18		1		29		2,151		361		1,451		0		0		0		1,451		916		2
SO UTE TRIBAL KK #1 (NPI)		13391	NON-UNIT		32N10W07		1		21		1,113		187		751		0		0		0		751		509		3
SO UTE TRIBAL LL #1 (NPI)		13392	NON-UNIT		32N10W08		1		21		1,524		256		1,028		0		0		0		1,028		720		4
SO UTE TRIBAL MM #1 (NPI)		13393	NON-UNIT		32N10W08		1		24		1,905		320		1,285		0		0		0		1,285		875		7
SO UTE TRIBAL NN #1 (NPI)		13394	NON-UNIT		32N10W17		1		21		1,491		250		1,006		0		0		0		1,006		700		5
SO UTE TRIBAL OO #1 (NPI)		13395	NON-UNIT		32N10W18		1		17		874		147		589		0		0		0		589		425		8
SO UTE TRIBAL SS #1 (NPI)		13396	NON-UNIT		32N10W21		1		24		1,883		316		1,270		0		0		0		1,270		852		20
TOTAL PROVED DEVELOPED: 320-Acre Colorado							18				42,852		7,199		28,905		0		0		0		28,905		19,376
TOTAL PROVED DEVELOPED: COLORADO							21				47,990		8,062		32,370		0		0		0		32,370		21,764
TOTAL PROVED RESERVES: COLORADO							21				47,990		8,062		32,370		0		0		0		32,370		21,764

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 4 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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
STATE NEW MEXICO
PROVED DEVELOPED RESERVES
BLANCO #202A		5607	NON-UNIT		31N08W26		1		20		1,375		203		775		70		86		0		618		443		1166
BLANCO #203A		5610	NON-UNIT		31N08W35		1		17		761		112		429		45		48		0		336		243		1233
BLANCO #204A		5608	NON-UNIT		31N08W26		1		18		839		124		473		49		53		0		371		269		1165
DECKER GAS COM A #1S		5840	NON-UNIT		32N10W17		1		20		1,800		132		502		42		56		0		404		281		1133
HUERFANO UNIT #258S		2326	HUERFANO		27N10W36		1		14		274		39		148		22		16		0		109		80		1191
MOORE, WAYNE COM #2S		5268	NON-UNIT		31N09W16		1		16		380		14		54		7		6		0		40		29		1034
NE BLANCO UNIT #406A		5192	NEBU		31N07W22		1		17		761		6		23		2		3		0		18		13		1008
NE BLANCO UNIT #407A		17895	NEBU		30N07W21		1		12		218		2		6		1		1		0		5		4		695
NE BLANCO UNIT #408A		5196	NEBU		31N07W20		1		13		243		2		7		1		1		0		5		4		1215
NE BLANCO UNIT #410A		17897	NEBU		31N07W09		1		19		2,557		20		76		5		8		0		62		47		668
NE BLANCO UNIT #413A		17899	NEBU		30N07W20		1		1		6		0		0		0		0		0		0		0		692
NE BLANCO UNIT #418A		5210	NEBU		31N07W28		1		16		606		5		18		2		2		0		14		10		1217
NE BLANCO UNIT #422A		5146	NEBU		31N07W20		1		16		606		5		18		2		2		0		14		10		1011
NE BLANCO UNIT #426A		5231	NEBU		31N06W06		1		17		761		6		23		2		3		0		18		13		1219
NE BLANCO UNIT #430A		5245	NEBU		30N07W05		1		18		917		7		27		2		3		0		22		16		1013
NE BLANCO UNIT #433A		1000	NEBU		30N07W19		1		13		243		2		7		1		1		0		5		4		1208
NE BLANCO UNIT #435A		4894	NEBU		30N08W01		1		17		704		5		21		2		2		0		17		12		999
NE BLANCO UNIT #436A		1149	NEBU		31N06W19		1		16		1,288		10		38		3		4		0		31		24		1004
NE BLANCO UNIT #437A		5251	NEBU		30N08W12		1		17		715		6		21		2		2		0		17		12		1015
NE BLANCO UNIT #438A		1160	NEBU		31N06W18		1		18		846		7		25		2		3		0		20		14		1000
NE BLANCO UNIT #440A		709	NEBU		31N07W11		1		19		1,033		8		31		3		3		0		25		18		1207
NE BLANCO UNIT #441A		1545	NEBU		30N08W24		1		14		669		5		20		2		2		0		16		12		735
NE BLANCO UNIT #442A		17900	NEBU		31N07W11		1		19		2,035		16		60		4		7		0		49		37		666
NE BLANCO UNIT #445A		5250	NEBU		31N08W25		1		17		693		5		21		2		2		0		16		12		1017
NE BLANCO UNIT #447A		5248	NEBU		31N08W36		1		18		911		7		27		2		3		0		22		16		1018
NE BLANCO UNIT #448A		5181	NEBU		31N07W32		1		13		243		2		7		1		1		0		5		4		1019
NE BLANCO UNIT #449A		5183	NEBU		31N07W19		1		17		648		5		19		2		2		0		15		11		1020
NE BLANCO UNIT #457A		5189	NEBU		31N07W30		1		12		770		6		23		2		3		0		18		15		1022
NE BLANCO UNIT #458A		5247	NEBU		31N07W13		1		13		2,074		16		62		4		7		0		51		42		1023
NE BLANCO UNIT #460A		1810	NEBU		31N06W07		1		12		2,399		19		71		5		8		0		59		50		753
NE BLANCO UNIT #462A		5246	NEBU		31N07W01		1		14		318		2		9		1		1		0		7		5		1025
NE BLANCO UNIT #463A		5170	NEBU		30N07W18		1		13		243		2		7		1		1		0		5		4		1213
NE BLANCO UNIT #464A		17898	NEBU		31N07W10		1		16		1,247		10		37		3		4		0		30		23		667
NE BLANCO UNIT #468A		5163	NEBU		31N07W35		1		17		1,300		10		39		3		4		0		31		23		772
NE BLANCO UNIT #478A		5212	NEBU		31N07W21		1		10		141		1		4		1		0		0		3		2		1218
NE BLANCO UNIT #480A		5209	NEBU		31N07W14		1		16		502		4		15		2		2		0		12		9		1029
NE BLANCO UNIT #482A		4895	NEBU		31N07W15		1		16		1,090		8		32		3		4		0		26		20		1002
NE BLANCO UNIT #483A		5149	NEBU		31N07W36		1		17		761		6		23		2		3		0		18		13		774

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 5 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 #484A		4896	NEBU		31N07W16		1		9		215		2		6		1		1		0		5		4		1003
NE BLANCO UNIT #486A		1150	NEBU		31N06W19		1		7		715		6		21		2		2		0		17		15		717
NE BLANCO UNIT #490A		5198	NEBU		31N07W14		1		18		917		7		27		2		3		0		22		16		1216
NE BLANCO UNIT #491A		5147	NEBU		31N07W25		1		17		761		6		23		2		3		0		18		13		1212
NE BLANCO UNIT #495A		1068	NEBU		31N06W30		1		18		1,300		10		39		3		4		0		31		22		754
NE BLANCO UNIT #496A		1161	NEBU		31N06W18		1		14		1,377		11		41		3		5		0		33		27		720
NE BLANCO UNIT #497A		1110	NEBU		31N06W30		1		13		518		4		15		1		2		0		12		9		713
NE BLANCO UNIT #498A		5193	NEBU		31N07W13		1		16		512		4		15		2		2		0		12		9		1214
NE BLANCO UNIT #499A		1152	NEBU		31N06W20		1		18		2,329		18		69		5		8		0		57		43		731
NE BLANCO UNIT #500A		1157	NEBU		31N06W20		1		18		917		7		27		2		3		0		22		16		1209
NE BLANCO UNIT #504A		1163	NEBU		31N07W16		1		15		1,809		14		54		4		6		0		44		35		738
PAYNE #201S		4128	NON-UNIT		32N10W20		1		20		1,291		24		91		8		10		0		72		52		743
SAN JUAN 28-6 UNIT #418S		19353	SJ 28-6		28N06W28		1		9		97		6		24		6		3		0		15		12		639
SAN JUAN 29-6 UNIT #201A		5403	SJ 29-6		29N06W06		1		17		733		89		339		35		38		0		266		193		740
SAN JUAN 29-6 UNIT #202A		5404	SJ 29-6		29N06W06		1		1		2		0		1		0		0		0		0		0		739
SAN JUAN 29-6 UNIT #203A		5406	SJ 29-6		29N06W07		1		20		1,401		169		647		57		72		0		518		371		816
SAN JUAN 29-6 UNIT #204A		5405	SJ 29-6		29N06W07		1		16		598		72		276		31		31		0		215		157		745
SAN JUAN 29-6 UNIT #205A		6095	SJ 29-6		29N06W21		1		17		800		97		369		37		41		0		292		202		926
SAN JUAN 29-6 UNIT #207A		5555	SJ 29-6		29N06W02		1		19		1,212		147		560		51		62		0		446		320		817
SAN JUAN 29-6 UNIT #208A		5551	SJ 29-6		29N06W17		1		11		185		22		85		15		9		0		61		46		995
SAN JUAN 29-6 UNIT #209A		5552	SJ 29-6		29N06W17		1		20		1,233		149		569		52		63		0		454		326		994
SAN JUAN 29-6 UNIT #210A		6093	SJ 29-6		29N06W20		1		17		800		97		369		37		41		0		292		204		924
SAN JUAN 29-6 UNIT #214A		5407	SJ 29-6		29N06W03		1		19		1,085		131		501		47		56		0		398		286		818
SAN JUAN 29-6 UNIT #215A		5408	SJ 29-6		29N06W03		1		22		2,055		249		949		77		105		0		766		546		775
SAN JUAN 29-6 UNIT #216A		5410	SJ 29-6		29N06W04		1		19		1,178		143		544		50		60		0		434		311		742
SAN JUAN 29-6 UNIT #217A		5411	SJ 29-6		29N06W05		1		15		469		57		217		26		24		0		166		122		741
SAN JUAN 29-6 UNIT #218A		5412	SJ 29-6		29N06W05		1		14		379		46		175		23		19		0		133		98		905
SAN JUAN 29-6 UNIT #236A		5553	SJ 29-6		29N06W18		1		16		527		64		244		28		27		0		188		138		819
SAN JUAN 29-6 UNIT #237A		5110	SJ 29-6		29N06W01		1		15		429		52		198		25		22		0		151		111		757
SAN JUAN 29-6 UNIT #238A		5033	SJ 29-6		29N06W01		1		15		445		54		206		25		23		0		158		116		734
SAN JUAN 29-6 UNIT #239A		5616	SJ 29-6		29N06W02		1		16		518		63		239		28		27		0		185		135		903
SAN JUAN 29-6 UNIT #240A		6078	SJ 29-6		29N06W18		1		19		979		118		452		43		50		0		358		258		921
SAN JUAN 29-6 UNIT #241A		6091	SJ 29-6		29N06W19		1		17		800		97		369		37		41		0		292		204		922
SAN JUAN 29-6 UNIT #242A		5554	SJ 29-6		29N06W19		1		19		1,489		180		688		58		76		0		553		406		820
SAN JUAN 29-6 UNIT #245A		5413	SJ 29-6		29N06W08		1		15		447		54		206		25		23		0		158		116		776
SAN JUAN 29-6 UNIT #72A		6098	SJ 29-6		29N06W22		1		18		839		125		475		49		53		0		374		270		1241
SAN JUAN 29-7 UNIT #176		707	SJ 29-7		29N07W22		1		13		161		16		62		12		7		0		43		30		684
SAN JUAN 29-7 UNIT #187		832	SJ 29-7		29N07W03		1		8		82		8		31		7		3		0		21		16		696
SAN JUAN 29-7 UNIT #188		18165	SJ 29-7		29N07W06		1		14		194		20		75		14		8		0		52		37		748
SAN JUAN 29-7 UNIT #189		8020	SJ 29-7		29N07W14		1		17		364		239		912		126		101		0		685		479		694
SAN JUAN 29-7 UNIT #191		945	SJ 29-7		29N07W22		1		12		120		12		46		11		5		0		31		22		749
SAN JUAN 29-7 UNIT #550S		1259	SJ 29-7		29N07W11		1		15		600		63		239		25		27		0		188		136		751

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 6 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 29-7 UNIT #563S		1195	SJ 29-7		29N07W24		1		4		171		75		285		28		32		0		226		209		693
SAN JUAN 30-5 UNIT #201A		5722	SJ 30-5		30N05W19		1		19		1,600		282		1,076		89		120		0		867		602		969
SAN JUAN 30-5 UNIT #202A		1551	SJ 30-5		30N05W06		1		19		1,600		238		907		77		101		0		729		519		947
SAN JUAN 30-5 UNIT #203A		9785	SJ 30-5		30N05W06		1		17		1,892		323		1,231		96		137		0		998		768		644
SAN JUAN 30-5 UNIT #206A		5721	SJ 30-5		30N05W18		1		19		1,600		282		1,076		89		120		0		867		612		967
SAN JUAN 30-5 UNIT #207A		5034	SJ 30-5		30N05W18		1		16		507		86		330		39		37		0		255		186		756
SAN JUAN 30-5 UNIT #208A		5723	SJ 30-5		30N05W19		1		19		1,600		282		1,076		89		120		0		867		602		968
SAN JUAN 30-5 UNIT #209A		5781	SJ 30-5		30N05W30		1		19		1,600		282		1,076		89		120		0		867		602		984
SAN JUAN 30-5 UNIT #210A		5780	SJ 30-5		30N05W30		1		19		1,600		282		1,076		89		120		0		867		607		985
SAN JUAN 30-5 UNIT #212A		5782	SJ 30-5		30N05W31		1		19		1,600		282		1,076		89		120		0		867		602		987
SAN JUAN 30-5 UNIT #213A		17901	SJ 30-5		30N05W05		1		6		280		48		182		18		20		0		144		127		643
SAN JUAN 30-5 UNIT #214A		8013	SJ 30-5		30N05W05		1		13		898		153		584		52		65		0		468		370		642
SAN JUAN 30-5 UNIT #215A		5702	SJ 30-5		30N05W08		1		19		1,600		1,400		5,343		428		594		0		4,321		3,073		993
SAN JUAN 30-5 UNIT #216A		5731	SJ 30-5		30N05W20		1		19		1,600		282		1,076		89		120		0		867		602		971
SAN JUAN 30-5 UNIT #217A		5734	SJ 30-5		30N05W21		1		19		1,020		174		664		63		74		0		527		379		1239
SAN JUAN 30-5 UNIT #218A		5720	SJ 30-5		30N05W17		1		19		1,600		273		1,041		86		116		0		839		597		965
SAN JUAN 30-5 UNIT #219A		5108	SJ 30-5		30N05W16		1		13		441		75		287		32		32		0		222		173		730
SAN JUAN 30-5 UNIT #223A		5733	SJ 30-5		30N05W20		1		18		917		156		596		58		66		0		472		340		1238
SAN JUAN 30-5 UNIT #229A		5735	SJ 30-5		30N05W21		1		19		1,600		282		1,076		89		120		0		867		612		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		10		124		21		81		16		9		0		55		43		736
SAN JUAN 30-5 UNIT #234A		5737	SJ 30-5		30N05W22		1		19		1,600		273		1,041		86		116		0		839		597		975
SAN JUAN 30-5 UNIT #237A		5052	SJ 30-5		30N05W16		1		15		886		453		1,730		155		192		0		1,382		1,061		725
SAN JUAN 30-5 UNIT #240A		5738	SJ 30-5		30N05W22		1		19		1,600		282		1,076		89		120		0		867		602		974
SAN JUAN 30-5 UNIT #243A		5718	SJ 30-5		30N05W15		1		19		1,600		273		1,041		86		116		0		839		587		963
SAN JUAN 30-5 UNIT #260A		9786	SJ 30-5		30N05W09		1		15		1,880		320		1,223		93		136		0		994		790		646
SAN JUAN 30-5 UNIT #264A		5710	SJ 30-5		30N05W09		1		19		1,600		282		1,076		89		120		0		867		612		956
SAN JUAN 30-5 UNIT #265A		5711	SJ 30-5		30N05W10		1		19		1,600		273		1,041		86		116		0		839		597		957
SAN JUAN 30-5 UNIT #266A		8017	SJ 30-5		30N05W10		1		19		3,195		545		2,079		152		231		0		1,696		1,285		645
SAN JUAN 30-6 UNIT #136		5428	SJ 30-6		30N06W11		1		18		1,000		1,000		3,816		305		424		0		3,087		2,121		729
SAN JUAN 30-6 UNIT #404S		5516	SJ 30-6		30N07W23		1		17		800		40		152		15		17		0		120		85		778
SAN JUAN 30-6 UNIT #405S		5436	SJ 30-6		30N06W09		1		18		1,000		50		191		18		21		0		151		105		779
SAN JUAN 30-6 UNIT #408S		19395	SJ 30-6		30N06W16		1		19		999		50		190		18		21		0		151		108		685
SAN JUAN 30-6 UNIT #411S		1258	SJ 30-6		30N07W27		1		13		557		28		106		11		12		0		83		64		648
SAN JUAN 30-6 UNIT #412S		996	SJ 30-6		30N07W24		1		17		800		40		152		15		17		0		120		85		781
SAN JUAN 30-6 UNIT #413S		5508	SJ 30-6		30N07W23		1		16		649		32		124		13		14		0		97		71		782
SAN JUAN 30-6 UNIT #414S		1260	SJ 30-6		30N07W35		1		8		66		3		13		4		1		0		8		6		651
SAN JUAN 30-6 UNIT #415S		5077	SJ 30-6		30N07W26		1		17		800		40		152		15		17		0		120		85		761
SAN JUAN 30-6 UNIT #422S		1261	SJ 30-6		30N07W27		1		17		625		31		119		13		13		0		93		68		690
SAN JUAN 30-6 UNIT #425S		1322	SJ 30-6		30N07W33		1		15		1,029		51		196		17		22		0		157		121		652
SAN JUAN 30-6 UNIT #426S		1271	SJ 30-6		30N07W34		1		17		675		34		129		14		14		0		101		73		650
SAN JUAN 30-6 UNIT #427S		1203	SJ 30-6		30N07W35		1		5		36		2		7		2		1		0		4		3		687

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 7 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 30-6 UNIT #431S		5450	SJ 30-6		30N06W10		1		16		606		30		115		13		13		0		90		65		1221
SAN JUAN 30-6 UNIT #432S		5448	SJ 30-6		30N06W10		1		19		1,020		51		194		18		22		0		154		111		1220
SAN JUAN 30-6 UNIT #434S		5469	SJ 30-6		30N06W12		1		13		963		48		184		16		20		0		147		118		1222
SAN JUAN 30-6 UNIT #437S		5504	SJ 30-6		30N06W11		1		21		980		49		187		19		21		0		147		102		790
SAN JUAN 30-6 UNIT #438S		5468	SJ 30-6		30N06W12		1		18		1,000		50		191		18		21		0		151		105		791
SAN JUAN 30-6 UNIT #443S		1206	SJ 30-6		30N06W36		1		15		527		26		100		11		11		0		78		57		649
SAN JUAN 30-6 UNIT #444S		19402	SJ 30-6		30N06W36		1		14		610		30		116		12		13		0		91		71		647
SAN JUAN 30-6 UNIT #445S		5479	SJ 30-6		30N06W13		1		19		1,000		50		191		18		21		0		151		103		794
SAN JUAN 30-6 UNIT #446S		5502	SJ 30-6		30N06W35		1		18		1,000		50		191		18		21		0		151		105		795
SAN JUAN 30-6 UNIT #450S		5437	SJ 30-6		30N06W07		1		18		1,000		50		191		18		21		0		151		105		796
SAN JUAN 30-6 UNIT #451S		5430	SJ 30-6		30N06W07		1		18		772		39		147		15		16		0		116		84		763
SAN JUAN 30-6 UNIT #452S		5438	SJ 30-6		30N06W08		1		18		1,000		50		191		18		21		0		151		105		797
SAN JUAN 30-6 UNIT #457S		5257	SJ 30-6		30N06W19		1		19		1,000		50		191		18		21		0		151		103		764
SAN JUAN 30-6 UNIT #460S		5487	SJ 30-6		30N06W20		1		18		1,000		50		191		18		21		0		151		105		798
SAN JUAN 30-6 UNIT #461S		5503	SJ 30-6		30N07W11		1		19		784		39		149		16		17		0		117		83		799
SAN JUAN 30-6 UNIT #463S		5505	SJ 30-6		30N07W13		1		17		800		40		152		15		17		0		120		85		800
SAN JUAN 30-6 UNIT #468S		5117	SJ 30-6		30N07W36		1		16		515		26		98		11		11		0		76		55		759
SAN JUAN 30-6 UNIT #471S		5488	SJ 30-6		30N06W21		1		22		1,214		61		231		22		26		0		184		125		803
SAN JUAN 30-6 UNIT #475S		5493	SJ 30-6		30N06W27		1		18		1,000		50		191		18		21		0		151		105		804
SAN JUAN 30-6 UNIT #477S		5130	SJ 30-6		30N06W28		1		18		2,011		100		383		30		43		0		311		236		760
SAN JUAN 30-6 UNIT #478S		5137	SJ 30-6		30N06W29		1		19		1,135		57		216		20		24		0		172		124		746
SAN JUAN 30-6 UNIT #481S		5431	SJ 30-6		30N06W30		1		18		1,000		50		191		18		21		0		151		104		765
SAN JUAN 30-6 UNIT #483S		5500	SJ 30-6		30N06W34		1		18		835		42		159		16		18		0		125		91		806
SAN JUAN 30-6 UNIT #484S		5499	SJ 30-6		30N06W34		1		18		1,000		50		191		18		21		0		151		105		807
SAN JUAN 30-6 UNIT #485S		5116	SJ 30-6		30N07W36		1		22		808		40		154		17		17		0		120		79		996
SAN JUAN 30-6 UNIT #486S		5143	SJ 30-6		30N06W23		1		18		917		46		175		17		19		0		138		100		766
SAN JUAN 30-6 UNIT #488S		5490	SJ 30-6		30N06W24		1		16		606		30		115		13		13		0		90		65		808
SAN JUAN 30-6 UNIT #489S		5489	SJ 30-6		30N06W24		1		18		1,000		50		191		18		21		0		151		105		809
SAN JUAN 30-6 UNIT #490S		5492	SJ 30-6		30N06W25		1		21		980		49		187		19		21		0		147		102		810
SAN JUAN 30-6 UNIT #491S		5491	SJ 30-6		30N06W25		1		18		968		48		184		18		20		0		146		102		811
SAN JUAN 30-6 UNIT #493S		5131	SJ 30-6		30N06W32		1		17		715		36		136		14		15		0		107		78		744
SAN JUAN 30-6 UNIT #496S		5501	SJ 30-6		30N06W35		1		18		1,000		50		191		18		21		0		151		105		814
SAN JUAN 31-6 UNIT #201A		1813	SJ 31-6		30N06W01		1		19		1,084		116		443		42		49		0		351		253		706
SAN JUAN 31-6 UNIT #202A		1812	SJ 31-6		30N06W01		1		17		614		66		251		28		28		0		195		142		1211
SAN JUAN 31-6 UNIT #203A		1819	SJ 31-6		30N06W03		1		18		787		84		322		33		36		0		252		183		718
SAN JUAN 31-6 UNIT #204A		1817	SJ 31-6		30N06W03		1		14		706		76		288		29		32		0		228		175		707
SAN JUAN 31-6 UNIT #205A		1821	SJ 31-6		30N06W04		1		6		63		7		26		6		3		0		17		14		712
SAN JUAN 31-6 UNIT #206A		1820	SJ 31-6		30N06W04		1		10		217		23		89		13		10		0		66		52		708
SAN JUAN 31-6 UNIT #210A		1816	SJ 31-6		30N06W02		1		22		1,186		127		485		47		54		0		383		262		719
SAN JUAN 31-6 UNIT #211A		1815	SJ 31-6		30N06W02		1		16		1,366		146		558		48		62		0		449		342		710
SAN JUAN 31-6 UNIT #212A		5613	SJ 31-6		30N06W05		1		18		1,000		107		409		40		45		0		324		221		935
SAN JUAN 31-6 UNIT #213A		5612	SJ 31-6		30N06W05		1		18		1,000		107		409		40		45		0		324		225		936

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 8 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 31-6 UNIT #214A		1360	SJ 31-6		31N06W36		1		19		1,155		124		472		44		52		0		375		270		702
SAN JUAN 31-6 UNIT #215A		1361	SJ 31-6		31N06W36		1		12		832		89		340		30		38		0		272		223		653
SAN JUAN 31-6 UNIT #217A		1363	SJ 31-6		31N06W35		1		15		552		59		226		25		25		0		175		131		703
SAN JUAN 31-6 UNIT #223A		1377	SJ 31-6		31N06W32		1		16		384		41		157		22		17		0		118		85		654
SAN JUAN 31-6 UNIT #229A		1386	SJ 31-6		31N06W28		1		21		1,684		180		688		59		76		0		552		394		715
SAN JUAN 31-6 UNIT #230A		1383	SJ 31-6		31N06W27		1		20		1,398		150		571		51		64		0		457		327		705
SAN JUAN 31-6 UNIT #231A		1384	SJ 31-6		31N06W27		1		14		488		52		199		23		22		0		154		115		704
SAN JUAN 31-6 UNIT #234A		1385	SJ 31-6		31N06W29		1		13		531		57		217		24		24		0		169		131		688
SAN JUAN 32-7 UNIT #203A		5109	SJ 32-7		32N07W22		1		11		446		74		283		30		31		0		222		181		664
SAN JUAN 32-7 UNIT #204A		4126	SJ 32-7		32N07W36		1		19		1,700		283		1,081		91		120		0		870		617		1176
SAN JUAN 32-7 UNIT #206A		719	SJ 32-7		32N07W27		1		17		1,712		285		1,088		89		121		0		879		669		722
SAN JUAN 32-7 UNIT #207A		5812	SJ 32-7		32N07W27		1		19		1,700		283		1,081		91		120		0		870		617		1174
SAN JUAN 32-7 UNIT #208A		970	SJ 32-7		32N07W34		1		9		639		245		936		83		104		0		748		639		670
SAN JUAN 32-7 UNIT #209A		1207	SJ 32-7		32N07W35		1		15		949		158		604		56		67		0		481		369		672
SAN JUAN 32-7 UNIT #210A		4125	SJ 32-7		32N07W36		1		19		1,700		283		1,081		91		120		0		870		617		1177
SAN JUAN 32-7 UNIT #211A		648	SJ 32-7		32N07W35		1		16		1,329		221		845		72		94		0		679		518		721
SAN JUAN 32-7 UNIT #214A		5804	SJ 32-7		32N07W34		1		19		1,700		652		2,489		209		277		0		2,003		1,420		1178
SAN JUAN 32-7 UNIT #215A		1210	SJ 32-7		32N07W32		1		17		1,398		233		889		75		99		0		715		545		671
SAN JUAN 32-7 UNIT #216A		6120	SJ 32-7		31N07W04		1		14		703		117		447		45		50		0		353		272		1242
SAN JUAN 32-7 UNIT #217A		655	SJ 32-7		31N07W04		1		12		1,143		190		727		59		81		0		587		486		716
SAN JUAN 32-7 UNIT #218A		1208	SJ 32-7		31N07W07		1		13		910		152		579		51		64		0		463		372		662
SAN JUAN 32-7 UNIT #219A		6122	SJ 32-7		31N07W05		1		15		1,737		289		1,105		87		123		0		895		714		1243
SAN JUAN 32-7 UNIT #221A		694	SJ 32-7		31N07W08		1		9		155		26		99		17		11		0		71		57		711
SAN JUAN 32-7 UNIT #224A		4795	SJ 32-7		32N07W21		1		18		2,315		289		1,104		86		123		0		896		680		659
SAN JUAN 32-7 UNIT #229A		4893	SJ 32-7		31N07W09		1		15		800		133		509		49		57		0		403		310		714
SAN JUAN 32-7 UNIT #230A		5798	SJ 32-7		31N07W17		1		18		917		153		583		58		65		0		460		332		1171
SAN JUAN 32-7 UNIT #231A		1323	SJ 32-7		31N07W17		1		10		287		48		183		23		20		0		140		114		663
SAN JUAN 32-7 UNIT #232A		4127	SJ 32-7		31N07W08		1		13		1,107		184		704		59		78		0		566		456		709
SAN JUAN 32-7 UNIT #234A		1229	SJ 32-7		32N07W32		1		16		568		95		361		42		40		0		279		203		661
SAN JUAN 32-7 UNIT #238A		1211	SJ 32-7		32N07W29		1		16		2,629		438		1,672		124		186		0		1,362		1,083		674
SAN JUAN 32-7 UNIT #242A		1212	SJ 32-7		32N07W33		1		14		1,200		200		763		65		85		0		614		485		669
SAN JUAN 32-8 UNIT #202A		1495	SJ 32-8		32N08W27		1		18		1,993		227		868		69		96		0		703		534		698
SAN JUAN 32-8 UNIT #203A		1213	SJ 32-8		32N08W33		1		12		777		89		339		31		38		0		270		217		686
SAN JUAN 32-8 UNIT #204A		5142	SJ 32-8		32N08W34		1		16		2,527		288		1,101		82		122		0		897		713		732
SAN JUAN 32-8 UNIT #205A		1504	SJ 32-8		32N08W34		1		15		2,395		273		1,043		78		116		0		849		675		680
SAN JUAN 32-8 UNIT #208A		4275	SJ 32-8		32N08W29		1		13		1,967		224		857		64		95		0		697		575		726
SAN JUAN 32-8 UNIT #218A		1514	SJ 32-8		32N08W35		1		15		2,136		244		930		71		103		0		756		602		691
SAN JUAN 32-8 UNIT #219A		1529	SJ 32-8		32N08W35		1		17		1,653		189		720		59		80		0		581		442		678
SAN JUAN 32-8 UNIT #220A		5602	SJ 32-8		31N08W24		1		16		1,302		149		567		49		63		0		455		348		1232
SAN JUAN 32-8 UNIT #221A		5583	SJ 32-8		31N08W09		1		19		1,020		116		444		43		49		0		352		254		1140
SAN JUAN 32-8 UNIT #222A		5584	SJ 32-8		31N08W09		1		17		1,859		212		810		65		90		0		655		498		1139
SAN JUAN 32-8 UNIT #223A		5588	SJ 32-8		31N08W10		1		13		2,349		268		1,023		75		114		0		834		688		1142

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 9 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 32-8 UNIT #224A		5589	SJ 32-8		31N08W10		1		15		2,220		253		967		73		108		0		787		626		1141
SAN JUAN 32-8 UNIT #225A		5592	SJ 32-8		31N08W15		1		15		923		105		402		37		45		0		320		246		1227
SAN JUAN 32-8 UNIT #226A		5593	SJ 32-8		31N08W15		1		16		1,181		135		514		45		57		0		412		315		1228
SAN JUAN 32-8 UNIT #227A		5594	SJ 32-8		31N08W16		1		17		994		113		433		40		48		0		344		257		1148
SAN JUAN 32-8 UNIT #228A		5595	SJ 32-8		31N08W16		1		16		1,357		155		591		50		66		0		475		363		1147
SAN JUAN 32-8 UNIT #229A		1204	SJ 32-8		32N08W20		1		15		1,980		226		863		66		96		0		700		558		660
SAN JUAN 32-8 UNIT #230A		1544	SJ 32-8		32N08W28		1		8		844		96		368		30		41		0		297		258		697
SAN JUAN 32-8 UNIT #231A		1541	SJ 32-8		32N08W28		1		17		2,668		305		1,162		87		129		0		946		734		677
SAN JUAN 32-8 UNIT #232A		972	SJ 32-8		32N08W29		1		12		675		77		294		28		33		0		233		188		665
SAN JUAN 32-8 UNIT #233A		5675	SJ 32-8		32N08W30		1		19		1,020		116		444		43		49		0		352		254		1237
SAN JUAN 32-8 UNIT #234A		4904	SJ 32-8		31N08W21		1		16		1,030		118		449		41		50		0		358		270		1150
SAN JUAN 32-8 UNIT #235A		5597	SJ 32-8		31N08W21		1		15		806		92		351		34		39		0		278		214		1149
SAN JUAN 32-8 UNIT #236A		5599	SJ 32-8		31N08W22		1		17		761		87		332		35		37		0		260		188		1229
SAN JUAN 32-8 UNIT #237A		5601	SJ 32-8		31N08W23		1		19		1,010		115		440		43		49		0		348		251		1231
SAN JUAN 32-8 UNIT #238A		5600	SJ 32-8		31N08W23		1		22		2,083		238		907		75		101		0		732		521		1230
SAN JUAN 32-8 UNIT #239A		5670	SJ 32-8		32N08W30		1		20		2,000		228		871		71		97		0		703		494		1161
SAN JUAN 32-8 UNIT #240A		5047	SJ 32-8		31N08W03		1		14		1,608		184		700		56		78		0		567		452		997
SAN JUAN 32-8 UNIT #241A		5558	SJ 32-8		31N08W04		1		13		1,807		206		787		60		87		0		640		528		1224
SAN JUAN 32-8 UNIT #242A		5557	SJ 32-8		31N08W04		1		17		735		84		320		34		36		0		251		182		1138
SAN JUAN 32-8 UNIT #243A		1884	SJ 32-8		31N08W11		1		14		644		74		281		29		31		0		221		170		679
SAN JUAN 32-8 UNIT #244A		5591	SJ 32-8		31N08W14		1		16		1,235		141		538		47		60		0		432		330		1226
SAN JUAN 32-8 UNIT #245A		5590	SJ 32-8		31N08W14		1		14		1,401		160		610		50		68		0		493		394		1225
SAN JUAN 32-8 UNIT #247A		5999	SJ 32-8		32N08W19		1		21		2,000		228		870		71		97		0		702		481		1199
SAN JUAN 32-8 UNIT #248A		1885	SJ 32-8		31N08W11		1		11		429		49		187		20		21		0		146		118		676
SAN JUAN 32-8 UNIT #249A		1886	SJ 32-8		31N08W03		1		12		465		53		202		23		23		0		157		123		675
SAN JUAN 32-8 UNIT #250A		5048	SJ 32-8		32N08W33		1		14		2,720		311		1,185		86		132		0		968		797		723
SAN JUAN 32-8 UNIT #253A		1887	SJ 32-8		32N08W27		1		20		2,225		254		969		77		108		0		784		575		699
SAN JUAN 32-8 UNIT #255A		1867	SJ 32-8		32N08W24		1		17		1,420		162		618		52		69		0		497		380		701
SAN JUAN 32-8 UNIT #256A		1888	SJ 32-8		32N08W25		1		15		1,689		193		736		58		82		0		596		473		700
SAN JUAN 32-8 UNIT #257A		6000	SJ 32-8		32N08W19		1		20		2,000		228		871		71		97		0		703		494		1200
SAN JUAN 32-9 UNIT #201S		5935	SJ 32-9		31N09W02		1		17		800		16		61		6		7		0		49		34		1076
SAN JUAN 32-9 UNIT #202S		5939	SJ 32-9		31N09W02		1		17		800		16		61		6		7		0		49		34		1075
SAN JUAN 32-9 UNIT #228S		5978	SJ 32-9		32N09W36		1		17		1,300		26		100		9		11		0		80		58		1127
SAN JUAN 32-9 UNIT #235S		5979	SJ 32-9		32N09W36		1		18		1,300		26		100		9		11		0		80		56		1126
SAN JUAN 32-9 UNIT #250S		5945	SJ 32-9		31N09W04		1		12		1,418		31		119		9		13		0		97		80		1240
SAN JUAN 32-9 UNIT #271S		1351	SJ 32-9		32N09W18		1		17		1,413		31		119		10		13		0		96		73		733
SAN JUAN 32-9 UNIT #277S		5966	SJ 32-9		32N09W30		1		17		1,300		26		100		9		11		0		80		58		1115
SAN JUAN 32-9 UNIT #282S		5975	SJ 32-9		32N09W33		1		17		1,300		26		100		9		11		0		80		58		1121
SAN JUAN 32-9 UNIT #283S		5976	SJ 32-9		32N09W33		1		17		1,300		26		100		9		11		0		80		58		1120
SAN JUAN 32-9 UNIT #284S		1357	SJ 32-9		32N10W13		1		10		1,354		30		114		9		13		0		93		79		998
SAN JUAN 32-9 UNIT #291S		5402	SJ 32-9		32N10W24		1		12		1,158		26		98		8		11		0		79		65		728
SAN JUAN 32-9 UNIT #301S		5857	SJ 32-9		32N10W12		1		20		1,800		36		138		11		15		0		112		79		1095

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 10 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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
STATE COM FC #20A		6006	NON-UNIT		30N08W02		1		19		952		17		65		6		7		0		51		36		1069
TOTAL PROVED DEVELOPED: 160-Acre New Mexico							249				263,367		28,498		108,756		9,533		12,089		0		87,134		64,560
BARNES GAS COM F #1		14369	NON-UNIT		32N11W26		1		14		94		5		20		7		2		0		11		7		474
BLANCO #201		13592	NON-UNIT		31N08W35		1		23		1,262		186		711		69		79		0		563		384		413
BLANCO #202		13651	NON-UNIT		31N08W26		1		25		2,075		306		1,169		101		130		0		938		633		509
BLANCO #203		13649	NON-UNIT		31N08W35		1		14		633		93		357		37		40		0		280		215		498
BLANCO #204R		14451	NON-UNIT		31N08W26		1		17		836		123		471		48		52		0		370		270		591
BLANCO #330		14219	NON-UNIT		31N08W05		1		22		2,793		204		779		61		87		0		631		459		547
BONDS COM #100 (APO)		14220	NON-UNIT		32N10W15		1		22		4,218		210		801		57		89		0		655		484		455
DECKER GAS COM A #1		14370	NON-UNIT		32N10W17		1		25		3,144		230		877		68		97		0		711		496		477
EAGLE #750 (BPO)		14375	NON-UNIT		32N09W16		1		24		1,413		0		0		0		0		0		0		0		495
FC BARNES #1		14371	NON-UNIT		32N11W15		1		33		645		11		43		9		5		0		29		15		418
FC FEE COM #2		14277	NON-UNIT		32N11W30		1		9		57		1		4		2		0		0		2		1		497
FC STATE COM #19		14276	NON-UNIT		30N09W36		1		22		202		4		15		4		2		0		10		5		541
FC STATE COM #20		12651	NON-UNIT		30N08W02		1		25		2,790		50		190		15		21		0		154		106		466
FEDERAL G #4 COM.PI		4755	NON-UNIT		31N07W10		1		22		1,187		49		189		18		21		0		149		103		467
GRASSY CANYON UNIT #3		4762	SJ 32-7		32N07W31		1		29		3,024		195		745		60		83		0		602		394		580
HEIZER #100		14203	NON-UNIT		32N10W15		1		20		3,335		2		6		0		1		0		5		4		378
HUBBARD GAS COM A #1		14250	NON-UNIT		32N11W30		1		17		147		5		19		7		2		0		10		6		496
HUERFANO UNIT #12		14215	HUERFANO		26N10W04		1		1		6		1		3		2		0		0		2		1		352
HUERFANO UNIT #138		17003	HUERFANO		26N09W22		1		12		108		15		58		15		6		0		37		26		350
HUERFANO UNIT #14R		14218	HUERFANO		26N10W05		1		23		332		47		179		33		20		0		127		76		362
HUERFANO UNIT #18 COM		16974	HUERFANO		27N10W32		1		2		11		2		6		2		1		0		3		3		355
HUERFANO UNIT #182		17019	HUERFANO		26N09W28		1		0		1		0		0		0		0		0		0		0		360
HUERFANO UNIT #19		14221	HUERFANO		26N10W05		1		6		47		7		26		7		3		0		16		13		354
HUERFANO UNIT #22		14216	HUERFANO		27N10W33		1		30		482		68		260		44		29		0		187		101		356
HUERFANO UNIT #223		14004	HUERFANO		26N10W04		1		20		312		44		168		29		19		0		121		77		363
HUERFANO UNIT #231		17004	HUERFANO		26N09W06		1		24		501		71		270		39		30		0		201		123		364
HUERFANO UNIT #237		17005	HUERFANO		26N09W17		1		33		646		91		348		53		39		0		257		134		365
HUERFANO UNIT #24		14222	HUERFANO		27N10W29		1		11		171		24		92		16		10		0		65		49		357
HUERFANO UNIT #255		17006	HUERFANO		27N09W31		1		40		1,236		175		667		79		74		0		514		256		369
HUERFANO UNIT #257		17007	HUERFANO		27N10W36		1		40		1,021		144		550		71		61		0		418		207		367
HUERFANO UNIT #282		14512	HUERFANO		27N10W31		1		19		403		57		218		31		24		0		163		109		372
HUERFANO UNIT #286		14202	HUERFANO		27N10W35		1		40		986		139		532		70		59		0		402		190		374
HUERFANO UNIT #46		13951	HUERFANO		26N09W23		1		24		542		77		292		40		32		0		219		135		349
HUERFANO UNIT #501		17009	HUERFANO		26N09W20		1		27		621		88		335		46		37		0		252		148		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		7		86		12		46		10		5		0		31		26		601
HUERFANO UNIT #504		17011	HUERFANO		26N09W22		1		7		80		11		43		9		5		0		29		24		608
HUERFANO UNIT #505		17012	HUERFANO		26N09W30		1		40		943		133		508		69		57		0		383		182		600
HUERFANO UNIT #507		17013	HUERFANO		26N09W27		1		23		446		63		241		37		27		0		177		108		604
HUERFANO UNIT #508		13985	HUERFANO		26N09W26		1		40		1,087		154		586		74		65		0		448		216		605

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 11 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 #509		13999	HUERFANO		27N10W30		1		19		289		41		156		28		17		0		111		71		607
HUERFANO UNIT #518		17014	HUERFANO		26N09W16		1		31		517		73		279		46		31		0		202		107		609
HUERFANO UNIT #520		17015	HUERFANO		26N09W17		1		25		412		58		222		37		25		0		160		94		610
HUERFANO UNIT #521		17016	HUERFANO		27N10W35		1		40		1,365		193		736		83		82		0		571		274		612
HUERFANO UNIT #522		17017	HUERFANO		27N09W31		1		38		1,186		168		640		75		71		0		494		258		611
HUERFANO UNIT #523		14008	HUERFANO		26N09W23		1		24		495		70		267		39		30		0		199		122		613
HUERFANO UNIT #528		12464	HUERFANO		26N10W06		1		27		401		57		216		38		24		0		154		86		620
HUERFANO UNIT #549		13950	HUERFANO		27N10W33		1		16		242		34		131		23		15		0		93		63		598
HUERFANO UNIT #55		14223	HUERFANO		26N09W27		1		20		314		44		169		30		19		0		121		76		347
HUERFANO UNIT #550		17018	HUERFANO		27N10W29		1		25		301		42		162		34		18		0		110		61		606
HUERFANO UNIT #59		13952	HUERFANO		26N09W26		1		9		73		10		39		11		4		0		24		18		348
HUERFANO UNIT #6		14377	HUERFANO		27N10W31		1		25		486		69		262		40		29		0		193		114		359
HUERFANO UNIT #600		706	HUERFANO		27N10W32		1		8		106		15		57		11		6		0		40		32		673
HUERFANO UNIT #70		14224	HUERFANO		26N10W08		1		9		85		12		46		11		5		0		30		23		351
HUERFANO UNIT #74		13988	HUERFANO		27N10W19		1		4		23		3		12		5		1		0		6		5		358
HUERFANO UNIT COM #118		4765	HUERFANO		27N10W30		1		10		137		10		37		7		4		0		26		20		366
HUERFANO UNIT COM #551		4766	HUERFANO		26N09W16		1		10		144		8		29		5		3		0		21		16		626
JACQUEZ #331		14343	NON-UNIT		31N08W06		1		32		3,872		296		1,128		83		125		0		920		588		530
KEYS GAS COM G #1R		14212	NON-UNIT		32N10W27		1		20		1,138		2		6		1		1		0		5		4		375
MOORE, WAYNE COM #2		14442	NON-UNIT		31N09W16		1		23		1,097		41		155		16		17		0		122		82		578
NE BLANCO UNIT #400R		14350	NEBU		31N06W07		1		26		3,453		27		103		7		11		0		84		58		550
NE BLANCO UNIT #401		14278	NEBU		30N07W09		1		13		471		4		14		1		2		0		11		8		34
NE BLANCO UNIT #402		13561	NEBU		30N07W05		1		26		2,602		20		77		6		9		0		63		43		376
NE BLANCO UNIT #403R		14279	NEBU		30N07W09		1		29		2,585		20		77		6		9		0		63		40		189
NE BLANCO UNIT #404R		14280	NEBU		31N07W34		1		7		332		3		10		1		1		0		8		7		561
NE BLANCO UNIT #406		13560	NEBU		31N07W22		1		25		2,275		18		68		5		8		0		55		38		377
NE BLANCO UNIT #407		14281	NEBU		30N07W21		1		21		1,315		10		39		3		4		0		32		22		36
NE BLANCO UNIT #408		13562	NEBU		31N07W20		1		15		817		6		24		2		3		0		19		15		406
NE BLANCO UNIT #409		14282	NEBU		30N07W10		1		19		1,328		10		39		3		4		0		32		23		35
NE BLANCO UNIT #410		14283	NEBU		31N07W09		1		19		2,126		17		63		4		7		0		52		38		421
NE BLANCO UNIT #411		14284	NEBU		30N07W10		1		27		1,852		14		55		4		6		0		44		29		78
NE BLANCO UNIT #412		14285	NEBU		31N07W29		1		24		2,662		21		79		6		9		0		65		45		408
NE BLANCO UNIT #413R		14286	NEBU		30N07W20		1		16		817		6		24		2		3		0		19		15		257
NE BLANCO UNIT #414		13569	NEBU		31N07W30		1		22		2,041		16		61		4		7		0		49		35		403
NE BLANCO UNIT #415		14287	NEBU		30N07W02		1		24		1,373		11		41		3		5		0		33		22		71
NE BLANCO UNIT #416		13563	NEBU		31N07W21		1		23		973		8		29		3		3		0		23		15		395
NE BLANCO UNIT #417		14288	NEBU		30N07W02		1		32		3,345		26		99		7		11		0		81		51		72
NE BLANCO UNIT #418		14289	NEBU		31N07W28		1		11		776		6		23		2		3		0		19		15		410
NE BLANCO UNIT #419		14290	NEBU		30N07W03		1		20		1,811		14		54		4		6		0		44		32		77
NE BLANCO UNIT #420		13564	NEBU		31N07W28		1		6		42		0		1		0		0		0		1		1		394
NE BLANCO UNIT #421R		14291	NEBU		30N07W04		1		17		1,534		12		46		3		5		0		37		28		151
NE BLANCO UNIT #422		13570	NEBU		31N07W20		1		20		1,168		9		35		3		4		0		28		20		397

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 12 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 #423R		14292	NEBU		30N07W08		1		22		2,367		18		70		5		8		0		57		41		286
NE BLANCO UNIT #424		14293	NEBU		30N07W04		1		25		2,934		23		87		6		10		0		71		49		385
NE BLANCO UNIT #425R		14294	NEBU		30N07W08		1		28		3,180		25		94		7		10		0		77		51		169
NE BLANCO UNIT #426		14262	NEBU		31N06W06		1		26		2,551		20		76		6		8		0		62		42		440
NE BLANCO UNIT #427R		14295	NEBU		30N07W16		1		14		784		6		23		2		3		0		19		15		194
NE BLANCO UNIT #428		13571	NEBU		31N07W24		1		21		2,089		16		62		4		7		0		51		36		420
NE BLANCO UNIT #429R		14296	NEBU		30N07W17		1		4		66		1		2		0		0		0		1		1		226
NE BLANCO UNIT #430		13565	NEBU		30N07W05		1		17		929		7		28		2		3		0		22		16		398
NE BLANCO UNIT #431		14297	NEBU		30N07W17		1		32		2,638		21		78		6		9		0		64		39		74
NE BLANCO UNIT #432		13566	NEBU		30N07W07		1		14		302		2		9		1		1		0		7		5		399
NE BLANCO UNIT #433		14298	NEBU		30N07W19		1		13		225		2		7		1		1		0		5		4		76
NE BLANCO UNIT #434		14299	NEBU		31N07W23		1		20		2,666		21		79		5		9		0		65		48		423
NE BLANCO UNIT #435		14300	NEBU		30N08W01		1		24		1,267		10		38		3		4		0		30		20		383
NE BLANCO UNIT #436		13572	NEBU		31N06W19		1		14		793		6		24		2		3		0		19		15		425
NE BLANCO UNIT #437		14301	NEBU		30N08W12		1		27		1,303		10		39		3		4		0		31		20		382
NE BLANCO UNIT #438		14361	NEBU		31N06W18		1		26		1,267		10		38		3		4		0		30		19		452
NE BLANCO UNIT #439		14302	NEBU		30N08W13		1		27		2,881		22		86		6		10		0		70		47		380
NE BLANCO UNIT #440		13573	NEBU		31N07W11		1		23		1,829		14		54		4		6		0		44		31		431
NE BLANCO UNIT #441R		14303	NEBU		30N08W24		1		22		1,092		8		32		3		4		0		26		18		475
NE BLANCO UNIT #442		14304	NEBU		31N07W11		1		24		1,989		15		59		4		7		0		48		33		436
NE BLANCO UNIT #443		14305	NEBU		30N08W24		1		22		1,079		8		32		3		4		0		26		17		381
NE BLANCO UNIT #444		14362	NEBU		31N07W23		1		22		2,724		21		81		6		9		0		66		48		461
NE BLANCO UNIT #445		14306	NEBU		31N08W25		1		27		2,092		16		62		5		7		0		50		33		388
NE BLANCO UNIT #446		14307	NEBU		31N07W33		1		14		511		4		15		2		2		0		12		9		400
NE BLANCO UNIT #447		14308	NEBU		31N08W36		1		17		694		5		21		2		2		0		16		12		379
NE BLANCO UNIT #448		13567	NEBU		31N07W32		1		18		1,054		8		31		3		3		0		25		18		384
NE BLANCO UNIT #449		14309	NEBU		31N07W19		1		24		1,242		10		37		3		4		0		30		20		391
NE BLANCO UNIT #450		14310	NEBU		31N07W32		1		18		930		7		28		2		3		0		22		16		389
NE BLANCO UNIT #451		14311	NEBU		30N07W06		1		26		1,817		14		54		4		6		0		44		29		405
NE BLANCO UNIT #452		13574	NEBU		31N07W15		1		2		21		0		1		0		0		0		0		0		422
NE BLANCO UNIT #453		14312	NEBU		30N07W06		1		25		1,880		15		56		4		6		0		45		30		390
NE BLANCO UNIT #454		14313	NEBU		31N07W33		1		18		1,166		9		35		3		4		0		28		21		409
NE BLANCO UNIT #455		14314	NEBU		31N07W31		1		25		3,342		26		99		7		11		0		81		57		387
NE BLANCO UNIT #456		13575	NEBU		31N07W26		1		15		793		6		24		2		3		0		19		14		417
NE BLANCO UNIT #457		14315	NEBU		31N07W31		1		20		1,308		10		39		3		4		0		31		22		392
NE BLANCO UNIT #458		13576	NEBU		31N07W13		1		27		1,861		14		55		4		6		0		45		29		416
NE BLANCO UNIT #459		14316	NEBU		31N07W19		1		29		3,664		29		109		7		12		0		89		59		415
NE BLANCO UNIT #460		14351	NEBU		31N06W07		1		27		3,157		25		94		7		10		0		77		52		424
NE BLANCO UNIT #461		14317	NEBU		30N07W07		1		23		1,282		10		38		3		4		0		31		21		543
NE BLANCO UNIT #462		14318	NEBU		31N07W01		1		26		3,338		26		99		7		11		0		81		56		428
NE BLANCO UNIT #463		14319	NEBU		30N07W18		1		23		1,091		8		32		3		4		0		26		17		411
NE BLANCO UNIT #464		13577	NEBU		31N07W10		1		18		1,040		8		31		3		3		0		25		18		429

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 13 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 #465		14320	NEBU		30N08W01		1		21		1,938		15		58		4		6		0		47		34		404
NE BLANCO UNIT #466		14321	NEBU		31N07W34		1		21		2,040		16		61		4		7		0		49		35		462
NE BLANCO UNIT #467		14322	NEBU		30N08W12		1		14		414		3		12		1		1		0		10		7		407
NE BLANCO UNIT #468		14323	NEBU		31N07W35		1		23		2,209		17		66		5		7		0		53		37		457
NE BLANCO UNIT #469		14324	NEBU		30N08W13		1		28		3,489		27		104		7		12		0		85		57		393
NE BLANCO UNIT #470		14352	NEBU		31N07W27		1		21		969		8		29		3		3		0		23		16		438
NE BLANCO UNIT #471		14325	NEBU		31N08W25		1		26		2,976		23		88		6		10		0		72		50		402
NE BLANCO UNIT #472		14326	NEBU		31N07W29		1		13		502		4		15		1		2		0		12		9		401
NE BLANCO UNIT #473		14327	NEBU		31N08W36		1		12		715		6		21		2		2		0		17		14		396
NE BLANCO UNIT #474		14353	NEBU		31N07W26		1		14		644		5		19		2		2		0		15		12		437
NE BLANCO UNIT #475		14328	NEBU		30N07W19		1		25		1,097		9		33		3		4		0		26		17		298
NE BLANCO UNIT #476		14329	NEBU		31N07W22		1		24		2,275		18		68		5		8		0		55		38		435
NE BLANCO UNIT #477		14379	NEBU		30N07W29		1		8		137		1		4		1		0		0		3		2		93
NE BLANCO UNIT #478		14330	NEBU		31N07W21		1		23		1,828		14		54		4		6		0		44		31		386
NE BLANCO UNIT #479R		13942	NEBU		30N07W20		1		22		1,255		10		37		3		4		0		30		20		334
NE BLANCO UNIT #480		14332	NEBU		31N07W14		1		25		2,154		17		64		5		7		0		52		35		463
NE BLANCO UNIT #481		14333	NEBU		31N07W36		1		19		1,117		9		33		3		4		0		27		19		86
NE BLANCO UNIT #482		14334	NEBU		31N07W15		1		24		2,714		21		81		6		9		0		66		46		439
NE BLANCO UNIT #483		14335	NEBU		31N07W36		1		7		195		2		6		1		1		0		4		4		85
NE BLANCO UNIT #484		14336	NEBU		31N07W16		1		7		65		1		2		0		0		0		1		1		430
NE BLANCO UNIT #485		14337	NEBU		30N07W03		1		15		724		6		22		2		2		0		17		13		131
NE BLANCO UNIT #486		14338	NEBU		31N06W19		1		22		2,852		22		85		6		9		0		69		50		472
NE BLANCO UNIT #487		14339	NEBU		31N07W35		1		33		3,890		30		115		8		13		0		95		59		464
NE BLANCO UNIT #488		14340	NEBU		31N07W24		1		20		2,888		22		86		6		10		0		70		52		458
NE BLANCO UNIT #489		14364	NEBU		31N07W12		1		10		244		2		7		1		1		0		6		5		456
NE BLANCO UNIT #490		14363	NEBU		31N07W14		1		20		1,817		14		54		4		6		0		44		32		434
NE BLANCO UNIT #491		14368	NEBU		31N07W25		1		9		309		2		9		1		1		0		7		6		152
NE BLANCO UNIT #492		14354	NEBU		31N07W12		1		24		2,222		17		66		5		7		0		54		37		453
NE BLANCO UNIT #493		14380	NEBU		31N07W25		1		26		1,735		14		52		4		6		0		42		27		143
NE BLANCO UNIT #494		14341	NEBU		31N07W27		1		17		815		6		24		2		3		0		19		14		465
NE BLANCO UNIT #495		14381	NEBU		31N06W30		1		21		1,378		11		41		3		5		0		33		23		144
NE BLANCO UNIT #496		14355	NEBU		31N06W18		1		19		1,995		16		59		4		7		0		48		36		459
NE BLANCO UNIT #497		14382	NEBU		31N06W30		1		21		1,565		12		46		4		5		0		38		27		146
NE BLANCO UNIT #498		14365	NEBU		31N07W13		1		16		1,339		10		40		3		4		0		32		25		460
NE BLANCO UNIT #499		14383	NEBU		31N06W20		1		27		1,954		15		58		5		6		0		47		31		179
NE BLANCO UNIT #500		14356	NEBU		31N06W20		1		22		1,421		11		42		3		5		0		34		24		454
NE BLANCO UNIT #504		14342	NEBU		31N07W16		1		23		1,829		14		54		4		6		0		44		31		513
NE BLANCO UNIT #505		14384	NEBU		30N07W21		1		24		1,483		12		44		4		5		0		36		24		319
NORDHAUS #716		14360	NON-UNIT		31N09W13		1		27		2,481		180		689		58		77		0		554		368		549
PAYNE #201		14225	NON-UNIT		32N10W20		1		20		1,387		25		97		9		11		0		78		55		546
QUINN #336		14226	NON-UNIT		31N08W17		1		12		858		63		240		22		27		0		192		155		451
SAN JUAN 28-5 UNIT #219		13793	SJ 28-5		28N05W30		1		23		198		82		311		87		35		0		190		103		245

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 14 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 28-5 UNIT #223		13740	SJ 28-5		28N05W34		1		9		43		19		71		30		8		0		34		25		246
SAN JUAN 28-6 UNIT #400		13883	SJ 28-6		28N06W09		1		26		270		17		66		15		7		0		43		23		98
SAN JUAN 28-6 UNIT #404		14227	SJ 28-6		28N06W13		1		14		83		35		132		50		15		0		68		43		124
SAN JUAN 28-6 UNIT #405		13884	SJ 28-6		28N06W18		1		24		334		21		82		15		9		0		57		33		153
SAN JUAN 28-6 UNIT #406		13885	SJ 28-6		28N06W19		1		27		341		22		83		17		9		0		57		31		112
SAN JUAN 28-6 UNIT #410		14228	SJ 28-6		28N06W13		1		3		12		5		20		9		2		0		10		9		214
SAN JUAN 28-6 UNIT #414		13886	SJ 28-6		28N06W08		1		22		251		16		61		14		7		0		41		24		260
SAN JUAN 28-6 UNIT #418		13757	SJ 28-6		28N06W28		1		10		89		6		22		6		2		0		13		10		297
SAN JUAN 28-6 UNIT #421		13758	SJ 28-6		28N06W33		1		17		257		16		63		11		7		0		44		29		247
SAN JUAN 28-6 UNIT #433		14387	SJ 28-6		28N06W24		1		14		144		0		0		0		0		0		0		0		288
SAN JUAN 28-6 UNIT #436		14347	SJ 28-6		28N06W16		1		28		348		22		85		17		9		0		58		31		277
SAN JUAN 28-6 UNIT #437		14456	SJ 28-6		28N06W28		1		21		235		15		57		13		6		0		38		22		309
SAN JUAN 28-6 UNIT #438		14348	SJ 28-6		28N06W15		1		18		157		24		91		24		10		0		57		35		293
SAN JUAN 28-6 UNIT #439		14388	SJ 28-6		28N06W29		1		19		213		66		252		56		28		0		167		106		248
SAN JUAN 28-6 UNIT #440		13759	SJ 28-6		28N06W16		1		4		29		2		7		2		1		0		4		3		276
SAN JUAN 28-6 UNIT #441		14389	SJ 28-6		28N06W17		1		32		438		28		107		21		12		0		74		38		296
SAN JUAN 28-6 UNIT #448		13760	SJ 28-6		28N06W15		1		3		12		2		7		3		1		0		3		3		228
SAN JUAN 28-6 UNIT #449		13761	SJ 28-6		27N06W02		1		12		91		9		36		11		4		0		21		14		218
SAN JUAN 28-6 UNIT #455		13719	SJ 28-6		28N06W17		1		20		173		26		100		27		11		0		62		36		278
SAN JUAN 28-6 UNIT #456		14229	SJ 28-6		28N06W19		1		10		106		16		62		14		7		0		41		31		243
SAN JUAN 28-6 UNIT #457		13720	SJ 28-6		28N06W20		1		20		139		21		81		26		9		0		46		26		279
SAN JUAN 28-6 UNIT #458		14263	SJ 28-6		28N06W20		1		25		415		26		101		17		11		0		73		43		231
SAN JUAN 28-6 UNIT #459		13733	SJ 28-6		28N06W21		1		40		1,199		77		292		36		32		0		224		101		280
SAN JUAN 28-6 UNIT #460		13721	SJ 28-6		28N06W21		1		24		305		19		74		15		8		0		51		29		294
SAN JUAN 28-6 UNIT #461		13762	SJ 28-6		28N06W22		1		34		404		61		235		49		26		0		159		76		266
SAN JUAN 28-6 UNIT #462		13732	SJ 28-6		28N06W22		1		23		256		39		149		33		17		0		99		57		295
SAN JUAN 28-6 UNIT #467		13724	SJ 28-6		28N06W34		1		35		737		47		180		26		20		0		133		69		282
SAN JUAN 28-6 UNIT #474		13723	SJ 28-6		28N06W27		1		31		347		22		85		19		9		0		56		28		281
SAN JUAN 28-6 UNIT #475		13887	SJ 28-6		28N06W29		1		29		476		30		116		20		13		0		84		46		289
SAN JUAN 29-5 UNIT #201		14367	SJ 29-5		29N05W27		1		15		93		0		0		0		0		0		0		0		267
SAN JUAN 29-5 UNIT #203		13547	SJ 29-5		29N05W06		1		16		977		126		481		45		54		0		383		287		122
SAN JUAN 29-5 UNIT #213		13597	SJ 29-5		29N05W22		1		40		920		119		453		64		50		0		339		165		136
SAN JUAN 29-5 UNIT #217		13763	SJ 29-5		29N05W34		1		10		69		0		0		0		0		0		0		0		268
SAN JUAN 29-5 UNIT #219		14398	SJ 29-5		29N05W04		1		23		567		73		279		38		31		0		211		134		304
SAN JUAN 29-5 UNIT #223		13653	SJ 29-5		29N05W33		1		4		26		3		13		5		1		0		7		6		241
SAN JUAN 29-5 UNIT #225		14391	SJ 29-5		29N05W06		1		13		263		34		129		20		14		0		95		70		305
SAN JUAN 29-5 UNIT #226		14392	SJ 29-5		29N05W07		1		26		730		94		360		45		40		0		275		169		302
SAN JUAN 29-5 UNIT #230		14405	SJ 29-5		29N05W05		1		27		1,140		147		562		59		62		0		440		276		326
SAN JUAN 29-5 UNIT #231		14393	SJ 29-5		29N05W05		1		0		0		0		0		0		0		0		0		0		301
SAN JUAN 29-6 UNIT #201		13589	SJ 29-6		29N06W06		1		20		1,653		200		763		64		85		0		615		449		132
SAN JUAN 29-6 UNIT #202		13654	SJ 29-6		29N06W06		1		19		950		115		439		43		49		0		347		250		235
SAN JUAN 29-6 UNIT #203		13684	SJ 29-6		29N06W07		1		16		1,133		137		523		46		58		0		419		317		180

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 15 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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		99		12		46		8		5		0		33		28		207
SAN JUAN 29-6 UNIT #205		13685	SJ 29-6		29N06W21		1		20		1,408		170		650		57		72		0		521		373		250
SAN JUAN 29-6 UNIT #206		13548	SJ 29-6		29N06W04		1		23		972		118		449		47		50		0		352		233		117
SAN JUAN 29-6 UNIT #207		13549	SJ 29-6		29N06W02		1		26		2,026		245		935		80		104		0		752		500		115
SAN JUAN 29-6 UNIT #208		13587	SJ 29-6		29N06W17		1		21		1,857		225		857		71		95		0		691		495		133
SAN JUAN 29-6 UNIT #209		13588	SJ 29-6		29N06W17		1		37		2,256		273		1,041		95		116		0		830		473		126
SAN JUAN 29-6 UNIT #210		14394	SJ 29-6		29N06W20		1		23		2,483		300		1,146		90		127		0		929		660		182
SAN JUAN 29-6 UNIT #211		14395	SJ 29-6		29N06W20		1		25		1,307		158		604		58		67		0		478		312		174
SAN JUAN 29-6 UNIT #213		13590	SJ 29-6		29N06W30		1		10		98		12		45		11		5		0		29		22		127
SAN JUAN 29-6 UNIT #214		13595	SJ 29-6		29N06W03		1		15		1,186		143		548		46		61		0		441		346		137
SAN JUAN 29-6 UNIT #215		13599	SJ 29-6		29N06W03		1		17		705		85		326		34		36		0		255		185		175
SAN JUAN 29-6 UNIT #216		13596	SJ 29-6		29N06W04		1		13		472		57		218		24		24		0		169		130		138
SAN JUAN 29-6 UNIT #217		13612	SJ 29-6		29N06W05		1		23		2,429		294		1,122		89		125		0		908		646		193
SAN JUAN 29-6 UNIT #218		13605	SJ 29-6		29N06W05		1		10		327		40		151		18		17		0		116		95		181
SAN JUAN 29-6 UNIT #219		13593	SJ 29-6		29N06W10		1		22		1,209		146		558		53		62		0		444		307		139
SAN JUAN 29-6 UNIT #220		13600	SJ 29-6		29N06W11		1		17		494		60		228		28		25		0		174		124		165
SAN JUAN 29-6 UNIT #221		13601	SJ 29-6		29N06W11		1		19		761		92		351		37		39		0		275		193		159
SAN JUAN 29-6 UNIT #222		13718	SJ 29-6		29N06W12		1		33		1,410		171		651		68		72		0		511		293		183
SAN JUAN 29-6 UNIT #223		13611	SJ 29-6		29N06W12		1		25		1,561		189		721		66		80		0		575		382		160
SAN JUAN 29-6 UNIT #224		13696	SJ 29-6		29N06W13		1		14		204		25		94		18		10		0		66		47		184
SAN JUAN 29-6 UNIT #225R		13947	SJ 29-6		29N06W13		1		3		13		2		6		3		1		0		3		2		332
SAN JUAN 29-6 UNIT #226		14396	SJ 29-6		29N06W14		1		36		4,978		602		2,298		173		255		0		1,870		1,154		154
SAN JUAN 29-6 UNIT #227		13765	SJ 29-6		29N06W14		1		0		2		0		1		0		0		0		0		0		155
SAN JUAN 29-6 UNIT #229		13766	SJ 29-6		29N06W35		1		21		259		31		119		24		13		0		82		50		162
SAN JUAN 29-6 UNIT #230		13602	SJ 29-6		29N06W35		1		19		211		8		30		7		3		0		20		12		140
SAN JUAN 29-6 UNIT #231		13594	SJ 29-6		29N06W36		1		1		5		1		3		1		0		0		1		1		141
SAN JUAN 29-6 UNIT #233		13767	SJ 29-6		29N06W26		1		12		176		20		76		14		8		0		54		41		176
SAN JUAN 29-6 UNIT #235		14513	SJ 29-6		29N06W34		1		34		509		62		235		43		26		0		166		83		208
SAN JUAN 29-6 UNIT #236		13694	SJ 29-6		29N06W18		1		26		1,347		163		622		60		69		0		492		316		177
SAN JUAN 29-6 UNIT #237		13674	SJ 29-6		29N06W01		1		23		1,048		127		484		49		54		0		381		254		197
SAN JUAN 29-6 UNIT #238		13675	SJ 29-6		29N06W01		1		14		634		77		293		30		33		0		231		178		198
SAN JUAN 29-6 UNIT #239		13676	SJ 29-6		29N06W02		1		14		683		83		315		31		35		0		249		192		170
SAN JUAN 29-6 UNIT #240		13686	SJ 29-6		29N06W18		1		25		2,046		247		944		80		105		0		760		510		251
SAN JUAN 29-6 UNIT #241		13687	SJ 29-6		29N06W19		1		31		2,054		249		948		84		105		0		759		470		252
SAN JUAN 29-6 UNIT #242		13688	SJ 29-6		29N06W19		1		29		1,571		190		725		69		81		0		576		358		178
SAN JUAN 29-6 UNIT #243		13768	SJ 29-6		29N06W31		1		23		216		8		31		8		3		0		19		11		255
SAN JUAN 29-6 UNIT #245		13667	SJ 29-6		29N06W08		1		20		1,126		136		520		49		58		0		413		291		242
SAN JUAN 29-6 UNIT #246		14397	SJ 29-6		29N06W08		1		7		61		7		28		8		3		0		17		14		209
SAN JUAN 29-6 UNIT #247R		13814	SJ 29-6		29N06W10		1		17		411		50		190		26		21		0		143		101		338
SAN JUAN 29-6 UNIT #249		13796	SJ 29-6		29N06W22		1		8		62		7		29		9		3		0		17		13		323
SAN JUAN 29-6 UNIT #251		13803	SJ 29-6		29N06W23		1		11		65		10		37		14		4		0		19		14		317
SAN JUAN 29-6 UNIT #257R		13815	SJ 29-6		29N06W09		1		26		1,263		153		583		58		65		0		460		294		339

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 16 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 #258		13695	SJ 29-6		29N06W16		1		26		2,053		248		948		80		105		0		762		510		186
SAN JUAN 29-6 UNIT #259		14399	SJ 29-6		29N06W09		1		9		243		29		112		14		12		0		85		70		185
SAN JUAN 29-6 UNIT #260		14400	SJ 29-6		29N06W16		1		12		205		25		95		16		11		0		68		51		187
SAN JUAN 29-6 UNIT #262		14401	SJ 29-6		29N06W21		1		25		1,857		225		858		74		95		0		688		463		307
SAN JUAN 29-6 UNIT #263		13802	SJ 29-6		29N06W22		1		7		67		10		38		10		4		0		24		20		320
SAN JUAN 29-6 UNIT #264		13841	SJ 29-6		29N06W27		1		10		67		8		31		10		3		0		17		13		341
SAN JUAN 29-7 UNIT #507R		12667	SJ 29-7		29N07W13		1		29		1,869		189		720		63		80		0		577		366		330
SAN JUAN 29-7 UNIT #520		12524	SJ 29-7		29N07W08		1		17		267		27		103		18		11		0		74		49		342
SAN JUAN 29-7 UNIT #521		12653	SJ 29-7		29N07W13		1		23		1,312		132		505		46		56		0		404		276		221
SAN JUAN 29-7 UNIT #530		13882	SJ 29-7		29N07W34		1		29		497		50		192		31		21		0		139		76		195
SAN JUAN 29-7 UNIT #532		14349	SJ 29-7		29N07W02		1		13		291		29		112		16		12		0		84		62		145
SAN JUAN 29-7 UNIT #533		14464	SJ 29-7		29N07W03		1		8		145		15		56		9		6		0		41		34		196
SAN JUAN 29-7 UNIT #534		12668	SJ 29-7		29N07W09		1		16		520		52		200		23		22		0		155		113		327
SAN JUAN 29-7 UNIT #537		12669	SJ 29-7		29N07W22		1		8		128		13		49		8		5		0		35		29		290
SAN JUAN 29-7 UNIT #538		14402	SJ 29-7		29N07W26		1		25		577		58		222		30		25		0		167		101		200
SAN JUAN 29-7 UNIT #540		12654	SJ 29-7		29N07W10		1		14		267		27		103		16		11		0		76		55		284
SAN JUAN 29-7 UNIT #543		12655	SJ 29-7		29N07W03		1		35		1,085		110		418		49		46		0		323		175		299
SAN JUAN 29-7 UNIT #544		12656	SJ 29-7		29N07W04		1		26		2,021		204		778		64		87		0		627		418		283
SAN JUAN 29-7 UNIT #545		12657	SJ 29-7		29N07W12		1		30		2,287		231		881		74		98		0		709		446		210
SAN JUAN 29-7 UNIT #547		14403	SJ 29-7		29N07W07		1		24		650		66		250		31		28		0		191		118		291
SAN JUAN 29-7 UNIT #548		14372	SJ 29-7		29N07W07		1		38		687		69		264		41		29		0		194		93		300
SAN JUAN 29-7 UNIT #550		12659	SJ 29-7		29N07W11		1		14		635		64		245		24		27		0		193		149		215
SAN JUAN 29-7 UNIT #552		12652	SJ 29-7		29N07W12		1		21		1,841		186		709		57		79		0		573		408		314
SAN JUAN 29-7 UNIT #553		12661	SJ 29-7		29N07W14		1		20		1,619		163		623		51		69		0		503		364		234
SAN JUAN 29-7 UNIT #554		12662	SJ 29-7		29N07W14		1		19		492		323		1,232		154		137		0		941		643		201
SAN JUAN 29-7 UNIT #559		14404	SJ 29-7		29N07W22		1		20		256		26		98		19		11		0		68		42		244
SAN JUAN 29-7 UNIT #562		12664	SJ 29-7		29N07W24		1		27		2,178		220		839		69		93		0		677		443		239
SAN JUAN 29-7 UNIT #563		12665	SJ 29-7		29N07W24		1		5		42		19		71		19		8		0		44		37		285
SAN JUAN 29-7 UNIT #565		14231	SJ 29-7		29N07W26		1		16		105		69		263		83		29		0		151		95		203
SAN JUAN 29-7 UNIT #577		14232	SJ 29-7		29N07W35		1		10		92		7		26		7		3		0		16		12		275
SAN JUAN 29-7 UNIT #580		14465	SJ 29-7		29N07W01		1		18		1,378		139		531		44		59		0		427		315		219
SAN JUAN 29-7 UNIT #582		12666	SJ 29-7		29N07W02		1		21		1,716		173		661		54		73		0		534		382		211
SAN JUAN 29-7 UNIT #583		12670	SJ 29-7		29N07W06		1		8		103		10		40		8		4		0		28		23		329
SAN JUAN 30-5 UNIT #201		13550	SJ 30-5		30N05W19		1		28		2,319		395		1,509		126		168		0		1,215		792		123
SAN JUAN 30-5 UNIT #202		13551	SJ 30-5		30N05W06		1		28		2,835		421		1,606		131		179		0		1,296		853		116
SAN JUAN 30-5 UNIT #203		13607	SJ 30-5		30N05W06		1		6		80		14		52		11		6		0		35		30		156
SAN JUAN 30-5 UNIT #204		13726	SJ 30-5		30N05W07		1		21		400		68		260		41		29		0		191		121		163
SAN JUAN 30-5 UNIT #205		13772	SJ 30-5		30N05W07		1		6		81		14		53		11		6		0		36		31		148
SAN JUAN 30-5 UNIT #206		13711	SJ 30-5		30N05W18		1		16		618		105		402		44		45		0		314		230		166
SAN JUAN 30-5 UNIT #207		13727	SJ 30-5		30N05W18		1		17		1,118		191		727		65		81		0		581		434		192
SAN JUAN 30-5 UNIT #208		13665	SJ 30-5		30N05W19		1		18		1,882		321		1,224		97		136		0		991		743		199
SAN JUAN 30-5 UNIT #209		13606	SJ 30-5		30N05W30		1		20		1,408		240		916		80		102		0		734		526		167

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 17 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 30-5 UNIT #210		13682	SJ 30-5		30N05W30		1		9		323		55		210		24		23		0		163		136		264
SAN JUAN 30-5 UNIT #211		13683	SJ 30-5		30N05W31		1		20		1,071		183		697		67		77		0		552		387		172
SAN JUAN 30-5 UNIT #212		13617	SJ 30-5		30N05W31		1		19		828		141		538		56		60		0		423		298		173
SAN JUAN 30-5 UNIT #213R		16986	SJ 30-5		30N05W05		1		24		1,777		303		1,156		100		129		0		928		631		624
SAN JUAN 30-5 UNIT #214		16987	SJ 30-5		30N05W05		1		17		1,510		257		983		80		109		0		793		604		638
SAN JUAN 30-5 UNIT #215		13660	SJ 30-5		30N05W08		1		18		1,252		1,095		4,180		352		465		0		3,363		2,495		190
SAN JUAN 30-5 UNIT #216R		13943	SJ 30-5		30N05W20		1		19		774		132		503		53		56		0		394		276		335
SAN JUAN 30-5 UNIT #217		13614	SJ 30-5		30N05W21		1		30		2,327		397		1,514		128		168		0		1,217		773		217
SAN JUAN 30-5 UNIT #218		13659	SJ 30-5		30N05W17		1		24		3,511		598		2,284		170		254		0		1,860		1,323		191
SAN JUAN 30-5 UNIT #219R		17250	SJ 30-5		30N05W16		1		4		143		24		93		11		10		0		72		65		625
SAN JUAN 30-5 UNIT #220R		15532	SJ 30-5		30N05W08		1		8		293		50		191		21		21		0		148		126		635
SAN JUAN 30-5 UNIT #223		13677	SJ 30-5		30N05W20		1		26		2,020		344		1,314		112		146		0		1,056		700		236
SAN JUAN 30-5 UNIT #224		12576	SJ 30-5		30N05W17		1		14		484		82		315		36		35		0		243		183		237
SAN JUAN 30-5 UNIT #225		14406	SJ 30-5		30N05W29		1		22		708		121		461		55		51		0		355		232		306
SAN JUAN 30-5 UNIT #226		13670	SJ 30-5		30N05W29		1		20		1,277		218		831		74		92		0		664		478		261
SAN JUAN 30-5 UNIT #226A		5772	SJ 30-5		30N05W29		1		19		1,600		282		1,076		89		120		0		867		607		983
SAN JUAN 30-5 UNIT #227		13672	SJ 30-5		30N05W28		1		24		1,125		192		732		74		81		0		577		377		232
SAN JUAN 30-5 UNIT #228		14407	SJ 30-5		30N05W28		1		17		540		92		351		41		39		0		271		195		310
SAN JUAN 30-5 UNIT #229		13673	SJ 30-5		30N05W21		1		31		2,669		455		1,736		144		193		0		1,399		875		270
SAN JUAN 30-5 UNIT #230		14366	SJ 30-5		30N05W32		1		19		1,471		251		957		81		106		0		769		564		238
SAN JUAN 30-5 UNIT #231		14409	SJ 30-5		30N05W32		1		18		544		93		354		43		39		0		272		191		233
SAN JUAN 30-5 UNIT #232		14408	SJ 30-5		30N05W33		1		1		7		1		4		2		0		0		2		2		321
SAN JUAN 30-5 UNIT #233		14443	SJ 30-5		30N05W33		1		25		920		157		599		66		67		0		466		295		322
SAN JUAN 30-5 UNIT #234		14410	SJ 30-5		30N05W22		1		36		4,246		724		2,762		213		307		0		2,242		1,370		318
SAN JUAN 30-5 UNIT #235		14411	SJ 30-5		30N05W27		1		16		407		69		265		35		29		0		200		142		311
SAN JUAN 30-5 UNIT #236		14412	SJ 30-5		30N05W27		1		6		76		13		50		10		6		0		34		30		303
SAN JUAN 30-5 UNIT #237		14413	SJ 30-5		30N05W16		1		0		1		0		2		1		0		0		1		1		308
SAN JUAN 30-5 UNIT #238		14414	SJ 30-5		30N05W34		1		10		173		29		112		18		12		0		82		64		312
SAN JUAN 30-5 UNIT #239		13949	SJ 30-5		30N05W15		1		20		994		169		647		64		72		0		511		355		315
SAN JUAN 30-5 UNIT #240		14415	SJ 30-5		30N05W22		1		30		3,263		556		2,123		167		236		0		1,720		1,113		324
SAN JUAN 30-5 UNIT #241		14416	SJ 30-5		30N05W23		1		16		410		70		267		36		30		0		201		143		325
SAN JUAN 30-5 UNIT #242		14444	SJ 30-5		30N05W34		1		3		26		4		17		5		2		0		11		10		316
SAN JUAN 30-5 UNIT #243		14069	SJ 30-5		30N05W15		1		30		1,859		317		1,209		110		134		0		965		600		346
SAN JUAN 30-5 UNIT #246		13948	SJ 30-5		30N05W26		1		16		598		102		389		43		43		0		303		223		331
SAN JUAN 30-5 UNIT #249		14068	SJ 30-5		30N05W23		1		15		819		140		533		50		59		0		424		326		632
SAN JUAN 30-5 UNIT #255		13842	SJ 30-5		30N05W14		1		15		782		133		509		49		57		0		403		306		340
SAN JUAN 30-5 UNIT #257		14025	SJ 30-5		30N05W11		1		22		2,018		344		1,313		107		146		0		1,060		749		345
SAN JUAN 30-5 UNIT #258		14026	SJ 30-5		30N05W14		1		27		2,901		495		1,887		149		210		0		1,529		1,027		344
SAN JUAN 30-5 UNIT #259		8011	SJ 30-5		30N05W13		1		16		935		159		608		57		68		0		484		362		630
SAN JUAN 30-5 UNIT #260		12646	SJ 30-5		30N05W09		1		5		610		104		397		31		44		0		322		295		633
SAN JUAN 30-5 UNIT #261		5424	SJ 30-5		30N05W11		1		15		829		141		539		51		60		0		429		329		682
SAN JUAN 30-5 UNIT #262		8012	SJ 30-5		30N05W12		1		13		900		153		586		51		65		0		470		378		631

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 18 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 30-5 UNIT #263		5425	SJ 30-5		30N05W13		1		17		1,098		187		714		64		79		0		571		430		683
SAN JUAN 30-5 UNIT #264		12619	SJ 30-5		30N05W09		1		22		3,781		645		2,460		179		273		0		2,008		1,465		634
SAN JUAN 30-5 UNIT #265		15533	SJ 30-5		30N05W10		1		20		3,929		670		2,556		182		284		0		2,090		1,581		637
SAN JUAN 30-5 UNIT #266		15534	SJ 30-5		30N05W10		1		23		3,915		667		2,547		185		283		0		2,079		1,513		636
SAN JUAN 30-5 UNIT #267		5046	SJ 30-5		30N05W24		1		13		780		133		508		47		56		0		405		320		1246
SAN JUAN 30-5 UNIT #268		10177	SJ 30-5		30N05W24		1		16		709		121		461		48		51		0		362		266		1247
SAN JUAN 30-6 UNIT #400		14164	SJ 30-6		30N07W14		1		16		1,450		72		276		23		31		0		223		172		23
SAN JUAN 30-6 UNIT #401R		14165	SJ 30-6		30N07W13		1		10		586		29		112		10		12		0		89		74		79
SAN JUAN 30-6 UNIT #403		13648	SJ 30-6		30N06W09		1		28		2,679		134		510		41		57		0		412		270		171
SAN JUAN 30-6 UNIT #404R		14459	SJ 30-6		30N07W23		1		9		453		23		86		9		10		0		68		57		328
SAN JUAN 30-6 UNIT #405		13580	SJ 30-6		30N06W09		1		19		862		43		164		17		18		0		129		92		128
SAN JUAN 30-6 UNIT #406R		14167	SJ 30-6		30N07W15		1		20		1,281		64		244		22		27		0		195		139		108
SAN JUAN 30-6 UNIT #407		13559	SJ 30-6		30N06W16		1		25		2,344		117		447		36		50		0		361		245		120
SAN JUAN 30-6 UNIT #408		13558	SJ 30-6		30N06W16		1		25		2,083		104		397		33		44		0		320		217		119
SAN JUAN 30-6 UNIT #409		14168	SJ 30-6		30N07W25		1		25		3,217		161		613		47		68		0		498		346		30
SAN JUAN 30-6 UNIT #410		14211	SJ 30-6		30N06W26		1		20		1,172		59		223		21		25		0		178		126		135
SAN JUAN 30-6 UNIT #411		14169	SJ 30-6		30N07W27		1		17		574		29		109		12		12		0		85		61		33
SAN JUAN 30-6 UNIT #412		14170	SJ 30-6		30N07W24		1		26		3,080		154		587		45		65		0		476		326		24
SAN JUAN 30-6 UNIT #413R		14171	SJ 30-6		30N07W23		1		23		2,020		101		385		32		43		0		310		217		84
SAN JUAN 30-6 UNIT #414		14172	SJ 30-6		30N07W35		1		24		980		49		187		20		21		0		146		96		25
SAN JUAN 30-6 UNIT #415		14173	SJ 30-6		30N07W26		1		29		2,930		146		558		44		62		0		452		296		32
SAN JUAN 30-6 UNIT #416		14174	SJ 30-6		30N07W24		1		24		3,183		159		607		46		67		0		493		349		28
SAN JUAN 30-6 UNIT #417		14175	SJ 30-6		30N07W25		1		21		1,820		91		347		29		39		0		280		202		29
SAN JUAN 30-6 UNIT #418		14176	SJ 30-6		30N07W26		1		25		3,095		155		590		45		66		0		479		318		31
SAN JUAN 30-6 UNIT #419		14177	SJ 30-6		30N07W11		1		15		664		33		127		13		14		0		100		76		26
SAN JUAN 30-6 UNIT #420		14178	SJ 30-6		30N07W12		1		20		945		47		180		18		20		0		142		100		27
SAN JUAN 30-6 UNIT #421		14179	SJ 30-6		30N07W34		1		5		37		2		7		2		1		0		4		4		37
SAN JUAN 30-6 UNIT #422		14264	SJ 30-6		30N07W27		1		24		1,079		54		206		21		23		0		162		106		59
SAN JUAN 30-6 UNIT #423		14462	SJ 30-6		30N07W28		1		25		744		37		142		17		16		0		109		67		95
SAN JUAN 30-6 UNIT #424		14463	SJ 30-6		30N07W33		1		15		451		23		86		10		10		0		66		49		56
SAN JUAN 30-6 UNIT #425		14385	SJ 30-6		30N07W33		1		17		1,205		60		230		20		26		0		184		137		47
SAN JUAN 30-6 UNIT #426		14180	SJ 30-6		30N07W34		1		4		53		3		10		2		1		0		7		6		54
SAN JUAN 30-6 UNIT #427		14181	SJ 30-6		30N07W35		1		17		977		49		186		17		21		0		148		109		60
SAN JUAN 30-6 UNIT #428		14358	SJ 30-6		30N07W28		1		24		1,317		66		251		24		28		0		199		132		82
SAN JUAN 30-6 UNIT #429		14359	SJ 30-6		30N07W32		1		6		98		5		19		3		2		0		13		12		67
SAN JUAN 30-6 UNIT #430		13543	SJ 30-6		30N06W08		1		17		1,562		78		298		24		33		0		240		183		38
SAN JUAN 30-6 UNIT #431		13544	SJ 30-6		30N06W10		1		24		2,417		121		461		37		51		0		372		258		40
SAN JUAN 30-6 UNIT #432		13545	SJ 30-6		30N06W10		1		27		1,931		96		368		32		41		0		295		194		39
SAN JUAN 30-6 UNIT #433		14182	SJ 30-6		30N06W11		1		20		1,327		66		253		22		28		0		202		146		48
SAN JUAN 30-6 UNIT #434		14183	SJ 30-6		30N06W12		1		22		1,941		97		370		30		41		0		298		212		58
SAN JUAN 30-6 UNIT #435		14184	SJ 30-6		30N06W13		1		24		1,571		78		299		27		33		0		239		161		70
SAN JUAN 30-6 UNIT #436		14185	SJ 30-6		30N06W15		1		21		1,900		95		362		30		40		0		292		212		41

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 19 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 30-6 UNIT #437		14186	SJ 30-6		30N06W11		1		31		2,660		133		507		42		56		0		409		258		62
SAN JUAN 30-6 UNIT #438		14187	SJ 30-6		30N06W12		1		17		1,512		75		288		24		32		0		232		177		68
SAN JUAN 30-6 UNIT #439		14188	SJ 30-6		30N06W14		1		23		1,396		70		266		24		30		0		212		145		49
SAN JUAN 30-6 UNIT #440		14189	SJ 30-6		30N06W15		1		7		113		6		22		4		2		0		16		13		50
SAN JUAN 30-6 UNIT #441		14190	SJ 30-6		30N06W31		1		19		604		30		115		14		13		0		89		62		53
SAN JUAN 30-6 UNIT #442		13568	SJ 30-6		30N06W14		1		29		2,972		148		566		45		63		0		458		298		96
SAN JUAN 30-6 UNIT #443		13532	SJ 30-6		30N06W36		1		4		30		2		6		2		1		0		3		3		69
SAN JUAN 30-6 UNIT #444		14208	SJ 30-6		30N06W36		1		26		1,650		82		314		28		35		0		251		166		66
SAN JUAN 30-6 UNIT #445		14209	SJ 30-6		30N06W13		1		23		1,660		83		316		27		35		0		254		176		73
SAN JUAN 30-6 UNIT #446		14204	SJ 30-6		30N06W35		1		35		4,542		227		866		66		96		0		703		436		129
SAN JUAN 30-6 UNIT #447		14206	SJ 30-6		30N07W31		1		17		615		31		117		13		13		0		91		66		147
SAN JUAN 30-6 UNIT #450		13536	SJ 30-6		30N06W07		1		27		2,748		137		524		42		58		0		424		285		43
SAN JUAN 30-6 UNIT #451		13534	SJ 30-6		30N06W07		1		32		3,930		196		749		58		83		0		608		387		42
SAN JUAN 30-6 UNIT #452		13535	SJ 30-6		30N06W08		1		19		1,442		72		275		23		31		0		221		162		61
SAN JUAN 30-6 UNIT #453		14191	SJ 30-6		30N06W17		1		22		1,439		72		274		25		30		0		219		152		57
SAN JUAN 30-6 UNIT #454		14192	SJ 30-6		30N06W17		1		26		2,539		127		484		39		54		0		391		266		44
SAN JUAN 30-6 UNIT #455		14161	SJ 30-6		30N06W18		1		22		1,405		70		268		24		30		0		214		147		52
SAN JUAN 30-6 UNIT #456		13537	SJ 30-6		30N06W18		1		23		2,800		140		534		41		59		0		433		310		51
SAN JUAN 30-6 UNIT #457		14193	SJ 30-6		30N06W19		1		24		2,501		125		477		38		53		0		386		267		45
SAN JUAN 30-6 UNIT #458		14194	SJ 30-6		30N06W19		1		18		1,153		58		220		20		24		0		175		128		63
SAN JUAN 30-6 UNIT #459		14195	SJ 30-6		30N06W20		1		16		1,072		54		204		18		23		0		164		125		64
SAN JUAN 30-6 UNIT #460		14162	SJ 30-6		30N06W20		1		16		1,254		63		239		20		27		0		192		146		55
SAN JUAN 30-6 UNIT #461		14251	SJ 30-6		30N07W11		1		20		858		43		163		17		18		0		128		89		80
SAN JUAN 30-6 UNIT #462		14196	SJ 30-6		30N07W12		1		28		1,920		96		366		32		41		0		293		189		83
SAN JUAN 30-6 UNIT #463		14197	SJ 30-6		30N07W13		1		24		1,413		71		269		25		30		0		214		143		81
SAN JUAN 30-6 UNIT #464		14198	SJ 30-6		30N07W14		1		18		767		38		146		15		16		0		115		82		46
SAN JUAN 30-6 UNIT #465		14199	SJ 30-6		30N07W15		1		22		1,512		75		288		25		32		0		231		161		65
SAN JUAN 30-6 UNIT #466		14200	SJ 30-6		30N07W22		1		12		495		25		94		10		10		0		74		59		75
SAN JUAN 30-6 UNIT #467 COM FRT.		4496	NEBU		30N07W22		1		19		999		28		106		10		12		0		84		61		105
SAN JUAN 30-6 UNIT #468		14252	SJ 30-6		30N07W36		1		30		3,364		168		641		50		71		0		520		336		91
SAN JUAN 30-6 UNIT #470		14253	SJ 30-6		30N06W21		1		19		1,410		70		269		23		30		0		216		157		102
SAN JUAN 30-6 UNIT #471		14254	SJ 30-6		30N06W21		1		17		1,152		58		220		19		24		0		176		132		113
SAN JUAN 30-6 UNIT #472		14255	SJ 30-6		30N06W22		1		21		757		38		144		16		16		0		112		76		107
SAN JUAN 30-6 UNIT #473		14256	SJ 30-6		30N06W22		1		19		1,136		57		217		20		24		0		172		124		106
SAN JUAN 30-6 UNIT #474		14257	SJ 30-6		30N06W27		1		27		2,652		132		505		41		56		0		409		272		97
SAN JUAN 30-6 UNIT #475		14258	SJ 30-6		30N06W27		1		29		3,565		178		679		52		76		0		552		364		109
SAN JUAN 30-6 UNIT #476		14163	SJ 30-6		30N06W28		1		24		1,945		97		371		31		41		0		298		205		100
SAN JUAN 30-6 UNIT #477		14210	SJ 30-6		30N06W28		1		31		3,718		186		708		55		79		0		575		370		111
SAN JUAN 30-6 UNIT #478		14205	SJ 30-6		30N06W29		1		26		2,782		139		530		42		59		0		429		290		101
SAN JUAN 30-6 UNIT #479		14259	SJ 30-6		30N06W29		1		22		1,835		92		350		29		39		0		281		197		134
SAN JUAN 30-6 UNIT #480		14260	SJ 30-6		30N06W30		1		19		1,108		55		211		20		23		0		168		121		110
SAN JUAN 30-6 UNIT #481		14261	SJ 30-6		30N06W30		1		33		3,939		197		751		58		83		0		609		387		99

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 20 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 30-6 UNIT #482		14266	SJ 30-6		30N06W31		1		30		3,145		157		599		48		67		0		485		313		142
SAN JUAN 30-6 UNIT #483		14207	SJ 30-6		30N06W34		1		23		1,229		61		234		22		26		0		186		126		104
SAN JUAN 30-6 UNIT #484		14249	SJ 30-6		30N06W34		1		40		2,137		107		407		39		45		0		323		174		103
SAN JUAN 30-6 UNIT #485		14233	SJ 30-6		30N07W36		1		27		2,766		138		527		42		59		0		426		285		204
SAN JUAN 30-6 UNIT #486		14234	SJ 30-6		30N06W23		1		14		951		47		181		16		20		0		145		115		271
SAN JUAN 30-6 UNIT #487		14235	SJ 30-6		30N06W23		1		25		2,134		107		407		34		45		0		328		221		292
SAN JUAN 30-6 UNIT #488		14236	SJ 30-6		30N06W24		1		15		484		24		92		11		10		0		71		52		222
SAN JUAN 30-6 UNIT #489		14237	SJ 30-6		30N06W24		1		23		2,012		100		383		32		43		0		309		214		249
SAN JUAN 30-6 UNIT #490		14238	SJ 30-6		30N06W25		1		15		1,034		52		197		18		22		0		158		121		223
SAN JUAN 30-6 UNIT #491		14239	SJ 30-6		30N06W25		1		23		1,757		88		335		29		37		0		269		187		224
SAN JUAN 30-6 UNIT #492		14240	SJ 30-6		30N06W26		1		23		1,244		62		237		23		26		0		188		126		230
SAN JUAN 30-6 UNIT #493		14241	SJ 30-6		30N06W32		1		20		1,203		60		229		21		25		0		183		129		205
SAN JUAN 30-6 UNIT #494		14242	SJ 30-6		30N06W33		1		32		4,042		202		770		59		86		0		626		399		212
SAN JUAN 30-6 UNIT #495		14243	SJ 30-6		30N06W33		1		26		2,132		106		406		34		45		0		327		220		213
SAN JUAN 30-6 UNIT #496		14244	SJ 30-6		30N06W35		1		21		842		42		160		17		18		0		126		86		225
SAN JUAN 30-6 UNIT #497		14245	SJ 30-6		30N07W29		1		28		884		44		168		20		19		0		130		78		259
SAN JUAN 30-6 UNIT #498R		13946	SJ 30-6		30N07W30		1		1		3		0		2		1		0		0		1		1		336
SAN JUAN 30-6 UNIT #500		14417	SJ 30-6		30N07W31		1		22		345		51		195		35		22		0		138		84		240
SAN JUAN 30-6 UNIT #501		14248	SJ 30-6		30N06W32		1		20		1,530		76		292		25		32		0		234		169		206
SAN JUAN 31 FEDERAL 3 #2		14418	NON-UNIT		31N09W03		1		29		2,235		332		1,267		110		141		0		1,016		654		559
SAN JUAN 31-6 UNIT #201		13540	SJ 31-6		30N06W01		1		25		1,243		133		508		51		56		0		401		261		130
SAN JUAN 31-6 UNIT #202		13552	SJ 31-6		30N06W01		1		29		2,471		265		1,010		86		112		0		812		523		118
SAN JUAN 31-6 UNIT #203		13539	SJ 31-6		30N06W03		1		15		509		55		208		24		23		0		161		120		88
SAN JUAN 31-6 UNIT #204		13541	SJ 31-6		30N06W03		1		18		1,350		145		552		49		61		0		442		326		90
SAN JUAN 31-6 UNIT #205R		12574	SJ 31-6		30N06W04		1		10		228		24		93		13		10		0		70		56		343
SAN JUAN 31-6 UNIT #206		13542	SJ 31-6		30N06W04		1		9		300		32		123		14		14		0		95		79		92
SAN JUAN 31-6 UNIT #207		13533	SJ 31-6		30N06W06		1		21		852		91		348		38		39		0		272		186		94
SAN JUAN 31-6 UNIT #208		14213	SJ 31-6		30N06W06		1		21		621		66		254		31		28		0		194		130		89
SAN JUAN 31-6 UNIT #209		14214	SJ 31-6		30N07W01		1		14		459		49		187		22		21		0		145		110		87
SAN JUAN 31-6 UNIT #210		13618	SJ 31-6		30N06W02		1		16		1,130		121		462		41		51		0		370		283		168
SAN JUAN 31-6 UNIT #211		13553	SJ 31-6		30N06W02		1		27		2,486		266		1,016		85		113		0		818		541		114
SAN JUAN 31-6 UNIT #212		13615	SJ 31-6		30N06W05		1		13		790		85		323		30		36		0		257		205		164
SAN JUAN 31-6 UNIT #213		13554	SJ 31-6		30N06W05		1		20		1,317		141		538		49		60		0		429		304		121
SAN JUAN 31-6 UNIT #214		13646	SJ 31-6		31N06W36		1		17		833		89		340		34		38		0		268		196		254
SAN JUAN 31-6 UNIT #215		13616	SJ 31-6		31N06W36		1		26		1,479		158		604		58		67		0		479		310		150
SAN JUAN 31-6 UNIT #216		13647	SJ 31-6		31N06W35		1		17		765		82		313		33		35		0		245		178		287
SAN JUAN 31-6 UNIT #217		13609	SJ 31-6		31N06W35		1		12		398		43		163		19		18		0		125		98		157
SAN JUAN 31-6 UNIT #218		13671	SJ 31-6		31N06W34		1		16		454		49		185		23		21		0		141		103		265
SAN JUAN 31-6 UNIT #219		13608	SJ 31-6		31N06W34		1		29		2,096		224		856		76		95		0		685		434		158
SAN JUAN 31-6 UNIT #220R		18278	SJ 31-6		31N06W33		1		0		0		0		0		0		0		0		0		0		641
SAN JUAN 31-6 UNIT #221		13656	SJ 31-6		31N06W33		1		22		861		92		352		39		39		0		274		183		253
SAN JUAN 31-6 UNIT #222		13666	SJ 31-6		31N06W32		1		12		320		34		131		17		15		0		99		76		220

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 21 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 31-6 UNIT #223		13613	SJ 31-6		31N06W32		1		23		1,214		130		496		49		55		0		392		265		149
SAN JUAN 31-6 UNIT #224		13691	SJ 31-6		31N06W31		1		11		395		42		161		19		18		0		125		99		274
SAN JUAN 31-6 UNIT #225R		13697	SJ 31-6		31N06W31		1		26		1,376		147		562		55		63		0		445		289		263
SAN JUAN 31-6 UNIT #228		14419	SJ 31-6		31N06W28		1		21		1,252		134		512		48		57		0		407		285		272
SAN JUAN 31-6 UNIT #229R		18279	SJ 31-6		31N06W28		1		16		590		63		241		27		27		0		187		136		640
SAN JUAN 31-6 UNIT #230		13555	SJ 31-6		31N06W27		1		28		1,817		195		743		68		83		0		592		381		125
SAN JUAN 31-6 UNIT #231R		17256	SJ 31-6		31N06W27		1		12		316		34		129		17		14		0		98		76		627
SAN JUAN 31-6 UNIT #232		13692	SJ 31-6		30N07W01		1		17		632		68		258		29		29		0		201		145		262
SAN JUAN 31-6 UNIT #233		13693	SJ 31-6		31N06W29		1		18		576		62		236		28		26		0		181		128		227
SAN JUAN 31-6 UNIT #234R		14007	SJ 31-6		31N06W29		1		8		165		18		68		10		8		0		50		41		337
SAN JUAN 32-7 UNIT #203R		12467	SJ 32-7		32N07W22		1		28		2,671		445		1,699		140		189		0		1,369		895		621
SAN JUAN 32-7 UNIT #204		13546	SJ 32-7		32N07W36		1		21		1,785		297		1,135		96		126		0		913		656		412
SAN JUAN 32-7 UNIT #206		12647	SJ 32-7		32N07W27		1		17		1,231		205		783		69		87		0		627		475		656
SAN JUAN 32-7 UNIT #207		13698	SJ 32-7		32N07W27		1		26		3,024		504		1,923		152		214		0		1,557		1,062		468
SAN JUAN 32-7 UNIT #208		13710	SJ 32-7		32N07W34		1		34		5,150		1,976		7,539		569		838		0		6,132		3,911		469
SAN JUAN 32-7 UNIT #209		13640	SJ 32-7		32N07W35		1		5		372		62		237		21		26		0		190		173		476
SAN JUAN 32-7 UNIT #210		13598	SJ 32-7		32N07W36		1		16		1,375		229		874		74		97		0		703		542		433
SAN JUAN 32-7 UNIT #211R		12642	SJ 32-7		32N07W35		1		16		940		157		598		56		66		0		476		362		618
SAN JUAN 32-7 UNIT #214		13717	SJ 32-7		32N07W34		1		7		81		31		119		26		13		0		79		66		551
SAN JUAN 32-7 UNIT #215		13700	SJ 32-7		32N07W32		1		15		987		164		627		58		70		0		500		383		481
SAN JUAN 32-7 UNIT #216		14422	SJ 32-7		31N07W04		1		10		204		34		130		20		14		0		95		75		581
SAN JUAN 32-7 UNIT #217		13701	SJ 32-7		31N07W04		1		11		322		54		204		26		23		0		156		122		570
SAN JUAN 32-7 UNIT #218		13702	SJ 32-7		31N07W05		1		25		1,627		271		1,035		94		115		0		826		554		571
SAN JUAN 32-7 UNIT #219		13703	SJ 32-7		31N07W05		1		21		2,003		334		1,274		105		142		0		1,027		735		572
SAN JUAN 32-7 UNIT #221		13704	SJ 32-7		31N07W08		1		26		1,988		331		1,265		110		141		0		1,014		676		552
SAN JUAN 32-7 UNIT #222		14423	SJ 32-7		32N07W20		1		16		1,234		186		710		61		79		0		570		436		588
SAN JUAN 32-7 UNIT #228		4816	SJ 32-7		31N07W07		1		18		2,456		209		798		61		89		0		648		492		617
SAN JUAN 32-7 UNIT #229		13729	SJ 32-7		31N07W09		1		26		2,021		337		1,285		111		143		0		1,031		689		566
SAN JUAN 32-7 UNIT #230		12620	SJ 32-7		31N07W17		1		26		2,448		408		1,557		128		173		0		1,256		850		616
SAN JUAN 32-7 UNIT #231		13664	SJ 32-7		31N07W17		1		11		207		34		132		21		15		0		96		75		567
SAN JUAN 32-7 UNIT #232		13705	SJ 32-7		31N07W08		1		14		564		94		358		39		40		0		279		211		556
SAN JUAN 32-7 UNIT #233		14452	SJ 32-7		32N07W20		1		22		2,330		388		1,482		119		165		0		1,198		858		592
SAN JUAN 32-7 UNIT #234		14425	SJ 32-7		32N07W32		1		19		1,321		220		840		75		93		0		672		491		583
SAN JUAN 32-7 UNIT #235		14426	SJ 32-7		32N07W29		1		30		5,927		988		3,769		274		419		0		3,077		2,064		589
SAN JUAN 32-7 UNIT #238		14455	SJ 32-7		32N07W29		1		25		3,015		502		1,917		150		213		0		1,554		1,077		593
SAN JUAN 32-7 UNIT #242		12643	SJ 32-7		32N07W33		1		20		2,740		457		1,742		134		194		0		1,415		1,048		657
SAN JUAN 32-7 UNIT COM #213 FRT.		4832	SJ 32-7		31N07W07		1		27		1,710		180		687		63		76		0		547		354		573
SAN JUAN 32-7 UNIT COM #220 FRT.		4835	SJ 32-7		31N07W05		1		24		2,342		341		1,303		107		145		0		1,051		730		619
SAN JUAN 32-7 UNIT COM #224		4792	SJ 32-7		32N07W21		1		26		3,296		412		1,572		122		175		0		1,275		874		582
SAN JUAN 32-7 UNIT COM #227 FRT.		4843	SJ 32-7		31N07W18		1		20		1,320		165		631		57		70		0		503		362		574
SAN JUAN 32-8 UNIT #202		13657	SJ 32-8		32N08W27		1		28		3,425		391		1,492		116		166		0		1,210		816		432
SAN JUAN 32-8 UNIT #203		14507	SJ 32-8		32N08W33		1		16		1,300		148		566		48		63		0		455		349		584

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 22 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 32-8 UNIT #204		14508	SJ 32-8		32N08W34		1		20		2,158		246		940		76		104		0		760		555		585
SAN JUAN 32-8 UNIT #205		14511	SJ 32-8		32N08W34		1		19		2,062		235		898		71		100		0		727		546		590
SAN JUAN 32-8 UNIT #206		14445	SJ 32-8		31N08W24		1		18		1,167		133		508		47		56		0		405		296		548
SAN JUAN 32-8 UNIT #207		13591	SJ 32-8		31N08W22		1		26		2,757		315		1,201		97		133		0		971		656		414
SAN JUAN 32-8 UNIT #208		13557	SJ 32-8		32N08W29		1		27		3,003		343		1,308		104		145		0		1,059		718		419
SAN JUAN 32-8 UNIT #213		12648	SJ 32-8		32N08W22		1		22		1,463		167		637		58		71		0		509		355		614
SAN JUAN 32-8 UNIT #218		14509	SJ 32-8		32N08W35		1		21		1,006		115		438		44		49		0		345		237		586
SAN JUAN 32-8 UNIT #219		14510	SJ 32-8		32N08W35		1		24		3,016		344		1,314		102		146		0		1,066		751		587
SAN JUAN 32-8 UNIT #220		13706	SJ 32-8		31N08W24		1		18		1,072		122		467		43		52		0		372		275		544
SAN JUAN 32-8 UNIT #221		13642	SJ 32-8		31N08W09		1		15		1,023		117		446		40		50		0		356		277		499
SAN JUAN 32-8 UNIT #222		13658	SJ 32-8		31N08W09		1		20		990		113		431		43		48		0		341		240		500
SAN JUAN 32-8 UNIT #223		13643	SJ 32-8		31N08W10		1		18		890		102		388		38		43		0		306		223		488
SAN JUAN 32-8 UNIT #224		13644	SJ 32-8		31N08W10		1		26		2,149		245		936		80		104		0		752		504		486
SAN JUAN 32-8 UNIT #225		14427	SJ 32-8		31N08W15		1		19		1,483		169		646		56		72		0		518		383		517
SAN JUAN 32-8 UNIT #226		13707	SJ 32-8		31N08W15		1		16		1,253		143		546		47		61		0		438		334		487
SAN JUAN 32-8 UNIT #227		14428	SJ 32-8		31N08W16		1		18		1,098		125		478		44		53		0		381		281		473
SAN JUAN 32-8 UNIT #228		14429	SJ 32-8		31N08W16		1		12		552		63		240		25		27		0		189		151		471
SAN JUAN 32-8 UNIT #229		13708	SJ 32-8		32N08W20		1		21		2,836		324		1,235		95		137		0		1,003		736		501
SAN JUAN 32-8 UNIT #230		13716	SJ 32-8		32N08W28		1		16		2,099		240		914		70		102		0		742		584		510
SAN JUAN 32-8 UNIT #231		13715	SJ 32-8		32N08W28		1		17		1,622		185		706		58		79		0		570		434		511
SAN JUAN 32-8 UNIT #232		13709	SJ 32-8		32N08W29		1		26		2,645		302		1,152		94		128		0		930		626		502
SAN JUAN 32-8 UNIT #233		13712	SJ 32-8		32N08W30		1		20		2,156		246		939		75		104		0		759		555		512
SAN JUAN 32-8 UNIT #234		14430	SJ 32-8		31N08W21		1		29		3,310		378		1,442		114		160		0		1,167		770		565
SAN JUAN 32-8 UNIT #235		14431	SJ 32-8		31N08W21		1		13		520		59		226		24		25		0		177		139		564
SAN JUAN 32-8 UNIT #236		14432	SJ 32-8		31N08W22		1		19		1,433		164		624		55		69		0		500		365		577
SAN JUAN 32-8 UNIT #237		13645	SJ 32-8		31N08W23		1		24		1,434		164		625		59		69		0		497		332		539
SAN JUAN 32-8 UNIT #238		13652	SJ 32-8		31N08W23		1		16		1,348		154		587		50		65		0		472		360		538
SAN JUAN 32-8 UNIT #239		13714	SJ 32-8		32N08W30		1		13		389		44		170		21		19		0		130		99		569
SAN JUAN 32-8 UNIT #240		13725	SJ 32-8		31N08W03		1		10		698		80		304		27		34		0		243		205		553
SAN JUAN 32-8 UNIT #241		13713	SJ 32-8		31N08W04		1		17		1,430		163		623		53		69		0		501		382		554
SAN JUAN 32-8 UNIT #242		14433	SJ 32-8		31N08W04		1		22		1,555		178		677		60		75		0		542		380		576
SAN JUAN 32-8 UNIT #243		14434	SJ 32-8		31N08W11		1		22		1,617		185		704		62		78		0		564		397		555
SAN JUAN 32-8 UNIT #244		13730	SJ 32-8		31N08W14		1		25		2,521		288		1,098		89		122		0		887		612		562
SAN JUAN 32-8 UNIT #245		14435	SJ 32-8		31N08W14		1		19		1,701		194		741		62		82		0		597		442		563
SAN JUAN 32-8 UNIT #247		12555	SJ 32-8		32N08W19		1		16		2,674		305		1,165		86		129		0		949		751		1195
SAN JUAN 32-8 UNIT #248		14436	SJ 32-8		31N08W11		1		19		1,417		162		617		54		69		0		495		362		568
SAN JUAN 32-8 UNIT #249		14437	SJ 32-8		31N08W03		1		17		1,541		176		671		56		75		0		541		410		557
SAN JUAN 32-8 UNIT #250		13731	SJ 32-8		32N08W33		1		28		3,081		352		1,342		107		149		0		1,086		727		558
SAN JUAN 32-8 UNIT #253		12649	SJ 32-8		32N08W27		1		15		871		99		379		36		42		0		301		230		615
SAN JUAN 32-8 UNIT #254		14084	SJ 32-8		32N08W23		1		17		449		51		195		25		22		0		148		106		622
SAN JUAN 32-8 UNIT #255		1874	SJ 32-8		32N08W24		1		13		515		59		224		25		25		0		175		136		1196
SAN JUAN 32-8 UNIT #256		19424	SJ 32-8		32N08W25		1		24		3,312		378		1,443		110		160		0		1,172		831		628

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 23 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 32-8 UNIT #257		16981	SJ 32-8		32N08W19		1		17		1,643		187		715		59		80		0		577		440		1197
SAN JUAN 32-8 UNIT #259A		5043	SJ 32-8		32N08W22		1		18		1,307		149		569		50		63		0		456		336		724
SAN JUAN 32-8 UNIT #261		17021	SJ 32-8		32N08W17		1		13		469		54		204		23		23		0		159		123		1198
SAN JUAN 32-8 UNIT #36		15041	SJ 32-8		32N08W25		1		15		189		22		82		17		9		0		56		38		371
SAN JUAN 32-9 UNIT #104		14466	SJ 32-9		32N10W24		1		27		3,442		76		290		22		32		0		236		160		426
SAN JUAN 32-9 UNIT #105		14467	SJ 32-9		31N09W08		1		16		553		12		47		5		5		0		36		27		427
SAN JUAN 32-9 UNIT #201		14438	SJ 32-9		31N09W02		1		14		479		11		40		5		4		0		31		24		441
SAN JUAN 32-9 UNIT #202		14439	SJ 32-9		31N09W02		1		9		417		9		35		4		4		0		28		23		442
SAN JUAN 32-9 UNIT #209		14273	SJ 32-9		31N10W02		1		12		161		4		14		3		2		0		9		7		443
SAN JUAN 32-9 UNIT #210		14274	SJ 32-9		31N10W02		1		15		206		20		75		14		8		0		52		36		444
SAN JUAN 32-9 UNIT #215		14468	SJ 32-9		32N09W10		1		17		694		15		58		6		6		0		46		33		503
SAN JUAN 32-9 UNIT #217		14275	SJ 32-9		32N09W16		1		18		887		17		64		6		7		0		51		37		482
SAN JUAN 32-9 UNIT #220		14000	SJ 32-9		31N10W11		1		27		3,517		78		296		23		33		0		241		163		594
SAN JUAN 32-9 UNIT #221		12458	SJ 32-9		31N10W11		1		4		26		1		2		1		0		0		1		1		595
SAN JUAN 32-9 UNIT #222		12556	SJ 32-9		31N10W12		1		2		17		0		1		0		0		0		1		1		596
SAN JUAN 32-9 UNIT #223		12459	SJ 32-9		31N10W12		1		11		191		4		16		3		2		0		12		9		597
SAN JUAN 32-9 UNIT #226		14469	SJ 32-9		32N09W32		1		16		1,192		26		100		9		11		0		81		62		445
SAN JUAN 32-9 UNIT #228		14440	SJ 32-9		32N09W36		1		6		228		5		19		2		2		0		15		13		446
SAN JUAN 32-9 UNIT #229		14267	SJ 32-9		32N10W36		1		24		2,624		58		221		17		25		0		179		126		447
SAN JUAN 32-9 UNIT #230		14470	SJ 32-9		32N10W36		1		21		544		12		46		6		5		0		35		23		448
SAN JUAN 32-9 UNIT #235		14450	SJ 32-9		32N09W36		1		18		1,613		36		136		11		15		0		110		81		449
SAN JUAN 32-9 UNIT #250		14268	SJ 32-9		31N09W04		1		22		2,910		64		245		19		27		0		199		144		531
SAN JUAN 32-9 UNIT #251		14269	SJ 32-9		31N09W04		1		24		3,374		74		284		21		32		0		231		163		478
SAN JUAN 32-9 UNIT #252		14471	SJ 32-9		31N09W05		1		22		2,135		47		180		14		20		0		145		104		479
SAN JUAN 32-9 UNIT #253		14472	SJ 32-9		31N09W05		1		16		1,387		31		117		10		13		0		94		72		504
SAN JUAN 32-9 UNIT #254		14473	SJ 32-9		31N09W06		1		16		1,184		26		100		9		11		0		80		62		483
SAN JUAN 32-9 UNIT #255		14474	SJ 32-9		31N09W06		1		17		1,378		30		116		10		13		0		93		70		489
SAN JUAN 32-9 UNIT #257		14475	SJ 32-9		31N09W08		1		22		781		17		66		7		7		0		51		34		545
SAN JUAN 32-9 UNIT #258		14476	SJ 32-9		31N09W09		1		26		1,968		43		166		14		18		0		133		88		506
SAN JUAN 32-9 UNIT #259		14477	SJ 32-9		31N09W09		1		25		1,447		32		122		11		14		0		97		64		490
SAN JUAN 32-9 UNIT #260		14270	SJ 32-9		31N09W10		1		16		1,185		26		100		9		11		0		80		62		484
SAN JUAN 32-9 UNIT #261		14271	SJ 32-9		31N09W10		1		2		14		0		1		0		0		0		1		1		491
SAN JUAN 32-9 UNIT #262		14478	SJ 32-9		31N09W15		1		25		853		19		72		8		8		0		56		35		492
SAN JUAN 32-9 UNIT #263		14479	SJ 32-9		31N09W15		1		19		803		18		68		7		8		0		53		37		485
SAN JUAN 32-9 UNIT #264		14480	SJ 32-9		31N09W17		1		25		851		19		72		8		8		0		55		35		514
SAN JUAN 32-9 UNIT #268		14482	SJ 32-9		31N10W01		1		18		1,035		23		87		8		10		0		69		51		535
SAN JUAN 32-9 UNIT #269		14483	SJ 32-9		31N10W01		1		16		777		17		65		7		7		0		52		38		518
SAN JUAN 32-9 UNIT #270		14484	SJ 32-9		32N09W18		1		30		3,809		84		321		24		36		0		261		172		519
SAN JUAN 32-9 UNIT #271		14485	SJ 32-9		32N09W18		1		24		4,474		99		377		27		42		0		308		223		520
SAN JUAN 32-9 UNIT #273		14486	SJ 32-9		32N09W19		1		20		2,835		63		239		18		27		0		194		145		521
SAN JUAN 32-9 UNIT #274		14272	SJ 32-9		32N09W28		1		17		1,804		40		152		12		17		0		123		94		575
SAN JUAN 32-9 UNIT #275		14487	SJ 32-9		32N09W29		1		20		1,597		35		135		11		15		0		108		79		536

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 24 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 #276		14344	SJ 32-9		32N09W27		1		22		2,222		49		187		15		21		0		151		108		579
SAN JUAN 32-9 UNIT #277		14488	SJ 32-9		32N09W30		1		17		1,776		39		150		12		17		0		121		93		516
SAN JUAN 32-9 UNIT #278		14489	SJ 32-9		32N09W31		1		19		1,614		36		136		11		15		0		110		80		515
SAN JUAN 32-9 UNIT #279		14490	SJ 32-9		32N09W31		1		21		2,100		46		177		14		20		0		143		103		528
SAN JUAN 32-9 UNIT #281		14491	SJ 32-9		32N09W32		1		30		2,285		50		193		16		21		0		155		98		470
SAN JUAN 32-9 UNIT #282		14345	SJ 32-9		32N09W33		1		23		2,037		45		172		14		19		0		138		98		522
SAN JUAN 32-9 UNIT #283		14346	SJ 32-9		32N09W33		1		31		4,039		89		340		26		38		0		277		180		480
SAN JUAN 32-9 UNIT #284		14492	SJ 32-9		32N10W13		1		20		3,177		70		268		20		30		0		218		165		523
SAN JUAN 32-9 UNIT #285		14493	SJ 32-9		32N10W13		1		18		2,981		66		251		18		28		0		205		158		537
SAN JUAN 32-9 UNIT #286		14494	SJ 32-9		32N10W14		1		23		3,230		71		272		20		30		0		222		160		493
SAN JUAN 32-9 UNIT #287		14495	SJ 32-9		32N10W14		1		21		3,090		68		260		19		29		0		212		156		533
SAN JUAN 32-9 UNIT #288		14496	SJ 32-9		32N10W23		1		16		2,543		56		214		16		24		0		175		138		534
SAN JUAN 32-9 UNIT #289		14497	SJ 32-9		32N10W23		1		29		4,371		97		368		27		41		0		300		202		524
SAN JUAN 32-9 UNIT #291		14498	SJ 32-9		32N10W24		1		20		2,036		45		172		14		19		0		139		103		505
SAN JUAN 32-9 UNIT #292		14499	SJ 32-9		32N10W25		1		23		3,038		67		256		19		28		0		208		148		525
SAN JUAN 32-9 UNIT #293		14500	SJ 32-9		32N10W25		1		18		2,001		44		169		13		19		0		137		103		494
SAN JUAN 32-9 UNIT #294		14501	SJ 32-9		32N10W26		1		18		1,625		36		137		11		15		0		110		82		529
SAN JUAN 32-9 UNIT #295		14502	SJ 32-9		32N10W26		1		17		1,529		34		129		11		14		0		104		79		526
SAN JUAN 32-9 UNIT #296		13928	SJ 32-9		32N10W35		1		12		704		16		59		6		7		0		47		38		560
SAN JUAN 32-9 UNIT #297		13929	SJ 32-9		32N10W35		1		5		128		3		11		1		1		0		8		7		527
SAN JUAN 32-9 UNIT #300		14503	SJ 32-9		32N10W11		1		21		3,849		85		324		23		36		0		265		198		507
SAN JUAN 32-9 UNIT #301		14504	SJ 32-9		32N10W12		1		31		4,609		102		388		29		43		0		316		207		508
SAN JUAN 32-9 UNIT #302		15548	SJ 32-9		32N09W09		1		19		1,143		25		96		9		11		0		77		55		658
SEYMOUR #720		14357	NON-UNIT		31N09W23		1		19		1,411		103		394		35		44		0		315		231		540
STATE GAS COM AA #1		14441	NON-UNIT		30N08W36		1		22		1,126		22		85		8		9		0		67		46		542
YAGER N COM #5 FRT.PI		4873	NON-UNIT		31N07W03		1		17		788		16		63		6		7		0		49		36		450
TOTAL PROVED DEVELOPED: 320-Acre New Mexico							612				820,588		62,531		238,637		21,883		26,527		0		190,227		130,977
TOTAL PROVED DEVELOPED NEW: MEXICO							861				1,083,954		91,029		347,393		31,415		38,616		0		277,361		195,536
PROVED UNDEVELOPED RESERVES
BLANCO #201A		5609	NON-UNIT		31N08W35		1		18		1,200		177		676		61		75		117		423		265		1168
BLANCO #330S		5559	NON-UNIT		31N08W05		1		18		1,200		88		334		31		37		58		209		132		1132
BONDS COM #100S		5140	NON-UNIT		32N10W15		1		20		1,800		90		342		28		38		38		238		156		1006
EAGLE #750S		5995	NON-UNIT		32N09W16		1		19		1,300		25		94		8		10		15		61		33		1179
FEDERAL G #4A COM.PI		5796	SJ 32-7		31N07W10		1		18		1,300		217		827		72		92		130		532		327		1129
FEDERAL G COM #5 FRT.PI		6009	NON-UNIT		31N07W03		1		19		1,300		27		103		9		11		16		67		38		1128
FRT 06-32N-7W		6011	SJ 32-7		31N07W06		1		18		1,300		217		827		72		92		130		532		312		1170
FRT 13-32N-10W		5855	SJ 32-9		32N10W13		1		22		1,800		36		138		11		15		15		96		49		1096
FRT 17-31N-8W (160-ACRE)		5596	NON-UNIT		31N08W17		1		20		1,200		88		336		31		37		58		210		110		1135
FRT 18-30N-7W (160-ACRE)		6048	NEBU		30N07W18		1		18		800		6		24		2		3		5		14		7		1062

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 25 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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
FRT 18-32N-7W		740	SJ 32-7		32N07W18		1		20		1,700		283		1,081		91		120		130		740		441		1172
FRT 22-30N-7W		6051	SJ 30-6		30N07W22		1		18		800		40		152		15		17		38		82		39		859
FRT 23-32N-10W (160-ACRE)		5916	SJ 32-9		32N10W23		1		22		1,800		36		138		11		15		15		96		49		1106
FRT 24-31N-8W		5603	SJ 32-8		31N08W24		1		18		1,200		137		522		47		58		89		328		202		1158
FRT 24-32N-10W (160-ACRE)		5911	SJ 32-9		32N10W24		1		22		1,800		36		138		11		15		15		96		50		1107
FRT 25-31N-7W (160-ACRE)		6012	NEBU		31N07W25		1		20		1,300		10		39		3		4		5		26		14		830
FRT 25-31N-8W (160-ACRE)		5272	NEBU		31N08W25		1		20		1,200		9		36		3		4		5		23		12		1064
FRT 25-32N-10W (160-ACRE)		5925	SJ 32-9		32N10W25		1		22		1,800		36		138		11		15		15		96		49		1109
FRT 26-31N-7W (160-ACRE)		6015	NEBU		31N07W26		1		20		1,300		10		39		3		4		5		26		14		1049
FRT 27-31N-7W (160-ACRE)		6021	NEBU		31N07W27		1		20		1,300		10		39		3		4		5		26		13		1050
FRT 29-32N-7W		5811	SJ 32-7		32N07W29		1		20		1,700		283		1,081		91		120		130		740		462		1175
FRT 31-31N-7W (160-ACRE)		6014	NEBU		31N07W31		1		20		1,300		10		39		3		4		5		26		13		1055
FRT 31-32N-7W (160-ACRE.PI)		5809	SJ 32-7		32N07W31		1		20		1,700		283		1,081		91		120		130		740		458		1130
FRT 32-31N-7W		5801	NEBU		31N07W32		1		18		1,300		10		39		3		4		5		26		15		1056
FRT 32-32N-9W		5974	SJ 32-9		32N09W32		1		20		1,300		26		100		9		11		15		65		34		1118
FRT 33-31N-7W (160-ACRE)		6024	NEBU		31N07W33		1		20		1,300		10		39		3		4		5		26		14		1058
FRT 33-31N-7W (160-ACRE)		6025	NEBU		31N07W33		1		20		1,300		10		39		3		4		5		26		14		1057
FRT 35-32N-10W (160-ACRE)		5853	SJ 32-9		32N10W35		1		23		1,800		36		138		11		15		15		96		48		1123
FRT 36-30N-8W (160-ACRE)		10782	NON-UNIT		30N08W36		1		21		900		18		68		6		8		15		39		16		1205
FRT 36-32N-10W (160-ACRE)		5933	SJ 32-9		32N10W36		1		22		1,800		36		138		11		15		15		96		49		1125
HEIZER #100S		5114	NON-UNIT		32N10W15		1		21		1,800		1		3		0		0		0		2		1		1005
JACQUEZ #331S		5582	NON-UNIT		31N08W07		1		19		1,200		92		350		30		39		56		225		130		1136
NE BLANCO UNIT #401A		5317	NEBU		30N07W09		1		19		800		6		24		2		3		5		14		6		834
NE BLANCO UNIT #402A		5145	NEBU		30N07W05		1		17		800		6		24		2		3		5		14		7		1007
NE BLANCO UNIT #403A		5191	NEBU		30N07W09		1		17		800		6		24		2		3		5		14		8		767
NE BLANCO UNIT #404A		6026	NEBU		31N07W34		1		19		1,300		10		39		3		4		5		26		14		1060
NE BLANCO UNIT #409A		5273	NEBU		30N07W10		1		20		800		6		24		2		3		5		14		6		835
NE BLANCO UNIT #411A		5200	NEBU		30N07W10		1		17		800		6		24		2		3		5		14		8		768
NE BLANCO UNIT #414A		6023	NEBU		31N07W30		1		20		1,300		10		39		3		4		5		26		14		1054
NE BLANCO UNIT #415A		5207	NEBU		30N07W02		1		17		800		6		24		2		3		5		14		8		769
NE BLANCO UNIT #416A		5282	NEBU		31N07W21		1		20		1,300		10		39		3		4		5		26		13		1063
NE BLANCO UNIT #417A		5274	NEBU		30N07W02		1		19		800		6		24		2		3		5		14		6		832
NE BLANCO UNIT #419A		6031	NEBU		30N07W03		1		18		800		6		24		2		3		5		14		7		824
NE BLANCO UNIT #420A		5279	NEBU		31N07W28		1		20		1,300		10		39		3		4		5		26		13		1065
NE BLANCO UNIT #421A		6033	NEBU		30N07W04		1		18		800		6		24		2		3		5		14		7		825
NE BLANCO UNIT #423A		6037	NEBU		30N07W08		1		19		800		6		24		2		3		5		14		7		827
NE BLANCO UNIT #424A		6034	NEBU		30N07W04		1		18		800		6		24		2		3		5		14		7		1035
NE BLANCO UNIT #425A		6038	NEBU		30N07W08		1		18		800		6		24		2		3		5		14		7		826
NE BLANCO UNIT #427A		5148	NEBU		30N07W16		1		17		800		6		24		2		3		5		14		7		770
NE BLANCO UNIT #428A		6018	NEBU		31N07W24		1		19		1,300		10		39		3		4		5		26		14		1048
NE BLANCO UNIT #429A		5150	NEBU		30N07W17		1		17		800		6		24		2		3		5		14		7		771
NE BLANCO UNIT #431A		6046	NEBU		30N07W17		1		18		800		6		24		2		3		5		14		7		829

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 26 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 #432A		5160	NEBU		30N07W07		1		17		800		6		24		2		3		5		14		8		1014
NE BLANCO UNIT #434A		6017	NEBU		31N07W23		1		19		1,300		10		39		3		4		5		26		14		1045
NE BLANCO UNIT #439A		5169	NEBU		30N08W13		1		18		900		7		27		2		3		5		16		10		1016
NE BLANCO UNIT #444A		6016	NEBU		31N07W23		1		20		1,300		10		39		3		4		5		26		14		1046
NE BLANCO UNIT #451A		6035	NEBU		30N07W06		1		18		800		6		24		2		3		5		14		7		1037
NE BLANCO UNIT #452A		5797	NEBU		31N07W15		1		19		1,300		10		39		3		4		5		26		15		1041
NE BLANCO UNIT #453A		6036	NEBU		30N07W06		1		18		800		6		24		2		3		5		14		7		1036
NE BLANCO UNIT #455A		5190	NEBU		31N07W31		1		18		1,300		10		39		3		4		5		26		16		1021
NE BLANCO UNIT #457		6022	NEBU		31N07W30		1		21		1,300		10		39		3		4		5		26		12		1066
NE BLANCO UNIT #459A		5800	NEBU		31N07W19		1		19		1,300		10		39		3		4		5		26		15		1043
NE BLANCO UNIT #461A		5182	NEBU		30N07W07		1		17		800		6		24		2		3		5		14		8		1024
NE BLANCO UNIT #465A		5243	NEBU		30N08W01		1		18		900		7		27		2		3		5		16		9		1027
NE BLANCO UNIT #466A		6027	NEBU		31N07W34		1		19		1,300		10		39		3		4		5		26		14		1059
NE BLANCO UNIT #467A		5269	NEBU		30N08W12		1		20		900		7		27		2		3		5		16		7		1061
NE BLANCO UNIT #469A		6007	NEBU		30N08W13		1		20		900		7		27		2		3		5		16		7		1040
NE BLANCO UNIT #472A		5803	NEBU		31N07W29		1		19		1,300		10		39		3		4		5		26		15		1052
NE BLANCO UNIT #473A		5281	NEBU		31N08W36		1		21		1,200		9		36		3		4		5		23		11		1067
NE BLANCO UNIT #475A		1787	NEBU		30N07W19		1		20		800		6		24		2		3		5		14		6		837
NE BLANCO UNIT #476A		5799	NEBU		31N07W22		1		19		1,300		10		39		3		4		5		26		15		1044
NE BLANCO UNIT #479A		1785	NEBU		30N07W20		1		20		800		6		24		2		3		5		14		6		839
NE BLANCO UNIT #481A		5153	NEBU		31N07W36		1		18		1,300		10		39		3		4		5		26		16		773
NE BLANCO UNIT #485A		6032	NEBU		30N07W03		1		18		800		6		24		2		3		5		14		7		823
NE BLANCO UNIT #487A		5201	NEBU		31N07W35		1		18		1,300		10		39		3		4		5		26		16		1030
NE BLANCO UNIT #488A		6019	NEBU		31N07W24		1		19		1,300		10		39		3		4		5		26		14		1047
NE BLANCO UNIT #489A		5792	NEBU		31N07W12		1		19		1,300		10		39		3		4		5		26		15		1039
NE BLANCO UNIT #492A		5795	NEBU		31N07W12		1		19		1,300		10		39		3		4		5		26		15		1038
NE BLANCO UNIT #494A		6020	NEBU		31N07W27		1		20		1,300		10		39		3		4		5		26		13		1051
NE BLANCO UNIT #505A		1784	NEBU		30N07W21		1		20		800		6		24		2		3		5		14		6		838
NORDHAUS #716S		5839	NON-UNIT		31N09W13		1		18		800		58		222		23		25		58		117		57		1131
SAN JUAN 29-5 UNIT #225A		5111	SJ 29-5		29N05W06		1		15		600		78		296		32		33		100		131		67		758
SAN JUAN 29-6 UNIT #206A		5409	SJ 29-6		29N06W04		1		18		800		97		369		37		41		93		198		99		904
SAN JUAN 29-6 UNIT #211A		6094	SJ 29-6		29N06W20		1		18		800		97		369		37		41		93		198		99		923
SAN JUAN 29-6 UNIT #219A		6079	SJ 29-6		29N06W10		1		17		800		97		369		37		41		93		198		106		910
SAN JUAN 29-6 UNIT #220A		6081	SJ 29-6		29N06W11		1		17		800		97		369		37		41		93		198		114		912
SAN JUAN 29-6 UNIT #221A		6082	SJ 29-6		29N06W11		1		17		800		97		369		37		41		93		198		109		911
SAN JUAN 29-6 UNIT #222A		6083	SJ 29-6		29N06W12		1		17		800		97		369		37		41		93		198		104		914
SAN JUAN 29-6 UNIT #223A		6084	SJ 29-6		29N06W12		1		17		800		97		369		37		41		93		198		104		913
SAN JUAN 29-6 UNIT #224A		6085	SJ 29-6		29N06W13		1		18		800		97		369		37		41		93		198		102		916
SAN JUAN 29-6 UNIT #226A		6088	SJ 29-6		29N06W14		1		18		800		97		369		37		41		93		198		102		917
SAN JUAN 29-6 UNIT #257A		5645	SJ 29-6		29N06W09		1		17		800		97		369		37		41		93		198		107		907
SAN JUAN 29-6 UNIT #258A		6089	SJ 29-6		29N06W16		1		18		800		97		369		37		41		93		198		102		920
SAN JUAN 29-6 UNIT #262A		6096	SJ 29-6		29N06W21		1		18		800		97		369		37		41		93		198		101		925

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 27 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 29-7 UNIT #507S		6070	SJ 29-7		29N07W13		1		16		600		63		239		25		27		78		110		48		894
SAN JUAN 29-7 UNIT #520S		6062	SJ 29-7		29N07W08		1		16		600		63		239		25		27		78		110		51		888
SAN JUAN 29-7 UNIT #521S		6069	SJ 29-7		29N07W13		1		17		600		63		239		25		27		78		110		47		895
SAN JUAN 29-7 UNIT #544S		6053	SJ 29-7		29N07W04		1		17		600		63		239		25		27		78		110		47		884
SAN JUAN 29-7 UNIT #545S		6068	SJ 29-7		29N07W12		1		16		600		63		239		25		27		78		110		49		892
SAN JUAN 29-7 UNIT #552S		6067	SJ 29-7		29N07W12		1		17		600		63		239		25		27		78		110		47		893
SAN JUAN 29-7 UNIT #553S		1546	SJ 29-7		29N07W14		1		18		600		63		239		25		27		78		110		43		901
SAN JUAN 29-7 UNIT #562S		6071	SJ 29-7		29N07W24		1		16		600		63		239		25		27		78		110		49		896
SAN JUAN 29-7 UNIT #577S		12177	SJ 29-7		29N07W35		1		15		600		42		160		18		18		58		66		30		1206
SAN JUAN 29-7 UNIT #580S		6052	SJ 29-7		29N07W01		1		17		600		63		239		25		27		78		110		47		881
SAN JUAN 30-5 UNIT #211A		5783	SJ 30-5		30N05W31		1		19		1,600		282		1,076		89		120		135		732		461		986
SAN JUAN 30-5 UNIT #220A		8014	SJ 30-5		30N05W08		1		20		1,600		282		1,076		89		120		135		732		429		1203
SAN JUAN 30-5 UNIT #224A		5719	SJ 30-5		30N05W17		1		19		1,600		282		1,076		89		120		135		732		453		966
SAN JUAN 30-5 UNIT #227A		5744	SJ 30-5		30N05W28		1		19		1,600		282		1,076		89		120		135		732		457		981
SAN JUAN 30-5 UNIT #228A		5745	SJ 30-5		30N05W28		1		20		1,600		282		1,076		89		120		135		732		446		980
SAN JUAN 30-5 UNIT #233A		5787	SJ 30-5		30N05W33		1		19		1,600		282		1,076		89		120		135		732		461		988
SAN JUAN 30-5 UNIT #239A		5716	SJ 30-5		30N05W15		1		19		1,600		282		1,076		89		120		135		732		453		964
SAN JUAN 30-5 UNIT #246A		5741	SJ 30-5		30N05W26		1		19		1,600		282		1,076		89		120		135		732		453		978
SAN JUAN 30-5 UNIT #249A		5740	SJ 30-5		30N05W23		1		19		1,600		282		1,076		89		120		135		732		461		976
SAN JUAN 30-5 UNIT #255A		5714	SJ 30-5		30N05W14		1		19		1,600		282		1,076		89		120		135		732		453		962
SAN JUAN 30-5 UNIT #257A		5712	SJ 30-5		30N05W11		1		20		1,600		282		1,076		89		120		135		732		446		959
SAN JUAN 30-5 UNIT #258A		5715	SJ 30-5		30N05W14		1		19		1,600		282		1,076		89		120		135		732		453		961
SAN JUAN 30-5 UNIT #261A		5713	SJ 30-5		30N05W11		1		19		1,600		282		1,076		89		120		135		732		457		958
SAN JUAN 30-5 UNIT #262A		5791	SJ 30-5		30N05W12		1		20		1,600		282		1,076		89		120		135		732		446		960
SAN JUAN 30-6 UNIT #400S		6042	SJ 30-6		30N07W14		1		18		800		40		152		15		17		38		82		41		845
SAN JUAN 30-6 UNIT #401S		6041	SJ 30-6		30N07W13		1		19		800		40		152		15		17		38		82		38		876
SAN JUAN 30-6 UNIT #403S		5435	SJ 30-6		30N06W09		1		18		1,000		50		191		18		21		38		113		67		777
SAN JUAN 30-6 UNIT #406S		6043	SJ 30-6		30N07W15		1		18		800		40		152		15		17		38		82		41		861
SAN JUAN 30-6 UNIT #407S		5527	SJ 30-6		30N06W16		1		19		1,000		50		191		18		21		38		113		60		849
SAN JUAN 30-6 UNIT #409S		5521	SJ 30-6		30N07W25		1		17		800		40		152		15		17		38		82		46		780
SAN JUAN 30-6 UNIT #410S		5539	SJ 30-6		30N06W26		1		20		1,000		50		191		18		21		38		113		58		864
SAN JUAN 30-6 UNIT #416S		5519	SJ 30-6		30N07W24		1		17		800		40		152		15		17		38		82		46		783
SAN JUAN 30-6 UNIT #417S		5429	SJ 30-6		30N07W25		1		17		800		40		152		15		17		38		82		43		762
SAN JUAN 30-6 UNIT #418S		5522	SJ 30-6		30N07W26		1		17		800		40		152		15		17		38		82		43		784
SAN JUAN 30-6 UNIT #419S		6028	SJ 30-6		30N07W11		1		19		800		40		152		15		17		38		82		38		842
SAN JUAN 30-6 UNIT #420S		6039	SJ 30-6		30N07W12		1		19		800		40		152		15		17		38		82		38		844
SAN JUAN 30-6 UNIT #435S		5484	SJ 30-6		30N06W13		1		19		1,000		50		191		18		21		38		113		64		789
SAN JUAN 30-6 UNIT #436S		5525	SJ 30-6		30N06W15		1		19		1,000		50		191		18		21		38		113		60		848
SAN JUAN 30-6 UNIT #439S		5524	SJ 30-6		30N06W14		1		19		1,000		50		191		18		21		38		113		63		846
SAN JUAN 30-6 UNIT #440S		5526	SJ 30-6		30N06W15		1		19		1,000		50		191		18		21		38		113		60		847
SAN JUAN 30-6 UNIT #441S		5495	SJ 30-6		30N06W31		1		19		1,000		50		191		18		21		38		113		61		792
SAN JUAN 30-6 UNIT #453		5528	SJ 30-6		30N06W17		1		19		1,000		50		191		18		21		38		113		60		851

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 28 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 30-6 UNIT #454S		5529	SJ 30-6		30N06W17		1		20		1,000		50		191		18		21		38		113		56		850
SAN JUAN 30-6 UNIT #455S		5530	SJ 30-6		30N06W18		1		20		1,000		50		191		18		21		38		113		56		853
SAN JUAN 30-6 UNIT #456S		5531	SJ 30-6		30N06W18		1		20		1,000		50		191		18		21		38		113		56		852
SAN JUAN 30-6 UNIT #458S		5532	SJ 30-6		30N06W19		1		20		1,000		50		191		18		21		38		113		56		854
SAN JUAN 30-6 UNIT #459S		5533	SJ 30-6		30N06W20		1		20		1,000		50		191		18		21		38		113		57		855
SAN JUAN 30-6 UNIT #462A		6040	SJ 30-6		30N07W12		1		18		800		40		152		15		17		38		82		41		843
SAN JUAN 30-6 UNIT #464S		5506	SJ 30-6		30N07W14		1		17		800		40		152		15		17		38		82		43		801
SAN JUAN 30-6 UNIT #465S		5507	SJ 30-6		30N07W15		1		17		800		40		152		15		17		38		82		43		802
SAN JUAN 30-6 UNIT #467A COM FRT		6049	NEBU		30N07W22		1		18		800		6		24		2		3		5		14		7		822
SAN JUAN 30-6 UNIT #470S		5534	SJ 30-6		30N06W21		1		20		1,000		50		191		18		21		38		113		57		856
SAN JUAN 30-6 UNIT #472		5536	SJ 30-6		30N06W22		1		20		1,000		50		191		18		21		38		113		57		857
SAN JUAN 30-6 UNIT #473S		5535	SJ 30-6		30N06W22		1		20		1,000		50		191		18		21		38		113		57		858
SAN JUAN 30-6 UNIT #474S		5540	SJ 30-6		30N06W27		1		20		1,000		50		191		18		21		38		113		58		866
SAN JUAN 30-6 UNIT #476S		5541	SJ 30-6		30N06W28		1		19		1,000		50		191		18		21		38		113		61		863
SAN JUAN 30-6 UNIT #479S		5542	SJ 30-6		30N06W29		1		20		1,000		50		191		18		21		38		113		58		869
SAN JUAN 30-6 UNIT #480S		5543	SJ 30-6		30N06W30		1		19		1,000		50		191		18		21		38		113		60		862
SAN JUAN 30-6 UNIT #482S		5494	SJ 30-6		30N06W31		1		19		1,000		50		191		18		21		38		113		61		805
SAN JUAN 30-6 UNIT #487S		5537	SJ 30-6		30N06W23		1		19		1,000		50		191		18		21		38		113		60		860
SAN JUAN 30-6 UNIT #494S		5498	SJ 30-6		30N06W33		1		19		1,000		50		191		18		21		38		113		62		812
SAN JUAN 30-6 UNIT #495S		5497	SJ 30-6		30N06W33		1		19		1,000		50		191		18		21		38		113		62		813
SAN JUAN 30-6 UNIT #501SR		5496	SJ 30-6		30N06W32		1		20		1,000		50		191		18		21		38		113		58		815
SAN JUAN 31 FEDERAL 3 #2A		5942	NON-UNIT		31N09W03		1		18		800		119		453		46		50		117		240		120		1169
SAN JUAN 31-6 UNIT #207A		5615	SJ 31-6		30N06W06		1		18		1,000		107		409		40		45		84		240		137		937
SAN JUAN 31-6 UNIT #208A		5614	SJ 31-6		30N06W06		1		20		1,000		107		409		40		45		84		240		123		938
SAN JUAN 31-6 UNIT #209A		6030	SJ 31-6		30N07W01		1		18		800		86		327		33		36		84		174		87		933
SAN JUAN 31-6 UNIT #224A		708	SJ 31-6		31N06W31		1		18		1,300		139		531		47		59		84		342		215		1164
SAN JUAN 31-6 UNIT #225A		5611	SJ 31-6		31N06W31		1		18		1,300		139		531		47		59		84		342		215		1163
SAN JUAN 31-6 UNIT #232A		6029	SJ 31-6		30N07W01		1		18		800		86		327		33		36		84		174		87		934
SAN JUAN 32-7 UNIT #222A		6008	SJ 32-7		32N07W20		1		19		1,700		256		978		81		109		117		672		442		1180
SAN JUAN 32-7 UNIT #233A		5819	SJ 32-7		32N07W20		1		20		1,700		283		1,081		91		120		130		740		470		1173
SAN JUAN 32-8 UNIT #207A		5598	SJ 32-8		31N08W22		1		18		1,200		137		522		47		58		89		328		202		1152
SAN JUAN 32-8 UNIT #213A		6003	SJ 32-8		32N08W22		1		21		2,000		228		870		71		97		89		613		375		1154
SAN JUAN 32-8 UNIT #259		6004	SJ 32-8		32N08W22		1		21		2,000		228		870		71		97		89		613		372		1153
SAN JUAN 32-8 UNIT #261A		6507	SJ 32-8		32N08W17		1		21		2,000		228		870		71		97		89		613		381		1202
SAN JUAN 32-9 UNIT #105S		5956	SJ 32-9		31N09W08		1		19		800		16		61		6		7		15		33		15		1084
SAN JUAN 32-9 UNIT #215S		5992	SJ 32-9		32N09W10		1		19		1,300		26		100		9		11		15		65		35		1089
SAN JUAN 32-9 UNIT #220S		5897	SJ 32-9		31N10W11		1		17		600		12		46		5		5		15		21		8		1090
SAN JUAN 32-9 UNIT #221S		5890	SJ 32-9		31N10W11		1		17		600		12		46		5		5		15		21		9		1091
SAN JUAN 32-9 UNIT #226S		5970	SJ 32-9		32N09W32		1		20		1,300		26		100		9		11		15		65		34		1119
SAN JUAN 32-9 UNIT #252S		5949	SJ 32-9		31N09W05		1		19		800		16		61		6		7		15		33		15		1080
SAN JUAN 32-9 UNIT #253S		5952	SJ 32-9		31N09W05		1		19		800		16		61		6		7		15		33		15		1079
SAN JUAN 32-9 UNIT #254S		5953	SJ 32-9		31N09W06		1		17		800		16		61		6		7		15		33		19		1082

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 29 of 30

WILLIAMS PRODUCTION CO.
FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2004

														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 #255S		5955	SJ 32-9		31N09W06		1		19		800		16		61		6		7		15		33		15		1081
SAN JUAN 32-9 UNIT #257S		5957	SJ 32-9		31N09W08		1		17		800		16		61		6		7		15		33		18		1083
SAN JUAN 32-9 UNIT #258S		5958	SJ 32-9		31N09W09		1		19		800		16		61		6		7		15		33		15		1086
SAN JUAN 32-9 UNIT #259S		5959	SJ 32-9		31N09W09		1		19		800		16		61		6		7		15		33		15		1085
SAN JUAN 32-9 UNIT #260S		5960	SJ 32-9		31N09W10		1		19		800		16		61		6		7		15		33		15		1088
SAN JUAN 32-9 UNIT #261S		5961	SJ 32-9		31N09W10		1		18		800		16		61		6		7		15		33		17		1087
SAN JUAN 32-9 UNIT #262S		5834	SJ 32-9		31N09W15		1		18		800		16		61		6		7		15		33		16		1099
SAN JUAN 32-9 UNIT #270S		5991	SJ 32-9		32N09W18		1		17		1,300		26		100		9		11		15		65		42		1103
SAN JUAN 32-9 UNIT #273S		5980	SJ 32-9		32N09W19		1		18		1,300		26		100		9		11		15		65		40		1104
SAN JUAN 32-9 UNIT #274S		5962	SJ 32-9		32N09W28		1		18		1,300		26		100		9		11		15		65		40		1113
SAN JUAN 32-9 UNIT #275S		5965	SJ 32-9		32N09W29		1		18		1,300		26		100		9		11		15		65		41		1114
SAN JUAN 32-9 UNIT #276S		5964	SJ 32-9		32N09W27		1		18		1,300		26		100		9		11		15		65		41		1112
SAN JUAN 32-9 UNIT #278S		5967	SJ 32-9		32N09W31		1		20		1,300		26		100		9		11		15		65		34		1117
SAN JUAN 32-9 UNIT #279S		5968	SJ 32-9		32N09W31		1		20		1,300		26		100		9		11		15		65		34		1116
SAN JUAN 32-9 UNIT #286S		5914	SJ 32-9		32N10W14		1		20		1,800		36		138		11		15		15		96		61		1098
SAN JUAN 32-9 UNIT #287S		5915	SJ 32-9		32N10W14		1		20		1,800		36		138		11		15		15		96		61		1097
SAN JUAN 32-9 UNIT #289S		5918	SJ 32-9		32N10W23		1		20		1,800		36		138		11		15		15		96		61		1105
SAN JUAN 32-9 UNIT #293S		5927	SJ 32-9		32N10W25		1		20		1,800		36		138		11		15		15		96		61		1108
SAN JUAN 32-9 UNIT #294S		5930	SJ 32-9		32N10W26		1		20		1,800		36		138		11		15		15		96		62		1111
SAN JUAN 32-9 UNIT #295S		5931	SJ 32-9		32N10W26		1		20		1,800		36		138		11		15		15		96		62		1110
SAN JUAN 32-9 UNIT #297S		5854	SJ 32-9		32N10W35		1		21		1,800		36		138		11		15		15		96		56		1122
SAN JUAN 32-9 UNIT #300S		5856	SJ 32-9		32N10W11		1		20		1,800		36		138		11		15		15		96		62		1092
SEYMOUR #720S		5837	NON-UNIT		31N09W23		1		19		800		58		223		23		25		58		117		50		1134
TOTAL PROVED UNDEVELOPED: 160-Acre New Mexico							201				224,299		13,337		50,899		4,528		5,658		8,708		32,006		18,565
FRT 18-30N-7W		6047	NEBU		30N07W18		1		18		800		6		24		2		3		5		14		7		1042
FRT 18-31N-7W (PI)		6010	SJ 32-7		31N07W18		1		18		1,300		217		827		72		92		130		532		314		1162
SAN JUAN 30-5 UNIT #225A		5773	SJ 30-5		30N05W29		1		19		1,600		282		1,076		89		120		135		732		450		982
SAN JUAN 30-5 UNIT #237R		6123	SJ 30-5		30N05W16		1		19		1,600		819		3,125		253		347		382		2,143		1,353		1201
TOTAL PROVED UNDEVELOPED: 320-Acre New Mexico							4				5,300		1,323		5,051		416		561		653		3,420		2,124
TOTAL PROVED UNDEVELOPED: NEW MEXICO							205				229,599		14,661		55,950		4,944		6,219		9,361		35,426		20,689
TOTAL PROVED RESERVES: NEW MEXICO							1066				1,313,553		105,689		403,343		36,359		44,836		9,361		312,787		216,226
TOTAL PROVED RESERVES							1087				1,361,543		113,752		435,713		36,359		44,836		9,361		345,157		237,990

DATE: 12/31/2004 This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report. TABLE 4
Page 30 of 30