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, 2006

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 (State or other jurisdiction of incorporation or organization)	75-6437433 (I.R.S. employer identification number)
Trust Division Royalty Trust Group Bank of America, N.A. 901 Main Street, 17th Floor Dallas, Texas (Address of principal executive offices)	75202 (Zip Code)

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

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

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

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT
NONE

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

     Yes o   No þ   

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

     Yes o   No þ   

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

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

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

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

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

     Yes o   No þ   

     The aggregate market value of the registrant’s units of beneficial interest outstanding (based on the closing sale price on the New York Stock Exchange on June 30, 2006, 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 $135,264,563.

     At March 1, 2007, 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		14
STATE TAX CONSIDERATIONS		14
REGULATION AND PRICES		14
Regulation of Natural Gas		14
Environmental Regulation		15
Competition, Markets and Prices		16
Item 1A. Risk Factors		17
Item 1B. Unresolved Staff Comments		22
Item 2. Properties		22
THE ROYALTY INTERESTS		22
The Underlying Properties		23
The NPI		25
Reserve Report		26
Historical Gas Sales Prices and Production		27
NPI Percentage Reduction		28
Gas Purchase Contract		28
Gas Gathering Contract		30
Federal and Indian Lands		31
Sale and Abandonment of Underlying Properties		32
The Infill Wells		33
Royalty Trust Reserves		33
Williams’ Performance Assurances		34
Title to Properties		34
Item 3. Legal Proceedings		35
Item 4. Submission of Matters to a Vote of Security Holders		36
PART II		36
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		36
Item 6. Selected Financial Data		36
Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations		36
Critical Accounting Policies and Estimates		36

	Page
Liquidity and Capital Resources		37
Results of Operations		38
Off-Balance Sheet Arrangements		40
Tabular Disclosure of Contractual Obligations		40
Forward-Looking Statements		40
Item 7A. Quantitative and Qualitative Disclosure About Market Risk		40
Item 8. Financial Statements and Supplementary Data		41
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		50
Item 9A. Controls and Procedures		51
Item 9B. Other Information		53
PART III		53
Item 10. Directors and Executive Officers of the Registrant		53
Item 11. Executive Compensation		53
Item 12. Security Ownership of Certain Beneficial Owners and Management		54
Williams’s Voting Authority Over Units		54
Item 13. Certain Relationships and Related Transactions		55
Administrative Services Agreement		55
Potential Conflicts of Interest		55
Item 14. Principal Accounting Fees and Services		55
PART IV		56
Item 15. Exhibits and Financial Statement Schedules		56
Consent of Ernst & Young LLP
Consent of Miller and Lents, Ltd
Certification Pursuant to Section 302
Certification Pursuant to Section 906
Reserve Report

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

PART I

Item 1. Business.

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

GLOSSARY

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

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

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

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

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

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

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

     “December 31, 2006 Reserve Report” means the Reserve Report, dated January 31, 2007, 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, 2006, prepared by Miller and Lents, Ltd., independent petroleum engineers, a copy of which is filed as an exhibit to this Form 10-K.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

     “Mcf” means thousand cubic feet of natural gas.

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

     “MMBtu” means million Btu.

     “MMcf” means million cubic feet of natural gas.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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     “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 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

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material terms of the Trust Agreement, and detailed provisions concerning the Trust may be found in the Trust Agreement.

Creation and Organization of the Trust

     The Trust was formed effective as of December 1, 1992 under Delaware law pursuant to the terms of the Trust Agreement to acquire and hold certain net profits interests (the “Royalty Interests”) in proved natural gas properties located in the San Juan Basin of New Mexico and Colorado (the “Underlying Properties”). The Royalty Interests were conveyed to the Trust on January 21, 1993, pursuant to the Conveyance, for the benefit of the Unitholders. All of the authorized units of beneficial interest in the Trust (“Units”) were issued to WPC on January 21, 1993. On that date, WPC transferred its Units to its parent, Williams, by dividend. Williams, in turn, sold, by means of a prospectus dated January 13, 1993, 5,200,000 Units on January 21, 1993, and an additional 780,000 Units on February 16, 1993, to the public through various underwriters (the “Public Offering”). In the second quarter of 1993, Williams sold an additional 151,209 Units. During the second quarter of 1995, Williams transferred its Units to Williams Holdings of Delaware, Inc. (“WHD”), a separate holding company for Williams’ non-regulated businesses. Effective July 31, 1999, WHD was merged into Williams, and by operation of the merger, Williams assumed all assets, liabilities and obligations of WHD, including without limitation ownership of WHD’s Units. Effective August 11, 2000, Williams sold its Units to Quatro Finale IV LLC, a Delaware limited liability company (“QFIV”), in a privately-negotiated transaction. Williams retained the voting rights and retained a “call” option on the transferred Units, and QFIV was granted a “put” option on the Units. Through a series of exercises of its call option, Williams reacquired an aggregate of 3,568,791 Units from December 2001 through June 2003. Williams has informed the Trustee that it has subsequently sold 2,779,500 of these Units through March 1, 2007 and owned a remaining 789,291 Units as of such date.

     Except for the commitment by WPC to pay the costs incurred to place into production certain proved nonproducing wells, neither WPC, Quatro Finale nor the operators of the Underlying Properties have any contractual commitment to the Trust to further develop the Underlying Properties, to remain as operator with respect to any of the leases on the Underlying Properties or to maintain their ownership interest in any of the properties. However, WPC retained an interest in each of the Underlying Properties immediately after conveyance of the Royalty Interests to the Trust. As described under “Item 2 —The Royalty Interests,” effective May 1, 1997, WPC sold the Underlying Properties subject to and burdened by the Royalty Interests to Quatro Finale LLC, an unaffiliated Delaware limited liability company. Ownership of the Underlying Properties reverted back to WPC effective February 1, 2001, pursuant to the terms of the May 1, 1997 transaction. Pursuant to a Purchase and Sale Agreement dated March 14, 2001 (the “2001 Transaction Agreement”), and effective March 1, 2001, WPC sold the Underlying Properties subject to and burdened by the Royalty Interests to Quatro Finale V LLC, an unaffiliated Delaware limited liability company. The sale of the Underlying Properties is expressly permitted under the Trust Agreement. Effective January 1, 2003, ownership of the Underlying Properties once again reverted back to WPC after it exercised its right to repurchase interests in the Underlying Properties from Quatro Finale V LLC pursuant to the 2001 Transaction Agreement (as defined in “Item 2—Properties—The Royal Interests”). Unless otherwise dictated by context, references herein to WPC with respect to the ownership of the Underlying Properties for any period from May 1, 1997 through February 28, 2001, and for the period from March 1, 2001 through January 1, 2003, shall be deemed to refer to Quatro Finale. For a description of the Underlying Properties and other information relating to such properties, see “Item 2—Properties—The Royalty Interests.”

     The Trustee has powers to collect and distribute proceeds received by the Trust and to pay Trust liabilities and expenses. The Delaware Trustee has only such powers as are set forth in the Trust Agreement and is not empowered to otherwise manage or take part in the business of the Trust. The Royalty Interests are passive in nature, and neither the Delaware Trustee nor the Trustee has any control over or any responsibility relating to the operation of the Underlying Properties. The Delaware Trustee and the Trustee may resign at any time or be removed with or without cause by a vote of not less than a majority of the outstanding Units. Any successor trustee must be a bank or trust company meeting certain requirements, including having capital, surplus and undivided profits of at least $20,000,000, in the case of the Delaware Trustee, and $100,000,000, in the case of the Trustee.

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Assets of the Trust

     The only assets of the Trust, other than cash and cash equivalents being held for the payment of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests. The Royalty Interests consist primarily of a net profits interest (the “NPI”) in the Underlying Properties. The NPI generally entitles the Trust to receive 60 percent of the NPI Net Proceeds attributable to (i) gas produced and sold from WPC’s net revenue interests (working interests less lease burdens) in the properties in which WPC has a working interest (the “WI Properties”) and (ii) the revenue stream received by WPC attributable to its 35 percent net profits interest in 5,348 gross acres in La Plata County, Colorado (the “Farmout Properties”).

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

     On October 15, 2002 the New Mexico Oil and Gas Commission (NMOCD) revised the field rules for the Basin Fruitland Coal (Gas) Pool to allow optional second (infill) wells 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 522 infill locations designated as proved locations according to U.S. Securities and Exchange Commission (“SEC”) guidelines. As of December 31, 2006, 406 infill locations are proved developed producing and 116 locations are proved undeveloped. Based on estimated costs from the 2006 reserve report, the majority of infill drilling is expected to be completed by the end of 2007.

     As of December 31, 2006, WPC has informed the Trustee that its estimate is that the Infill Net Profit Costs exceeded the Infill Net Profit Gross Proceeds by $7,353,000. 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

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convey production payments; (iii) include all terms, powers, remedies, covenants and provisions it deems necessary 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

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year if, based on a reserve report as of December 31 of the prior year, it is determined that, as of such date, the net present value (discounted at 10 percent) of the estimated future net revenues (calculated in accordance with criteria established by the SEC 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, 2007, there were 9,700,000 Units outstanding. The Trust may not issue additional Units.

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Distributions and Income Computations

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

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

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

Transfer of Royalty Interests

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

Possible Divestiture of Units

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

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

Periodic Reports to Unitholders

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

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

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

Voting Rights of Unitholders

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

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

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

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

Liability of Unitholders

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

Transfer Agent

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

Website/SEC Filings

     The Trust maintains an Internet Website (www.wtu-williamscoalseamgastrust.com), and as a result provides free of charge 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.

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     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 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.

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 2006, 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 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

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	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.
Unitholder’s Depletion Allowance	Each Unitholder is entitled to amortize the cost of the Units through cost depletion over the life of the NPI (or if greater, through percentage depletion equal to 15 percent of gross income). If any portion of the NPI is treated as a production payment or is not treated as an economic interest, however, a Unitholder will not be entitled to depletion in respect of such portion.
Depletion Recapture	If a taxpayer disposes of any “section 1254 property” (certain oil, gas, geothermal or other mineral property), and if the adjusted basis of such property includes adjustments for deductions for depletion under Section 611 of the IRC (discussed above), the taxpayer generally must recapture the amount deducted for depletion in ordinary income (to the extent of gain realized on the disposition of the property). This depletion recapture rule applies to any disposition of property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the United States Treasury regulations govern dispositions of property after March 13, 1995. The IRS will likely take the position that a Unitholder who purchases a Unit subsequent to December 31, 1986, must recapture depletion upon the disposition of that Unit.
Non-Passive Activity Income, Credits 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.

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ERISA CONSIDERATIONS

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

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

STATE TAX CONSIDERATIONS

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

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

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

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

REGULATION AND PRICES

Regulation of Natural Gas

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

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

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

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

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

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

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

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

Environmental Regulation

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

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

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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 previous operators. Federal, state and local laws applicable to gas-related wastes and properties have become increasingly more stringent. Under these laws, WPC or an operator of the Underlying Properties could be required to remove or remediate previously disposed wastes or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination.

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

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

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

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

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

Competition, Markets and Prices

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

     Demand for natural gas has increased recently because of late winter conditions. This increase was in response to stronger domestic economic conditions, relatively higher prices for alternative energy sources such as crude oil, and other factors. Increased demand has recently resulted in higher prices for natural gas. In addition, in

16

the recent short term, demand for natural gas production in the United States has generally resulted in 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 distributions are made to Unitholders, however, any seasonality that affects production and prices generally should be reflected in distributions that are made to Unitholders in later periods. See “—Description of Units—Distributions and Income Computations.”

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

Item 1A. Risk Factors.

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

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

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

• Worldwide economic conditions;

• weather conditions;

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

• the level of consumer demand;

• the price and availability of alternative fuels;

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

• the effect of worldwide energy conservation measures; and

• the nature and extent of governmental regulation and taxation.

     When natural gas prices decline, the Trust is affected in two ways. First, net income from the Royalty Interests is reduced. Second, exploration and development activity on the Underlying Properties may decline as some projects may become uneconomic and are either delayed or eliminated. It is impossible to predict future natural gas price movements, and this reduces the predictability of future cash distributions to Unitholders. Approximately 90 percent of the natural gas produced from the WI Properties, which generates most of the natural gas produced burdened by the Trust’s Royalty Interests, is currently being sold pursuant to the Gas Purchase Contract entered into at the inception of the Trust whereby a subsidiary of Williams purchases the gas in accordance

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with a contractual pricing mechanism. At present, this contract is year-to-year and may be terminated at the end of any calendar year upon notice, and could be terminated as soon as December 31, 2007. Under this agreement, the adverse impact on Trust revenues and, therefore, cash available for distribution to Unitholders, that would otherwise result from low natural gas prices is somewhat mitigated. However, the gas purchase agreement may significantly reduce Trust revenues and, therefore, cash available for distribution to Unitholders, that would otherwise result from high natural gas prices. There is no assurance that the gas purchase contract will remain in effect after December 31, 2007. If it is terminated, revenues of the Trust and, therefore, cash available for distribution to Unitholders, will become increasingly susceptible to fluctuations resulting from changes in prevailing natural gas prices.

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

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

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

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

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

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

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

• the effects of governmental regulation;

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

• the availability of enhanced recovery techniques; and

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

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

The assets of the Trust are depleting assets and, if the other operators developing the Underlying Properties do not perform additional development projects, the assets may deplete faster than expected. Eventually, the

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assets of the Trust will cease to produce in commercial quantities and the Trust will cease to receive proceeds from such assets. In addition, a reduction in depletion tax benefits may reduce the market value of the Units.

     The net proceeds payable to the Trust are derived from the sale of depleting assets. The reduction in proved reserve quantities is a common measure of depletion. Future maintenance and development projects on the Underlying Properties will affect the quantity of proved reserves and can offset the reduction in proved reserves. The timing and size of these projects will depend on the market prices of natural gas. If the operators developing the Underlying Properties do not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by the Trust.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

     The Trust will be terminated and the Trustee must sell the Royalty Interest if (i) the holders of a majority or more of the outstanding Units approve the sale or vote to terminate the Trust; (ii) the ratio of the cash amounts received by the Trust from the Royalty Interests (excluding deductions for capital expenditures for enhanced recovery or similar operations on the WI Properties) to administrative costs of the Trust is less than 1.2 to 1.0 for three consecutive calendar quarters; (iii) such time as the Royalty Interests held by the Trust have been sold by the Trust; (iv) March 1 of any calendar year if, based on a reserve report as of December 31 of the prior year, it is determined that, as of such date, the net present value (discounted at 10 percent) of the estimated future net revenues (calculated in accordance with criteria established by the SEC but using the average monthly Blanco Hub Spot Price (as defined; see “Item 2—Properties—The Royalty Interests—Gas Purchase Contract”)) of proved reserves attributable to the Royalty Interests is equal to or less than $30 million; and (v) December 31, 2012 (the date of any such occurrence is referred to herein as the “Termination Date”). Following termination, the Trustee and the Delaware Trustee will continue to act as trustees of the Trust until all remaining Trust assets have been sold and the net proceeds from such sales distributed to Unitholders. There is no assurance that any such sale will be on terms acceptable to all Unitholders.

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

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

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

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

The limited liability of Trust Unitholders is uncertain.

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

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

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

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

     As described in “Item 3—Legal Proceedings,” in 2001 WPC received an Audit Issue Letter from the State of New Mexico, acting under authority of MMS, followed by an MMS Order to Report and Pay Additional Royalties and Perform Restructured Accounting for the alleged underpayment of royalties, on gas produced from the Underlying Properties due to Federal royalty owners. The MMS order requires WPC (1) to pay additional royalties of $943,964 on production related to the audit period of January 1, 1992 through December 31, 1996; (2) to pay an estimated incremental royalty amount of $991,549 for production covering January 1, 1997 through March 31, 2001; and (3) to perform a restructured accounting and pay an additional royalty for months after March 2001. WPC contested the Audit Issue Letter and the MMS order. Applying the MMS methodology asserted by the State of New Mexico could potentially result in negative adjustments to amounts previously paid to the Trust. On November 1, 2004, WPC received notice that its appeal was denied in part by the MMS. On January 14, 2005, WPC filed a Complaint for Review of Agency Action and Declaratory Relief requesting the United States District Court for the District of New Mexico hold unlawful and set aside the Assistant Secretary’s October 2004 decision. A separate but similar matter has been determined unfavorably against another major oil and gas producer in the D.C. Circuit court. WPC has informed the Trustee that it expects to reach a settlement with the MMS in 2007. Accordingly, distributions to the Trust will likely begin to be affected by withholding, as early as the second quarter 2007 distribution, an estimated $1.3 million recoupment on a quarterly basis in 2007 and continue until the Trust’s share (currently estimated to be to be over $5 million) has been recovered. See “Item 3—Legal Proceedings” for additional information on this royalty dispute.

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

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

Item 1B. Unresolved Staff Comments.

     The Trust has not received any written comments from the SEC staff regarding its periodic or current reports under the Act within the 180 days preceding December 31, 2006.

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.

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     Concurrently with the 2001 Transaction, WPC, Williams, the Trust and Quatro Finale entered into an Agreement dated March 1, 2001 (the “Performance Acknowledgement Agreement”), pursuant to which (i) the parties acknowledged that, although WPC was selling the Underlying Properties to Quatro Finale, WPC retained all of its duties and obligations under the Trust Agreement, Conveyance and related documents (the “Trust Documents”), subject to the terms and conditions set forth in the 2001 Transaction Agreement and the agreements entered into pursuant to the 2001 Transaction Agreement, (ii) Williams and WPC each confirmed and agreed that, notwithstanding the sale of the Underlying Properties to Quatro Finale, Williams and WPC would continue to perform their respective obligations to the Trust pursuant to the Trust Documents, including without limitation the performance assurances of Williams set forth in the Conveyance, and (iii) Quatro Finale acknowledged and agreed 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 1073 gross coal seam gas wells in the Underlying Properties, 21 of which are producing 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. 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

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Commission and the Bureau of Land Management to establish or expand participating areas which produce oil and gas in paying quantities from designated formations. The interests of participants in a participating area are based on the surface acreage included in the participating area. Under the terms of the Unit Agreements, the operators, selected by a vote of the respective working interest owners, perform all operating functions.

     In all of the Federal Units, participating areas have been formed for the Fruitland coal formation. After the wells capable of producing gas in paying quantities from the Fruitland coal formation are drilled on the undeveloped drill blocks included within a Federal Unit, such wells are added to the participating area if approved in accordance 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 60 percent.

     The following table reflects certain information from the Reserve Report as of December 31, 2006 prepared by Miller and Lents, Ltd. dated January 31, 2007 (the “December 31, 2006 Reserve Report”) regarding the Federal Units in which the WI Properties participate. At December 31, 2006, the WI Properties covered 1124 gross (117.5 net) coal seam gas wells with working interests ranging from .8330 percent to 75 percent, with an average working interest of approximately 10.45 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, 2006.

		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		16.2		30,017.1
San Juan 32-7	Conoco Phillips Petroleum Company		13.8		28,321.6
San Juan 32-8	Conoco Phillips Petroleum Company		15.3		32,003.2
San Juan 30-6	Burlington Resources		7.9		13,710.5
San Juan 31-6	Conoco Phillips Petroleum Company		4.6		7,629.5
San Juan 29-6	Conoco Phillips Petroleum Company		9.7		15,746.3
San Juan 29-7	Burlington Resources		4.4		6,043.1
San Juan 32-9	Burlington Resources		3.0		5,759.6
Northeast Blanco	Devon Energy		1.7		3,051.5
Huerfano	Burlington Resources		2.0		2,666.3
San Juan 29-5	Conoco Phillips Petroleum Company		1.0		1,328.3
San Juan 28-6	Burlington Resources		0.6		636.3
San Juan 28-5	Burlington Resources		0.1		43.1

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     Well Count and Acreage Summary. The following table shows as of December 31, 2006, 2005, and 2004, the gross and net wells and acreage by proved producing and nonproducing categories for the WI Properties.

	Number of
	Wells				Acres
December 31,	Gross		Net		Gross		Net
2006
Producing		1,072		115.6		150,988		20,681
Nonproducing		1		0		0		0
Total		1,073		115.6		150,988		20,681
2005
Producing		953		100.1		150,988		20,681
Nonproducing		0		0		0		0
Total		953		100.1		150,988		20,681
2004
Producing		870		99		150,988		20,681
Nonproducing		0		0		0		0
Total		870		99		150,988		20,681

     Of the total gross wells described above at December 31, 2006, 1,011 gross wells are located in unitized areas. In addition to the above, the Farmout Properties have 21 gross wells.

     Properties Outside Unitized Areas. The WI Properties also include interests held by WPC in 62 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, 2006, WPC’s working interest and net revenue interests in these wells averaged 13.30 percent and 12.30 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, 2006, 22 gross wells had been drilled on the Farmout Properties. For a further description of the Farmout Properties, see “ — The NPI.”

The NPI

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

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     Most of the wells reflected in the December 31, 2006 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, 2006 Reserve Report was prepared on the basis that there will be no capital expenditures borne by the Royalty Interests for non-infill wells. 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, 2006, and certain related information for the Royalty Interests and Underlying Properties from the December 31, 2006 Reserve Report prepared by Miller and Lents, Ltd., independent petroleum engineers. A summary of the December 31, 2006 Reserve Report is filed as an exhibit to this Form 10-K and incorporated herein by reference. See Note 9 to “Item 8—Financial Statements and Supplementary Data—Notes to Financial Statements” for additional information regarding the net proved reserves of the Trust.

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

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Accordingly, the reserves presented for the Royalty Interests reflect quantities of gas that are free of future costs and expenses (other than production, severance and ad valorem taxes in respect of the WI Properties) if the price and cost assumptions set forth in the December 31, 2006 Reserve Report occur. The December 31, 2006 Reserve Report was prepared in accordance with criteria established by the SEC and, accordingly, is based upon a contractual price for gas for December 2006, of $3.735 per MMBtu before transportation charges through 2012. The December 31, 2006 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 $5.470 per MMBtu, based on December 31, 2006 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)		24,267		89,741
Estimated Future Net Revenues (in millions)(c)		55,789		233,899
Discounted Estimated Future Net Revenues (in millions)(c)		33,689		165,173

(a)	Although the prices utilized in preparing the estimates in this table are in accordance with criteria established by the SEC, 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 SEC 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 SEC.

Historical Gas Sales Prices and Production

     The following table sets forth the actual net production volumes attributed from the WI Properties, weighted average lifting costs and information regarding historical gas sales prices for each of the years ended December 31, 2006, 2005 and 2004:

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	Year Ended December 31,
	2006		2005		2004
Production from the WI Properties (MMcf)		6,047		8,110		10,101
Weighted average lifting costs (dollars per Mcf)	$	0.70	$	0.60	$	0.37
Weighted average sales price of gas produced from the WI Properties (dollars per Mcf)	$	3.17	$	3.62	$	2.66
Average Blanco Hub Spot Price (dollars per MMBtu)	$	5.88	$	6.92	$	5.21

     The published Blanco Hub Spot Price for December 2006 was $5.47 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 attributed to the Farmout Properties (in MMcf) was 1,694, 1,849, and 2,227 in 2006, 2005, and 2004, 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 2004, 2005 and 2006, 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, 2007. 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

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WPX Gas Resources to gather, treat and process the gas and deliver it to specified delivery points and plus (c) under certain circumstances, additional amounts determined as described below:

(i) If the Index Price (as defined below) in any month during any Contract Year, including 2007, 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 2007, 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 2007, 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, 2006, which is based on production volumes and natural gas prices for the twelve months ended September 30, 2006, the Index Price exceeded the Minimum Purchase Price for each month during the year. As of December 31, 2006 and 2005, 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

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gathering, treating and processing costs. As used in this “Item 2. Properties — Reserve Report,” “Index Price” means 97 percent of the first of month El Paso Natural Gas Co. — San Juan Spot Price. The El Paso Natural Gas Co. — San Juan Spot Price is a posted index price per MMBtu (dry basis) published in Inside F.E.R.C.’s Gas Market Report, which is a bi-monthly publication by The McGraw-Hill Companies, Inc. The Gas Purchase Contract provides WPX Gas Resources a one-time option to convert the Index Price from the first of month posting of El Paso Natural Gas Co. — San Juan Spot Price to the average of the bi-monthly postings for that same index. The Gas Purchase Contract further provides for an alternative indexing mechanism in the event the Inside F.E.R.C.’s Gas Market Report indices are modified or discontinued. All prices used as index prices are delivered prices at the specified point of delivery and are, therefore, before deducting gathering and/or transportation charges, taxes, treating costs or other costs payable prior to the delivery points. During periods when there is a Price Differential, WPX Gas Resources will absorb a portion of the gathering charges based on a formula specified within the Gas Purchase Contract.

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

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

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

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

Gas Gathering Contract

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

     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

30

exceeds 10 percent) and adjusted annually based on average annual price comparisons determined on the basis of the Blanco Hub Spot Price, provided that the gathering rate will be no less than $.35 per Mcf (currently 1.046/Mcf) increased or decreased on the basis of an increase or decrease in a published index measuring the gross domestic product. A significant portion of the gas to be gathered pursuant to the Gas Gathering Contract must first be gathered from the Wellhead to a Federal Unit central delivery point by TEPPCO Partners, L.P. (“TEPPCO”). WPX Gas Resources has been assigned a one-year gathering contract (with a monthly evergreen provision) whereby TEPPCO provides interruptible gathering service at the price of $.44 per Mcf, which escalates annually at $0.015 per year, plus actual fuel used (historically averaging approximately 7 percent). It is anticipated that WPX Gas Resources will be able to extend the term of this agreement.

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

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

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

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

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

Federal and Indian Lands

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

     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

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gas is purchased by nonaffiliates. The NPI Net Proceeds, a portion of which is payable to the Trust, reflects the deduction of all royalty and overriding royalty burdens. The ratio of royalties paid on Federal and Indian lands to the NPI Net Proceeds increases as the Resale Price exceeds the price under the Gas Purchase Contract.

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

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

     As described in “Item 3—Legal Proceedings,” in 2001 WPC received an Audit Issue Letter from the State of New Mexico, acting under authority of MMS, followed by an MMS Order to Report and Pay Additional Royalties and Perform Restructured Accounting for the alleged underpayment of royalties, on gas produced from the Underlying Properties due to Federal royalty owners. The MMS order requires WPC (1) to pay additional royalties of $943,964 on production related to the audit period of January 1, 1992 through December 31, 1996; (2) to pay an estimated incremental royalty amount of $991,549 for production covering January 1, 1997 through March 31, 2001; and (3) to perform a restructured accounting and pay an additional royalty for months after March 2001. WPC contested the Audit Issue Letter and the MMS order. Applying the MMS methodology asserted by the State of New Mexico could potentially result in negative adjustments to amounts previously paid to the Trust. On November 1, 2004, WPC received notice that its appeal was denied in part by the MMS. On January 14, 2005, WPC filed a Complaint for Review of Agency Action and Declaratory Relief requesting the United States District Court for the District of New Mexico hold unlawful and set aside the Assistant Secretary’s October 2004 decision. A separate but similar matter has been determined unfavorably against another major oil and gas producer in the D.C. circuit court. WPC has informed the Trustee that it expects to reach a settlement with the MMS in 2007. Accordingly, distributions to the Trust will likely begin to be affected by withholding, as early as the second quarter 2007 distribution, an estimated $1.3 million recoupment on a quarterly basis in 2007 and continue until the Trust’s share (currently estimated to be over $5 million) has been recovered. 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

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ceases to produce or is not capable of producing in commercially paying quantities (ignoring for purposes of such determination the NPI and Infill NPI). The purchase price payable by WPC will be the fair market value at the date of repurchase of the portion of the NPI or Infill NPI so purchased, as established on the basis of an appraisal provided by an independent expert.

The Infill Wells

     The only assets of the Trust, other than cash and cash equivalents being held for the payment of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests. The Royalty Interests consist primarily of a net profits interest (the “NPI”) in the Underlying Properties. The NPI generally entitles the Trust to receive 60 percent of the NPI Net Proceeds attributable to (i) gas produced and sold from WPC’s net revenue interests (working interests less lease burdens) in the properties in which WPC has a working interest (the “WI Properties”) and (ii) the revenue stream received by WPC attributable to its 35 percent net profits interest in 5,348 gross acres in La Plata County, Colorado (the “Farmout Properties”).

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

     On October 15, 2002 the New Mexico Oil and Gas Commission (NMOCD) revised the field rules for the Basin Fruitland Coal (Gas) Pool to allow an optional second (infill) well on the standard 320-acre spacing unit in certain designated areas of the pool (the non-fairway wells). On July 17, 2003 the NMOCD further modified the field rules for the Basin Fruitland Coal (Gas) Pool to allow these infill wells on the standard 320-acre spacing unit in all areas of the pool. The WI Properties contain 522 infill locations designated as proved locations according to SEC guidelines. As of December 31, 2006, 406 infill locations are proved developed producing and 116 locations are proved undeveloped. Infill drilling is expected to be substantially completed by the end of 2007.

     As of December 31, 2006, WPC has informed the Trustee that its estimate is that the Infill Net Profit Costs exceeded the Infill Net Profit Gross Proceeds by $7,353,167. 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 with SEC guidelines. As of December 31, 2006, total proved reserves were 24,267 MMcf, consisting of 23,556 MMcf proved developed producing and 711 MMcf proved undeveloped.

     As of December 31, 2006 total proved reserves for the 320-acre spaced wells in the Working Interest Properties were 17,966 MMcf, consisting of 17,961 MMcf proved developed producing and 5 MMcf proved undeveloped.

     As of December 31, 2006 total proved reserves for the infill wells in the Working Interest Properties were 2,245 MMcf, consisting of reserves of 1,539 MMcf proved developed producing and 706 MMcf proved undeveloped.

     As of December 31, 2006, total proved reserves for the Farmout Properties were 4,056 MMcf, all of these reserves are proved developed producing.

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Williams’ Performance Assurances

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

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

Title to Properties

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

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contracts and other agreements that may affect the properties or their titles; (iv) liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements; (v) pooling, unitization and communitization agreements, declarations and orders; and (vi) easements, restrictions, rights-of-way and other matters that commonly affect property. To the extent that such burdens and obligations affect WPC’s rights to production and the value of production from the Underlying Properties, they have been taken into account in calculating the Trust’s interests and in estimating the size and value of the reserves attributable to the Royalty Interests. Except as noted below, Williams believes that the burdens and obligations affecting the Underlying Properties and Royalty Interests are conventional in the industry for similar properties, do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially and adversely affect the value of the Royalty Interests.

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

Item 3. Legal Proceedings.

     On January 5, 2001, the State of New Mexico, acting under authority of the Minerals Management Service (“MMS”), a subagency of the United States Department of the Interior, presented WPC with an Audit Issue Letter for the alleged underpayment of royalties in the amount of $948,501, on gas produced from the Underlying Properties due to Federal royalty owners during the time period from January 1992 through December 1996. MMS regulations permit a lessee to deduct from its gross proceeds its reasonable actual costs of transportation and processing to transport the gas from the lease to the point of sale in calculating the market value of its production. The State of New Mexico claims that certain costs of removing and transporting carbon dioxide gas are not deductible. On March 22, 2001, WPC responded to the Audit Issue Letter and contested the State of New Mexico’s claim for additional royalties as being contrary to law. In early November 2001, WPC received from the MMS an Order to Report and Pay Additional Royalties and Perform Restructured Accounting on subsequent periods. The order was dated October 30, 2001. The order requires WPC (1) to pay additional royalties of $943,964 on production related to the audit period of January 1, 1992 through December 31, 1996; (2) to pay an estimated incremental royalty amount of $991,549 for production covering January 1, 1997 through March 31, 2001; and (3) to perform a restructured accounting and pay an additional royalty for months after March 2001. On January 30, 2002, WPC filed its Statement of Reasons in support of its earlier appeal of the Audit Issue Letter. Applying the MMS methodology asserted by the State of New Mexico could potentially result in negative adjustments to amounts previously paid to the Trust. On November 1, 2004, WPC received notice that its appeal was denied in part by the MMS. On January 14, 2005, WPC filed a Complaint for Review of Agency Action and Declaratory Relief requesting the United States District Court for the District of New Mexico hold unlawful and set aside the Assistant Secretary’s October 2004 decision. A separate but similar matter has been determined unfavorably against another major oil and gas producer in the D.C. circuit court. WPC has informed the Trustee that it expects to reach a settlement with the MMS in 2007. Accordingly, distributions to the Trust will likely begin to be affected by withholding, as early as the second quarter 2007 distribution, an estimated $1.3 million recoupment on a quarterly

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basis in 2007 and continue until the Trust’s share (currently estimated to be to be over $5 million) has been recovered.

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

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

     Not applicable.

PART II

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

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

	Sales Price				Distributions
	High		Low		per Unit
2006
First Quarter	$	20.39	$	17.02	$	.562572
Second Quarter	$	23.05	$	14.48	$	.266448
Third Quarter	$	17.00	$	10.10	$	.231941
Fourth Quarter	$	13.63	$	10.50	$	.282846
2005
First Quarter	$	18.00	$	15.50	$	.346311
Second Quarter	$	17.20	$	14.00	$	.321706
Third Quarter	$	21.43	$	16.10	$	.357841
Fourth Quarter	$	21.95	$	16.58	$	.379323

     At March 1, 2007, there were 9,700,000 Units outstanding and approximately 310 Unitholders of record. The Trust does not maintain any equity compensation plans. The Trust did not sell nor did it repurchase any Units during the period covered by this report.

Item 6. Selected Financial Data.

	Year Ended December 31,
	2006		2005		2004		2003		2002
Royalty Income	$	13,945,315	$	14,497,187	$	15,375,469	$	14,754,582	$	9,296,774
Distributable Income	$	13,032,064	$	13,565,620	$	14,640,743	$	14,012,292	$	8,634,497
Distributable Income per Unit	$	1.34	$	1.40	$	1.51	$	1.44	$	.89
Distributions per Unit	$	1.34	$	1.41	$	1.50	$	1.45	$	.89
Total Assets at Year End	$	8,372,798	$	10,138,644	$	12,317,821	$	14,731,450	$	18,240,451
Total Corpus at Year End	$	8,316,439	$	10,091,169	$	12,285,070	$	14,638,833	$	18,165,048

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:

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

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

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

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

     The financial statements of the Trust differ from financial statements prepared in accordance with GAAP. For example, royalty income is not accrued in the period of production, amortization of the Royalty Interests is not charged against operating results, and loss contingencies are not charged to operating results until paid. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

     The Trust’s financial statements reflect the selection and application of accounting policies that require the Trust to make significant estimates and assumptions. The following are some of the more critical judgment areas in the application of accounting policies that currently affect the Trust’s financial condition and results of operations.

     Revenue Recognition. Revenues from Royalty Interests are recognized in the period in which amounts are received by the Trust. Royalty income received by the Trust in a given calendar year will generally reflect the proceeds, on an entitlements basis, from natural gas produced for the 12-month period ended September 30th in that calendar year.

     Reserve Recognition. Independent petroleum engineers estimate the net proved reserves attributable to the Royalty Interests. In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities,” estimates of future net revenues from proved reserves have been prepared using year-end contractual gas prices and related costs. Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and the timing of development of non-producing reserves. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.

     Contingencies. Contingencies related to the Underlying Properties that are unfavorably resolved would generally be reflected by the Trust as reductions to future royalty income payments to the Trust with corresponding reductions to cash distributions to Unitholders.

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.

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Results of Operations

     The Trust makes quarterly cash distributions to Unitholders. The only assets of the Trust, other than cash and cash equivalents being held for the payment of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests. The Royalty Interests owned by the Trust burden the Underlying Properties, which are owned by WPC and not the Trust.

     Distributable income of the Trust generally consists of the excess of royalty income plus interest income over the general and administrative expenses of the Trust. Upon receipt by the Trust, royalty income is invested in short-term investments in accordance with the Trust Agreement until its subsequent distribution to Unitholders.

     The amount of distributable income of the Trust for any calendar year may differ from the amount of cash available for distribution to Unitholders in such year due to differences in the treatment of the expenses of the Trust in the determination of those amounts. The financial statements of the Trust are prepared on a modified cash basis pursuant to which the expenses of the Trust are recognized when incurred whereas royalty income is recognized when received. Consequently, the reported distributable income of the Trust for any year is determined by deducting from the income received by the Trust the amount of expenses incurred by the Trust during such year. The amount of cash available for distribution to Unitholders, however, is determined in accordance with the provisions of the Trust Agreement and reflects the deduction from the income actually received by the Trust of the amount of expenses actually paid by the Trust and adjustment for changes in reserves for unpaid liabilities. See Note 5 to “Item 8—Financial Statements and Supplementary Data—Notes to Financial Statements” for additional information regarding the determination of the amount of cash available for distribution to Unitholders.

     For 2006, royalty income received by the Trust amounted to $13,945,315 as compared to $14,497,187 and $15,375,469 for 2005 and 2004, respectively. The decrease in royalty income in 2006 compared to 2005 was primarily due to lower natural gas production, partially offset by the effect of higher natural gas prices. The decrease in royalty income in 2005 compared to 2004 was primarily due to lower production, partially offset by the effect of higher natural gas prices. Net production related to the royalty income received by the Trust in 2006 was approximately 4,406,089 MMBtu as compared to 5,352,416 MMBtu and 6,373,931 MMBtu in 2005 and 2004, respectively. In 2005 retroactive adjustments increased the natural gas attributable to the NPI of the Underlying Properties by approximately 335,311 MMbtu’s and that of the Trust by approximately 201,187 MMbtu’s (representing a retroactive adjustment based on actual prices in effect during the year of approximately $530,487). The average net natural gas price received for royalty income in 2006 was $2.63 per MMBtu as compared to $2.35 MMBtu and $2.16 MMBtu in 2005 and 2004, respectively. Interest income for 2006 was $51,533 as compared to $29,173 and $10,518 for 2005 and 2004. The increase in interest income for 2006 reflects higher interest rates. The increase in interest income in 2005 compared to 2004 reflects higher interest rates.

     General and administrative expenses for 2006 were $964,784, as compared to $960,740 and $745,244 for 2005 and 2004, respectively. General and administrative expenses in 2006 were comparable to 2005. The increase in general and administrative expenses in 2005 compared to 2004 was primarily due to higher administrative expenses relating to Sarbanes-Oxley Act compliance in 2005.

     Distributable income for 2006 was $13,032,064 or $1.34 per Unit, compared to $13,565,620 or $1.40 per Unit for 2005, and $14,640,743 or $1.51 per Unit, for 2004. The decrease in distributable income in 2006 compared to 2005 was primarily due to lower net production from the Underlying Properties but offset by higher gas prices. The decrease in distributable income in 2005 compared to 2004 was primarily due to lower net production from the Underlying Properties but offset by higher gas prices.

     Reserve values at December 31, 2006, December 31, 2005 and December 31, 2004 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 $5.47 per Mcf, $7.58 per Mcf and $5.44 per Mcf as at December 31, 2006, 2005 and 2004 respectively.

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     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, 2006, 2005 and 2004, was based on production volumes and natural gas prices for the 12 months ended in September 30, 2006, 2005 and 2004, 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,
	2006		2005		2004
Production, Net (MMBtu)(1)
WI Properties		5,904,596		7,319,114		8,711,628
Farmout Properties(2)		1,438,886		1,601,580		1,911,591
Average Blanco Hub Spot Price ($/MMBtu)(3)	$	6.92	$	5.96	$	4.78
Average Net Wellhead Price WI Properties ($/MMBtu)	$	2.63	$	2.35	$	2.16

(1)	Million British Thermal Units.
(2)	Includes previously reported estimated amounts for certain months.
(3)	Total Gross Proceeds divided by Entitled W.I. Dry MMBtu for 12 months ending on September 30.

     Production from the WI Properties is generally sold pursuant to the Gas Purchase Contract. For more information regarding the Gas Purchase Contract and the right of WFS Gas Resources to recoup certain Price Credits, see “Item 2 — Properties — The Royalty Interests — Gas Purchase Contract” in this Form 10-K.

     The information herein concerning production and prices relating to the Underlying Properties is based on information prepared and furnished by WPC (on behalf of itself and Quatro Finale) to the Trustee. The Trustee has no control over and no responsibility relating to the operation of the Underlying Properties.

     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. See “Item 3—Legal Proceedings” for additional information on this royalty dispute.

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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, 2006.

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

Forward-Looking Statements

     This Annual Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, which are intended to be covered by the safe harbor created thereby. All statements other than statements of historical fact included in this Annual Report are forward-looking statements. Such statements include, without limitation, factors affecting the price of oil and natural gas contained in Item 1, “Business”; certain reserve information and other statements contained in Item 2, “Properties”; and certain statements regarding the Trust’s financial position, industry conditions and other matters contained in this Item 7. Although the Trustee believes that the expectations reflected in such forward-looking statements are reasonable, such expectations are subject to numerous risks and uncertainties and the Trustee can give no assurance that they will prove correct. There are many factors, none of which is within the Trustee’s control, that may cause such expectations not to be realized, including, among other things, factors identified in this Annual Report affecting oil and gas prices and the recoverability of reserves, general economic conditions, actions and policies of petroleum-producing nations and other changes in the domestic and international energy markets and the factors identified in Item 1A, “Risk Factors”.

Item 7A. Quantitative and Qualitative Disclosure About Market Risk

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

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     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, 2006 and 2005, and the related Statements of Distributable Income and Changes in Trust Corpus for each of the 3 years in the period ended December 31, 2006, are included in this Form 10-K.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Trustee
Williams Coal Seam Gas Royalty Trust

     We have audited the accompanying statements of assets, liabilities and trust corpus of the Williams Coal Seam Gas Royalty Trust as of December 31, 2006 and 2005, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2006. 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, 2006 and 2005, and its distributable income and its changes in trust corpus for each of the three years in the period ended December 31, 2006, on the basis of accounting described in Note 2.

     We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Williams Coal Seam Gas Royalty Trust’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 9, 2007 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP  

Tulsa, Oklahoma
March 9, 2007

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Financial Statements
Williams Coal Seam Gas Royalty Trust

Statements of Assets, Liabilities and Trust Corpus

	December 31,
	2006		2005
Assets
Current assets — cash and cash equivalents	$	61,607	$	55,586
Royalty interests in oil and gas properties (less accumulated amortization of $130,255,472 and $128,483,605 at December 31, 2006 and 2005, respectively) (Note 2)		8,311,191		10,083,058
Total	$	8,372,798	$	10,138,644
Liabilities and Trust Corpus
Current liabilities:
Other accounts payable	$	56,359	$	47,475
Current liabilities		56,359		47,475
Trust corpus (9,700,000 units of beneficial interest authorized and outstanding) (Note 2)		8,316,439		10,091,169
Total	$	8,372,798	$	10,138,644

Statements of Distributable Income

	Year Ended December 31,
	2006			2005			2004
Royalty income (Note 2)	$	13,945,315		$	14,497,187		$	15,375,469
Interest income		51,533			29,173			10,518
Total		13,996,848			14,526,360			15,385,987
General and administrative expenses (Note 4)		(964,784	)		(960,740	)		(745,244	)
Distributable income	$	13,032,064		$	13,565,620		$	14,640,743
Distributable income per Unit (9,700,000 units) (Note 2)	$	1.34		$	1.40		$	1.51
Distributions per Unit (Note 5)	$	1.34		$	1.41		$	1.50

Statements of Changes in Trust Corpus

	Year Ended December 31,
	2006			2005			2004
Trust corpus, beginning of year	$	10,091,169		$	12,285,070		$	14,638,833
Amortization of royalty interests (Note 2)		(1,771,867	)		(2,129,266	)		(2,408,538	)
Distributable income		13,032,064			13,565,620			14,640,743
Distributions to Unitholders (Note 5)		(13,034,927	)		(13,630,255	)		(14,585,968	)
Trust corpus, end of year	$	8,316,439		$	10,091,169		$	12,285,070

See accompanying notes

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Notes to Financial Statements

1. Trust Organization and Provisions

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

     The Trust was formed to acquire and hold certain net profits interests (the “Royalty Interests”) in proved natural gas properties located in the San Juan Basin of New Mexico and Colorado (the “Underlying Properties”) owned by WPC. The Trust was initially created effective as of December 1, 1992, with a $100 contribution by WPC. On January 21, 1993, the Royalty Interests were conveyed to the Trust by WPC pursuant to the Net Profits Conveyance (the “Conveyance”) entered into effective as of October 1, 1992, by and among WPC, Williams, the Trustee and the Delaware Trustee, in consideration for all the 9,700,000 authorized units of beneficial interest in the Trust (“Units”). WPC transferred its Units by dividend to its parent, Williams, which sold an aggregate of 5,980,000 Units to the public through various underwriters in January and February 1993 (the “Public Offering”). Subsequently, Williams sold to the public an additional 151,209 Units. During the second quarter of 1995, Williams transferred its remaining Units to Williams Holdings of Delaware, Inc. (“WHD”), a separate holding company for Williams’ non-regulated businesses. Effective July 31, 1999, WHD was merged into Williams, and by operation of the merger, Williams assumed all assets, liabilities and obligations of WHD, including without limitation ownership of WHD’s Units. Effective August 11, 2000, Williams sold its Units to Quatro Finale IV LLC, a Delaware limited liability company (“QFIV”), in a privately negotiated transaction. Williams retained the voting rights and retained a “call” option on the transferred Units, and QFIV was granted a “put” option on the Units. Through a series of exercises of its call option, Williams reacquired an aggregate of 3,568,791 Units from December 2001 through June 2003. Williams has informed the Trustee that it has subsequently sold 2,779,500 of these Units through March 15, 2007 and owned a remaining 789,291 Units as of such date.

     Effective May 1, 1997, WPC sold the Underlying Properties subject to and burdened by the Royalty Interests to Quatro Finale LLC, an unaffiliated Delaware limited liability company. Ownership of the Underlying Properties reverted back to WPC effective February 1, 2001, pursuant to the terms of the May 1, 1997 transaction. Pursuant to a Purchase and Sale Agreement dated March 14, 2001 (the “2001 Transaction Agreement”), and effective March 1, 2001, WPC sold the Underlying Properties subject to and burdened by the Royalty Interests to Quatro Finale V LLC, an unaffiliated Delaware limited liability company. The sale of the Underlying Properties is expressly permitted under the Trust Agreement. Effective January 1, 2003, ownership of the Underlying Properties once again reverted back to WPC after it exercised its right to repurchase interests in the Underlying Properties from Quatro Finale V LLC pursuant to the 2001 Transaction Agreement. Unless otherwise dictated by context, references herein to WPC with respect to the ownership of the Underlying Properties for any period from May 1, 1997 through February 1, 2001, and for the period from March 1, 2001 through December 31, 2002, shall be deemed to refer to Quatro Finale.

     The Trustee has the power to collect and distribute the proceeds received by the Trust and to pay Trust liabilities and expenses. The Delaware Trustee has only such powers as are set forth in the Trust Agreement and is not empowered to otherwise manage or take part in the business of the Trust. The Royalty Interests are passive in nature, and neither the Delaware Trustee nor the Trustee has any control over or any responsibility relating to the operation of the Underlying Properties.

     The Trust will terminate no later than December 31, 2012, subject to earlier termination under certain circumstances described in the Trust Agreement (the “Termination Date”). Cancellation of the Trust will occur on or following the Termination Date when all Trust assets have been sold and the net proceeds therefrom distributed to holders of Units in the Trust (“Unitholders”).

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     The only assets of the Trust, other than cash and cash equivalents being held for the payment of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests. The Royalty Interests consist primarily of a net profits interest (the “NPI”) in the Underlying Properties. The NPI generally entitles the Trust to receive 60 percent of the NPI Net Proceeds, as defined below, attributable to (i) gas produced and sold from WPC’s net revenue interests (working interests less lease burdens) in the properties in which WPC has a working interest (the “WI Properties”) and (ii) the revenue stream received by WPC attributable to its 35 percent net profits interest in 5,348 gross acres in La Plata County, Colorado (the “Farmout Properties”).

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

     On October 15, 2002, the New Mexico Oil and Gas Commission (NMOCD) revised the field rules for the Basin Fruitland Coal (Gas) Pool to allow optional second (infill) wells 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 522 infill locations designated as proved locations according to SEC guidelines. As of December 31, 2006, 406 infill locations are proved developed producing and 116 locations are proved undeveloped. Infill drilling is expected to be substantially completed by the end of 2007.

     As of December 31, 2006, WPC has informed the Trustee that its estimate is that the Infill Net Profit Costs exceeded the Infill Net Profit Gross Proceeds by approximately $7,353,000. 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 Proceeds, Infill Net Profit Costs, Excess Infill Net Profit Costs, and Infill Net Profit Gross Proceeds are set forth in the Conveyance.

2. Basis of Accounting

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

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

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

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

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

     The financial statements of the Trust differ from financial statements prepared in accordance with GAAP. For example, royalty income is not accrued in the period of production, amortization of the Royalty Interests is not charged against operating results, and loss contingencies are not charged to operating results until paid. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

45

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. Each Unitholder should consult his tax advisor regarding Trust tax compliance matters.

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 2006, 2005 and 2004 were $293,707, $285,152, and $276,847, 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 interests 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’ interest 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 2006, 2005 and 2004 were $55,492, $54,055 and $52,660, 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.

46

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

6. Contingencies

     WPX Gas Resources Company (“WPX Gas Resources,” as successor in interest to Williams Gas Marketing Company) purchases natural gas produced from the WI Properties (except for certain small volumes) at the wellhead under the terms of a gas purchase contract dated October 1, 1992, as amended (the “Gas Purchase Contract”). The Gas Purchase Contract provides for a pricing mechanism during an initial 5-year period, which expired on December 31, 1997, and continuing for one or more consecutive additional 1-year terms unless and until WPX Gas Resources exercises its annual option, exercisable 15 days prior to the end of each contract year, to discontinue purchasing gas under the pricing mechanism of the Gas Purchase Contract and instead purchase gas at a monthly market-based price. WPX Gas Resources has not exercised this option, and therefore, the pricing mechanism will continue to remain in effect through at least December 31, 2007.

     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, 2006 and 2005, 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, when the market price for natural gas exceeds $1.94 per MMBtu (as was the case during all months in 2006, 2005 and 2004), 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. There were no significant unit expansions affecting royalty income during 2006. For the year ended December 31, 2005, retroactive adjustments resulted from unit expansions on certain Federal Units as well as some nominal net pricing adjustments and adjustments to actualize estimates. The total impact of these adjustments was to increase the natural gas attributable to the NPI of the Trust by approximately 201,000 MMbtu’s (representing a retroactive adjustment based on actual prices of approximately $530,000 to the Trust). The royalty income presented in the accompanying statements of distributable income is on an entitlement basis and reflects the most recent BLM participating area approvals through December 31, 2006, except that WPC has notified the Trustee that there are pending expansions approved by the BLM prior to December 31, 2006 for additional participating area enlargements that will impact future results. WPC has indicated that it anticipates these unit expansions will be processed by year end 2007.

47

     The fourth quarter 2006 royalty income reflects an adjustment to previously estimated operating costs of approximately $210,000, which increased net proceeds attributable to the NPI of the Trust. In 2007, WPC has further analyzed and adjusted these estimated costs and reduced the first quarter 2007 distribution to the Trust decreasing the net proceeds attributable to the NPI of the Trust by approximately $206,000. Additionally, WPC has informed the Trustee that for production periods from October 2005 through December 2006, WPC has been estimating the excess capital component of the Trust’s royalty income. Upon obtaining actual amounts the Trust will incur adjustments to royalty income distributed by WPC for these cumulative estimate to actual differences.

     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. On November 1, 2004, WPC received notice that its appeal was denied in part by the MMS. On January 14, 2005, WPC filed a Complaint for Review of Agency Action and Declaratory Relief requesting the United States District Court for the District of New Mexico hold unlawful and set aside the Assistant Secretary’s October 2004 decision. A separate but similar matter has been determined unfavorably against another major oil and gas producer in the D.C. circuit court. WPC has informed the Trustee that it expects to reach a settlement with the MMS in 2007. Accordingly, distributions to the Trust will likely begin to be affected by withholding, as early as the second quarter 2007 distribution, an estimated $1.3 million recoupment on a quarterly basis in 2007 and continue until the Trust’s share (currently estimated to be to be over $5 million) has been recovered.

7. Subsequent Event

     Subsequent to December 31, 2006, the Trust declared the following distribution:

Quarterly Record Date	Payment Date	Distribution per Unit
February 14, 2007	March 1, 2007	$	0.208780

     This distribution includes the $206,000 effect of the adjustment to estimated operating costs described in Note 6, offset by the $245,000 impact of net royalty income distributed by WPC to the Trust in anticipation of certain pending unit expansions.

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, 2006 and 2005 (in thousands, except per Unit amounts):

48

Calendar Quarter	Royalty Income		Distributable Income		Distributions per Unit
2006
First	$	5,688	$	5,356	$	.562572
Second		2,926		2,665		.266448
Third		2,398		2,262		.231941
Fourth		2,933		2,749		.282846
TOTAL	$	13,945	$	13,032	$	1.343807
2005
First	$	3,534	$	3,142	$	.346311
Second		3,464		3,277		.321706
Third		3,663		3,491		.357841
Fourth		3,836		3,656		.379323
TOTAL	$	14,497	$	13,566	$	1.405181

     Selected 2006 fourth quarter data are as follows (in thousands except per Unit amounts):

	2006			2005
Royalty income	$	2,933		$	3,836
Interest income		12			11
General and administrative expenses		(196	)		(191	)
Distributable income	$	2,749		$	3,656
Distributable income per Unit (9,700,000 units)	$	.28		$	.38
Distributions per Unit	$	.28		$	.38

9. Supplemental Oil and Gas Information (Unaudited)

     The net proved reserves attributable to the Royalty Interests have been estimated as of December 31, 2006, 2005 and 2004, 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 $5.47, $7.58 and $5.44 per MMBtu, after adjustments for certain costs and provisions of the Gas Purchase Contract, at December 31, 2006, 2005, and 2004, respectively. This resulted in a weighted average wellhead price of $3.735, $4.78 and $3.72 per Mcf at December 31, 2006, 2005, and 2004, 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. This table reflects calendar year activity and will differ from the financial statement presentation which is lagging by 3 months.

     The reserve estimates as of December 31, 2006, 2005 and 2004, are based on a percentage share of NPI Net Proceeds payable to the Trust of 60 percent.

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	Natural Gas (MMcf)
Proved reserves at January 1, 2004		44,363
Production		(7,402	)
Extensions and revisions of previous estimates		427
Proved reserves at December 31, 2004		37,388
Production		(5,976	)
Extensions and revisions of previous estimates		(2,806	)
Proved reserves at December 31, 2005		28,606
Production		(4,645	)
Extensions and revisions of previous estimates		306
Proved reserves at December 31, 2006		24,267
Proved developed reserves at December 31, 2006		23,557

     Proved reserve estimates presented above at January 1, 2004 are proved developed reserves. Proved reserves at December 31, 2005, include 897 MMcf of proved undeveloped reserves. Proved reserves at December 31, 2006, include 710 MMcf of proved undeveloped reserves.

     Proved reserves are estimated quantities of natural gas that geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. The Trust’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, 2006, 2005 and 2004 relating to proved reserves (in thousands):

	Year Ended December 31,
	2006			2005			2004
Future cash inflows	$	66,386		$	109,580		$	106,058
Future production taxes		(7,934	)		(12,701	)		(11,907	)
Future development costs		(2,663	)		(3,266	)		(2,486	)
Future net cash flows		55,789			93,613			91,665
10% discount factor		(22,100	)		(38,916	)		(36,748	)
Standardized measure of discounted future net revenues	$	33,689		$	54,697		$	54,917

     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, 2006, 2005 and 2004 (in thousands):

	2006			2005			2004
Balance at January 1	$	54,697		$	54,917		$	65,326
Increase (decrease) due to:
Net sales of coal seam gas		(10,117	)		(16,298	)		(15,145	)
Net changes in prices and costs		(11,223	)		13,857			862
Development costs incurred		(1,860	)		(278	)		(208	)
Changes in estimated future development cost		(1,296	)		(1,110	)		(2,211	)
Extensions and revisions of previous quantity estimates		300			(3,714	)		427
Accretion of discount		5,470			5,492			6,533
Other		(2,281	)		1,831			(667	)
		(21,008	)		(220	)		(10,408	)
Balance at December 31	$	33,689		$	54,697		$	54,917

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

     None.

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Item 9A. Controls and Procedures.

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

     Changes in Internal Control over Financial Reporting. There has not been any change in the Trust’s internal control over financial reporting during the fourth quarter of 2006 that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.

     Trustee’s Report on Internal Control Over Financial Reporting. The Trustee is responsible for establishing and maintaining adequate control over financial reporting, as such term is defined in Rule 13a-15 promulgated under the Securities Exchange Act of 1934, as amended. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control-Integrated Framework, the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2006. The Trustee’s assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2006 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The Trustee
Williams Coal Seam Gas Royalty Trust

We have audited the Trustee’s assessment, included in the accompanying Trustee’ Report on Internal Control Over Financial Reporting, that the Williams Coal Seam Gas Royalty Trust (the “Trust”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Management of the Trustee is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the Trustee’s assessment and an opinion on the effectiveness of the Trust’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, the Trustee’s assessment that the Trust maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statements of assets, liabilities and trust corpus of the Trust as of December 31, 2006 and 2005, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2006 of the Trust and our report dated March 9, 2007 expressed an unqualified opinion on those financial statements.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma
March 9, 2007

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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 2006, no person who was a beneficial owner of more than 10 percent the Trust’s Units failed to file on a timely basis any report required by Section 16(a).

Item 11. Executive Compensation.

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

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

     Compensation of the Trustee, Delaware Trustee and Transfer Agent. The Trust Agreement provides for compensation to the Trustee and the Delaware Trustee for administrative services, out of the Trust assets. The Trustee was paid a 2006 base amount of $49,343, 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 2006 of $49,343 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

53

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 2006 were $18,808.

     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.”

     Compensation Committee. The Trust has no directors and therefore has no compensation committee.

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

     (a) Security Ownership of Certain Beneficial Owners. The following table sets forth as of March 1, 2007 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. One Williams Center Tulsa, Oklahoma 74172 (1)		789,291		8.14	%

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

     (b) Securities Authorized for Issuance under Equity Compensation Plans. The Trust has no equity compensation plans.

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, 2007, Bank of America, N.A., the Trustee, held an aggregate of 39,994 Units in various fiduciary capacities, with no investment or voting powers. As of March 1, 2007, Chase Bank (as successor to Chemical Bank Delaware), the Delaware Trustee, did not beneficially own any Units.

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     (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 2006 was $293,707.

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, 2006 and 2005 are:

	2006		2005
Audit Fees	$	183,190	$	188,700
Audit-Related Fees	$	0	$	0
Tax Fees	$	0	$	0
All Other Fees	$	0	$	0

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

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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		42
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2006 and 2005		43
Statements of Distributable Income for each of the three years in the period ended December 31, 2006		43
Statements of Changes in Trust Corpus for each of the three years in the period ended December 31, 2006		43
Notes to Financial Statements		44-50

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).

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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 15, 2007, and submitted pursuant to Rule 13a-14(a)/15d-14(a) and pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

57

Exhibit
Number		Exhibit
32.1	—	Certificate by Bank of America, Trustee of Williams Coal Seam Gas Royalty Trust, dated March 15, 2007, 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 31, 2007 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, 2006, prepared by Miller and Lents, Ltd., independent petroleum engineers.

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SIGNATURES

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

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

Date: March 15, 2007

(The Registrant has no directors or executive officers.)

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INDEX TO EXHIBITS

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

Exhibit
Number		Description
10.7	—	Amendment #3 to the Gas Gathering and Treating Agreement dated as of October 1, 1993, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.7 to the Registrant’s Form 10-K for the year ended December 31, 1993 and incorporated herein by reference).
10.8	—	Confirmation Agreement effective as of May 1, 1995 by and among Williams Production Company, The Williams Companies, Inc. and Williams Coal Seam Gas Royalty Trust (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 1995 and incorporated herein by reference).
23.1	—	Consent of Ernst & Young LLP.
23.2	—	Consent of Miller and Lents, Ltd.
31.1	—	Certification by Ron E. Hooper, Senior Vice President and Administrator of Bank of America, Trustee of Williams Coal Seam Gas Royalty Trust, dated March 15, 2007, and submitted pursuant to Rule 13a-14(a)/15d-14(a) and pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	—	Certificate by Bank of America, Trustee of Williams Coal Seam Gas Royalty Trust, dated March 15, 2007, 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 31, 2007, 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, 2006, prepared by Miller and Lents, Ltd., independent petroleum engineers.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statement (Form S-3, No. 333-70394-01) of the Williams Coal Seam Gas Royalty Trust and in the related Prospectus of our report dated March 9, 2007, with respect to the financial statements of the Williams Coal Seam Gas Royalty Trust, the Trustee’s assessment of the effectiveness of internal control over financial reporting, and the effectiveness of internal control over financial reporting of the Williams Coal Seam Gas Royalty Trust included in this Annual Report (Form 10-K) for the year ended December 31, 2006.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma
March 9, 2007

EX-23.2

Exhibit 23.2

CONSENT OF MILLER AND LENTS, LTD.

March 9, 2007

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 31, 2007 for reserves as of December 31, 2006.

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

Very truly yours,

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

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Ron Hooper, certify that:

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

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

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

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

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

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

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting; and

In giving the certifications in paragraphs 4 and 5 above, I have relied to the extent I consider reasonable on information provided to me by Williams Production Company.

Date: March 15, 2007

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, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, not in its individual capacity but solely as the trustee of the Trust, certifies pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to its knowledge:

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

	BANK OF AMERICA, N.A., TRUSTEE FOR WILLIAMS COAL SEAM GAS ROYALTY TRUST
Date: March 15, 2007	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 31, 2007

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:	Williams Coal Seam Gas Royalty Trust
	Proved Reserves and Future Net Revenues
	As of December 31, 2006

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		81,161		221,550		160,143
Proved Undeveloped		8,580		12,349		5,030
Total Proved		89,741		233,899		165,173
The Royalty Interests (Net to the Trust)
Proved Developed		23,557		53,871		32,786
Proved Undeveloped		711		1,918		903
Total Proved		24,267		55,789		33,689

Mr. Ron E. Hooper
Bank of America, N.A., Trustee
Williams Coal Seam Gas Royalty Trust January 31, 2007
Page 2

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

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

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

     The production forecast for the total proved reserves and future net revenues as of December 31, 2006 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, 2006 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 406 developed infill locations and 116 additional infill locations that 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. According to the estimates of WPC, the infill drilling program will pay out, and the Trust will start to receive net proceeds in 2008.

Mr. Ron E. Hooper
Bank of America, N.A., Trustee
Williams Coal Seam Gas Royalty Trust January 31, 2007
Page 3

     The gas prices and deductions for WTU are based upon information provided by WPC. The gas price for the Farmout Properties is $5.470 per MMBtu based on the December 31, 2006 Blanco Hub Index Price. For the Working Interest Properties, the adjusted price of $3.735 per MMBtu was employed as provided for in the Gas Purchase Contract. On December 31, 2012, the WTU terminates and the Gas Purchase Contract is no longer in effect. The gas price reverts to $5.470 per MMBtu, based on the December 31, 2006 Blanco Hub Index Price. Gathering and transportation charges, taxes, treating, and other costs payable prior to the delivery points were deducted from the index price in order to determine the net wellhead price used in this evaluation. These prices and deductions were held constant.

     Deductions for lease royalty and production and ad valorem taxes for the Working Interest Properties were based on the December 31, 2006 index gas price of $5.470 per MMBtu less appropriate deductions as reported by WPC.

     Operating expense estimates were based on expenses incurred during 2006 and were not escalated. Where appropriate, estimated operating expenses which exceeded the operating expenses in Exhibit B to the Conveyance were deducted in calculating Net Proceeds and, therefore, reduced the amounts payable to the WTU.

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

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

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

     Miller and Lents, Ltd. is an independent oil and gas consulting firm. No director, officer, or key employee of Miller and Lents, Ltd. has any financial ownership in WTU or WPC or any related company. Our compensation for the required investigations and preparation of this report is not contingent on the results obtained and reported, and we have not performed other work that would affect our objectivity.

Mr. Ron E. Hooper
Bank of America, N.A., Trustee
Williams Coal Seam Gas Royalty Trust January 31, 2007
Page 4

Production of this report was supervised by an officer of the firm who is a professionally qualified and licensed Professional Engineer in the State of Texas with more than 20 years of relevant experience in the estimation, assessment, and evaluation of oil and gas reserves.

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

SMH/jj

WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMICS AS OF DECEMBER 31, 2006
UNDERLYING PROPERTIES AND TRUST INTERESTS

NON-ESCALATED 12/31/2006 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%
2007		200,940		17,295		3.619		62,583		6,110		6,449		7,007		43,017		40,985				4,021		7,368		7,022
2008		165,223		14,275		3.619		51,661		5,320		5,326		2,349		38,666		33,604				3,329		6,093		5,262
2009		135,395		11,508		3.618		41,635		4,552		4,288		1,462		31,333		24,776				2,835		5,166		4,043
2010		110,341		9,269		3.617		33,525		3,919		3,449		347		25,811		18,574				2,357		4,284		3,043
2011		88,364		7,397		3.615		26,740		3,375		2,746		—		20,619		13,494				1,909		3,480		2,239
2012		70,636		5,913		3.613		21,362		2,936		2,189		—		16,237		9,660				1,510		2,765		1,613
2013		56,655		4,743		3.611		17,128		2,578		1,752		—		12,798		6,923				1,747		5,622		2,960
2014		45,579		3,819		3.609		13,784		2,286		1,408		—		10,090		4,962				1,393		4,479		2,136
2015		36,753		3,084		3.607		11,124		2,043		1,134		—		7,947		3,553				1,109		3,565		1,540
2016		29,694		2,494		3.606		8,992		1,827		916		—		6,250		2,540				883		2,834		1,110
2017		24,008		2,018		3.604		7,272		1,629		739		—		4,904		1,812				701		2,248		798
2018		19,394		1,634		3.602		5,886		1,454		597		—		3,835		1,289				555		1,778		572
2019		15,656		1,322		3.600		4,758		1,289		482		—		2,987		913				438		1,401		408
2020		12,645		1,069		3.599		3,845		1,144		389		—		2,313		642				344		1,098		290
2021		10,199		861		3.596		3,097		1,004		312		—		1,781		450				269		858		206
2022		8,132		691		3.593		2,482		873		250		—		1,360		312				209		666		145
2023		6,450		553		3.591		1,986		758		199		—		1,029		214				161		513		101
2024		4,969		425		3.587		1,526		610		152		—		763		145				123		391		70
2025		3,733		322		3.580		1,154		478		115		—		561		96				94		296		48
2026		2,785		243		3.572		868		368		85		—		415		66				71		225		33
AFTER		8,581		807		3.571		2,881		1,414		283		—		1,183		163				210		659		51
TOTAL		1,056,132		89,741		3.614		324,290		45,965		33,262		11,164		233,899		165,173				24,267		55,789		33,689

DATE: 12/31/2006 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, 2006
UNDERLYING PROPERTIES AND TRUST INTERESTS

NON-ESCALATED 12/31/2006 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%
2007		197,290		16,947		3.617		61,303		5,982		6,310		—		49,011		46,836				4,021		7,368		7,022
2008		153,545		13,187		3.614		47,656		4,911		4,890		—		37,856		32,885				3,329		6,093		5,262
2009		120,349		10,330		3.611		37,300		4,095		3,816		—		29,389		23,208				2,835		5,166		4,043
2010		94,930		8,144		3.608		29,385		3,467		2,998		—		22,920		16,454				2,282		4,168		2,956
2011		75,275		6,458		3.605		23,282		2,976		2,369		—		17,937		11,706				1,814		3,326		2,138
2012		59,980		5,146		3.603		18,542		2,588		1,882		—		14,072		8,348				1,435		2,643		1,541
2013		47,979		4,118		3.601		14,828		2,271		1,502		—		11,055		5,962				1,644		5,283		2,776
2014		38,514		3,309		3.598		11,908		2,013		1,204		—		8,691		4,262				1,310		4,206		2,002
2015		31,000		2,668		3.596		9,594		1,798		968		—		6,829		3,044				1,043		3,347		1,443
2016		25,008		2,155		3.594		7,744		1,605		780		—		5,360		2,172				830		2,660		1,039
2017		20,191		1,741		3.592		6,253		1,425		628		—		4,200		1,547				659		2,111		747
2018		16,285		1,408		3.590		5,055		1,265		507		—		3,284		1,100				522		1,671		536
2019		13,123		1,137		3.587		4,080		1,113		408		—		2,560		780				413		1,318		383
2020		10,581		918		3.585		3,292		977		328		—		1,986		550				324		1,035		273
2021		8,518		739		3.582		2,646		846		263		—		1,537		387				254		811		194
2022		6,815		594		3.579		2,125		729		211		—		1,184		271				199		632		137
2023		5,418		476		3.576		1,701		625		168		—		907		189				154		490		96
2024		4,239		374		3.574		1,336		515		132		—		689		131				119		377		67
2025		3,278		291		3.570		1,039		417		102		—		520		89				91		289		47
2026		2,550		228		3.565		814		338		80		—		396		63				70		222		32
AFTER		8,391		794		3.569		2,833		1,387		278		—		1,167		161				209		657		51
TOTAL		943,256		81,161		3.607		292,716		41,343		29,823		—		221,550		160,143				23,557		53,871		32,786

DATE: 12/31/2006 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, 2006
UNDERLYING PROPERTIES AND TRUST INTERESTS

NON-ESCALATED 12/31/2006 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%
2007		3,650		348		3.680		1,280		128		139		7,007		(5,994	)		(5,852	)				—		—		—
2008		11,679		1,088		3.680		4,005		409		436		2,349		810			719					—		—		—
2009		15,046		1,178		3.680		4,334		457		472		1,462		1,944			1,568					—		—		—
2010		15,411		1,125		3.680		4,141		452		451		347		2,891			2,120					75		116		87
2011		13,089		940		3.680		3,459		400		377		—		2,683			1,788					95		154		101
2012		10,656		767		3.680		2,821		348		307		—		2,165			1,312					75		122		72
2013		8,676		625		3.680		2,300		307		251		—		1,743			960					104		340		183
2014		7,065		510		3.680		1,876		273		204		—		1,399			701					83		273		134
2015		5,754		416		3.680		1,530		245		167		—		1,119			509					66		218		97
2016		4,686		339		3.680		1,248		222		136		—		890			368					53		173		70
2017		3,817		277		3.681		1,019		204		111		—		704			265					42		137		50
2018		3,110		226		3.680		831		189		91		—		552			189					33		107		36
2019		2,534		184		3.679		678		177		74		—		428			133					25		83		25
2020		2,064		150		3.680		553		167		60		—		327			92					19		63		17
2021		1,681		123		3.678		451		158		49		—		244			63					14		47		12
2022		1,318		97		3.681		358		143		39		—		175			41					10		34		8
2023		1,032		77		3.683		285		132		31		—		121			26					7		23		5
2024		731		52		3.679		190		96		21		—		74			14					4		14		3
2025		455		31		3.678		114		62		12		—		40			7					2		8		1
2026		234		15		3.667		54		29		6		—		19			3					1		4		1
AFTER		190		13		3.700		48		27		5		—		16			2					1		3		0
TOTAL		112,876		8,580		3.680		31,574		4,622		3,439		11,164		12,349			5,030					711		1,918		903

DATE: 12/31/2006 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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
STATE: COLORADO
PROVED DEVELOPED RESERVES
HENDRICKSON GU B #1 (NPI)		13385	NON-UNIT		32N10W20		1		27		1,612		494		1,381		0		0		0		1,381		870		12
SO UTE TRIBAL I 2 (NPI)		13389	NON-UNIT		32N10W07		1		16		933		286		800		0		0		0		800		596		17
SO UTE TRIBAL J #2 (NPI)		13390	NON-UNIT		32N10W07		1		22		991		304		850		0		0		0		850		568		22
TOTAL PROVED DEVELOPED: 160-Acre Colorado							3				3,537		1,083		3,031		0		0		0		3,031		2,035
CARTER UTE #101 (NPI)		14449	NON-UNIT		32N10W12		1		23		2,418		93		259		0		0		0		259		180		6
CARTER UTE #106 (NPI)		13397	NON-UNIT		32N10W11		1		17		1,246		95		267		0		0		0		267		199		16
CARTER UTE #107(NPI)		13398	NON-UNIT		32N10W13		1		18		1,180		113		316		0		0		0		316		229		14
CLARK CUMMINS GU A #1 (NPI)		13383	NON-UNIT		32N10W19		1		32		2,479		750		2,098		0		0		0		2,098		1,281		13
HENDRICKSON GU A #1 (NPI)		13384	NON-UNIT		32N10W20		1		18		711		215		601		0		0		0		601		423		11
J B GARDNER GU A #1 (NPI)		13386	NON-UNIT		32N10W22		1		25		2,162		449		1,256		0		0		0		1,256		841		18
MONTGOMERY, M H #9 (NPI)		15248	NON-UNIT		32N10W12		1		28		3,161		605		1,693		0		0		0		1,693		1,116		15
ROBIN FRAZIER GU A #1 (NPI)		13387	NON-UNIT		32N10W23		1		17		1,316		261		731		0		0		0		731		547		19
SO UTE 10-3, 32-10 (NPI)		13399	NON-UNIT		32N10W10		1		24		2,359		361		1,011		0		0		0		1,011		693		21
SO UTE 15-3, 32-10 (NPI)		13400	NON-UNIT		32N10W15		1		31		2,860		219		613		0		0		0		613		385		9
SO UTE 16-2, 32-10 (NPI)		13401	NON-UNIT		32N10W16		1		25		2,320		266		746		0		0		0		746		501		10
SO UTE TRIBAL H #2 (NPI)		13388	NON-UNIT		32N10W18		1		19		969		297		831		0		0		0		831		581		2
SO UTE TRIBAL KK #1 (NPI)		13391	NON-UNIT		32N10W07		1		20		854		261		731		0		0		0		731		497		3
SO UTE TRIBAL LL #1 (NPI)		13392	NON-UNIT		32N10W08		1		21		1,197		367		1,026		0		0		0		1,026		704		4
SO UTE TRIBAL MM #1 (NPI)		13393	NON-UNIT		32N10W08		1		24		1,568		480		1,343		0		0		0		1,343		887		7
SO UTE TRIBAL NN #1 (NPI)		13394	NON-UNIT		32N10W17		1		17		857		262		734		0		0		0		734		528		5
SO UTE TRIBAL OO #1 (NPI)		13395	NON-UNIT		32N10W18		1		13		460		141		394		0		0		0		394		298		8
SO UTE TRIBAL SS #1 (NPI)		13396	NON-UNIT		32N10W21		1		24		1,438		440		1,232		0		0		0		1,232		813		20
TOTAL PROVED DEVELOPED: 320-Acre Colorado							18				29,556		5,676		15,882		0		0		0		15,882		10,705
TOTAL PROVED DEVELOPED: COLORADO							21				33,093		6,760		18,913		0		0		0		18,913		12,740
TOTAL PROVED RESERVES: COLORADO							21				33,093		6,760		18,913		0		0		0		18,913		12,740
STATE: NEW MEXICO
PROVED DEVELOPED RESERVES
ALLISON UNIT COM #105S		5141	SJ 32-7		32N07W15		1		16		690		29		108		19		12		0		77		57		1390
ALLISON UNIT COM #146S		5266	SJ 32-7		32N07W24		1		8		362		31		113		19		12		0		81		69		1391
BLANCO #201A		5609	NON-UNIT		31N08W35		1		13		802		118		436		64		47		0		324		256		1168
BLANCO #202A		5607	NON-UNIT		31N08W26		1		6		177		26		96		20		10		0		65		57		1166
BLANCO #203A		5610	NON-UNIT		31N08W35		1		13		381		56		207		45		23		0		139		106		1233
BLANCO #204A		5608	NON-UNIT		31N08W26		1		10		296		44		161		35		17		0		108		87		1165

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	Page 1 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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
BLANCO #330S		5559	NON-UNIT		31N08W05		1		12		842		61		226		31		25		0		170		138		1132
BONDS COM #100S		5140	NON-UNIT		32N10W15		1		14		779		39		143		21		16		0		106		83		1006
CAT DRAW COM #101S		20071	SJ 30-5		30N05W34		1		15		1,265		60		220		28		24		0		168		130		1467
DECKER GAS COM A #1S		5840	NON-UNIT		32N10W17		1		10		187		14		50		15		5		0		30		24		1133
EAGLE #750S		5995	NON-UNIT		32N09W16		1		13		1,172		23		85		10		9		0		66		53		1179
HUERFANO UNIT #79		12186	HUERFANO		27N10W31		1		8		185		26		96		24		10		0		62		50		1268
JAQUEZ #331S		5582	NON-UNIT		31N08W07		1		13		871		67		245		32		27		0		186		147		1136
MIDDLE MESA COM #3S		4769	SJ 32-7		32N07W06		1		12		829		36		133		18		15		0		100		81		1386
MOORE, WAYNE COM #2S		5268	NON-UNIT		31N09W16		1		9		186		7		25		7		3		0		16		13		1034
NE BLANCO UNIT #400A		1809	NEBU		31N06W07		1		14		781		6		22		3		2		0		17		13		1290
NE BLANCO UNIT #401A		5317	NEBU		30N07W09		1		11		647		5		19		2		2		0		14		11		834
NE BLANCO UNIT #402A		5145	NEBU		30N07W05		1		19		1,047		8		30		4		3		0		23		16		1007
NE BLANCO UNIT #403A		5191	NEBU		30N07W09		1		13		631		5		18		3		2		0		13		11		767
NE BLANCO UNIT #406A		5192	NEBU		31N07W22		1		2		10		0		0		0		0		0		0		0		1008
NE BLANCO UNIT #407A		17895	NEBU		30N07W21		1		16		335		3		10		2		1		0		6		4		695
NE BLANCO UNIT #408A		5196	NEBU		31N07W20		1		11		161		1		5		1		1		0		3		2		1215
NE BLANCO UNIT #409A		5273	NEBU		30N07W10		1		10		474		4		14		2		1		0		10		8		835
NE BLANCO UNIT #410A		17897	NEBU		31N07W09		1		16		1,422		11		41		5		4		0		32		24		668
NE BLANCO UNIT #411A		5200	NEBU		30N07W10		1		13		585		5		17		2		2		0		12		10		768
NE BLANCO UNIT #412A		5802	NEBU		31N07W29		1		14		1,030		8		29		3		3		0		23		18		1310
NE BLANCO UNIT #413A		17899	NEBU		30N07W20		1		9		278		2		8		1		1		0		6		5		692
NE BLANCO UNIT #415A		5207	NEBU		30N07W02		1		15		589		5		17		3		2		0		12		9		769
NE BLANCO UNIT #418A		5210	NEBU		31N07W28		1		18		888		7		25		4		3		0		19		14		1217
NE BLANCO UNIT #422A		5146	NEBU		31N07W20		1		9		263		2		8		1		1		0		5		4		1011
NE BLANCO UNIT #425A		6038	NEBU		30N07W08		1		16		800		6		23		3		2		0		17		12		826
NE BLANCO UNIT #426A		5231	NEBU		31N06W06		1		12		570		4		16		2		2		0		12		10		1219
NE BLANCO UNIT #428A		6018	NEBU		31N07W24		1		16		901		7		26		3		3		0		20		14		1048
NE BLANCO UNIT #430A		5245	NEBU		30N07W05		1		11		362		3		10		2		1		0		7		6		1013
NE BLANCO UNIT #433A		1000	NEBU		30N07W19		1		15		488		4		14		3		2		0		10		7		1208
NE BLANCO UNIT #434A		6017	NEBU		31N07W23		1		11		552		4		16		2		2		0		12		10		1045
NE BLANCO UNIT #435A		4894	NEBU		30N08W01		1		19		1,355		11		39		5		4		0		30		22		999
NE BLANCO UNIT #436A		1149	NEBU		31N06W19		1		17		845		7		24		3		3		0		18		13		1004
NE BLANCO UNIT #437A		5251	NEBU		30N08W12		1		17		781		6		22		3		2		0		17		12		1015
NE BLANCO UNIT #438A		1160	NEBU		31N06W18		1		11		943		7		27		3		3		0		21		18		1000
NE BLANCO UNIT #439A		5169	NEBU		30N08W13		1		11		644		5		18		2		2		0		14		11		1016
NE BLANCO UNIT #440A		709	NEBU		31N07W11		1		18		1,494		12		43		5		5		0		33		25		1207
NE BLANCO UNIT #441A		1545	NEBU		30N08W24		1		14		661		5		19		3		2		0		14		11		735
NE BLANCO UNIT #442A		17900	NEBU		31N07W11		1		21		2,208		17		63		7		7		0		50		36		666
NE BLANCO UNIT #443A		17896	NEBU		30N08W24		1		5		37		0		1		1		0		0		0		0		689
NE BLANCO UNIT #445A		5250	NEBU		31N08W25		1		16		765		6		22		3		2		0		16		12		1017
NE BLANCO UNIT #447A		5248	NEBU		31N08W36		1		17		1,043		8		30		4		3		0		23		17		1018

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	Page 2 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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
NE BLANCO UNIT #448A		5181	NEBU		31N07W32		1		13		368		3		11		2		1		0		7		6		1019
NE BLANCO UNIT #449A		5183	NEBU		31N07W19		1		18		1,486		12		43		5		5		0		33		25		1020
NE BLANCO UNIT #450A		5801	NEBU		31N07W32		1		11		731		6		21		3		2		0		16		13		1056
NE BLANCO UNIT #451A		6035	NEBU		30N07W06		1		12		694		5		20		3		2		0		15		12		1037
NE BLANCO UNIT #452A		5797	NEBU		31N07W15		1		18		1,418		11		41		5		4		0		31		23		1041
NE BLANCO UNIT #454A		6025	NEBU		31N07W33		1		12		1,082		8		31		3		3		0		24		20		1057
NE BLANCO UNIT #455A		5190	NEBU		31N07W31		1		12		1,240		10		35		4		4		0		28		23		1021
NE BLANCO UNIT #457A		5189	NEBU		31N07W30		1		12		966		8		28		3		3		0		21		18		1022
NE BLANCO UNIT #458A		5247	NEBU		31N07W13		1		13		1,166		9		33		4		4		0		26		21		1023
NE BLANCO UNIT #460A		1810	NEBU		31N06W07		1		10		598		5		17		2		2		0		13		11		753
NE BLANCO UNIT #461A		5182	NEBU		30N07W07		1		13		517		4		15		2		2		0		11		9		1024
NE BLANCO UNIT #462A		5246	NEBU		31N07W01		1		4		96		1		3		1		0		0		2		2		1025
NE BLANCO UNIT #463A		5170	NEBU		30N07W18		1		12		452		4		13		2		1		0		9		7		1213
NE BLANCO UNIT #464A		17898	NEBU		31N07W10		1		17		943		7		27		4		3		0		20		15		667
NE BLANCO UNIT #465A		5243	NEBU		30N08W01		1		12		741		6		21		3		2		0		16		13		1027
NE BLANCO UNIT #468A		5163	NEBU		31N07W35		1		17		1,159		9		33		4		4		0		25		19		772
NE BLANCO UNIT #471A		5272	NEBU		31N08W25		1		12		770		6		22		3		2		0		17		14		1064
NE BLANCO UNIT #476A		5799	NEBU		31N07W22		1		19		1,064		8		30		4		3		0		23		16		1044
NE BLANCO UNIT #478A		5212	NEBU		31N07W21		1		12		371		3		11		2		1		0		7		6		1218
NE BLANCO UNIT #480A		5209	NEBU		31N07W14		1		21		796		6		23		4		2		0		17		11		1029
NE BLANCO UNIT #481A		5153	NEBU		31N07W36		1		8		586		5		17		2		2		0		13		11		773
NE BLANCO UNIT #482A		4895	NEBU		31N07W15		1		13		870		7		25		3		3		0		19		15		1002
NE BLANCO UNIT #483A		5149	NEBU		31N07W36		1		16		632		5		18		3		2		0		13		10		774
NE BLANCO UNIT #484A		4896	NEBU		31N07W16		1		15		1,106		9		32		4		3		0		24		19		1003
NE BLANCO UNIT #486A		1150	NEBU		31N06W19		1		14		1,209		9		35		4		4		0		27		21		717
NE BLANCO UNIT #487A		5201	NEBU		31N07W35		1		5		65		1		2		1		0		0		1		1		1030
NE BLANCO UNIT #490A		5198	NEBU		31N07W14		1		7		193		2		6		1		1		0		4		3		1216
NE BLANCO UNIT #491A		5147	NEBU		31N07W25		1		13		528		4		15		2		2		0		11		9		1212
NE BLANCO UNIT #492A		5795	NEBU		31N07W12		1		10		262		2		8		2		1		0		5		4		1038
NE BLANCO UNIT #493A		6012	NEBU		31N07W25		1		18		951		7		27		4		3		0		21		14		830
NE BLANCO UNIT #495A		1068	NEBU		31N06W30		1		13		348		3		10		2		1		0		7		5		754
NE BLANCO UNIT #496A		1161	NEBU		31N06W18		1		12		957		7		27		3		3		0		21		17		720
NE BLANCO UNIT #497A		1110	NEBU		31N06W30		1		8		179		1		5		1		1		0		3		3		713
NE BLANCO UNIT #498A		5193	NEBU		31N07W13		1		19		1,350		11		39		5		4		0		30		22		1214
NE BLANCO UNIT #499A		1152	NEBU		31N06W20		1		17		1,913		15		55		6		6		0		43		33		731
NE BLANCO UNIT #500A		1157	NEBU		31N06W20		1		15		1,072		8		31		4		3		0		24		18		1209
NE BLANCO UNIT #504A		1163	NEBU		31N07W16		1		11		1,191		9		34		4		4		0		27		22		738
PAYNE #201S		4128	NON-UNIT		32N10W20		1		19		1,075		20		73		11		8		0		54		38		743
QUINN #336S		5596	NON-UNIT		31N08W17		1		11		734		54		198		28		22		0		148		120		1135
RATTLESNAKE CANYON #105S		4771	SJ 32-8		32N08W32		1		17		1,903		81		298		35		33		0		231		178		1388
SAN JUAN 28-6 UNIT #418S		19353	SJ 28-6		28N06W28		1		11		113		6		24		11		3		0		10		8		639

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	Page 3 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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 28-6 UNIT #437S		6102	SJ 28-6		28N06W28		1		8		149		8		31		9		3		0		19		15		1344
SAN JUAN 28-6 UNIT #467S		12609	SJ 28-6		28N06W34		1		2		19		1		4		2		0		0		2		2		1367
SAN JUAN 28-6 UNIT #474S		12616	SJ 28-6		28N06W27		1		6		101		6		21		6		2		0		12		11		1369
SAN JUAN 28-6 UNIT #475S		12610	SJ 28-6		28N06W29		1		9		196		11		41		10		4		0		26		21		1419
SAN JUAN 29-6 UNIT #201A		5403	SJ 29-6		29N06W06		1		15		450		59		217		44		24		0		149		111		740
SAN JUAN 29-6 UNIT #202A		5404	SJ 29-6		29N06W06		1		9		115		15		56		20		6		0		29		24		739
SAN JUAN 29-6 UNIT #203A		5406	SJ 29-6		29N06W07		1		8		389		51		188		30		20		0		137		116		816
SAN JUAN 29-6 UNIT #204A		5405	SJ 29-6		29N06W07		1		16		534		70		257		49		28		0		180		132		745
SAN JUAN 29-6 UNIT #205A		6095	SJ 29-6		29N06W21		1		15		1,030		135		497		66		54		0		376		291		926
SAN JUAN 29-6 UNIT #207A		5555	SJ 29-6		29N06W02		1		16		765		100		369		59		40		0		270		199		817
SAN JUAN 29-6 UNIT #208A		5551	SJ 29-6		29N06W17		1		11		219		29		106		28		11		0		66		51		995
SAN JUAN 29-6 UNIT #209A		5552	SJ 29-6		29N06W17		1		17		876		115		422		65		46		0		312		229		994
SAN JUAN 29-6 UNIT #210A		6093	SJ 29-6		29N06W20		1		12		703		92		339		48		37		0		254		206		924
SAN JUAN 29-6 UNIT #211A		6094	SJ 29-6		29N06W20		1		14		323		42		156		38		17		0		101		75		923
SAN JUAN 29-6 UNIT #214A		5407	SJ 29-6		29N06W03		1		16		684		90		330		55		36		0		239		177		818
SAN JUAN 29-6 UNIT #215A		5408	SJ 29-6		29N06W03		1		19		1,408		184		679		89		74		0		516		375		775
SAN JUAN 29-6 UNIT #216A		5410	SJ 29-6		29N06W04		1		14		751		98		362		55		39		0		268		207		742
SAN JUAN 29-6 UNIT #217A		5411	SJ 29-6		29N06W05		1		12		380		50		183		37		20		0		127		98		741
SAN JUAN 29-6 UNIT #218A		5412	SJ 29-6		29N06W05		1		2		17		2		8		4		1		0		4		3		905
SAN JUAN 29-6 UNIT #220A		6081	SJ 29-6		29N06W11		1		11		669		88		323		46		35		0		242		198		912
SAN JUAN 29-6 UNIT #221A		6082	SJ 29-6		29N06W11		1		6		82		11		40		13		4		0		22		19		911
SAN JUAN 29-6 UNIT #236A		5553	SJ 29-6		29N06W18		1		12		262		34		126		31		14		0		81		63		819
SAN JUAN 29-6 UNIT #237A		5110	SJ 29-6		29N06W01		1		12		271		36		131		32		14		0		84		65		757
SAN JUAN 29-6 UNIT #238A		5033	SJ 29-6		29N06W01		1		6		122		16		59		16		6		0		37		32		734
SAN JUAN 29-6 UNIT #239A		5616	SJ 29-6		29N06W02		1		16		442		58		213		45		23		0		144		105		903
SAN JUAN 29-6 UNIT #240A		6078	SJ 29-6		29N06W18		1		14		570		75		275		47		30		0		197		151		921
SAN JUAN 29-6 UNIT #241A		6091	SJ 29-6		29N06W19		1		17		1,484		195		716		89		78		0		549		411		922
SAN JUAN 29-6 UNIT #242A		5554	SJ 29-6		29N06W19		1		13		765		100		369		54		40		0		275		215		820
SAN JUAN 29-6 UNIT #245A		5413	SJ 29-6		29N06W08		1		14		428		56		206		43		22		0		141		106		776
SAN JUAN 29-6 UNIT #72A		6098	SJ 29-6		29N06W22		1		6		61		9		33		15		4		0		14		12		1241
SAN JUAN 29-7 UNIT #176		707	SJ 29-7		29N07W22		1		6		52		6		22		12		2		0		8		7		684
SAN JUAN 29-7 UNIT #187		832	SJ 29-7		29N07W03		1		3		18		2		8		5		1		0		2		2		696
SAN JUAN 29-7 UNIT #188		18165	SJ 29-7		29N07W06		1		8		76		9		33		15		4		0		14		11		748
SAN JUAN 29-7 UNIT #189		8020	SJ 29-7		29N07W14		1		12		221		26		96		27		10		0		59		45		694
SAN JUAN 29-7 UNIT #190		11717	SJ 29-7		29N07W16		1		8		57		7		25		14		3		0		8		6		1372
SAN JUAN 29-7 UNIT #191		945	SJ 29-7		29N07W22		1		8		74		9		32		15		3		0		13		11		749
SAN JUAN 29-7 UNIT #507S		6070	SJ 29-7		29N07W13		1		14		1,029		122		447		58		49		0		340		264		894
SAN JUAN 29-7 UNIT #520S		6062	SJ 29-7		29N07W08		1		15		600		71		261		44		28		0		188		138		888
SAN JUAN 29-7 UNIT #521S		6069	SJ 29-7		29N07W13		1		9		550		65		239		34		26		0		179		151		895
SAN JUAN 29-7 UNIT #526S		12224	SJ 29-7		29N07W21		1		8		156		18		68		19		7		0		41		34		1364
SAN JUAN 29-7 UNIT #530S		6076	SJ 29-7		29N07W34		1		19		1,100		130		478		68		52		0		358		251		1334

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 29-7 UNIT #545S		6068	SJ 29-7		29N07W12		1		17		812		96		353		54		38		0		260		192		892
SAN JUAN 29-7 UNIT #563S		1195	SJ 29-7		29N07W24		1		11		477		56		207		33		23		0		151		123		693
SAN JUAN 30-5 UNIT #201A		5722	SJ 30-5		30N05W19		1		13		443		83		307		59		33		0		214		164		969
SAN JUAN 30-5 UNIT #202A		1551	SJ 30-5		30N05W06		1		9		863		162		598		71		65		0		462		397		947
SAN JUAN 30-5 UNIT #203A		9785	SJ 30-5		30N05W06		1		10		612		115		424		60		46		0		317		264		644
SAN JUAN 30-5 UNIT #206A		5721	SJ 30-5		30N05W18		1		11		223		42		154		42		17		0		96		74		967
SAN JUAN 30-5 UNIT #207A		5034	SJ 30-5		30N05W18		1		4		61		11		42		15		5		0		23		21		756
SAN JUAN 30-5 UNIT #208A		5723	SJ 30-5		30N05W19		1		12		408		77		283		55		31		0		196		152		968
SAN JUAN 30-5 UNIT #209A		5781	SJ 30-5		30N05W30		1		3		24		4		16		10		2		0		5		4		984
SAN JUAN 30-5 UNIT #210A		5780	SJ 30-5		30N05W30		1		9		140		26		97		31		11		0		55		45		985
SAN JUAN 30-5 UNIT #212A		5782	SJ 30-5		30N05W31		1		5		39		7		27		15		3		0		10		8		987
SAN JUAN 30-5 UNIT #213A		17901	SJ 30-5		30N05W05		1		10		506		95		350		54		38		0		259		215		643
SAN JUAN 30-5 UNIT #214A		8013	SJ 30-5		30N05W05		1		12		545		102		377		61		41		0		275		219		642
SAN JUAN 30-5 UNIT #215A		5702	SJ 30-5		30N05W08		1		11		333		63		230		46		25		0		159		127		993
SAN JUAN 30-5 UNIT #216A		5731	SJ 30-5		30N05W20		1		6		114		21		79		23		9		0		47		41		971
SAN JUAN 30-5 UNIT #217A		5734	SJ 30-5		30N05W21		1		15		533		100		369		68		40		0		260		194		1239
SAN JUAN 30-5 UNIT #218A		5720	SJ 30-5		30N05W17		1		5		94		18		65		17		7		0		41		37		965
SAN JUAN 30-5 UNIT #219A		5108	SJ 30-5		30N05W16		1		9		445		84		308		50		34		0		225		187		730
SAN JUAN 30-5 UNIT #220A		8014	SJ 30-5		30N05W08		1		18		1,323		249		916		120		100		0		696		506		1203
SAN JUAN 30-5 UNIT #223A		5733	SJ 30-5		30N05W20		1		3		33		6		23		9		2		0		11		10		1238
SAN JUAN 30-5 UNIT #226A		5772	SJ 30-5		30N05W29		1		10		300		56		208		43		23		0		142		115		983
SAN JUAN 30-5 UNIT #229A		5735	SJ 30-5		30N05W21		1		15		649		122		449		76		49		0		324		242		972
SAN JUAN 30-5 UNIT #231A		5139	SJ 30-5		30N05W32		1		0		0		0		0		0		0		0		0		0		736
SAN JUAN 30-5 UNIT #234A		5737	SJ 30-5		30N05W22		1		13		373		70		258		55		28		0		175		134		975
SAN JUAN 30-5 UNIT #237A		5052	SJ 30-5		30N05W16		1		9		399		75		276		45		30		0		201		170		725
SAN JUAN 30-5 UNIT #239A		5716	SJ 30-5		30N05W15		1		10		403		76		279		49		30		0		199		162		964
SAN JUAN 30-5 UNIT #240A		5738	SJ 30-5		30N05W22		1		12		469		88		325		58		35		0		231		182		974
SAN JUAN 30-5 UNIT #241A		5739	SJ 30-5		30N05W23		1		18		1,000		188		692		103		75		0		513		359		1304
SAN JUAN 30-5 UNIT #243A		5718	SJ 30-5		30N05W15		1		11		547		103		379		58		41		0		279		228		963
SAN JUAN 30-5 UNIT #249A		5740	SJ 30-5		30N05W23		1		18		951		179		659		100		72		0		487		344		976
SAN JUAN 30-5 UNIT #255A		5714	SJ 30-5		30N05W14		1		9		211		40		146		36		16		0		94		77		962
SAN JUAN 30-5 UNIT #257A		5712	SJ 30-5		30N05W11		1		20		1,896		357		1,313		158		143		0		1,012		718		959
SAN JUAN 30-5 UNIT #258A		5715	SJ 30-5		30N05W14		1		7		493		93		341		46		37		0		258		226		961
SAN JUAN 30-5 UNIT #259A		12145	SJ 30-5		30N05W13		1		18		951		179		659		100		72		0		487		344		1353
SAN JUAN 30-5 UNIT #260A		9786	SJ 30-5		30N05W09		1		11		1,044		196		723		87		79		0		557		459		646
SAN JUAN 30-5 UNIT #261A		5713	SJ 30-5		30N05W11		1		20		1,896		357		1,313		158		143		0		1,012		718		958
SAN JUAN 30-5 UNIT #263A		12144	SJ 30-5		30N05W13		1		13		977		184		676		89		74		0		514		408		1352
SAN JUAN 30-5 UNIT #264A		5710	SJ 30-5		30N05W09		1		14		1,350		254		935		111		102		0		722		573		956
SAN JUAN 30-5 UNIT #265A		5711	SJ 30-5		30N05W10		1		12		1,307		246		905		104		99		0		703		579		957
SAN JUAN 30-5 UNIT #266A		8017	SJ 30-5		30N05W10		1		13		1,373		258		951		111		104		0		736		590		645
SAN JUAN 30-5 UNIT #267A		11794	SJ 30-5		30N05W24		1		18		1,000		188		692		103		75		0		513		359		1348

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 30-5 UNIT #268A		11795	SJ 30-5		30N05W24		1		18		1,000		188		692		103		75		0		513		359		1349
SAN JUAN 30-6 UNIT #400S		6042	SJ 30-6		30N07W14		1		11		349		17		64		13		7		0		44		35		845
SAN JUAN 30-6 UNIT #401S		6041	SJ 30-6		30N07W13		1		13		752		38		138		20		15		0		103		81		876
SAN JUAN 30-6 UNIT #404S		5516	SJ 30-6		30N07W23		1		4		69		3		13		4		1		0		8		7		778
SAN JUAN 30-6 UNIT #405S		5436	SJ 30-6		30N06W09		1		7		174		9		32		8		3		0		21		17		779
SAN JUAN 30-6 UNIT #408S		19395	SJ 30-6		30N06W16		1		16		599		30		110		20		12		0		78		58		685
SAN JUAN 30-6 UNIT #410S		5539	SJ 30-6		30N06W26		1		18		1,107		55		203		29		22		0		152		111		864
SAN JUAN 30-6 UNIT #411S		1258	SJ 30-6		30N07W27		1		13		420		21		77		15		8		0		54		41		648
SAN JUAN 30-6 UNIT #412S		996	SJ 30-6		30N07W24		1		15		526		26		97		18		11		0		68		51		781
SAN JUAN 30-6 UNIT #413S		5508	SJ 30-6		30N07W23		1		14		492		25		90		17		10		0		63		47		782
SAN JUAN 30-6 UNIT #414S		1260	SJ 30-6		30N07W35		1		10		207		10		38		10		4		0		23		18		651
SAN JUAN 30-6 UNIT #415S		5077	SJ 30-6		30N07W26		1		3		27		1		5		2		1		0		2		2		761
SAN JUAN 30-6 UNIT #419S		6028	SJ 30-6		30N07W11		1		6		216		11		40		8		4		0		28		24		842
SAN JUAN 30-6 UNIT #420S		6039	SJ 30-6		30N07W12		1		2		35		2		6		2		1		0		4		4		844
SAN JUAN 30-6 UNIT #422S		1261	SJ 30-6		30N07W27		1		19		657		33		121		23		13		0		84		58		690
SAN JUAN 30-6 UNIT #424S		1723	SJ 30-6		30N07W33		1		11		400		20		73		14		8		0		52		42		1272
SAN JUAN 30-6 UNIT #425S		1322	SJ 30-6		30N07W33		1		12		544		27		100		17		11		0		72		57		652
SAN JUAN 30-6 UNIT #426S		1271	SJ 30-6		30N07W34		1		4		70		3		13		4		1		0		8		7		650
SAN JUAN 30-6 UNIT #427S		1203	SJ 30-6		30N07W35		1		0		0		0		0		0		0		0		0		0		687
SAN JUAN 30-6 UNIT #429S		1773	SJ 30-6		30N07W32		1		13		684		34		126		20		14		0		92		72		1273
SAN JUAN 30-6 UNIT #430S		5447	SJ 30-6		30N06W08		1		7		165		8		30		7		3		0		20		17		1260
SAN JUAN 30-6 UNIT #431S		5450	SJ 30-6		30N06W10		1		12		301		15		55		13		6		0		36		28		1221
SAN JUAN 30-6 UNIT #432S		5448	SJ 30-6		30N06W10		1		11		298		15		55		12		6		0		37		29		1220
SAN JUAN 30-6 UNIT #433S		11700	SJ 30-6		30N06W11		1		15		432		22		79		17		9		0		54		40		1266
SAN JUAN 30-6 UNIT #434S		5469	SJ 30-6		30N06W12		1		13		647		32		119		19		13		0		87		69		1222
SAN JUAN 30-6 UNIT #435S		5484	SJ 30-6		30N06W13		1		2		25		1		5		2		0		0		2		2		789
SAN JUAN 30-6 UNIT #436S		5525	SJ 30-6		30N06W15		1		12		491		25		90		16		10		0		65		51		848
SAN JUAN 30-6 UNIT #437S		5504	SJ 30-6		30N06W11		1		16		718		36		132		22		14		0		96		71		790
SAN JUAN 30-6 UNIT #438S		5468	SJ 30-6		30N06W12		1		11		315		16		58		12		6		0		40		32		791
SAN JUAN 30-6 UNIT #442S		5485	SJ 30-6		30N06W14		1		13		407		20		75		15		8		0		51		39		1223
SAN JUAN 30-6 UNIT #443S		1206	SJ 30-6		30N06W36		1		11		212		11		39		11		4		0		24		19		649
SAN JUAN 30-6 UNIT #444S		19402	SJ 30-6		30N06W36		1		6		73		4		13		5		1		0		7		6		647
SAN JUAN 30-6 UNIT #445S		5479	SJ 30-6		30N06W13		1		11		325		16		60		13		6		0		40		32		794
SAN JUAN 30-6 UNIT #446S		5502	SJ 30-6		30N06W35		1		11		336		17		62		12		7		0		43		34		795
SAN JUAN 30-6 UNIT #450S		5437	SJ 30-6		30N06W07		1		7		95		5		17		6		2		0		9		8		796
SAN JUAN 30-6 UNIT #451S		5430	SJ 30-6		30N06W07		1		9		303		15		56		11		6		0		39		32		763
SAN JUAN 30-6 UNIT #452S		5438	SJ 30-6		30N06W08		1		13		387		19		71		15		8		0		48		37		797
SAN JUAN 30-6 UNIT #454S		5529	SJ 30-6		30N06W17		1		14		501		25		92		18		10		0		65		48		850
SAN JUAN 30-6 UNIT #455S		5530	SJ 30-6		30N06W18		1		9		383		19		70		12		8		0		51		42		853
SAN JUAN 30-6 UNIT #457S		5257	SJ 30-6		30N06W19		1		12		364		18		67		14		7		0		46		36		764
SAN JUAN 30-6 UNIT #460S		5487	SJ 30-6		30N06W20		1		4		71		4		13		4		1		0		8		7		798

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 30-6 UNIT #461S		5503	SJ 30-6		30N07W11		1		13		370		18		68		15		7		0		46		35		799
SAN JUAN 30-6 UNIT #462S		6040	SJ 30-6		30N07W12		1		2		11		1		2		1		0		0		1		1		843
SAN JUAN 30-6 UNIT #463S		5505	SJ 30-6		30N07W13		1		2		16		1		3		2		0		0		1		1		800
SAN JUAN 30-6 UNIT #466S		6051	SJ 30-6		30N07W22		1		14		385		19		71		16		8		0		47		35		859
SAN JUAN 30-6 UNIT #468S		5117	SJ 30-6		30N07W36		1		5		66		3		12		4		1		0		7		6		759
SAN JUAN 30-6 UNIT #471S		5488	SJ 30-6		30N06W21		1		7		231		12		42		9		5		0		29		25		803
SAN JUAN 30-6 UNIT #473S		5535	SJ 30-6		30N06W22		1		11		131		7		24		9		3		0		12		9		858
SAN JUAN 30-6 UNIT #475S		5493	SJ 30-6		30N06W27		1		12		393		20		72		15		8		0		50		39		804
SAN JUAN 30-6 UNIT #476S		5541	SJ 30-6		30N06W28		1		17		846		42		156		24		17		0		114		84		863
SAN JUAN 30-6 UNIT #477S		5130	SJ 30-6		30N06W28		1		12		860		43		158		21		17		0		119		95		760
SAN JUAN 30-6 UNIT #478S		5137	SJ 30-6		30N06W29		1		11		374		19		69		14		7		0		48		38		746
SAN JUAN 30-6 UNIT #479S		5542	SJ 30-6		30N06W29		1		9		535		27		98		14		11		0		73		62		869
SAN JUAN 30-6 UNIT #481S		5431	SJ 30-6		30N06W30		1		12		428		21		79		15		9		0		56		44		765
SAN JUAN 30-6 UNIT #483S		5500	SJ 30-6		30N06W34		1		19		1,020		51		187		28		20		0		139		100		806
SAN JUAN 30-6 UNIT #484S		5499	SJ 30-6		30N06W34		1		15		741		37		136		21		15		0		100		75		807
SAN JUAN 30-6 UNIT #485S		5116	SJ 30-6		30N07W36		1		10		270		13		50		11		5		0		33		27		996
SAN JUAN 30-6 UNIT #486S		5143	SJ 30-6		30N06W23		1		5		83		4		15		5		2		0		9		8		766
SAN JUAN 30-6 UNIT #488S		5490	SJ 30-6		30N06W24		1		8		132		7		24		8		3		0		14		11		808
SAN JUAN 30-6 UNIT #489S		5489	SJ 30-6		30N06W24		1		5		56		3		10		4		1		0		5		5		809
SAN JUAN 30-6 UNIT #490S		5492	SJ 30-6		30N06W25		1		11		235		12		43		11		5		0		27		21		810
SAN JUAN 30-6 UNIT #491S		5491	SJ 30-6		30N06W25		1		17		479		24		88		19		10		0		59		42		811
SAN JUAN 30-6 UNIT #493S		5131	SJ 30-6		30N06W32		1		4		56		3		10		4		1		0		5		5		744
SAN JUAN 30-6 UNIT #494S		5498	SJ 30-6		30N06W33		1		17		822		41		151		24		16		0		111		82		812
SAN JUAN 30-6 UNIT #495S		5497	SJ 30-6		30N06W33		1		11		626		31		115		17		13		0		85		69		813
SAN JUAN 30-6 UNIT #496S		5501	SJ 30-6		30N06W35		1		9		273		14		50		10		5		0		35		29		814
SAN JUAN 30-6 UNIT #497S		1778	SJ 30-6		30N07W29		1		13		328		16		60		14		7		0		40		31		1277
SAN JUAN 30-6 UNIT COM #467S		6049	NEBU		30N07W22		1		12		571		16		59		9		6		0		43		34		822
SAN JUAN 31 FED 3 #2A		5942	NON-UNIT		31N09W03		1		17		870		129		476		76		52		0		347		247		1169
SAN JUAN 31-6 UNIT #201A		1813	SJ 31-6		30N06W01		1		21		1,059		113		417		66		45		0		306		212		706
SAN JUAN 31-6 UNIT #202A		1812	SJ 31-6		30N06W01		1		9		250		27		98		21		11		0		66		55		1211
SAN JUAN 31-6 UNIT #203A		1819	SJ 31-6		30N06W03		1		13		296		32		116		29		13		0		75		56		718
SAN JUAN 31-6 UNIT #204A		1817	SJ 31-6		30N06W03		1		10		337		36		133		26		14		0		92		75		707
SAN JUAN 31-6 UNIT #205A		1821	SJ 31-6		30N06W04		1		1		5		1		2		1		0		0		0		0		712
SAN JUAN 31-6 UNIT #206A		1820	SJ 31-6		30N06W04		1		9		157		17		62		19		7		0		36		30		708
SAN JUAN 31-6 UNIT #209A		6030	SJ 31-6		30N07W01		1		17		877		94		346		54		38		0		254		187		933
SAN JUAN 31-6 UNIT #210A		1816	SJ 31-6		30N06W02		1		14		628		67		247		42		27		0		179		136		719
SAN JUAN 31-6 UNIT #211A		1815	SJ 31-6		30N06W02		1		15		1,320		141		520		66		57		0		397		306		710
SAN JUAN 31-6 UNIT #212A		5613	SJ 31-6		30N06W05		1		5		56		6		22		10		2		0		10		9		935
SAN JUAN 31-6 UNIT #213A		5612	SJ 31-6		30N06W05		1		10		293		31		116		25		13		0		78		63		936
SAN JUAN 31-6 UNIT #214A		1360	SJ 31-6		31N06W36		1		7		228		24		90		19		10		0		62		53		702
SAN JUAN 31-6 UNIT #215A		1361	SJ 31-6		31N06W36		1		20		1,203		129		474		70		52		0		353		247		653

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 31-6 UNIT #216A		1788	SJ 31-6		31N06W35		1		18		1,322		142		521		70		57		0		395		287		1282
SAN JUAN 31-6 UNIT #217A		1363	SJ 31-6		31N06W35		1		10		411		44		162		28		18		0		117		96		703
SAN JUAN 31-6 UNIT #218A		1790	SJ 31-6		31N06W34		1		17		1,157		124		456		64		50		0		342		247		1284
SAN JUAN 31-6 UNIT #219A		1789	SJ 31-6		31N06W34		1		18		951		102		375		58		41		0		276		195		1283
SAN JUAN 31-6 UNIT #223A		1377	SJ 31-6		31N06W32		1		5		73		8		29		10		3		0		16		14		654
SAN JUAN 31-6 UNIT #229A		1386	SJ 31-6		31N06W28		1		8		328		35		129		23		14		0		92		78		715
SAN JUAN 31-6 UNIT #230A		1383	SJ 31-6		31N06W27		1		21		1,440		154		568		78		62		0		427		301		705
SAN JUAN 31-6 UNIT #231A		1384	SJ 31-6		31N06W27		1		11		255		27		100		25		11		0		65		51		704
SAN JUAN 31-6 UNIT #234A		1385	SJ 31-6		31N06W29		1		11		344		37		136		28		15		0		93		74		688
SAN JUAN 32-7 UNIT #202A		10784	SJ 32-7		32N07W18		1		20		1,768		263		966		121		105		0		740		528		1450
SAN JUAN 32-7 UNIT #203A		5109	SJ 32-7		32N07W22		1		13		839		142		524		75		57		0		392		311		664
SAN JUAN 32-7 UNIT #204A		4126	SJ 32-7		32N07W36		1		1		8		1		5		3		1		0		1		1		1176
SAN JUAN 32-7 UNIT #205A		1231	SJ 32-7		32N07W22		1		14		2,381		404		1,486		158		162		0		1,166		940		1383
SAN JUAN 32-7 UNIT #206A		719	SJ 32-7		32N07W27		1		18		1,269		215		792		109		86		0		597		440		722
SAN JUAN 32-7 UNIT #207A		5812	SJ 32-7		32N07W27		1		9		565		96		353		51		38		0		264		224		1174
SAN JUAN 32-7 UNIT #208A		970	SJ 32-7		32N07W34		1		15		802		136		500		79		54		0		367		277		670
SAN JUAN 32-7 UNIT #209A		1207	SJ 32-7		32N07W35		1		12		821		139		512		72		56		0		384		308		672
SAN JUAN 32-7 UNIT #210A		4125	SJ 32-7		32N07W36		1		17		887		150		554		88		60		0		405		296		1177
SAN JUAN 32-7 UNIT #211A		648	SJ 32-7		32N07W35		1		10		571		97		356		55		39		0		262		215		721
SAN JUAN 32-7 UNIT #213A		12143	SJ 32-7		31N07W18		1		18		1,070		115		422		62		46		0		313		229		1351
SAN JUAN 32-7 UNIT #214A		5804	SJ 32-7		32N07W34		1		10		389		66		243		44		26		0		173		143		1178
SAN JUAN 32-7 UNIT #215A		1210	SJ 32-7		32N07W32		1		18		1,442		244		900		119		98		0		682		502		671
SAN JUAN 32-7 UNIT #216A		6120	SJ 32-7		31N07W04		1		11		415		70		259		48		28		0		183		146		1242
SAN JUAN 32-7 UNIT #217A		655	SJ 32-7		31N07W04		1		10		729		124		455		61		50		0		344		289		716
SAN JUAN 32-7 UNIT #218A		1208	SJ 32-7		31N07W07		1		22		1,914		325		1,194		152		130		0		912		641		662
SAN JUAN 32-7 UNIT #219A		6122	SJ 32-7		31N07W05		1		11		911		155		569		75		62		0		432		352		1243
SAN JUAN 32-7 UNIT #220A		6011	SJ 32-7		31N07W06		1		19		1,194		177		652		94		71		0		487		352		1170
SAN JUAN 32-7 UNIT #221A		694	SJ 32-7		31N07W08		1		10		274		46		171		39		19		0		114		92		711
SAN JUAN 32-7 UNIT #222A		6008	SJ 32-7		32N07W20		1		12		1,128		191		704		88		77		0		539		438		1180
SAN JUAN 32-7 UNIT #224A		4795	SJ 32-7		32N07W21		1		17		1,737		221		813		99		89		0		626		473		659
SAN JUAN 32-7 UNIT #227A		6010	SJ 32-7		31N07W18		1		15		573		73		268		50		29		0		189		140		1162
SAN JUAN 32-7 UNIT #228A		12142	SJ 32-7		31N07W07		1		10		351		30		112		22		12		0		77		62		1350
SAN JUAN 32-7 UNIT #229A		4893	SJ 32-7		31N07W09		1		7		243		41		152		29		17		0		106		92		714
SAN JUAN 32-7 UNIT #230A		5798	SJ 32-7		31N07W17		1		9		239		41		149		34		16		0		99		81		1171
SAN JUAN 32-7 UNIT #231A		1323	SJ 32-7		31N07W17		1		6		122		21		76		22		8		0		46		40		663
SAN JUAN 32-7 UNIT #232A		4127	SJ 32-7		31N07W08		1		13		821		139		513		75		56		0		382		300		709
SAN JUAN 32-7 UNIT #233A		11353	SJ 32-7		32N07W20		1		15		1,290		219		805		104		88		0		614		474		1365
SAN JUAN 32-7 UNIT #234A		1229	SJ 32-7		32N07W32		1		8		301		51		188		34		20		0		133		113		661
SAN JUAN 32-7 UNIT #235A		5811	SJ 32-7		32N07W29		1		11		1,318		224		823		95		90		0		638		531		1175
SAN JUAN 32-7 UNIT #237A		721	SJ 32-7		32N07W28		1		12		289		49		180		44		20		0		116		90		1380
SAN JUAN 32-7 UNIT #238A		1211	SJ 32-7		32N07W29		1		17		2,349		398		1,466		164		160		0		1,143		874		674

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 32-7 UNIT #241A		718	SJ 32-7		32N07W21		1		16		1,717		291		1,072		129		117		0		826		635		1378
SAN JUAN 32-7 UNIT #242A		1212	SJ 32-7		32N07W33		1		15		1,328		225		829		104		90		0		634		496		669
SAN JUAN 32-7 UNIT #243A		750	SJ 32-7		32N07W19		1		12		922		156		575		78		63		0		435		345		1453
SAN JUAN 32-7 UNIT #244A		5818	SJ 32-7		32N07W17		1		17		470		80		293		67		32		0		194		136		1393
SAN JUAN 32-7 UNIT #246A		12147	SJ 32-7		32N07W18		1		19		1,292		219		806		113		88		0		605		437		1354
SAN JUAN 32-8 UNIT #202A		1495	SJ 32-8		32N08W27		1		16		1,826		208		764		89		83		0		591		454		698
SAN JUAN 32-8 UNIT #203A		1213	SJ 32-8		32N08W33		1		9		399		45		167		29		18		0		120		99		686
SAN JUAN 32-8 UNIT #204A		5142	SJ 32-8		32N08W34		1		15		1,650		187		690		82		75		0		533		414		732
SAN JUAN 32-8 UNIT #205A		1504	SJ 32-8		32N08W34		1		16		1,688		192		706		84		77		0		545		419		680
SAN JUAN 32-8 UNIT #206A		5603	SJ 32-8		31N08W24		1		17		1,300		148		544		73		59		0		412		301		1158
SAN JUAN 32-8 UNIT #207A		5598	SJ 32-8		31N08W22		1		19		1,082		123		453		67		49		0		336		236		1152
SAN JUAN 32-8 UNIT #208A		4275	SJ 32-8		32N08W29		1		18		3,307		376		1,383		142		151		0		1,090		840		726
SAN JUAN 32-8 UNIT #213A		6003	SJ 32-8		32N08W22		1		16		1,950		222		815		93		89		0		633		489		1154
SAN JUAN 32-8 UNIT #218A		1514	SJ 32-8		32N08W35		1		20		2,219		252		928		108		101		0		719		525		691
SAN JUAN 32-8 UNIT #219A		1529	SJ 32-8		32N08W35		1		18		1,292		147		540		73		59		0		408		301		678
SAN JUAN 32-8 UNIT #220A		5602	SJ 32-8		31N08W24		1		14		841		96		352		51		38		0		262		204		1232
SAN JUAN 32-8 UNIT #221A		5583	SJ 32-8		31N08W09		1		7		568		65		238		31		26		0		181		159		1140
SAN JUAN 32-8 UNIT #222A		5584	SJ 32-8		31N08W09		1		18		1,430		163		598		78		65		0		455		339		1139
SAN JUAN 32-8 UNIT #223A		5588	SJ 32-8		31N08W10		1		14		1,461		166		611		73		67		0		472		375		1142
SAN JUAN 32-8 UNIT #224A		5589	SJ 32-8		31N08W10		1		11		827		94		346		46		38		0		262		215		1141
SAN JUAN 32-8 UNIT #225A		5592	SJ 32-8		31N08W15		1		14		814		92		340		50		37		0		253		197		1227
SAN JUAN 32-8 UNIT #226A		5593	SJ 32-8		31N08W15		1		12		670		76		280		42		31		0		208		168		1228
SAN JUAN 32-8 UNIT #227A		5594	SJ 32-8		31N08W16		1		14		646		73		270		46		29		0		195		148		1148
SAN JUAN 32-8 UNIT #228A		5595	SJ 32-8		31N08W16		1		15		966		110		404		58		44		0		302		229		1147
SAN JUAN 32-8 UNIT #229A		1204	SJ 32-8		32N08W20		1		14		1,299		148		543		68		59		0		417		328		660
SAN JUAN 32-8 UNIT #230A		1544	SJ 32-8		32N08W28		1		19		1,880		214		786		95		86		0		606		448		697
SAN JUAN 32-8 UNIT #231A		1541	SJ 32-8		32N08W28		1		30		4,073		463		1,703		188		186		0		1,329		863		677
SAN JUAN 32-8 UNIT #232A		972	SJ 32-8		32N08W29		1		15		1,370		156		573		72		62		0		439		338		665
SAN JUAN 32-8 UNIT #233A		5675	SJ 32-8		32N08W30		1		17		1,349		153		564		73		61		0		429		323		1237
SAN JUAN 32-8 UNIT #234A		4904	SJ 32-8		31N08W21		1		12		515		59		215		37		23		0		155		123		1150
SAN JUAN 32-8 UNIT #235A		5597	SJ 32-8		31N08W21		1		11		468		53		196		33		21		0		141		114		1149
SAN JUAN 32-8 UNIT #236A		5599	SJ 32-8		31N08W22		1		14		550		63		230		42		25		0		163		123		1229
SAN JUAN 32-8 UNIT #237A		5601	SJ 32-8		31N08W23		1		9		297		34		124		25		14		0		86		71		1231
SAN JUAN 32-8 UNIT #238A		5600	SJ 32-8		31N08W23		1		7		237		27		99		19		11		0		69		60		1230
SAN JUAN 32-8 UNIT #239A		5670	SJ 32-8		32N08W30		1		9		467		53		195		31		21		0		144		120		1161
SAN JUAN 32-8 UNIT #240A		5047	SJ 32-8		31N08W03		1		16		1,279		145		535		69		58		0		407		312		997
SAN JUAN 32-8 UNIT #241A		5558	SJ 32-8		31N08W04		1		12		1,174		133		491		60		53		0		377		306		1224
SAN JUAN 32-8 UNIT #242A		5557	SJ 32-8		31N08W04		1		12		917		104		383		51		42		0		291		236		1138
SAN JUAN 32-8 UNIT #243A		1884	SJ 32-8		31N08W11		1		14		1,025		117		429		58		47		0		324		251		679
SAN JUAN 32-8 UNIT #244A		5591	SJ 32-8		31N08W14		1		10		480		55		201		33		22		0		146		119		1226
SAN JUAN 32-8 UNIT #245A		5590	SJ 32-8		31N08W14		1		10		542		62		227		34		25		0		168		139		1225

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 32-8 UNIT #247A		5999	SJ 32-8		32N08W19		1		16		1,953		222		817		92		89		0		636		496		1199
SAN JUAN 32-8 UNIT #248A		1885	SJ 32-8		31N08W11		1		10		354		40		148		28		16		0		104		84		676
SAN JUAN 32-8 UNIT #249R		11696	SJ 32-8		31N08W03		1		7		326		37		136		22		15		0		99		86		1265
SAN JUAN 32-8 UNIT #250A		5048	SJ 32-8		32N08W33		1		15		1,888		215		789		90		86		0		614		480		723
SAN JUAN 32-8 UNIT #253A		1887	SJ 32-8		32N08W27		1		16		1,259		143		527		69		57		0		401		306		699
SAN JUAN 32-8 UNIT #254A		12149	SJ 32-8		32N08W23		1		18		1,692		192		708		87		77		0		544		407		1355
SAN JUAN 32-8 UNIT #255A		1867	SJ 32-8		32N08W24		1		15		1,160		132		485		65		53		0		367		281		701
SAN JUAN 32-8 UNIT #256A		1888	SJ 32-8		32N08W25		1		20		2,087		237		873		104		95		0		674		490		700
SAN JUAN 32-8 UNIT #257A		6000	SJ 32-8		32N08W19		1		7		937		106		392		44		43		0		305		271		1200
SAN JUAN 32-8 UNIT #258A		6001	SJ 32-8		32N08W15		1		19		1,609		183		673		86		73		0		514		369		1438
SAN JUAN 32-8 UNIT #259		6004	SJ 32-8		32N08W22		1		22		2,374		270		993		117		108		0		768		539		1153
SAN JUAN 32-8 UNIT #260A		5998	SJ 32-8		32N08W18		1		11		1,389		158		581		65		63		0		453		380		1370
SAN JUAN 32-8 UNIT #261A		6507	SJ 32-8		32N08W17		1		13		352		40		147		34		16		0		97		73		1202
SAN JUAN 32-8 UNIT #262A		727	SJ 32-8		32N08W17		1		7		381		43		159		24		17		0		117		102		1362
SAN JUAN 32-8 UNIT #264A		11695	SJ 32-8		32N08W09		1		0		2		0		1		1		0		0		0		0		1374
SAN JUAN 32-8 UNIT #267		6005	SJ 32-8		32N08W23		1		22		2,457		279		1,028		120		112		0		796		558		1323
SAN JUAN 32-9 UNIT #104S		5911	SJ 32-9		32N10W24		1		18		1,445		38		139		18		15		0		106		76		1107
SAN JUAN 32-9 UNIT #201S		5935	SJ 32-9		31N09W02		1		7		232		6		22		4		2		0		15		13		1076
SAN JUAN 32-9 UNIT #202S		5939	SJ 32-9		31N09W02		1		12		536		14		51		9		6		0		37		30		1075
SAN JUAN 32-9 UNIT #215S		5992	SJ 32-9		32N09W10		1		17		856		22		82		13		9		0		60		43		1089
SAN JUAN 32-9 UNIT #217S		5994	SJ 32-9		32N09W16		1		9		382		10		37		6		4		0		26		22		1322
SAN JUAN 32-9 UNIT #226S		5970	SJ 32-9		32N09W32		1		7		239		6		23		5		3		0		16		14		1119
SAN JUAN 32-9 UNIT #228S		5978	SJ 32-9		32N09W36		1		4		124		3		12		2		1		0		8		8		1127
SAN JUAN 32-9 UNIT #229S		5933	SJ 32-9		32N10W36		1		10		461		12		44		7		5		0		32		27		1125
SAN JUAN 32-9 UNIT #230S		5934	SJ 32-9		32N10W36		1		6		331		9		32		5		3		0		23		21		1320
SAN JUAN 32-9 UNIT #235S		5979	SJ 32-9		32N09W36		1		7		406		11		39		6		4		0		29		25		1126
SAN JUAN 32-9 UNIT #241S		5993	SJ 32-9		32N09W13		1		22		2,415		63		232		27		25		0		180		126		1441
SAN JUAN 32-9 UNIT #250S		5945	SJ 32-9		31N09W04		1		16		912		24		88		13		10		0		65		48		1240
SAN JUAN 32-9 UNIT #251S		5947	SJ 32-9		31N09W04		1		15		676		18		65		11		7		0		47		35		1321
SAN JUAN 32-9 UNIT #252S		5949	SJ 32-9		31N09W05		1		10		597		16		57		8		6		0		43		36		1080
SAN JUAN 32-9 UNIT #253S		5952	SJ 32-9		31N09W05		1		5		139		4		13		3		1		0		9		8		1079
SAN JUAN 32-9 UNIT #254S		5953	SJ 32-9		31N09W06		1		12		531		14		51		8		6		0		37		29		1082
SAN JUAN 32-9 UNIT #255S		5955	SJ 32-9		31N09W06		1		7		95		2		9		3		1		0		5		4		1081
SAN JUAN 32-9 UNIT #257S		5957	SJ 32-9		31N09W08		1		8		91		2		9		4		1		0		4		3		1083
SAN JUAN 32-9 UNIT #259S		5959	SJ 32-9		31N09W09		1		7		261		7		25		5		3		0		18		15		1085
SAN JUAN 32-9 UNIT #260S		5960	SJ 32-9		31N09W10		1		6		308		8		30		5		3		0		22		19		1088
SAN JUAN 32-9 UNIT #261S		5961	SJ 32-9		31N09W10		1		16		654		17		63		11		7		0		45		34		1087
SAN JUAN 32-9 UNIT #262S		12591	SJ 32-9		31N09W15		1		13		471		12		45		8		5		0		32		24		1443
SAN JUAN 32-9 UNIT #268S		5859	SJ 32-9		31N10W01		1		16		787		21		76		12		8		0		55		41		1314
SAN JUAN 32-9 UNIT #270S		5991	SJ 32-9		32N09W18		1		6		643		17		62		7		7		0		48		43		1103
SAN JUAN 32-9 UNIT #271S		1351	SJ 32-9		32N09W18		1		16		1,377		36		132		17		14		0		101		77		733

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 32-9 UNIT #272S		12611	SJ 32-9		32N09W21		1		17		1,227		32		118		16		13		0		89		65		1447
SAN JUAN 32-9 UNIT #273S		5980	SJ 32-9		32N09W19		1		10		956		25		92		11		10		0		71		59		1104
SAN JUAN 32-9 UNIT #274S		5962	SJ 32-9		32N09W28		1		10		473		12		45		7		5		0		33		27		1113
SAN JUAN 32-9 UNIT #275S		5965	SJ 32-9		32N09W29		1		7		427		11		41		6		4		0		30		26		1114
SAN JUAN 32-9 UNIT #276S		5964	SJ 32-9		32N09W27		1		11		656		17		63		9		7		0		47		39		1112
SAN JUAN 32-9 UNIT #277S		5966	SJ 32-9		32N09W30		1		16		683		18		66		11		7		0		47		35		1115
SAN JUAN 32-9 UNIT #278S		5967	SJ 32-9		32N09W31		1		9		345		9		33		6		4		0		23		19		1117
SAN JUAN 32-9 UNIT #279S		5968	SJ 32-9		32N09W31		1		6		235		6		23		4		2		0		16		14		1116
SAN JUAN 32-9 UNIT #281S		5974	SJ 32-9		32N09W32		1		8		299		8		29		5		3		0		20		17		1118
SAN JUAN 32-9 UNIT #282S		5975	SJ 32-9		32N09W33		1		4		71		2		7		2		1		0		4		4		1121
SAN JUAN 32-9 UNIT #283S		5976	SJ 32-9		32N09W33		1		8		370		10		36		6		4		0		26		22		1120
SAN JUAN 32-9 UNIT #284S		1357	SJ 32-9		32N10W13		1		13		1,089		28		105		13		11		0		80		64		998
SAN JUAN 32-9 UNIT #285S		5855	SJ 32-9		32N10W13		1		18		1,472		38		141		18		15		0		108		78		1096
SAN JUAN 32-9 UNIT #286S		5914	SJ 32-9		32N10W14		1		8		794		21		76		9		8		0		59		51		1098
SAN JUAN 32-9 UNIT #287S		5915	SJ 32-9		32N10W14		1		7		561		15		54		7		6		0		41		37		1097
SAN JUAN 32-9 UNIT #288S		5916	SJ 32-9		32N10W23		1		18		1,445		38		139		18		15		0		106		76		1106
SAN JUAN 32-9 UNIT #289S		5918	SJ 32-9		32N10W23		1		3		132		3		13		2		1		0		9		8		1105
SAN JUAN 32-9 UNIT #291S		5402	SJ 32-9		32N10W24		1		17		1,287		34		124		16		13		0		94		71		728
SAN JUAN 32-9 UNIT #292S		5925	SJ 32-9		32N10W25		1		11		653		17		63		9		7		0		47		38		1109
SAN JUAN 32-9 UNIT #293S		5927	SJ 32-9		32N10W25		1		13		746		19		72		11		8		0		53		41		1108
SAN JUAN 32-9 UNIT #294S		5930	SJ 32-9		32N10W26		1		6		219		6		21		4		2		0		15		13		1111
SAN JUAN 32-9 UNIT #295S		5931	SJ 32-9		32N10W26		1		12		454		12		44		8		5		0		31		25		1110
SAN JUAN 32-9 UNIT #300S		5856	SJ 32-9		32N10W11		1		6		399		10		38		5		4		0		29		26		1092
SAN JUAN 32-9 UNIT #301S		5857	SJ 32-9		32N10W12		1		10		558		15		54		8		6		0		40		33		1095
SAN JUAN 32-9 UNIT #302S		12613	SJ 32-9		32N09W09		1		13		1,599		42		154		17		17		0		119		96		1368
SEYMOUR #720S		12603	NON-UNIT		31N09W23		1		15		504		37		136		28		15		0		93		69		1134
STATE COM FC #20A		6006	NON-UNIT		30N08W02		1		11		412		7		27		5		3		0		19		15		1069
NE BLANCO UNIT #416A		5282	NEBU		31N07W21		1		19		1,100		9		31		4		3		0		24		17		1063
NE BLANCO UNIT #466A		6027	NEBU		31N07W34		1		18		1,400		11		40		5		4		0		31		22		1059
SAN JUAN 32-7 UNIT #240A		717	SJ 32-7		32N07W19		1		20		2,000		339		1,248		153		136		0		959		680		1452
SAN JUAN 32-9 UNIT #297S		5854	SJ 32-9		32N10W35		1		18		1,000		26		96		14		10		0		71		49		1122
TOTAL PROVED DEVELOPED: 160-Acre New Mexico							406				286,052		25,236		92,868		13,439		10,115		0		69,314		53,022
ALLISON UNIT COM #105		13888	SJ 32-7		32N07W26		1		17		1,588		67		248		31		27		0		190		143		1406
ALLISON UNIT COM #146		4750	SJ 32-7		32N07W26		1		15		1,357		115		423		54		46		0		323		250		1384
BARNES GAS COM F #1		14369	NON-UNIT		32N11W23		1		8		63		4		13		7		1		0		4		3		474
BLANCO #201		13592	NON-UNIT		31N08W35		1		19		1,412		208		767		105		84		0		579		416		413
BLANCO #202		13651	NON-UNIT		31N08W26		1		30		2,417		357		1,313		172		143		0		998		626		509
BLANCO #203		13649	NON-UNIT		31N08W35		1		16		739		109		401		67		44		0		291		216		498
BLANCO #204R		14451	NON-UNIT		31N08W26		1		19		1,006		149		547		86		60		0		401		284		591
BLANCO #330		14219	NON-UNIT		31N08W05		1		18		1,643		120		442		56		48		0		337		249		547
BONDS COM #100		14220	NON-UNIT		32N10W15		1		30		4,493		223		822		86		90		0		647		426		455

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
CAT DRAW COM #101		20070	SJ 30-5		30N05W29		1		18		1,698		80		295		35		32		0		227		170		1466
DECKER GAS COM A #1		14370	NON-UNIT		32N10W17		1		18		1,604		117		431		54		47		0		330		246		477
EAGLE #750 (APO)		14375	NON-UNIT		32N09W16		1		14		909		18		66		9		7		0		50		39		495
FC BARNES #1		14371	NON-UNIT		32N11W15		1		23		493		9		32		11		3		0		17		10		418
FC FEE COM #2		14277	NON-UNIT		32N11W30		1		4		31		1		2		2		0		0		0		0		497
FC STATE COM #19		14276	NON-UNIT		30N09W36		1		18		165		3		12		6		1		0		5		3		541
FC STATE COM #20		12651	NON-UNIT		30N08W02		1		18		1,277		23		84		12		9		0		63		47		466
FEDERAL G #4 COM		4755	NON-UNIT		31N07W10		1		12		439		18		67		13		7		0		47		37		467
GRASSY CANYON UNIT #3		4762	SJ 32-7		32N07W31		1		24		2,080		134		494		63		54		0		377		256		580
HEIZER #100		14203	NON-UNIT		32N10W15		1		17		2,153		1		4		0		0		0		3		2		378
HUBBARD GAS COM A #1		14250	NON-UNIT		32N11W30		1		8		78		3		10		6		1		0		3		2		496
HUERFANO UNIT #118 COM		4765	HUERFANO		27N10W30		1		12		181		13		47		15		5		0		27		20		366
HUERFANO UNIT #12		14215	HUERFANO		26N10W04		1		1		3		0		2		1		0		0		0		0		352
HUERFANO UNIT #138		17003	HUERFANO		26N09W22		1		4		29		4		15		9		2		0		4		4		350
HUERFANO UNIT #14R		14218	HUERFANO		26N10W05		1		18		308		43		160		49		17		0		94		63		362
HUERFANO UNIT #18 COM		16974	HUERFANO		27N10W32		1		0		0		0		0		0		0		0		0		0		355
HUERFANO UNIT #182		17019	HUERFANO		26N09W28		1		0		0		0		0		0		0		0		0		0		360
HUERFANO UNIT #19		14221	HUERFANO		26N10W05		1		4		33		5		17		9		2		0		7		6		354
HUERFANO UNIT #22		14216	HUERFANO		27N10W33		1		25		387		55		201		64		22		0		115		68		356
HUERFANO UNIT #223		14004	HUERFANO		26N10W04		1		17		274		39		143		44		16		0		83		57		363
HUERFANO UNIT #231		17004	HUERFANO		26N09W06		1		22		468		66		243		62		27		0		155		99		364
HUERFANO UNIT #237		17005	HUERFANO		26N09W17		1		20		295		42		153		51		17		0		86		55		365
HUERFANO UNIT #24		14222	HUERFANO		27N10W29		1		7		78		11		41		17		4		0		19		16		357
HUERFANO UNIT #255		17006	HUERFANO		27N09W31		1		36		1,081		153		562		116		61		0		385		203		369
HUERFANO UNIT #257		17007	HUERFANO		27N10W36		1		35		850		120		442		103		48		0		292		154		367
HUERFANO UNIT #258S		2326	HUERFANO		27N10W36		1		14		296		42		154		40		17		0		97		71		1191
HUERFANO UNIT #259		13989	HUERFANO		26N10W06		1		6		50		7		26		13		3		0		10		9		368
HUERFANO UNIT #282		14512	HUERFANO		27N10W31		1		17		348		49		181		48		20		0		113		78		372
HUERFANO UNIT #286		14202	HUERFANO		27N10W35		1		32		575		81		299		86		33		0		180		96		374
HUERFANO UNIT #46		13951	HUERFANO		26N09W23		1		21		460		65		239		61		26		0		153		98		349
HUERFANO UNIT #500		17008	HUERFANO		26N09W20		1		1		3		0		2		1		0		0		0		0		603
HUERFANO UNIT #501		17009	HUERFANO		26N09W20		1		18		449		63		234		54		25		0		154		105		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		4		39		5		20		10		2		0		8		7		601
HUERFANO UNIT #504		17011	HUERFANO		26N09W22		1		3		27		4		14		7		2		0		5		5		608
HUERFANO UNIT #505		17012	HUERFANO		26N09W30		1		36		839		119		437		104		48		0		285		148		600
HUERFANO UNIT #507		17013	HUERFANO		26N09W27		1		21		397		56		207		56		23		0		128		83		604
HUERFANO UNIT #508		13985	HUERFANO		26N09W26		1		36		887		125		462		107		50		0		304		157		605
HUERFANO UNIT #509		13999	HUERFANO		27N10W30		1		7		69		10		36		16		4		0		16		14		607
HUERFANO UNIT #518		17014	HUERFANO		26N09W16		1		28		491		69		255		75		28		0		152		85		609
HUERFANO UNIT #520		17015	HUERFANO		26N09W17		1		25		406		57		211		65		23		0		124		74		610

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
HUERFANO UNIT #521		17016	HUERFANO		27N10W35		1		40		1,171		166		609		126		66		0		417		210		612
HUERFANO UNIT #522		17017	HUERFANO		27N09W31		1		38		1,191		168		619		123		67		0		429		224		611
HUERFANO UNIT #523		14008	HUERFANO		26N09W23		1		25		509		72		265		70		29		0		166		100		613
HUERFANO UNIT #528		12464	HUERFANO		26N10W06		1		16		190		27		99		38		11		0		50		35		620
HUERFANO UNIT #549		13950	HUERFANO		27N10W33		1		18		361		51		188		50		20		0		117		79		598
HUERFANO UNIT #55		14223	HUERFANO		26N09W27		1		10		115		16		60		25		7		0		28		22		347
HUERFANO UNIT #550		17018	HUERFANO		27N10W29		1		19		263		37		137		48		15		0		74		48		606
HUERFANO UNIT #551 COM		4766	HUERFANO		26N09W16		1		15		232		12		45		15		5		0		26		18		626
HUERFANO UNIT #59		13952	HUERFANO		26N09W26		1		7		49		7		25		15		3		0		8		6		348
HUERFANO UNIT #6		14377	HUERFANO		27N10W31		1		15		252		36		131		40		14		0		77		55		359
HUERFANO UNIT #600		706	HUERFANO		27N10W32		1		10		120		17		62		24		7		0		31		24		673
HUERFANO UNIT #70		14224	HUERFANO		26N10W08		1		10		100		14		52		24		6		0		23		18		351
HUERFANO UNIT #74		13988	HUERFANO		27N10W19		1		2		9		1		5		3		0		0		1		1		358
JAQUEZ #331		14343	NON-UNIT		31N08W06		1		23		2,084		159		585		69		64		0		453		315		530
KEYS GAS COM G #1R		14212	NON-UNIT		32N10W27		1		12		420		1		2		0		0		0		2		1		375
MIDDLE MESA COM #3		4768	SJ 32-7		32N07W33		1		16		1,476		64		237		30		26		0		182		140		1385
MOORE, WAYNE COM #2		14442	NON-UNIT		31N09W16		1		22		928		34		127		22		14		0		91		61		578
NE BLANCO UNIT #400R		14350	NEBU		31N06W07		1		21		1,824		14		52		6		6		0		41		29		550
NE BLANCO UNIT #401		14278	NEBU		30N07W09		1		17		1,141		9		33		4		4		0		25		19		34
NE BLANCO UNIT #402		13561	NEBU		30N07W05		1		24		1,967		15		56		7		6		0		44		30		376
NE BLANCO UNIT #403R		14279	NEBU		30N07W09		1		22		1,531		12		44		5		5		0		34		23		189
NE BLANCO UNIT #404R		14280	NEBU		31N07W34		1		15		1,116		9		32		4		3		0		25		19		561
NE BLANCO UNIT #406		13560	NEBU		31N07W22		1		25		1,833		14		52		6		6		0		41		27		377
NE BLANCO UNIT #407		14281	NEBU		30N07W21		1		27		1,700		13		49		6		5		0		37		24		36
NE BLANCO UNIT #408		13562	NEBU		31N07W20		1		17		827		6		24		3		3		0		18		13		406
NE BLANCO UNIT #409		14282	NEBU		30N07W10		1		18		1,105		9		32		4		3		0		24		18		35
NE BLANCO UNIT #410		14283	NEBU		31N07W09		1		16		1,097		9		31		4		3		0		24		18		421
NE BLANCO UNIT #411		14284	NEBU		30N07W10		1		26		1,490		12		43		6		5		0		32		21		78
NE BLANCO UNIT #412		14285	NEBU		31N07W29		1		15		1,047		8		30		4		3		0		23		18		408
NE BLANCO UNIT #413R		14286	NEBU		30N07W20		1		20		1,045		8		30		4		3		0		23		16		257
NE BLANCO UNIT #414		13569	NEBU		31N07W30		1		18		1,122		9		32		4		3		0		25		18		403
NE BLANCO UNIT #415		14287	NEBU		30N07W02		1		25		1,347		10		39		5		4		0		29		19		71
NE BLANCO UNIT #416		13563	NEBU		31N07W21		1		19		627		5		18		3		2		0		13		9		395
NE BLANCO UNIT #417		14288	NEBU		30N07W02		1		31		2,767		22		79		9		9		0		62		39		72
NE BLANCO UNIT #418		14289	NEBU		31N07W28		1		13		721		6		21		3		2		0		16		12		410
NE BLANCO UNIT #419		14290	NEBU		30N07W03		1		20		1,379		11		39		5		4		0		30		22		77
NE BLANCO UNIT #420		13564	NEBU		31N07W28		1		0		0		0		0		0		0		0		0		0		394
NE BLANCO UNIT #421R		14291	NEBU		30N07W04		1		17		1,210		9		35		4		4		0		27		20		151
NE BLANCO UNIT #422		13570	NEBU		31N07W20		1		20		1,061		8		30		4		3		0		23		16		397
NE BLANCO UNIT #423R		14292	NEBU		30N07W08		1		16		1,080		8		31		4		3		0		24		18		286
NE BLANCO UNIT #424		14293	NEBU		30N07W04		1		22		1,935		15		55		6		6		0		43		30		385

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
NE BLANCO UNIT #425R		14294	NEBU		30N07W08		1		29		2,718		21		78		8		8		0		61		40		169
NE BLANCO UNIT #426		14262	NEBU		31N06W06		1		24		1,750		14		50		6		5		0		39		26		440
NE BLANCO UNIT #427R		14295	NEBU		30N07W16		1		15		685		5		20		3		2		0		15		11		194
NE BLANCO UNIT #428		13571	NEBU		31N07W24		1		16		1,066		8		31		4		3		0		23		18		420
NE BLANCO UNIT #429R		14296	NEBU		30N07W17		1		10		369		3		11		2		1		0		8		6		226
NE BLANCO UNIT #430		13565	NEBU		30N07W05		1		15		582		5		17		3		2		0		12		9		398
NE BLANCO UNIT #431		14297	NEBU		30N07W17		1		30		2,334		18		67		8		7		0		52		32		74
NE BLANCO UNIT #432		13566	NEBU		30N07W07		1		23		1,829		14		52		6		6		0		41		28		399
NE BLANCO UNIT #433		14298	NEBU		30N07W19		1		12		206		2		6		2		1		0		4		3		76
NE BLANCO UNIT #434		14299	NEBU		31N07W23		1		22		2,236		17		64		7		7		0		50		36		423
NE BLANCO UNIT #435		14300	NEBU		30N08W01		1		21		906		7		26		4		3		0		19		13		383
NE BLANCO UNIT #436		13572	NEBU		31N06W19		1		18		910		7		26		4		3		0		20		14		425
NE BLANCO UNIT #437		14301	NEBU		30N08W12		1		22		815		6		23		4		3		0		17		11		382
NE BLANCO UNIT #438		14361	NEBU		31N06W18		1		23		1,006		8		29		4		3		0		21		14		452
NE BLANCO UNIT #439		14302	NEBU		30N08W13		1		29		2,596		20		74		8		8		0		58		38		380
NE BLANCO UNIT #440		13573	NEBU		31N07W11		1		19		1,147		9		33		4		4		0		25		18		431
NE BLANCO UNIT #441R		14303	NEBU		30N08W24		1		30		1,457		11		42		6		5		0		31		19		475
NE BLANCO UNIT #442		14304	NEBU		31N07W11		1		19		1,136		9		33		4		4		0		25		18		436
NE BLANCO UNIT #443		14305	NEBU		30N08W24		1		29		1,333		10		38		6		4		0		28		17		381
NE BLANCO UNIT #444		14362	NEBU		31N07W23		1		12		493		4		14		2		2		0		10		8		461
NE BLANCO UNIT #445		14306	NEBU		31N08W25		1		25		1,414		11		40		5		4		0		31		20		388
NE BLANCO UNIT #446		14307	NEBU		31N07W33		1		18		527		4		15		3		2		0		11		7		400
NE BLANCO UNIT #447		14308	NEBU		31N08W36		1		17		602		5		17		3		2		0		12		9		379
NE BLANCO UNIT #448		13567	NEBU		31N07W32		1		16		752		6		22		3		2		0		16		12		384
NE BLANCO UNIT #449		14309	NEBU		31N07W19		1		20		773		6		22		4		2		0		16		11		391
NE BLANCO UNIT #450		14310	NEBU		31N07W32		1		15		588		5		17		3		2		0		12		9		389
NE BLANCO UNIT #451		14311	NEBU		30N07W06		1		25		1,478		12		42		6		5		0		32		21		405
NE BLANCO UNIT #452		13574	NEBU		31N07W15		1		4		88		1		3		1		0		0		2		1		422
NE BLANCO UNIT #453		14312	NEBU		30N07W06		1		23		1,314		10		38		5		4		0		29		19		390
NE BLANCO UNIT #454		14313	NEBU		31N07W33		1		20		1,420		11		41		5		4		0		31		23		409
NE BLANCO UNIT #455		14314	NEBU		31N07W31		1		25		2,612		20		75		8		8		0		59		40		387
NE BLANCO UNIT #456		13575	NEBU		31N07W26		1		10		346		3		10		2		1		0		7		6		417
NE BLANCO UNIT #457		14315	NEBU		31N07W31		1		19		1,077		8		31		4		3		0		23		17		392
NE BLANCO UNIT #458		13576	NEBU		31N07W13		1		11		437		3		13		2		1		0		9		7		416
NE BLANCO UNIT #459		14316	NEBU		31N07W19		1		31		3,238		25		93		10		10		0		73		46		415
NE BLANCO UNIT #460		14351	NEBU		31N06W07		1		21		1,818		14		52		6		6		0		40		29		424
NE BLANCO UNIT #461		14317	NEBU		30N07W07		1		20		860		7		25		4		3		0		18		13		543
NE BLANCO UNIT #462		14318	NEBU		31N07W01		1		21		1,948		15		56		6		6		0		44		31		428
NE BLANCO UNIT #463		14319	NEBU		30N07W18		1		21		816		6		23		4		3		0		17		11		411
NE BLANCO UNIT #464		13577	NEBU		31N07W10		1		13		518		4		15		2		2		0		11		8		429
NE BLANCO UNIT #465		14320	NEBU		30N08W01		1		16		1,021		8		29		4		3		0		22		17		404

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
NE BLANCO UNIT #466		14321	NEBU		31N07W34		1		15		893		7		26		3		3		0		19		15		462
NE BLANCO UNIT #467		14322	NEBU		30N08W12		1		16		548		4		16		3		2		0		11		8		407
NE BLANCO UNIT #468		14323	NEBU		31N07W35		1		20		1,212		9		35		4		4		0		26		19		457
NE BLANCO UNIT #469		14324	NEBU		30N08W13		1		25		2,626		20		75		8		8		0		59		40		393
NE BLANCO UNIT #470		14352	NEBU		31N07W27		1		19		741		6		21		3		2		0		15		11		438
NE BLANCO UNIT #471		14325	NEBU		31N08W25		1		20		1,548		12		44		5		5		0		34		25		402
NE BLANCO UNIT #472		14326	NEBU		31N07W29		1		13		505		4		14		2		2		0		11		8		401
NE BLANCO UNIT #473		14327	NEBU		31N08W36		1		22		2,393		19		69		7		7		0		54		39		396
NE BLANCO UNIT #474		14353	NEBU		31N07W26		1		12		403		3		12		2		1		0		8		7		437
NE BLANCO UNIT #475		14328	NEBU		30N07W19		1		16		547		4		16		3		2		0		11		8		298
NE BLANCO UNIT #476		14329	NEBU		31N07W22		1		21		1,513		12		43		5		5		0		33		23		435
NE BLANCO UNIT #477		14379	NEBU		30N07W29		1		14		379		3		11		2		1		0		8		6		93
NE BLANCO UNIT #478		14330	NEBU		31N07W21		1		19		1,215		9		35		4		4		0		27		19		386
NE BLANCO UNIT #479R		13942	NEBU		30N07W20		1		22		1,365		11		39		5		4		0		30		21		334
NE BLANCO UNIT #480		14332	NEBU		31N07W14		1		19		1,176		9		34		4		4		0		26		18		463
NE BLANCO UNIT #481		14333	NEBU		31N07W36		1		16		836		7		24		3		3		0		18		14		86
NE BLANCO UNIT #482		14334	NEBU		31N07W15		1		20		1,819		14		52		6		6		0		41		29		439
NE BLANCO UNIT #483		14335	NEBU		31N07W36		1		12		418		3		12		2		1		0		9		7		85
NE BLANCO UNIT #484		14336	NEBU		31N07W16		1		12		426		3		12		2		1		0		9		7		430
NE BLANCO UNIT #485		14337	NEBU		30N07W03		1		14		792		6		23		3		2		0		17		13		131
NE BLANCO UNIT #486		14338	NEBU		31N06W19		1		17		1,481		12		42		5		5		0		33		25		472
NE BLANCO UNIT #487		14339	NEBU		31N07W35		1		30		2,868		22		82		9		9		0		64		41		464
NE BLANCO UNIT #488		14340	NEBU		31N07W24		1		20		2,067		16		59		6		6		0		46		34		458
NE BLANCO UNIT #489		14364	NEBU		31N07W12		1		9		181		1		5		1		1		0		3		3		456
NE BLANCO UNIT #490		14363	NEBU		31N07W14		1		14		783		6		22		3		2		0		17		13		434
NE BLANCO UNIT #491		14368	NEBU		31N07W25		1		15		537		4		15		3		2		0		11		8		152
NE BLANCO UNIT #492		14354	NEBU		31N07W12		1		16		935		7		27		4		3		0		20		15		453
NE BLANCO UNIT #493		14380	NEBU		31N07W25		1		16		700		5		20		3		2		0		15		11		143
NE BLANCO UNIT #494		14341	NEBU		31N07W27		1		24		1,107		9		32		5		3		0		24		16		465
NE BLANCO UNIT #495		14381	NEBU		31N06W30		1		18		895		7		26		4		3		0		19		14		144
NE BLANCO UNIT #496		14355	NEBU		31N06W18		1		15		928		7		27		3		3		0		20		16		459
NE BLANCO UNIT #497		14382	NEBU		31N06W30		1		21		1,064		8		30		4		3		0		23		16		146
NE BLANCO UNIT #498		14365	NEBU		31N07W13		1		16		982		8		28		4		3		0		21		16		460
NE BLANCO UNIT #499		14383	NEBU		31N06W20		1		24		1,689		13		48		6		5		0		37		25		179
NE BLANCO UNIT #500		14356	NEBU		31N06W20		1		29		1,870		15		54		7		6		0		41		26		454
NE BLANCO UNIT #504		14342	NEBU		31N07W16		1		15		808		6		23		3		3		0		17		13		513
NE BLANCO UNIT #505		14384	NEBU		30N07W21		1		31		1,717		13		49		7		5		0		37		23		319
NORDHAUS #716		14360	NON-UNIT		31N09W13		1		25		1,985		144		531		71		58		0		403		268		549
PAYNE #201		14225	NON-UNIT		32N10W20		1		13		621		11		42		7		5		0		30		23		546
QUINN #336		14226	NON-UNIT		31N08W17		1		14		808		59		218		33		24		0		161		125		451
RATTLESNAKE CANYON #105		4770	SJ 32-8		32N08W20		1		16		1,802		77		283		33		31		0		219		170		1387

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 28-5 UNIT #219		13793	SJ 28-5		28N05W30		1		14		117		48		177		96		19		0		62		43		245
SAN JUAN 28-5 UNIT #223		13740	SJ 28-5		28N05W34		1		0		0		0		0		0		0		0		0		0		246
SAN JUAN 28-6 UNIT #230		19631	SJ 28-6		27N06W06		1		4		28		2		6		4		1		0		1		1		1376
SAN JUAN 28-6 UNIT #232		19627	SJ 28-6		27N06W07		1		7		49		3		10		6		1		0		3		2		1375
SAN JUAN 28-6 UNIT #400		13883	SJ 28-6		28N06W09		1		21		238		13		49		21		5		0		23		14		98
SAN JUAN 28-6 UNIT #404		14227	SJ 28-6		28N06W13		1		6		38		16		59		42		6		0		10		8		124
SAN JUAN 28-6 UNIT #405		13884	SJ 28-6		28N06W18		1		13		154		9		32		13		3		0		16		12		153
SAN JUAN 28-6 UNIT #406		13885	SJ 28-6		28N06W19		1		24		307		17		64		24		7		0		33		19		112
SAN JUAN 28-6 UNIT #410		14228	SJ 28-6		28N06W13		1		0		0		0		0		0		0		0		0		0		214
SAN JUAN 28-6 UNIT #414		13886	SJ 28-6		28N06W08		1		19		222		13		46		19		5		0		22		14		260
SAN JUAN 28-6 UNIT #418		13757	SJ 28-6		28N06W28		1		5		37		2		8		5		1		0		2		2		297
SAN JUAN 28-6 UNIT #421		13758	SJ 28-6		28N06W33		1		8		98		6		20		8		2		0		10		8		247
SAN JUAN 28-6 UNIT #433		14387	SJ 28-6		28N06W24		1		14		166		0		0		0		0		0		0		0		288
SAN JUAN 28-6 UNIT #436		14347	SJ 28-6		28N06W16		1		22		306		17		64		23		7		0		34		21		277
SAN JUAN 28-6 UNIT #437		14456	SJ 28-6		28N06W28		1		8		70		4		15		7		2		0		6		5		309
SAN JUAN 28-6 UNIT #438		14348	SJ 28-6		28N06W15		1		16		148		23		83		40		9		0		34		23		293
SAN JUAN 28-6 UNIT #439		14388	SJ 28-6		28N06W29		1		11		111		34		127		60		14		0		53		40		248
SAN JUAN 28-6 UNIT #440		13759	SJ 28-6		28N06W16		1		11		162		9		34		11		4		0		19		15		276
SAN JUAN 28-6 UNIT #441		14389	SJ 28-6		28N06W17		1		19		237		13		49		19		5		0		25		16		296
SAN JUAN 28-6 UNIT #448		13760	SJ 28-6		28N06W15		1		5		31		5		17		12		2		0		4		3		228
SAN JUAN 28-6 UNIT #449		13761	SJ 28-6		27N06W02		1		9		71		7		27		16		3		0		8		7		218
SAN JUAN 28-6 UNIT #455		13719	SJ 28-6		28N06W17		1		11		84		13		47		26		5		0		16		12		278
SAN JUAN 28-6 UNIT #456		14229	SJ 28-6		28N06W19		1		10		106		16		59		26		6		0		27		21		243
SAN JUAN 28-6 UNIT #457		13720	SJ 28-6		28N06W20		1		13		102		16		57		33		6		0		18		13		279
SAN JUAN 28-6 UNIT #458		14263	SJ 28-6		28N06W20		1		15		213		12		44		16		5		0		24		17		231
SAN JUAN 28-6 UNIT #459		13733	SJ 28-6		28N06W21		1		40		1,053		60		219		50		24		0		146		69		280
SAN JUAN 28-6 UNIT #460		13721	SJ 28-6		28N06W21		1		20		252		14		53		20		6		0		27		17		294
SAN JUAN 28-6 UNIT #461		13762	SJ 28-6		28N06W22		1		27		332		51		186		73		20		0		93		51		266
SAN JUAN 28-6 UNIT #462		13732	SJ 28-6		28N06W22		1		20		241		37		135		53		15		0		67		42		295
SAN JUAN 28-6 UNIT #467		13724	SJ 28-6		28N06W34		1		29		603		34		125		33		14		0		78		44		282
SAN JUAN 28-6 UNIT #474		13723	SJ 28-6		28N06W27		1		25		281		16		59		25		6		0		28		16		281
SAN JUAN 28-6 UNIT #475		13887	SJ 28-6		28N06W29		1		28		480		27		100		31		11		0		58		33		289
SAN JUAN 29-5 UNIT #201		14367	SJ 29-5		29N05W27		1		11		65		0		0		0		0		0		0		0		267
SAN JUAN 29-5 UNIT #203		13547	SJ 29-5		29N05W06		1		15		820		106		390		60		42		0		288		218		122
SAN JUAN 29-5 UNIT #213		13597	SJ 29-5		29N05W22		1		34		759		98		361		92		39		0		230		121		136
SAN JUAN 29-5 UNIT #217		13763	SJ 29-5		29N05W34		1		5		32		0		0		0		0		0		0		0		268
SAN JUAN 29-5 UNIT #219		14398	SJ 29-5		29N05W04		1		19		412		53		196		51		21		0		124		83		304
SAN JUAN 29-5 UNIT #223		13653	SJ 29-5		29N05W33		1		3		27		4		13		7		1		0		5		4		241
SAN JUAN 29-5 UNIT #225		14391	SJ 29-5		29N05W06		1		7		117		15		56		18		6		0		31		26		305
SAN JUAN 29-5 UNIT #226		14392	SJ 29-5		29N05W07		1		23		644		83		306		67		33		0		205		130		302
SAN JUAN 29-5 UNIT #230		14405	SJ 29-5		29N05W05		1		24		976		126		464		81		51		0		332		215		326

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 29-5 UNIT #231		14393	SJ 29-5		29N05W05		1		1		6		1		3		3		0		0		0		0		301
SAN JUAN 29-6 UNIT #201		13589	SJ 29-6		29N06W06		1		26		2,118		278		1,022		129		111		0		781		518		132
SAN JUAN 29-6 UNIT #202		13654	SJ 29-6		29N06W06		1		17		748		98		361		60		39		0		262		191		235
SAN JUAN 29-6 UNIT #203		13684	SJ 29-6		29N06W07		1		15		791		104		381		58		42		0		281		212		180
SAN JUAN 29-6 UNIT #204		13655	SJ 29-6		29N06W07		1		9		316		41		152		28		17		0		108		90		207
SAN JUAN 29-6 UNIT #205		13685	SJ 29-6		29N06W21		1		25		1,581		207		763		106		83		0		573		379		250
SAN JUAN 29-6 UNIT #206		13548	SJ 29-6		29N06W04		1		27		1,080		142		521		90		57		0		374		233		117
SAN JUAN 29-6 UNIT #207		13549	SJ 29-6		29N06W02		1		24		1,933		253		932		118		102		0		712		484		115
SAN JUAN 29-6 UNIT #208		13587	SJ 29-6		29N06W17		1		16		1,513		198		730		87		79		0		563		433		133
SAN JUAN 29-6 UNIT #209		13588	SJ 29-6		29N06W17		1		20		974		128		470		75		51		0		344		238		126
SAN JUAN 29-6 UNIT #210		14394	SJ 29-6		29N06W20		1		26		2,338		306		1,128		138		123		0		867		575		182
SAN JUAN 29-6 UNIT #211		14395	SJ 29-6		29N06W20		1		24		1,046		137		504		84		55		0		365		238		174
SAN JUAN 29-6 UNIT #213		13590	SJ 29-6		29N06W30		1		8		69		9		33		17		4		0		13		10		127
SAN JUAN 29-6 UNIT #214		13595	SJ 29-6		29N06W03		1		10		263		35		127		28		14		0		85		68		137
SAN JUAN 29-6 UNIT #215		13599	SJ 29-6		29N06W03		1		16		545		71		263		50		29		0		184		135		175
SAN JUAN 29-6 UNIT #216		13596	SJ 29-6		29N06W04		1		13		465		61		224		41		24		0		159		124		138
SAN JUAN 29-6 UNIT #217		13612	SJ 29-6		29N06W05		1		25		2,561		336		1,235		145		135		0		956		646		193
SAN JUAN 29-6 UNIT #218		13605	SJ 29-6		29N06W05		1		10		369		48		178		32		19		0		126		103		181
SAN JUAN 29-6 UNIT #219		13593	SJ 29-6		29N06W10		1		22		1,110		145		535		83		58		0		394		266		139
SAN JUAN 29-6 UNIT #220		13600	SJ 29-6		29N06W11		1		20		550		72		265		58		29		0		178		120		165
SAN JUAN 29-6 UNIT #221		13601	SJ 29-6		29N06W11		1		17		741		97		357		61		39		0		258		186		159
SAN JUAN 29-6 UNIT #222		13718	SJ 29-6		29N06W12		1		27		1,017		133		491		89		53		0		348		213		183
SAN JUAN 29-6 UNIT #223		13611	SJ 29-6		29N06W12		1		25		1,355		178		654		99		71		0		484		313		160
SAN JUAN 29-6 UNIT #224		13696	SJ 29-6		29N06W13		1		14		530		69		256		45		28		0		183		140		184
SAN JUAN 29-6 UNIT #225R		13947	SJ 29-6		29N06W13		1		0		0		0		0		0		0		0		0		0		332
SAN JUAN 29-6 UNIT #226		14396	SJ 29-6		29N06W14		1		24		2,469		324		1,191		140		130		0		921		631		154
SAN JUAN 29-6 UNIT #227		13765	SJ 29-6		29N06W14		1		2		9		1		4		3		0		0		0		0		155
SAN JUAN 29-6 UNIT #229		13766	SJ 29-6		29N06W35		1		21		280		37		135		50		15		0		71		44		162
SAN JUAN 29-6 UNIT #230		13602	SJ 29-6		29N06W35		1		17		219		8		30		12		3		0		15		10		140
SAN JUAN 29-6 UNIT #231		13594	SJ 29-6		29N06W36		1		0		0		0		0		0		0		0		0		0		141
SAN JUAN 29-6 UNIT #233		13767	SJ 29-6		29N06W26		1		14		247		28		103		31		11		0		60		44		176
SAN JUAN 29-6 UNIT #235		14513	SJ 29-6		29N06W34		1		29		456		60		220		71		24		0		125		69		208
SAN JUAN 29-6 UNIT #236		13694	SJ 29-6		29N06W18		1		24		1,190		156		574		90		63		0		422		278		177
SAN JUAN 29-6 UNIT #237		13674	SJ 29-6		29N06W01		1		13		417		55		201		40		22		0		139		106		197
SAN JUAN 29-6 UNIT #238		13675	SJ 29-6		29N06W01		1		11		268		35		129		30		14		0		85		68		198
SAN JUAN 29-6 UNIT #239		13676	SJ 29-6		29N06W02		1		13		472		62		228		42		25		0		161		125		170
SAN JUAN 29-6 UNIT #240		13686	SJ 29-6		29N06W18		1		24		1,667		219		804		108		88		0		609		410		251
SAN JUAN 29-6 UNIT #241		13687	SJ 29-6		29N06W19		1		30		1,828		240		882		126		96		0		660		403		252
SAN JUAN 29-6 UNIT #242		13688	SJ 29-6		29N06W19		1		31		1,828		240		882		127		96		0		659		399		178
SAN JUAN 29-6 UNIT #243		13768	SJ 29-6		29N06W31		1		17		163		6		22		11		2		0		9		6		255
SAN JUAN 29-6 UNIT #245		13667	SJ 29-6		29N06W08		1		20		1,006		132		485		75		53		0		357		250		242

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 29-6 UNIT #246		14397	SJ 29-6		29N06W08		1		3		23		3		11		7		1		0		3		3		209
SAN JUAN 29-6 UNIT #247R		13814	SJ 29-6		29N06W10		1		16		386		51		186		43		20		0		123		88		338
SAN JUAN 29-6 UNIT #249		13796	SJ 29-6		29N06W22		1		5		31		4		15		10		2		0		3		3		323
SAN JUAN 29-6 UNIT #251		13803	SJ 29-6		29N06W23		1		6		35		5		19		13		2		0		4		3		317
SAN JUAN 29-6 UNIT #257R		13815	SJ 29-6		29N06W09		1		23		918		120		443		77		48		0		318		210		339
SAN JUAN 29-6 UNIT #258		13695	SJ 29-6		29N06W16		1		22		1,488		195		718		97		78		0		542		376		186
SAN JUAN 29-6 UNIT #259		14399	SJ 29-6		29N06W09		1		11		277		36		134		31		15		0		88		69		185
SAN JUAN 29-6 UNIT #260		14400	SJ 29-6		29N06W16		1		15		304		40		146		38		16		0		92		67		187
SAN JUAN 29-6 UNIT #262		14401	SJ 29-6		29N06W21		1		33		2,359		309		1,138		151		124		0		863		518		307
SAN JUAN 29-6 UNIT #263		13802	SJ 29-6		29N06W22		1		6		53		8		29		14		3		0		12		10		320
SAN JUAN 29-6 UNIT #264		13841	SJ 29-6		29N06W27		1		7		46		6		22		14		2		0		6		5		341
SAN JUAN 29-6 UNIT #47		4888	SJ 29-6		29N06W28		1		14		424		56		205		41		22		0		141		106		1389
SAN JUAN 29-6 UNIT #68		5779	SJ 29-6		29N06W29		1		14		561		74		271		48		29		0		193		146		1392
SAN JUAN 29-7 UNIT #186		11729	SJ 29-7		29N07W21		1		11		192		23		83		23		9		0		51		40		1421
SAN JUAN 29-7 UNIT #507R		12667	SJ 29-7		29N07W13		1		19		803		95		349		58		38		0		253		178		330
SAN JUAN 29-7 UNIT #509		11718	SJ 29-7		29N07W16		1		9		200		24		87		21		9		0		57		46		1399
SAN JUAN 29-7 UNIT #519		12671	SJ 29-7		29N07W08		1		1		9		1		4		2		0		0		1		1		333
SAN JUAN 29-7 UNIT #520		12524	SJ 29-7		29N07W08		1		15		212		25		92		31		10		0		51		36		342
SAN JUAN 29-7 UNIT #521		12653	SJ 29-7		29N07W13		1		20		1,034		122		449		68		49		0		333		232		221
SAN JUAN 29-7 UNIT #526		11728	SJ 29-7		29N07W21		1		9		84		10		37		17		4		0		16		13		1373
SAN JUAN 29-7 UNIT #530		13882	SJ 29-7		29N07W34		1		25		380		45		165		53		18		0		94		56		195
SAN JUAN 29-7 UNIT #532		14349	SJ 29-7		29N07W02		1		18		345		41		150		40		16		0		93		64		145
SAN JUAN 29-7 UNIT #533		14464	SJ 29-7		29N07W03		1		6		92		11		40		13		4		0		22		19		196
SAN JUAN 29-7 UNIT #534		12668	SJ 29-7		29N07W09		1		10		119		14		52		20		6		0		26		20		327
SAN JUAN 29-7 UNIT #537		12669	SJ 29-7		29N07W22		1		9		121		14		53		19		6		0		28		23		290
SAN JUAN 29-7 UNIT #538		14402	SJ 29-7		29N07W26		1		30		618		73		268		69		29		0		170		95		200
SAN JUAN 29-7 UNIT #540		12654	SJ 29-7		29N07W10		1		14		330		39		143		33		16		0		94		71		284
SAN JUAN 29-7 UNIT #543		12655	SJ 29-7		29N07W03		1		17		476		56		207		44		23		0		140		99		299
SAN JUAN 29-7 UNIT #544		12656	SJ 29-7		29N07W04		1		29		1,997		236		868		114		95		0		659		416		283
SAN JUAN 29-7 UNIT #545		12657	SJ 29-7		29N07W12		1		28		1,999		236		869		113		95		0		661		424		210
SAN JUAN 29-7 UNIT #547		14403	SJ 29-7		29N07W07		1		27		642		76		279		65		30		0		184		109		291
SAN JUAN 29-7 UNIT #548		14372	SJ 29-7		29N07W07		1		30		570		67		248		68		27		0		152		83		300
SAN JUAN 29-7 UNIT #550		12659	SJ 29-7		29N07W11		1		16		742		88		322		50		35		0		237		177		215
SAN JUAN 29-7 UNIT #552		12652	SJ 29-7		29N07W12		1		19		1,471		174		639		80		70		0		490		359		314
SAN JUAN 29-7 UNIT #553		12661	SJ 29-7		29N07W14		1		17		1,367		161		594		74		65		0		456		342		234
SAN JUAN 29-7 UNIT #554		12662	SJ 29-7		29N07W14		1		21		498		327		1,202		277		131		0		794		523		201
SAN JUAN 29-7 UNIT #559		14404	SJ 29-7		29N07W22		1		14		162		19		70		28		8		0		35		25		244
SAN JUAN 29-7 UNIT #560		12663	SJ 29-7		29N07W23		1		5		36		16		58		32		6		0		20		18		202
SAN JUAN 29-7 UNIT #562		12664	SJ 29-7		29N07W24		1		18		1,118		132		486		68		53		0		365		265		239
SAN JUAN 29-7 UNIT #563		12665	SJ 29-7		29N07W24		1		2		16		7		25		16		3		0		7		6		285
SAN JUAN 29-7 UNIT #565		14231	SJ 29-7		29N07W26		1		12		87		57		211		124		23		0		64		46		203

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 29-7 UNIT #577		14232	SJ 29-7		29N07W35		1		9		88		7		24		11		3		0		10		8		275
SAN JUAN 29-7 UNIT #580		14465	SJ 29-7		29N07W01		1		21		1,345		159		584		79		64		0		442		312		219
SAN JUAN 29-7 UNIT #582		12666	SJ 29-7		29N07W02		1		17		1,394		165		606		75		66		0		465		351		211
SAN JUAN 29-7 UNIT #583		12670	SJ 29-7		29N07W06		1		15		282		33		122		33		13		0		76		55		329
SAN JUAN 29-7 UNIT #92R		12025	SJ 29-7		29N07W16		1		4		42		5		18		7		2		0		9		8		1248
SAN JUAN 30-5 UNIT #201		13550	SJ 30-5		30N05W19		1		24		1,643		309		1,138		155		124		0		859		573		123
SAN JUAN 30-5 UNIT #202		13551	SJ 30-5		30N05W06		1		5		137		26		95		22		10		0		63		56		116
SAN JUAN 30-5 UNIT #203		13607	SJ 30-5		30N05W06		1		3		27		5		19		9		2		0		8		7		156
SAN JUAN 30-5 UNIT #204		13726	SJ 30-5		30N05W07		1		19		408		77		283		71		31		0		180		122		163
SAN JUAN 30-5 UNIT #205		13772	SJ 30-5		30N05W07		1		12		242		46		168		44		18		0		105		81		148
SAN JUAN 30-5 UNIT #206		13711	SJ 30-5		30N05W18		1		20		952		179		659		106		72		0		481		333		166
SAN JUAN 30-5 UNIT #207		13727	SJ 30-5		30N05W18		1		16		894		168		619		93		67		0		459		340		192
SAN JUAN 30-5 UNIT #208		13665	SJ 30-5		30N05W19		1		17		1,496		282		1,036		129		113		0		795		596		199
SAN JUAN 30-5 UNIT #209		13606	SJ 30-5		30N05W30		1		18		921		173		638		97		69		0		471		342		167
SAN JUAN 30-5 UNIT #210		13682	SJ 30-5		30N05W30		1		12		366		69		254		51		28		0		175		137		264
SAN JUAN 30-5 UNIT #211		13683	SJ 30-5		30N05W31		1		16		580		109		401		73		44		0		284		210		172
SAN JUAN 30-5 UNIT #212		13617	SJ 30-5		30N05W31		1		16		539		101		373		71		41		0		262		192		173
SAN JUAN 30-5 UNIT #213R		16986	SJ 30-5		30N05W05		1		12		545		103		377		63		41		0		274		215		624
SAN JUAN 30-5 UNIT #214		16987	SJ 30-5		30N05W05		1		10		532		100		368		55		40		0		274		228		638
SAN JUAN 30-5 UNIT #215		13660	SJ 30-5		30N05W08		1		20		1,197		225		829		119		90		0		620		437		190
SAN JUAN 30-5 UNIT #216R		13943	SJ 30-5		30N05W20		1		13		394		74		273		57		30		0		186		142		335
SAN JUAN 30-5 UNIT #217		13614	SJ 30-5		30N05W21		1		22		1,227		231		850		125		93		0		632		435		217
SAN JUAN 30-5 UNIT #218		13659	SJ 30-5		30N05W17		1		8		513		97		355		49		39		0		267		231		191
SAN JUAN 30-5 UNIT #219R		17250	SJ 30-5		30N05W16		1		11		559		105		387		59		42		0		286		233		625
SAN JUAN 30-5 UNIT #220R		15532	SJ 30-5		30N05W08		1		17		674		127		467		82		51		0		334		241		635
SAN JUAN 30-5 UNIT #223		13677	SJ 30-5		30N05W20		1		16		762		143		528		83		57		0		387		289		236
SAN JUAN 30-5 UNIT #224		12576	SJ 30-5		30N05W17		1		14		387		73		268		58		29		0		181		136		237
SAN JUAN 30-5 UNIT #225		14406	SJ 30-5		30N05W29		1		16		431		81		298		65		32		0		201		146		306
SAN JUAN 30-5 UNIT #226		13670	SJ 30-5		30N05W29		1		19		1,059		199		733		109		80		0		545		389		261
SAN JUAN 30-5 UNIT #227		13672	SJ 30-5		30N05W28		1		20		746		140		517		95		56		0		366		249		232
SAN JUAN 30-5 UNIT #228		14407	SJ 30-5		30N05W28		1		19		589		111		408		82		44		0		281		194		310
SAN JUAN 30-5 UNIT #229		13673	SJ 30-5		30N05W21		1		23		1,290		243		893		133		97		0		663		442		270
SAN JUAN 30-5 UNIT #230		14366	SJ 30-5		30N05W32		1		9		492		93		340		51		37		0		253		213		238
SAN JUAN 30-5 UNIT #231		14409	SJ 30-5		30N05W32		1		17		408		77		282		68		31		0		184		129		233
SAN JUAN 30-5 UNIT #232		14408	SJ 30-5		30N05W33		1		0		0		0		0		0		0		0		0		0		321
SAN JUAN 30-5 UNIT #233		14443	SJ 30-5		30N05W33		1		22		705		133		488		98		53		0		337		220		322
SAN JUAN 30-5 UNIT #234		14410	SJ 30-5		30N05W22		1		28		2,555		481		1,769		216		193		0		1,361		880		318
SAN JUAN 30-5 UNIT #235		14411	SJ 30-5		30N05W27		1		10		299		56		207		43		23		0		141		114		311
SAN JUAN 30-5 UNIT #236		14412	SJ 30-5		30N05W27		1		8		240		45		166		34		18		0		115		97		303
SAN JUAN 30-5 UNIT #237R		6123	SJ 30-5		30N05W16		1		8		369		69		255		42		28		0		185		157		1201
SAN JUAN 30-5 UNIT #238		14414	SJ 30-5		30N05W34		1		6		146		27		101		24		11		0		66		57		312

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 30-5 UNIT #239		13949	SJ 30-5		30N05W15		1		13		716		135		496		74		54		0		367		288		315
SAN JUAN 30-5 UNIT #240		14415	SJ 30-5		30N05W22		1		27		2,111		397		1,462		189		159		0		1,114		723		324
SAN JUAN 30-5 UNIT #241		14416	SJ 30-5		30N05W23		1		14		314		59		218		55		24		0		139		102		325
SAN JUAN 30-5 UNIT #242		14444	SJ 30-5		30N05W34		1		4		44		8		31		14		3		0		13		12		316
SAN JUAN 30-5 UNIT #243		14069	SJ 30-5		30N05W15		1		27		2,291		431		1,587		198		173		0		1,215		795		346
SAN JUAN 30-5 UNIT #246		13948	SJ 30-5		30N05W26		1		17		566		106		392		75		43		0		274		197		331
SAN JUAN 30-5 UNIT #249		14068	SJ 30-5		30N05W23		1		15		1,049		197		727		97		79		0		551		426		632
SAN JUAN 30-5 UNIT #255		13842	SJ 30-5		30N05W14		1		15		1,096		206		759		99		83		0		577		446		340
SAN JUAN 30-5 UNIT #257		14025	SJ 30-5		30N05W11		1		22		2,259		425		1,564		184		170		0		1,210		853		345
SAN JUAN 30-5 UNIT #258		14026	SJ 30-5		30N05W14		1		30		3,678		692		2,547		283		277		0		1,987		1,285		344
SAN JUAN 30-5 UNIT #259		8011	SJ 30-5		30N05W13		1		14		597		112		414		71		45		0		298		226		630
SAN JUAN 30-5 UNIT #260		12646	SJ 30-5		30N05W09		1		10		958		180		663		80		72		0		511		430		633
SAN JUAN 30-5 UNIT #261		5424	SJ 30-5		30N05W11		1		26		1,513		285		1,048		153		114		0		780		501		682
SAN JUAN 30-5 UNIT #262		8012	SJ 30-5		30N05W12		1		12		932		175		645		83		70		0		492		398		631
SAN JUAN 30-5 UNIT #263		5425	SJ 30-5		30N05W13		1		9		369		69		255		44		28		0		184		154		683
SAN JUAN 30-5 UNIT #264		12619	SJ 30-5		30N05W09		1		12		1,053		198		729		90		79		0		560		455		634
SAN JUAN 30-5 UNIT #265		15533	SJ 30-5		30N05W10		1		14		1,651		311		1,144		128		125		0		891		713		637
SAN JUAN 30-5 UNIT #266		15534	SJ 30-5		30N05W10		1		20		2,380		448		1,648		184		180		0		1,285		947		636
SAN JUAN 30-5 UNIT #267		5046	SJ 30-5		30N05W24		1		11		401		76		278		51		30		0		197		159		1246
SAN JUAN 30-5 UNIT #268		10177	SJ 30-5		30N05W24		1		12		381		72		264		54		29		0		182		141		1247
SAN JUAN 30-6 UNIT #400		14164	SJ 30-6		30N07W14		1		20		1,536		77		282		37		31		0		215		153		23
SAN JUAN 30-6 UNIT #401R		14165	SJ 30-6		30N07W13		1		16		1,089		54		200		27		22		0		151		114		79
SAN JUAN 30-6 UNIT #403		13648	SJ 30-6		30N06W09		1		27		2,154		108		396		51		43		0		302		198		171
SAN JUAN 30-6 UNIT #404R		14459	SJ 30-6		30N07W23		1		22		2,253		112		414		49		45		0		320		226		328
SAN JUAN 30-6 UNIT #405		13580	SJ 30-6		30N06W09		1		19		717		36		132		24		14		0		94		65		128
SAN JUAN 30-6 UNIT #406R		14167	SJ 30-6		30N07W15		1		17		816		41		150		24		16		0		110		81		108
SAN JUAN 30-6 UNIT #407		13559	SJ 30-6		30N06W16		1		23		1,807		90		332		43		36		0		253		172		120
SAN JUAN 30-6 UNIT #408		13558	SJ 30-6		30N06W16		1		23		1,597		80		293		40		32		0		222		151		119
SAN JUAN 30-6 UNIT #409		14168	SJ 30-6		30N07W25		1		23		2,285		114		420		50		46		0		324		226		30
SAN JUAN 30-6 UNIT #410		14211	SJ 30-6		30N06W26		1		18		865		43		159		26		17		0		116		83		135
SAN JUAN 30-6 UNIT #411		14169	SJ 30-6		30N07W27		1		11		485		24		89		15		10		0		64		52		33
SAN JUAN 30-6 UNIT #412		14170	SJ 30-6		30N07W24		1		21		1,878		94		345		43		38		0		265		187		24
SAN JUAN 30-6 UNIT #413R		14171	SJ 30-6		30N07W23		1		23		1,808		90		332		43		36		0		253		175		84
SAN JUAN 30-6 UNIT #414		14172	SJ 30-6		30N07W35		1		11		306		15		56		12		6		0		38		30		25
SAN JUAN 30-6 UNIT #415		14173	SJ 30-6		30N07W26		1		21		1,549		77		285		38		31		0		216		152		32
SAN JUAN 30-6 UNIT #416		14174	SJ 30-6		30N07W24		1		23		2,535		127		466		54		51		0		361		251		28
SAN JUAN 30-6 UNIT #417		14175	SJ 30-6		30N07W25		1		19		1,456		73		267		35		29		0		203		147		29
SAN JUAN 30-6 UNIT #418		14176	SJ 30-6		30N07W26		1		20		1,615		81		297		38		32		0		226		163		31
SAN JUAN 30-6 UNIT #419		14177	SJ 30-6		30N07W11		1		13		460		23		85		16		9		0		59		46		26
SAN JUAN 30-6 UNIT #420		14178	SJ 30-6		30N07W12		1		20		896		45		165		27		18		0		119		82		27
SAN JUAN 30-6 UNIT #421		14179	SJ 30-6		30N07W34		1		0		0		0		0		0		0		0		0		0		37

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 30-6 UNIT #422		14264	SJ 30-6		30N07W27		1		22		1,008		50		185		30		20		0		135		90		59
SAN JUAN 30-6 UNIT #423		14462	SJ 30-6		30N07W28		1		8		153		8		28		8		3		0		17		14		95
SAN JUAN 30-6 UNIT #424		14463	SJ 30-6		30N07W33		1		18		590		29		108		21		12		0		75		53		56
SAN JUAN 30-6 UNIT #425		14385	SJ 30-6		30N07W33		1		22		1,387		69		255		36		28		0		191		132		47
SAN JUAN 30-6 UNIT #426		14180	SJ 30-6		30N07W34		1		9		153		8		28		8		3		0		17		13		54
SAN JUAN 30-6 UNIT #427		14181	SJ 30-6		30N07W35		1		14		615		31		113		19		12		0		81		62		60
SAN JUAN 30-6 UNIT #428		14358	SJ 30-6		30N07W28		1		21		1,055		53		194		30		21		0		142		98		82
SAN JUAN 30-6 UNIT #429		14359	SJ 30-6		30N07W32		1		13		657		33		121		19		13		0		89		70		67
SAN JUAN 30-6 UNIT #430		13543	SJ 30-6		30N06W08		1		18		1,446		72		266		34		29		0		203		151		38
SAN JUAN 30-6 UNIT #431		13544	SJ 30-6		30N06W10		1		24		1,992		99		366		47		40		0		280		189		40
SAN JUAN 30-6 UNIT #432		13545	SJ 30-6		30N06W10		1		25		1,623		81		298		42		32		0		224		148		39
SAN JUAN 30-6 UNIT #433		14182	SJ 30-6		30N06W11		1		16		829		41		152		24		17		0		112		83		48
SAN JUAN 30-6 UNIT #434		14183	SJ 30-6		30N06W12		1		18		1,140		57		209		29		23		0		157		116		58
SAN JUAN 30-6 UNIT #435		14184	SJ 30-6		30N06W13		1		21		1,213		61		223		33		24		0		166		114		70
SAN JUAN 30-6 UNIT #436		14185	SJ 30-6		30N06W15		1		21		1,589		79		292		38		32		0		222		157		41
SAN JUAN 30-6 UNIT #437		14186	SJ 30-6		30N06W11		1		27		1,938		97		356		48		39		0		270		174		62
SAN JUAN 30-6 UNIT #438		14187	SJ 30-6		30N06W12		1		21		1,953		98		359		43		39		0		276		199		68
SAN JUAN 30-6 UNIT #439		14188	SJ 30-6		30N06W14		1		21		1,073		54		197		31		21		0		145		99		49
SAN JUAN 30-6 UNIT #440		14189	SJ 30-6		30N06W15		1		3		23		1		4		2		0		0		2		2		50
SAN JUAN 30-6 UNIT #441		14190	SJ 30-6		30N06W31		1		1		8		0		2		1		0		0		0		0		53
SAN JUAN 30-6 UNIT #442		13568	SJ 30-6		30N06W14		1		21		1,505		75		277		37		30		0		209		147		96
SAN JUAN 30-6 UNIT #443		13532	SJ 30-6		30N06W36		1		1		4		0		1		1		0		0		0		0		69
SAN JUAN 30-6 UNIT #444		14208	SJ 30-6		30N06W36		1		27		1,634		82		300		43		33		0		224		143		66
SAN JUAN 30-6 UNIT #445		14209	SJ 30-6		30N06W13		1		21		1,255		63		231		33		25		0		172		120		73
SAN JUAN 30-6 UNIT #446		14204	SJ 30-6		30N06W35		1		25		2,467		123		453		54		49		0		350		236		129
SAN JUAN 30-6 UNIT #447		14206	SJ 30-6		30N07W31		1		13		324		16		60		14		6		0		39		30		147
SAN JUAN 30-6 UNIT #450		13536	SJ 30-6		30N06W07		1		21		1,579		79		290		38		32		0		221		156		43
SAN JUAN 30-6 UNIT #451		13534	SJ 30-6		30N06W07		1		19		1,558		78		286		37		31		0		218		158		42
SAN JUAN 30-6 UNIT #452		13535	SJ 30-6		30N06W08		1		16		836		42		154		24		17		0		113		84		61
SAN JUAN 30-6 UNIT #453		14191	SJ 30-6		30N06W17		1		19		955		48		175		27		19		0		129		92		57
SAN JUAN 30-6 UNIT #454		14192	SJ 30-6		30N06W17		1		22		1,701		85		312		41		34		0		238		164		44
SAN JUAN 30-6 UNIT #455		14161	SJ 30-6		30N06W18		1		19		939		47		173		27		19		0		127		90		52
SAN JUAN 30-6 UNIT #456		13537	SJ 30-6		30N06W18		1		22		2,179		109		400		48		44		0		309		218		51
SAN JUAN 30-6 UNIT #457		14193	SJ 30-6		30N06W19		1		24		2,141		107		393		49		43		0		302		206		45
SAN JUAN 30-6 UNIT #458		14194	SJ 30-6		30N06W19		1		17		811		40		149		24		16		0		109		80		63
SAN JUAN 30-6 UNIT #459		14195	SJ 30-6		30N06W20		1		23		1,602		80		294		40		32		0		222		152		64
SAN JUAN 30-6 UNIT #460		14162	SJ 30-6		30N06W20		1		19		1,292		64		237		32		26		0		179		129		55
SAN JUAN 30-6 UNIT #461		14251	SJ 30-6		30N07W11		1		15		562		28		103		19		11		0		73		55		80
SAN JUAN 30-6 UNIT #462		14196	SJ 30-6		30N07W12		1		29		1,556		78		286		43		31		0		211		130		83
SAN JUAN 30-6 UNIT #463		14197	SJ 30-6		30N07W13		1		17		1,013		51		186		27		20		0		139		103		81
SAN JUAN 30-6 UNIT #464		14198	SJ 30-6		30N07W14		1		18		691		34		127		23		14		0		90		64		46

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 30-6 UNIT #465		14199	SJ 30-6		30N07W15		1		20		1,160		58		213		31		23		0		159		111		65
SAN JUAN 30-6 UNIT #466		14200	SJ 30-6		30N07W22		1		12		504		25		93		16		10		0		66		52		75
SAN JUAN 30-6 UNIT #467 COM		4496	NEBU		30N07W22		1		12		435		12		45		8		5		0		31		25		105
SAN JUAN 30-6 UNIT #468		14252	SJ 30-6		30N07W36		1		22		1,836		92		337		43		37		0		258		179		91
SAN JUAN 30-6 UNIT #470		14253	SJ 30-6		30N06W21		1		19		1,173		59		216		31		23		0		161		115		102
SAN JUAN 30-6 UNIT #471		14254	SJ 30-6		30N06W21		1		18		1,088		54		200		29		22		0		150		110		113
SAN JUAN 30-6 UNIT #472		14255	SJ 30-6		30N06W22		1		17		521		26		96		20		10		0		65		46		107
SAN JUAN 30-6 UNIT #473		14256	SJ 30-6		30N06W22		1		16		719		36		132		22		14		0		96		71		106
SAN JUAN 30-6 UNIT #474		14257	SJ 30-6		30N06W27		1		27		2,208		110		406		51		44		0		310		203		97
SAN JUAN 30-6 UNIT #475		14258	SJ 30-6		30N06W27		1		28		2,776		139		510		61		56		0		393		255		109
SAN JUAN 30-6 UNIT #476		14163	SJ 30-6		30N06W28		1		20		1,297		65		238		33		26		0		179		126		100
SAN JUAN 30-6 UNIT #477		14210	SJ 30-6		30N06W28		1		23		1,966		98		361		45		39		0		277		191		111
SAN JUAN 30-6 UNIT #478		14205	SJ 30-6		30N06W29		1		22		1,829		91		336		43		37		0		257		179		101
SAN JUAN 30-6 UNIT #479		14259	SJ 30-6		30N06W29		1		21		1,278		64		235		34		26		0		176		122		134
SAN JUAN 30-6 UNIT #480		14260	SJ 30-6		30N06W30		1		14		639		32		117		20		13		0		85		65		110
SAN JUAN 30-6 UNIT #481		14261	SJ 30-6		30N06W30		1		26		2,350		117		432		53		47		0		332		222		99
SAN JUAN 30-6 UNIT #482		14266	SJ 30-6		30N06W31		1		28		2,537		127		466		58		51		0		358		231		142
SAN JUAN 30-6 UNIT #483		14207	SJ 30-6		30N06W34		1		15		524		26		96		18		10		0		68		51		104
SAN JUAN 30-6 UNIT #484		14249	SJ 30-6		30N06W34		1		5		103		5		19		5		2		0		12		11		103
SAN JUAN 30-6 UNIT #485		14233	SJ 30-6		30N07W36		1		19		1,377		69		253		34		28		0		192		139		204
SAN JUAN 30-6 UNIT #486		14234	SJ 30-6		30N06W23		1		23		1,787		89		328		42		36		0		250		173		271
SAN JUAN 30-6 UNIT #487		14235	SJ 30-6		30N06W23		1		25		1,739		87		320		43		35		0		242		161		292
SAN JUAN 30-6 UNIT #488		14236	SJ 30-6		30N06W24		1		16		553		28		102		19		11		0		71		52		222
SAN JUAN 30-6 UNIT #489		14237	SJ 30-6		30N06W24		1		19		1,517		76		279		36		30		0		212		153		249
SAN JUAN 30-6 UNIT #490		14238	SJ 30-6		30N06W25		1		10		342		17		63		12		7		0		44		36		223
SAN JUAN 30-6 UNIT #491		14239	SJ 30-6		30N06W25		1		18		1,042		52		192		28		21		0		142		103		224
SAN JUAN 30-6 UNIT #492		14240	SJ 30-6		30N06W26		1		18		758		38		139		24		15		0		100		72		230
SAN JUAN 30-6 UNIT #493		14241	SJ 30-6		30N06W32		1		15		649		32		119		20		13		0		86		64		205
SAN JUAN 30-6 UNIT #494		14242	SJ 30-6		30N06W33		1		29		2,916		146		536		63		58		0		414		268		212
SAN JUAN 30-6 UNIT #495		14243	SJ 30-6		30N06W33		1		25		1,763		88		324		44		35		0		245		163		213
SAN JUAN 30-6 UNIT #496		14244	SJ 30-6		30N06W35		1		16		531		27		98		19		11		0		68		49		225
SAN JUAN 30-6 UNIT #497		14245	SJ 30-6		30N07W29		1		29		942		47		173		35		19		0		120		70		259
SAN JUAN 30-6 UNIT #498R		13946	SJ 30-6		30N07W30		1		3		21		3		12		7		1		0		3		3		336
SAN JUAN 30-6 UNIT #500		14417	SJ 30-6		30N07W31		1		19		298		44		163		54		18		0		91		59		240
SAN JUAN 30-6 UNIT #501		14248	SJ 30-6		30N06W32		1		20		1,145		57		210		31		23		0		157		111		206
SAN JUAN 31 FED 3 #2		14418	NON-UNIT		31N09W03		1		21		1,342		199		733		106		80		0		548		380		559
SAN JUAN 31-6 UNIT #201		13540	SJ 31-6		30N06W01		1		14		487		52		192		37		21		0		134		103		130
SAN JUAN 31-6 UNIT #202		13552	SJ 31-6		30N06W01		1		28		2,046		219		806		109		88		0		610		391		118
SAN JUAN 31-6 UNIT #203		13539	SJ 31-6		30N06W03		1		10		249		27		98		24		11		0		64		51		88
SAN JUAN 31-6 UNIT #204		13541	SJ 31-6		30N06W03		1		20		1,244		133		490		70		53		0		366		261		90
SAN JUAN 31-6 UNIT #205R		12574	SJ 31-6		30N06W04		1		10		432		46		170		29		19		0		123		101		343

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 31-6 UNIT #206		13542	SJ 31-6		30N06W04		1		11		507		54		200		33		22		0		145		117		92
SAN JUAN 31-6 UNIT #207		13533	SJ 31-6		30N06W06		1		17		580		62		229		45		25		0		158		113		94
SAN JUAN 31-6 UNIT #208		14213	SJ 31-6		30N06W06		1		11		186		20		73		22		8		0		43		34		89
SAN JUAN 31-6 UNIT #209		14214	SJ 31-6		30N07W01		1		9		286		31		113		24		12		0		77		63		87
SAN JUAN 31-6 UNIT #210		13618	SJ 31-6		30N06W02		1		21		1,852		198		730		92		80		0		559		398		168
SAN JUAN 31-6 UNIT #211		13553	SJ 31-6		30N06W02		1		25		1,916		205		755		101		82		0		572		380		114
SAN JUAN 31-6 UNIT #212		13615	SJ 31-6		30N06W05		1		14		835		89		329		49		36		0		244		187		164
SAN JUAN 31-6 UNIT #213		13554	SJ 31-6		30N06W05		1		17		935		100		369		56		40		0		272		200		121
SAN JUAN 31-6 UNIT #214		13646	SJ 31-6		31N06W36		1		12		388		42		153		30		17		0		106		84		254
SAN JUAN 31-6 UNIT #215		13616	SJ 31-6		31N06W36		1		22		979		105		386		66		42		0		278		186		150
SAN JUAN 31-6 UNIT #216		13647	SJ 31-6		31N06W35		1		19		666		71		263		50		29		0		184		128		287
SAN JUAN 31-6 UNIT #217		13609	SJ 31-6		31N06W35		1		4		33		4		13		7		1		0		5		4		157
SAN JUAN 31-6 UNIT #218		13671	SJ 31-6		31N06W34		1		16		563		60		222		42		24		0		155		114		265
SAN JUAN 31-6 UNIT #219		13608	SJ 31-6		31N06W34		1		29		1,893		203		746		106		81		0		559		348		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		25		856		92		337		66		37		0		234		146		253
SAN JUAN 31-6 UNIT #222		13666	SJ 31-6		31N06W32		1		9		192		21		76		20		8		0		47		38		220
SAN JUAN 31-6 UNIT #223		13613	SJ 31-6		31N06W32		1		27		1,732		186		683		98		74		0		510		325		149
SAN JUAN 31-6 UNIT #224		13691	SJ 31-6		31N06W31		1		13		401		43		158		33		17		0		108		83		274
SAN JUAN 31-6 UNIT #225R		13697	SJ 31-6		31N06W31		1		16		663		71		261		47		28		0		186		136		263
SAN JUAN 31-6 UNIT #228		14419	SJ 31-6		31N06W28		1		11		449		48		177		32		19		0		126		101		272
SAN JUAN 31-6 UNIT #229R		18279	SJ 31-6		31N06W28		1		13		328		35		129		30		14		0		85		65		640
SAN JUAN 31-6 UNIT #230		13555	SJ 31-6		31N06W27		1		23		1,104		118		435		71		47		0		317		211		125
SAN JUAN 31-6 UNIT #231R		17256	SJ 31-6		31N06W27		1		12		332		36		131		29		14		0		88		68		627
SAN JUAN 31-6 UNIT #232		13692	SJ 31-6		30N07W01		1		9		200		21		79		20		9		0		51		42		262
SAN JUAN 31-6 UNIT #233		13693	SJ 31-6		31N06W29		1		23		676		72		267		57		29		0		181		116		227
SAN JUAN 31-6 UNIT #234R		14007	SJ 31-6		31N06W29		1		6		94		10		37		13		4		0		21		18		337
SAN JUAN 32-7 UNIT #202R		10783	SJ 32-7		32N07W18		1		13		471		70		257		49		28		0		181		137		1449
SAN JUAN 32-7 UNIT #203R		12467	SJ 32-7		32N07W22		1		28		2,377		403		1,484		193		162		0		1,129		724		621
SAN JUAN 32-7 UNIT #204		13546	SJ 32-7		32N07W36		1		16		1,312		223		819		108		89		0		622		470		412
SAN JUAN 32-7 UNIT #205		12471	SJ 32-7		32N07W22		1		16		1,793		304		1,119		133		122		0		864		664		1403
SAN JUAN 32-7 UNIT #206		12647	SJ 32-7		32N07W27		1		12		744		126		464		67		51		0		346		279		656
SAN JUAN 32-7 UNIT #207		13698	SJ 32-7		32N07W27		1		20		1,845		313		1,151		144		125		0		882		639		468
SAN JUAN 32-7 UNIT #208		13710	SJ 32-7		32N07W34		1		16		1,564		265		976		121		106		0		749		572		469
SAN JUAN 32-7 UNIT #209		13640	SJ 32-7		32N07W35		1		13		1,072		182		669		87		73		0		509		407		476
SAN JUAN 32-7 UNIT #210		13598	SJ 32-7		32N07W36		1		17		1,216		206		759		105		83		0		571		426		433
SAN JUAN 32-7 UNIT #211R		12642	SJ 32-7		32N07W35		1		14		819		139		511		77		56		0		378		291		618
SAN JUAN 32-7 UNIT #213 COM		4832	SJ 32-7		31N07W07		1		21		1,105		118		435		69		47		0		319		220		573
SAN JUAN 32-7 UNIT #214		13717	SJ 32-7		32N07W34		1		8		166		28		103		29		11		0		63		52		551
SAN JUAN 32-7 UNIT #215		13700	SJ 32-7		32N07W32		1		19		1,366		232		853		117		93		0		643		468		481
SAN JUAN 32-7 UNIT #216		14422	SJ 32-7		31N07W04		1		7		102		17		64		22		7		0		35		30		581

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 32-7 UNIT #217		13701	SJ 32-7		31N07W04		1		13		360		61		224		51		24		0		149		114		570
SAN JUAN 32-7 UNIT #218		13702	SJ 32-7		31N07W05		1		25		1,754		297		1,095		151		119		0		824		550		571
SAN JUAN 32-7 UNIT #219		13703	SJ 32-7		31N07W05		1		19		1,391		236		868		120		95		0		654		469		572
SAN JUAN 32-7 UNIT #220 COM		4835	SJ 32-7		31N07W05		1		20		1,518		225		828		113		90		0		626		444		619
SAN JUAN 32-7 UNIT #221		13704	SJ 32-7		31N07W08		1		13		671		114		419		67		46		0		306		238		552
SAN JUAN 32-7 UNIT #222		14423	SJ 32-7		32N07W20		1		17		989		168		617		93		67		0		456		335		588
SAN JUAN 32-7 UNIT #224 COM		4792	SJ 32-7		32N07W21		1		25		1,969		250		922		122		100		0		699		466		582
SAN JUAN 32-7 UNIT #227 COM		4843	SJ 32-7		31N07W18		1		18		855		109		401		66		44		0		291		210		574
SAN JUAN 32-7 UNIT #228		4816	SJ 32-7		31N07W07		1		16		1,504		130		479		60		52		0		367		278		617
SAN JUAN 32-7 UNIT #229		13729	SJ 32-7		31N07W09		1		16		794		135		496		81		54		0		361		266		566
SAN JUAN 32-7 UNIT #230		12620	SJ 32-7		31N07W17		1		18		1,193		202		745		105		81		0		559		411		616
SAN JUAN 32-7 UNIT #231		13664	SJ 32-7		31N07W17		1		17		460		78		287		65		31		0		190		134		567
SAN JUAN 32-7 UNIT #232		13705	SJ 32-7		31N07W08		1		12		349		59		218		47		24		0		147		114		556
SAN JUAN 32-7 UNIT #233		14452	SJ 32-7		32N07W20		1		16		1,161		197		725		101		79		0		545		409		592
SAN JUAN 32-7 UNIT #234		14425	SJ 32-7		32N07W32		1		18		1,381		234		862		115		94		0		653		483		583
SAN JUAN 32-7 UNIT #235		14426	SJ 32-7		32N07W29		1		14		1,373		233		857		106		93		0		658		520		589
SAN JUAN 32-7 UNIT #237		14454	SJ 32-7		32N07W32		1		13		1,133		192		707		91		77		0		539		430		1408
SAN JUAN 32-7 UNIT #238		14455	SJ 32-7		32N07W29		1		24		2,833		480		1,768		206		193		0		1,369		945		593
SAN JUAN 32-7 UNIT #240		12579	SJ 32-7		32N07W19		1		14		612		104		382		66		42		0		274		209		1404
SAN JUAN 32-7 UNIT #241		12580	SJ 32-7		32N07W21		1		13		1,592		270		994		115		108		0		770		618		1405
SAN JUAN 32-7 UNIT #242		12643	SJ 32-7		32N07W33		1		12		940		159		587		77		64		0		445		362		657
SAN JUAN 32-7 UNIT #243		17813	SJ 32-7		32N07W19		1		20		783		133		489		91		53		0		345		235		1410
SAN JUAN 32-7 UNIT #244		15582	SJ 32-7		32N07W17		1		22		994		169		620		105		68		0		448		302		1409
SAN JUAN 32-7 UNIT #246		740	SJ 32-7		32N07W18		1		18		1,030		175		643		97		70		0		476		346		1172
SAN JUAN 32-8 UNIT #202		13657	SJ 32-8		32N08W27		1		19		2,023		230		846		99		92		0		654		486		432
SAN JUAN 32-8 UNIT #203		14507	SJ 32-8		32N08W33		1		18		1,741		198		728		88		79		0		560		420		584
SAN JUAN 32-8 UNIT #204		14508	SJ 32-8		32N08W34		1		19		1,778		202		744		92		81		0		571		418		585
SAN JUAN 32-8 UNIT #205		14511	SJ 32-8		32N08W34		1		13		1,102		125		461		58		50		0		352		283		590
SAN JUAN 32-8 UNIT #206		14445	SJ 32-8		31N08W24		1		13		509		58		213		39		23		0		150		115		548
SAN JUAN 32-8 UNIT #207		13591	SJ 32-8		31N08W22		1		21		1,477		168		618		85		67		0		466		328		414
SAN JUAN 32-8 UNIT #208		13557	SJ 32-8		32N08W29		1		26		2,331		265		975		122		106		0		747		498		419
SAN JUAN 32-8 UNIT #213		12648	SJ 32-8		32N08W22		1		18		1,122		128		469		68		51		0		350		253		614
SAN JUAN 32-8 UNIT #218		14509	SJ 32-8		32N08W35		1		11		1,174		133		491		58		53		0		380		316		586
SAN JUAN 32-8 UNIT #219		14510	SJ 32-8		32N08W35		1		20		2,385		271		997		114		109		0		774		566		587
SAN JUAN 32-8 UNIT #220		13706	SJ 32-8		31N08W24		1		13		555		63		232		40		25		0		167		130		544
SAN JUAN 32-8 UNIT #221		13642	SJ 32-8		31N08W09		1		14		760		86		318		48		35		0		235		182		499
SAN JUAN 32-8 UNIT #222		13658	SJ 32-8		31N08W09		1		24		1,441		164		602		88		66		0		449		301		500
SAN JUAN 32-8 UNIT #223		13643	SJ 32-8		31N08W10		1		17		748		85		313		53		34		0		225		163		488
SAN JUAN 32-8 UNIT #224		13644	SJ 32-8		31N08W10		1		29		2,308		262		965		126		105		0		734		465		486
SAN JUAN 32-8 UNIT #225		14427	SJ 32-8		31N08W15		1		24		1,817		206		760		101		83		0		576		388		517
SAN JUAN 32-8 UNIT #226		13707	SJ 32-8		31N08W15		1		23		1,685		191		705		95		77		0		533		363		487

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 32-8 UNIT #227		14428	SJ 32-8		31N08W16		1		14		661		75		276		46		30		0		200		152		473
SAN JUAN 32-8 UNIT #228		14429	SJ 32-8		31N08W16		1		18		1,235		140		516		72		56		0		388		283		471
SAN JUAN 32-8 UNIT #229		13708	SJ 32-8		32N08W20		1		21		2,297		261		960		112		105		0		744		539		501
SAN JUAN 32-8 UNIT #230		13716	SJ 32-8		32N08W28		1		16		2,107		239		881		98		96		0		687		538		510
SAN JUAN 32-8 UNIT #231		13715	SJ 32-8		32N08W28		1		16		1,656		188		692		83		75		0		534		410		511
SAN JUAN 32-8 UNIT #232		13709	SJ 32-8		32N08W29		1		21		2,345		266		981		115		107		0		759		546		502
SAN JUAN 32-8 UNIT #233		13712	SJ 32-8		32N08W30		1		19		3,451		392		1,443		149		157		0		1,137		864		512
SAN JUAN 32-8 UNIT #234		14430	SJ 32-8		31N08W21		1		12		633		72		265		42		29		0		194		154		565
SAN JUAN 32-8 UNIT #235		14431	SJ 32-8		31N08W21		1		15		536		61		224		42		24		0		158		118		564
SAN JUAN 32-8 UNIT #236		14432	SJ 32-8		31N08W22		1		17		1,242		141		520		71		57		0		392		291		577
SAN JUAN 32-8 UNIT #237		13645	SJ 32-8		31N08W23		1		17		762		87		319		53		35		0		231		169		539
SAN JUAN 32-8 UNIT #238		13652	SJ 32-8		31N08W23		1		16		1,291		147		540		70		59		0		411		313		538
SAN JUAN 32-8 UNIT #239		13714	SJ 32-8		32N08W30		1		18		1,441		164		603		79		66		0		458		337		569
SAN JUAN 32-8 UNIT #240		13725	SJ 32-8		31N08W03		1		15		1,137		129		475		63		52		0		361		279		553
SAN JUAN 32-8 UNIT #241		13713	SJ 32-8		31N08W04		1		15		942		107		394		56		43		0		295		227		554
SAN JUAN 32-8 UNIT #242		14433	SJ 32-8		31N08W04		1		19		1,292		147		540		75		59		0		406		294		576
SAN JUAN 32-8 UNIT #243		14434	SJ 32-8		31N08W11		1		20		1,163		132		486		72		53		0		362		257		555
SAN JUAN 32-8 UNIT #244		13730	SJ 32-8		31N08W14		1		21		1,673		190		700		92		76		0		532		374		562
SAN JUAN 32-8 UNIT #245		14435	SJ 32-8		31N08W14		1		14		770		88		322		50		35		0		237		182		563
SAN JUAN 32-8 UNIT #247		12555	SJ 32-8		32N08W19		1		21		2,818		320		1,179		131		128		0		919		667		1195
SAN JUAN 32-8 UNIT #248		14436	SJ 32-8		31N08W11		1		15		599		68		251		45		27		0		178		133		1371
SAN JUAN 32-8 UNIT #249		14437	SJ 32-8		31N08W03		1		18		1,263		144		528		73		58		0		398		291		557
SAN JUAN 32-8 UNIT #250		13731	SJ 32-8		32N08W33		1		18		1,457		166		609		78		66		0		464		346		558
SAN JUAN 32-8 UNIT #253		12649	SJ 32-8		32N08W27		1		15		1,098		125		459		61		50		0		348		270		615
SAN JUAN 32-8 UNIT #254		14084	SJ 32-8		32N08W23		1		15		602		68		252		45		27		0		180		135		622
SAN JUAN 32-8 UNIT #255		1874	SJ 32-8		32N08W24		1		14		431		49		180		37		20		0		123		93		1196
SAN JUAN 32-8 UNIT #256		19424	SJ 32-8		32N08W25		1		19		2,063		234		863		101		94		0		667		494		628
SAN JUAN 32-8 UNIT #257		16981	SJ 32-8		32N08W19		1		19		2,081		236		870		102		95		0		673		499		1197
SAN JUAN 32-8 UNIT #258		19425	SJ 32-8		32N08W15		1		15		620		70		259		45		28		0		186		140		1359
SAN JUAN 32-8 UNIT #259A		5043	SJ 32-8		32N08W22		1		15		981		111		410		59		45		0		307		233		724
SAN JUAN 32-8 UNIT #260		19426	SJ 32-8		32N08W18		1		15		1,310		149		548		70		60		0		418		323		1361
SAN JUAN 32-8 UNIT #261		17021	SJ 32-8		32N08W17		1		13		542		62		227		40		25		0		162		125		1198
SAN JUAN 32-8 UNIT #262		19427	SJ 32-8		32N08W17		1		17		579		66		242		47		26		0		169		121		1360
SAN JUAN 32-8 UNIT #264		11694	SJ 32-8		32N08W09		1		11		302		34		126		28		14		0		85		68		1397
SAN JUAN 32-8 UNIT #267A		10123	SJ 32-8		32N08W23		1		19		1,590		181		665		85		72		0		508		371		1345
SAN JUAN 32-8 UNIT #36		15041	SJ 32-8		32N08W25		1		17		222		25		93		35		10		0		48		32		371
SAN JUAN 32-9 UNIT #104		14466	SJ 32-9		32N10W24		1		16		1,241		32		119		15		13		0		91		69		426
SAN JUAN 32-9 UNIT #105		14467	SJ 32-9		31N09W08		1		15		545		14		52		10		6		0		37		28		427
SAN JUAN 32-9 UNIT #201		14438	SJ 32-9		31N09W02		1		7		146		4		14		4		2		0		9		7		441
SAN JUAN 32-9 UNIT #202		14439	SJ 32-9		31N09W02		1		12		497		13		48		8		5		0		34		27		442
SAN JUAN 32-9 UNIT #209		14273	SJ 32-9		31N10W02		1		8		89		2		9		4		1		0		4		3		443

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 32-9 UNIT #210		14274	SJ 32-9		31N10W02		1		16		262		25		91		28		10		0		53		38		444
SAN JUAN 32-9 UNIT #215		14468	SJ 32-9		32N09W10		1		14		842		22		81		12		9		0		60		47		503
SAN JUAN 32-9 UNIT #217		14275	SJ 32-9		32N09W16		1		14		1,046		27		100		13		11		0		76		59		482
SAN JUAN 32-9 UNIT #220		14000	SJ 32-9		31N10W11		1		26		3,126		82		300		34		33		0		233		157		594
SAN JUAN 32-9 UNIT #221		12458	SJ 32-9		31N10W11		1		3		25		1		2		1		0		0		1		1		595
SAN JUAN 32-9 UNIT #222		12556	SJ 32-9		31N10W12		1		0		0		0		0		0		0		0		0		0		596
SAN JUAN 32-9 UNIT #223		12459	SJ 32-9		31N10W12		1		6		74		2		7		3		1		0		4		3		597
SAN JUAN 32-9 UNIT #226		14469	SJ 32-9		32N09W32		1		13		641		17		62		10		7		0		45		36		445
SAN JUAN 32-9 UNIT #228		14440	SJ 32-9		32N09W36		1		21		2,028		53		195		23		21		0		150		108		446
SAN JUAN 32-9 UNIT #229		14267	SJ 32-9		32N10W36		1		18		1,461		38		140		18		15		0		107		79		447
SAN JUAN 32-9 UNIT #230		14470	SJ 32-9		32N10W36		1		12		194		5		19		6		2		0		11		8		448
SAN JUAN 32-9 UNIT #235		14450	SJ 32-9		32N09W36		1		11		580		15		56		9		6		0		41		33		449
SAN JUAN 32-9 UNIT #241		19430	SJ 32-9		32N09W13		1		13		494		13		47		9		5		0		34		26		1377
SAN JUAN 32-9 UNIT #242		766	SJ 32-9		32N09W14		1		5		182		5		18		3		2		0		12		11		1363
SAN JUAN 32-9 UNIT #250		14268	SJ 32-9		31N09W04		1		18		1,655		43		159		20		17		0		122		91		531
SAN JUAN 32-9 UNIT #251		14269	SJ 32-9		31N09W04		1		21		1,964		51		189		23		21		0		145		104		478
SAN JUAN 32-9 UNIT #252		14471	SJ 32-9		31N09W05		1		18		1,325		35		127		17		14		0		97		71		479
SAN JUAN 32-9 UNIT #253		14472	SJ 32-9		31N09W05		1		17		1,142		30		110		15		12		0		82		61		504
SAN JUAN 32-9 UNIT #254		14473	SJ 32-9		31N09W06		1		16		981		26		94		14		10		0		70		52		483
SAN JUAN 32-9 UNIT #255		14474	SJ 32-9		31N09W06		1		17		1,030		27		99		14		11		0		74		55		489
SAN JUAN 32-9 UNIT #257		14475	SJ 32-9		31N09W08		1		26		899		23		86		17		9		0		60		37		545
SAN JUAN 32-9 UNIT #258		14476	SJ 32-9		31N09W09		1		21		1,218		32		117		17		13		0		87		60		506
SAN JUAN 32-9 UNIT #259		14477	SJ 32-9		31N09W09		1		20		916		24		88		14		10		0		64		44		490
SAN JUAN 32-9 UNIT #260		14270	SJ 32-9		31N09W10		1		13		693		18		67		10		7		0		49		38		484
SAN JUAN 32-9 UNIT #261		14271	SJ 32-9		31N09W10		1		7		160		4		15		4		2		0		10		8		491
SAN JUAN 32-9 UNIT #262		14478	SJ 32-9		31N09W15		1		20		580		15		56		12		6		0		38		26		492
SAN JUAN 32-9 UNIT #263		14479	SJ 32-9		31N09W15		1		20		671		18		64		12		7		0		45		31		485
SAN JUAN 32-9 UNIT #264		14480	SJ 32-9		31N09W17		1		22		695		18		67		14		7		0		46		30		514
SAN JUAN 32-9 UNIT #268		14482	SJ 32-9		31N10W01		1		14		592		15		57		10		6		0		41		32		535
SAN JUAN 32-9 UNIT #269		14483	SJ 32-9		31N10W01		1		15		543		14		52		10		6		0		37		28		518
SAN JUAN 32-9 UNIT #270		14484	SJ 32-9		32N09W18		1		24		2,999		78		288		32		31		0		225		157		519
SAN JUAN 32-9 UNIT #271		14485	SJ 32-9		32N09W18		1		23		3,188		83		306		33		33		0		240		170		520
SAN JUAN 32-9 UNIT #272		5838	SJ 32-9		32N09W21		1		8		192		5		18		4		2		0		12		10		1366
SAN JUAN 32-9 UNIT #273		14486	SJ 32-9		32N09W19		1		9		850		22		82		10		9		0		63		53		521
SAN JUAN 32-9 UNIT #274		14272	SJ 32-9		32N09W28		1		25		2,175		57		209		26		23		0		160		109		575
SAN JUAN 32-9 UNIT #275		14487	SJ 32-9		32N09W29		1		14		739		19		71		11		8		0		52		41		536
SAN JUAN 32-9 UNIT #276		14344	SJ 32-9		32N09W27		1		17		1,211		32		116		16		13		0		88		66		579
SAN JUAN 32-9 UNIT #277		14488	SJ 32-9		32N09W30		1		21		1,774		46		170		22		19		0		130		92		516
SAN JUAN 32-9 UNIT #278		14489	SJ 32-9		32N09W31		1		18		1,239		32		119		16		13		0		90		65		515
SAN JUAN 32-9 UNIT #279		14490	SJ 32-9		32N09W31		1		18		1,286		34		124		17		13		0		94		69		528
SAN JUAN 32-9 UNIT #281		14491	SJ 32-9		32N09W32		1		21		1,207		31		116		17		13		0		86		60		470

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 32-9 UNIT #282		14345	SJ 32-9		32N09W33		1		20		1,393		36		134		18		15		0		101		72		522
SAN JUAN 32-9 UNIT #283		14346	SJ 32-9		32N09W33		1		22		2,004		52		192		24		21		0		148		103		480
SAN JUAN 32-9 UNIT #284		14492	SJ 32-9		32N10W13		1		16		1,701		44		163		19		18		0		126		97		523
SAN JUAN 32-9 UNIT #285		14493	SJ 32-9		32N10W13		1		15		1,424		37		137		16		15		0		105		83		537
SAN JUAN 32-9 UNIT #286		14494	SJ 32-9		32N10W14		1		19		2,231		58		214		24		23		0		167		123		493
SAN JUAN 32-9 UNIT #287		14495	SJ 32-9		32N10W14		1		16		1,628		42		156		19		17		0		121		93		533
SAN JUAN 32-9 UNIT #288		14496	SJ 32-9		32N10W23		1		12		1,077		28		103		13		11		0		79		64		534
SAN JUAN 32-9 UNIT #289		14497	SJ 32-9		32N10W23		1		21		2,283		60		219		26		24		0		170		121		524
SAN JUAN 32-9 UNIT #291		14498	SJ 32-9		32N10W24		1		16		1,211		32		116		15		13		0		88		66		505
SAN JUAN 32-9 UNIT #292		14499	SJ 32-9		32N10W25		1		22		2,059		54		198		24		22		0		152		106		525
SAN JUAN 32-9 UNIT #293		14500	SJ 32-9		32N10W25		1		14		1,265		33		121		15		13		0		93		73		494
SAN JUAN 32-9 UNIT #294		14501	SJ 32-9		32N10W26		1		18		1,150		30		110		16		12		0		83		61		529
SAN JUAN 32-9 UNIT #295		14502	SJ 32-9		32N10W26		1		18		1,254		33		120		16		13		0		91		67		526
SAN JUAN 32-9 UNIT #296		13928	SJ 32-9		32N10W35		1		10		375		10		36		6		4		0		26		21		560
SAN JUAN 32-9 UNIT #297		13929	SJ 32-9		32N10W35		1		6		146		4		14		3		2		0		9		8		527
SAN JUAN 32-9 UNIT #300		14503	SJ 32-9		32N10W11		1		15		1,512		39		145		17		16		0		112		87		507
SAN JUAN 32-9 UNIT #301		14504	SJ 32-9		32N10W12		1		26		2,688		70		258		30		28		0		200		135		508
SAN JUAN 32-9 UNIT #302		15548	SJ 32-9		32N09W09		1		19		1,405		37		135		18		15		0		102		74		658
SAN JUAN 32-9 UNIT #303 COM		12172	SJ 32-9		31N10W14		1		27		651		9		33		8		4		0		22		13		1261
SEYMOUR #720		14357	NON-UNIT		31N09W23		1		17		973		71		262		40		29		0		194		144		540
STATE GAS COM AA #1		14441	NON-UNIT		30N08W36		1		28		1,500		30		109		16		12		0		81		51		542
YAGER N COM #5		4873	NON-UNIT		31N07W03		1		8		114		2		9		3		1		0		5		4		450
TOTAL PROVED DEVELOPED: 320-Acre New Mexico							646				624,111		49,166		180,934		27,904		19,708		0		133,323		94,380
TOTAL PROVED DEVELOPED: NEW MEXICO							1052				910,164		74,402		273,803		41,343		29,823		0		202,637		147,402
PROVED UNDEVELOPED RESERVES
FC STATE COM #19A		10781	NON-UNIT		30N09W36		1		19		700		14		51		8		6		24		13		2		1346
FEDERAL G #4A COM		5796	SJ 32-7		31N07W10		1		23		1,900		81		296		37		32		56		171		76		1129
FRT 18-30N-7W (160-ACRE)		6048	NEBU		30N07W18		1		19		1,200		9		34		4		4		9		17		9		1062
FRT 26-32N-11W		10780	NON-UNIT		32N11W26		1		21		1,000		56		205		31		22		73		78		26		1204
GRASSY CANYON UNIT #3A		5809	SJ 32-7		32N07W31		1		25		2,700		177		653		76		71		87		419		211		1130
HEIZER #100S		5114	NON-UNIT		32N10W15		1		19		1,000		0		2		0		0		1		1		0		1005
NE BLANCO UNIT #404A		6026	NEBU		31N07W34		1		20		1,400		11		40		5		4		9		22		11		1060
NE BLANCO UNIT #414A		6023	NEBU		31N07W30		1		21		1,400		11		40		5		4		9		22		10		1054
NE BLANCO UNIT #417A		5274	NEBU		30N07W02		1		17		600		5		17		3		2		9		4		0		832
NE BLANCO UNIT #419A		6031	NEBU		30N07W03		1		18		900		7		26		4		3		9		10		4		824
NE BLANCO UNIT #420A		5279	NEBU		31N07W28		1		19		900		7		26		4		3		9		10		4		1065
NE BLANCO UNIT #421A		6033	NEBU		30N07W04		1		19		900		7		26		4		3		9		10		4		825
NE BLANCO UNIT #423A		6037	NEBU		30N07W08		1		18		800		6		23		3		2		9		8		3		827

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
NE BLANCO UNIT #424A		6034	NEBU		30N07W04		1		20		900		7		26		4		3		9		10		4		1035
NE BLANCO UNIT #427A		5148	NEBU		30N07W16		1		18		600		5		17		3		2		9		4		0		770
NE BLANCO UNIT #429A		5150	NEBU		30N07W17		1		17		700		5		20		3		2		9		6		1		771
NE BLANCO UNIT #431A		6046	NEBU		30N07W17		1		20		700		5		20		3		2		9		6		1		829
NE BLANCO UNIT #432A		5160	NEBU		30N07W07		1		19		900		7		26		4		3		9		10		4		1014
NE BLANCO UNIT #444A		6016	NEBU		31N07W23		1		20		1,100		9		31		4		3		9		15		7		1046
NE BLANCO UNIT #446A		6024	NEBU		31N07W33		1		20		1,200		9		34		4		4		9		17		8		1058
NE BLANCO UNIT #453A		6036	NEBU		30N07W06		1		18		1,200		9		34		4		4		9		17		9		1036
NE BLANCO UNIT #456A		6015	NEBU		31N07W26		1		17		800		6		23		3		2		9		8		3		1049
NE BLANCO UNIT #457		6022	NEBU		31N07W30		1		19		1,400		11		40		5		4		9		22		12		1066
NE BLANCO UNIT #457A		6014	NEBU		31N07W31		1		20		1,400		11		40		5		4		9		22		11		1055
NE BLANCO UNIT #459A		5800	NEBU		31N07W19		1		19		1,300		10		37		4		4		9		20		10		1043
NE BLANCO UNIT #467A		5269	NEBU		30N08W12		1		18		900		7		26		4		3		9		10		4		1061
NE BLANCO UNIT #469A		6007	NEBU		30N08W13		1		18		800		6		23		3		2		9		8		3		1040
NE BLANCO UNIT #470A		6021	NEBU		31N07W27		1		20		1,000		8		29		4		3		9		13		5		1050
NE BLANCO UNIT #472A		5803	NEBU		31N07W29		1		20		1,400		11		40		5		4		9		22		11		1052
NE BLANCO UNIT #473A		5281	NEBU		31N08W36		1		18		1,400		11		40		5		4		9		22		13		1067
NE BLANCO UNIT #475A		1787	NEBU		30N07W19		1		16		600		5		17		3		2		9		4		0		837
NE BLANCO UNIT #477S		1777	NEBU		30N07W29		1		17		700		5		20		3		2		9		6		1		1276
NE BLANCO UNIT #479A		1785	NEBU		30N07W20		1		16		600		5		17		3		2		9		4		0		839
NE BLANCO UNIT #488A		6019	NEBU		31N07W24		1		19		1,200		9		34		4		4		9		17		8		1047
NE BLANCO UNIT #489A		5792	NEBU		31N07W12		1		21		1,500		12		43		5		5		9		24		11		1039
NE BLANCO UNIT #494A		6020	NEBU		31N07W27		1		19		1,000		8		29		4		3		9		13		6		1051
NE BLANCO UNIT #505A		1784	NEBU		30N07W21		1		16		600		5		17		3		2		9		4		0		838
NORDHAUS #716S		5839	NON-UNIT		31N09W13		1		17		800		58		214		35		23		97		59		15		1131
SAN JUAN 28-6 UNIT #400S		6101	SJ 28-6		28N06W09		1		18		800		45		166		26		18		73		49		13		1343
SAN JUAN 28-6 UNIT #414S		6100	SJ 28-6		28N06W08		1		18		900		51		187		29		20		73		65		24		1342
SAN JUAN 29-5 UNIT #225A		5111	SJ 29-5		29N05W06		1		21		1,900		245		903		110		98		167		527		286		758
SAN JUAN 29-5 UNIT #231A		5416	SJ 29-5		29N05W05		1		19		1,500		223		822		107		90		195		431		245		1181
SAN JUAN 29-6 UNIT #206A		5409	SJ 29-6		29N06W04		1		19		900		118		434		67		47		167		152		54		904
SAN JUAN 29-6 UNIT #219A		6079	SJ 29-6		29N06W10		1		19		1,200		157		579		79		63		167		270		125		910
SAN JUAN 29-6 UNIT #222A		6083	SJ 29-6		29N06W12		1		23		2,000		262		965		114		105		167		578		278		914
SAN JUAN 29-6 UNIT #223A		6084	SJ 29-6		29N06W12		1		21		2,000		262		965		114		105		167		578		336		913
SAN JUAN 29-6 UNIT #224A		6085	SJ 29-6		29N06W13		1		21		1,000		131		482		72		53		167		190		65		916
SAN JUAN 29-6 UNIT #225A		6086	SJ 29-6		29N06W13		1		19		1,000		131		482		72		53		167		190		78		1337
SAN JUAN 29-6 UNIT #227A		6087	SJ 29-6		29N06W14		1		20		1,700		223		820		101		89		167		463		271		1338
SAN JUAN 29-6 UNIT #235A		5618	SJ 29-6		29N06W34		1		18		900		118		434		67		47		167		152		57		1297
SAN JUAN 29-6 UNIT #246A		5414	SJ 29-6		29N06W08		1		17		800		105		386		61		42		167		115		34		1294
SAN JUAN 29-6 UNIT #247A		6080	SJ 29-6		29N06W10		1		18		1,200		157		579		79		63		167		270		140		1336
SAN JUAN 29-6 UNIT #249A		6097	SJ 29-6		29N06W22		1		18		900		118		434		67		47		167		152		56		1340
SAN JUAN 29-6 UNIT #257A		5645	SJ 29-6		29N06W09		1		19		1,000		131		482		72		53		167		190		76		907

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 29-6 UNIT #258A		6089	SJ 29-6		29N06W16		1		18		800		105		386		61		42		167		115		30		920
SAN JUAN 29-6 UNIT #259A		5644	SJ 29-6		29N06W09		1		19		1,000		131		482		72		53		167		190		80		1301
SAN JUAN 29-6 UNIT #262A		6096	SJ 29-6		29N06W21		1		17		800		105		386		61		42		167		115		34		925
SAN JUAN 29-7 UNIT #538S		6075	SJ 29-7		29N07W26		1		17		800		94		348		54		38		147		109		34		1333
SAN JUAN 29-7 UNIT #544S		6053	SJ 29-7		29N07W04		1		17		700		83		304		50		33		147		74		11		884
SAN JUAN 29-7 UNIT #546S		6054	SJ 29-7		29N07W04		1		17		700		83		304		50		33		147		74		11		1324
SAN JUAN 29-7 UNIT #551S		6066	SJ 29-7		29N07W11		1		17		700		230		846		137		92		407		209		33		1330
SAN JUAN 29-7 UNIT #552S		6067	SJ 29-7		29N07W12		1		17		800		94		348		54		38		147		109		34		893
SAN JUAN 29-7 UNIT #553S		1546	SJ 29-7		29N07W14		1		17		800		94		348		54		38		147		109		34		901
SAN JUAN 29-7 UNIT #560S		6072	SJ 29-7		29N07W23		1		17		700		290		1,067		175		116		519		257		36		1331
SAN JUAN 29-7 UNIT #562S		6071	SJ 29-7		29N07W24		1		21		1,100		130		478		68		52		147		211		86		896
SAN JUAN 29-7 UNIT #580S		6052	SJ 29-7		29N07W01		1		19		700		83		304		50		33		147		74		9		881
SAN JUAN 30-5 UNIT #204A		5685	SJ 30-5		30N05W07		1		19		1,000		170		627		94		68		219		246		100		1303
SAN JUAN 30-5 UNIT #205A		5678	SJ 30-5		30N05W07		1		19		1,000		170		627		94		68		219		246		101		1302
SAN JUAN 30-5 UNIT #211A		5783	SJ 30-5		30N05W31		1		18		1,200		226		831		113		91		241		387		198		986
SAN JUAN 30-5 UNIT #224A		5719	SJ 30-5		30N05W17		1		19		900		169		623		96		68		241		218		71		966
SAN JUAN 30-5 UNIT #232A		5786	SJ 30-5		30N05W33		1		20		1,700		290		1,066		132		116		219		599		353		1307
SAN JUAN 30-5 UNIT #233A		5787	SJ 30-5		30N05W33		1		20		1,700		320		1,177		145		128		241		663		376		988
SAN JUAN 30-5 UNIT #235A		5743	SJ 30-5		30N05W27		1		18		900		153		565		88		61		219		196		73		1306
SAN JUAN 30-5 UNIT #236A		5742	SJ 30-5		30N05W27		1		18		900		153		565		88		61		219		196		71		1305
SAN JUAN 30-5 UNIT #246A		5741	SJ 30-5		30N05W26		1		18		800		150		554		88		60		241		165		44		978
SAN JUAN 30-5 UNIT #248A		11693	SJ 30-5		30N05W35		1		19		1,000		149		550		84		60		195		211		87		1347
SAN JUAN 30-5 UNIT #262A		5791	SJ 30-5		30N05W12		1		19		1,000		188		692		103		75		241		273		112		960
SAN JUAN 30-6 UNIT #406S		6043	SJ 30-6		30N07W15		1		18		600		30		110		19		12		64		15		-5		861
SAN JUAN 30-6 UNIT #407S		5527	SJ 30-6		30N06W16		1		15		600		30		110		19		12		64		15		-6		849
SAN JUAN 30-6 UNIT #416S		5519	SJ 30-6		30N07W24		1		15		600		30		110		19		12		64		15		-6		783
SAN JUAN 30-6 UNIT #417S		5429	SJ 30-6		30N07W25		1		17		800		40		147		23		16		64		43		13		762
SAN JUAN 30-6 UNIT #418S		5522	SJ 30-6		30N07W26		1		15		600		30		110		19		12		64		15		-6		784
SAN JUAN 30-6 UNIT #423S		1782	SJ 30-6		30N07W28		1		16		700		35		129		22		14		64		29		3		1280
SAN JUAN 30-6 UNIT #428S		1783	SJ 30-6		30N07W28		1		17		700		35		129		22		14		64		29		2		1281
SAN JUAN 30-6 UNIT #440S		5526	SJ 30-6		30N06W15		1		15		600		30		110		19		12		64		15		-6		847
SAN JUAN 30-6 UNIT #441S		5495	SJ 30-6		30N06W31		1		15		600		30		110		19		12		64		15		-6		792
SAN JUAN 30-6 UNIT #453S		5528	SJ 30-6		30N06W17		1		15		600		30		110		19		12		64		15		-6		851
SAN JUAN 30-6 UNIT #456S		5531	SJ 30-6		30N06W18		1		16		600		30		110		19		12		64		15		-6		852
SAN JUAN 30-6 UNIT #458S		5532	SJ 30-6		30N06W19		1		18		700		35		129		22		14		64		29		2		854
SAN JUAN 30-6 UNIT #459S		5533	SJ 30-6		30N06W20		1		17		800		40		147		23		16		64		43		12		855
SAN JUAN 30-6 UNIT #465S		5507	SJ 30-6		30N07W15		1		15		600		30		110		19		12		64		15		-6		802
SAN JUAN 30-6 UNIT #470S		5534	SJ 30-6		30N06W21		1		17		800		40		147		23		16		64		43		12		856
SAN JUAN 30-6 UNIT #472S		5536	SJ 30-6		30N06W22		1		18		800		40		147		23		16		64		43		12		857
SAN JUAN 30-6 UNIT #474S		5540	SJ 30-6		30N06W27		1		17		800		40		147		23		16		64		43		12		866
SAN JUAN 30-6 UNIT #480S		5543	SJ 30-6		30N06W30		1		18		700		35		129		22		14		64		29		2		862

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	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, 2006

																OPER.						BFIT NET
								LIFE		GROSS GAS		NET GAS		REVENUE TO		EXPENSE		ADV&SEV		CAPITAL		REVENUE		10% DISC
LEASE NAME	PROPID		UNIT	LOCATION		WELLS		YEARS		MMCF		MMCF		INT. M$		M$		TAXES M$		M$		M$		REVENUE M$		SEQ NUM
SAN JUAN 30-6 UNIT #492S		5538	SJ 30-6		30N06W26		1		18		600		30		110		19		12		64		15		-4		1296
SAN JUAN 30-6 UNIT #498S		1779	SJ 30-6		30N07W30		1		18		700		104		382		66		42		195		80		2		1278
SAN JUAN 30-6 UNIT #499S		1780	SJ 30-6		30N07W30		1		17		700		35		129		22		14		64		29		2		1279
SAN JUAN 30-6 UNIT #501SR		5496	SJ 30-6		30N06W32		1		18		800		40		147		23		16		64		43		11		815
SAN JUAN 31-6 UNIT #220A		1791	SJ 31-6		31N06W33		1		17		800		86		315		51		34		140		89		24		1285
SAN JUAN 31-6 UNIT #221A		1801	SJ 31-6		31N06W33		1		17		800		86		315		51		34		140		89		24		1286
SAN JUAN 31-6 UNIT #222A		1803	SJ 31-6		31N06W32		1		17		600		64		236		42		26		140		28		-13		1287
SAN JUAN 31-6 UNIT #224A		708	SJ 31-6		31N06W31		1		15		600		64		236		42		26		140		28		-15		1164
SAN JUAN 31-6 UNIT #225A		5611	SJ 31-6		31N06W31		1		16		600		64		236		42		26		140		28		-15		1163
SAN JUAN 31-6 UNIT #228A		1806	SJ 31-6		31N06W28		1		20		1,400		150		552		73		60		140		278		128		1289
SAN JUAN 31-6 UNIT #232A		6029	SJ 31-6		30N07W01		1		15		600		64		236		42		26		140		28		-16		934
SAN JUAN 31-6 UNIT #233A		1805	SJ 31-6		31N06W29		1		20		1,400		150		552		73		60		140		278		128		1288
SAN JUAN 32-9 UNIT #105S		5956	SJ 32-9		31N09W08		1		15		600		16		58		10		6		34		7		-3		1084
SAN JUAN 32-9 UNIT #209S		5862	SJ 32-9		31N10W02		1		19		600		16		58		10		6		34		7		-2		1316
SAN JUAN 32-9 UNIT #210S		5865	SJ 32-9		31N10W02		1		18		600		57		209		37		23		122		28		-8		1317
SAN JUAN 32-9 UNIT #220S		5897	SJ 32-9		31N10W11		1		20		1,000		26		96		14		10		34		37		14		1090
SAN JUAN 32-9 UNIT #221S		5890	SJ 32-9		31N10W11		1		19		1,000		26		96		14		10		34		37		15		1091
SAN JUAN 32-9 UNIT #242A		764	SJ 32-9		32N09W14		1		21		900		23		86		14		9		34		30		8		1442
SAN JUAN 32-9 UNIT #258S		5958	SJ 32-9		31N09W09		1		18		700		18		67		11		7		34		15		1		1086
SAN JUAN 32-9 UNIT #296S		5853	SJ 32-9		32N10W35		1		21		1,000		26		96		14		10		34		37		12		1123
YAGER N COM #5A		6009	SJ 32-7		31N07W03		1		22		2,000		42		153		19		17		27		91		49		1128
TOTAL PROVED UNDEVELOPED: 160-Acre New Mexico							116				111,676		8,570		31,539		4,618		3,435		11,155		12,331		5,022
FRT 18-30N-7W		6047	NEBU		30N07W18		1		20		1,200		9		34		4		4		9		17		8		1042
TOTAL PROVED UNDEVELOPED: 320-Acre New Mexico							1				1,200		9		34		4		4		9		17		8
TOTAL PROVED UNDEVELOPED: NEW MEXICO							117				112,876		8,580		31,574		4,622		3,439		11,164		12,349		5,030
TOTAL PROVED RESERVES: NEW MEXICO							1169				1,023,040		82,981		305,377		45,965		33,262		11,164		214,985		152,431
TOTAL PROVED RESERVES							1190				1,056,132		89,741		324,290		45,965		33,262		11,164		233,898		165,171

	TABLE 4
This page is a part of a Miller and Lents, Ltd. report and should not be used independently of the report.	Page 30 of 30