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, 2009

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 U.S. Trust, Bank of America Private Wealth Management 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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o 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, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o
		(Do not check if a smaller reporting company)

     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, 2009, 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 $45,088,188.

     At March 31, 2010, 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
Termination and Liquidation of the Trust		6
Assets of the Trust		7
Liabilities of the Trust		8
Duties and Limited Powers of the Trustee		8
Liabilities of the Delaware Trustee and the Trustee		9
DESCRIPTION OF UNITS		9
Distributions and Income Computations		9
Transfer of Royalty Interests		10
Possible Divestiture of Units		10
Periodic Reports to Unitholders		10
Voting Rights of Unitholders		11
Liability of Unitholders		11
Transfer Agent		12
Website/SEC Filings		12
FEDERAL INCOME TAXATION		12
Summary of Certain Federal Income Tax Consequences		14
ERISA CONSIDERATIONS		15
STATE TAX CONSIDERATIONS		16
REGULATION AND PRICES		16
Regulation of Natural Gas		16
Environmental Regulation		17
Competition, Markets and Prices		18
Item 1A. Risk Factors		19
Item 1B. Unresolved Staff Comments		23
Item 2. Properties		24
THE ROYALTY INTERESTS		24
The Underlying Properties		25
The NPI		27
Reserve Report		28
Historical Gas Sales Prices and Production		30
NPI Percentage Reduction		31
Gas Purchase Contract		31
Gas Gathering Contract		33
Federal and Indian Lands		34
Sale and Abandonment of Underlying Properties		35
The Infill Wells		35
Royalty Trust Reserves		36
Williams’ Performance Assurances		36
Title to Properties		37
Item 3. Legal Proceedings		38
Item 4. Reserved		38
PART II		38
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		38
Item 6. Selected Financial Data		39
Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations		39
Critical Accounting Policies and Estimates		40

	Page
Liquidity and Capital Resources		41
Results of Operations		41
Off-Balance Sheet Arrangements		43
Tabular Disclosure of Contractual Obligations		44
Forward-Looking Statements		44
Item 7A. Quantitative and Qualitative Disclosure About Market Risk		44
Item 8. Financial Statements and Supplementary Data		45
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		56
Item 9A. Controls and Procedures		56
Item 9B. Other Information		56
PART III		57
Item 10. Directors, Executive Officers and Corporate Governance		57
Item 11. Executive Compensation		57
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		58
Williams’s Voting Authority Over Units		58
Item 13. Certain Relationships and Related Transactions, and Director Independence		59
Administrative Services Agreement		59
Potential Conflicts of Interest		59
Item 14. Principal Accounting Fees and Services		59
PART IV		60
Item 15. Exhibits and Financial Statement Schedules		60
Commission and Exclusive Agency Agreement
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, 2009 Reserve Report” means the Reserve Report, dated February 12, 2010, 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, 2009, 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 The Bank of New York Mellon Trust Company, N.A. (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 applicable provisions of the IRC and the Treasury Regulations thereunder.

     “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 working 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.

     “Treasury Regulations” shall mean the United States treasury regulations promulgated under the IRC.

     “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, The Bank of New York Mellon Trust Company, N.A. (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. In 2007 the Bank of America private wealth management group officially became known as “U.S. Trust, Bank of America Private Wealth Management.” The legal entity that serves as Trustee of the Trust did not change,

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and references in this Form 10-K to U.S. Trust, Bank of America Private Wealth Management shall describe the legal entity Bank of America, N.A.

     “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; The Bank of New York Mellon Trust Company, N.A. (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. In accordance with the terms of the Trust Agreement, the Trust is required to

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terminate effective as of March 1, 2010, and the Trustee is required to use best efforts to sell the Royalty Interests and liquidate the Trust. See “Termination and Liquidation of the Trust” below for additional information. 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 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, 2009 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

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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.

Termination and Liquidation of the Trust

     The following is a description of the termination and liquidation provisions in the Trust Agreement. Please also see “Item 7 – Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8 – Financial Statements and Supplementary Data” for information regarding the current status of the termination events as described below.

     Pursuant to the terms of the Trust Agreement, the Trust is required to terminate effective March 1, 2010 (the “Termination Date”) because, based on a reserve report as of December 31, 2009, it was determined that, as of such date, the net present value (discounted at 10 percent) of the estimated future net revenues (calculated in accordance with criteria established by the SEC) for proved reserves attributable to the Royalty Interests but using the average monthly Blanco Hub Spot Price (including no consideration for the Gas Purchase Contract) for the past calendar year less certain gathering costs was equal to or less than $30 million thereby triggering a termination of the Trust. Based on a report prepared by independent petroleum engineers, the Trust’s computed net present value of the estimated future net revenues for proved reserves attributable to the Royalty Interests calculated in accordance with the Trust Agreement was approximately $8.4 million as of December 31, 2009. This calculation does not necessarily represent the fair value of the Underlying Properties.

     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, if any, are distributed to Unitholders.

     Upon the termination of the Trust, the Trustee is obligated to 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 has retained Albrecht & Associates, Inc., an investment banking firm (the “Advisor”), on behalf of the Trust who will assist the Trustee in selling the remaining Royalty Interests owned by the Trust (the “Remaining Royalty Interests”). WPC has the right, but not the obligation, to make a cash offer to purchase all Remaining Royalty Interests following termination of the Trust as described in the following paragraph.

     WPC may, within 60 days following the Termination Date, make a cash offer to purchase all of the Remaining Royalty Interests then held by the Trust. In the event such an offer is made by WPC, the Trustee will decide, based on the recommendation of the Advisor, to either (i) accept such offer (in which case no sale to WPC will be made unless a fairness opinion is given by the Advisor that the purchase price is fair to the Trust and Unitholders) or (ii) defer action on such offer. If the Trustee defers action on WPC’s offer, the offer will be deemed withdrawn and the Trustee will then use Best Efforts, assisted by the Advisor to obtain alternative offers for the Remaining Royalty Interests. At the end of a 120-day period following the Termination Date, the Trustee is required to notify WPC of the highest of any other offers (net of any commissions or other fees payable by the Trust), acceptable to the Trustee (which must be an all-cash offer), received during such period (the “Highest Acceptable Offer”). WPC then has the exclusive right (whether or not it made an initial offer), but not the obligation, to purchase all Remaining Royalty Interests for a cash purchase price computed as follows: (i) if the Highest Acceptable Offer is more than 105 percent of WPC’s initial offer (or if WPC did not make an initial offer), the purchase price will be 105 percent of the Highest Acceptable Offer, or (ii) if the Highest Acceptable Offer is equal to or less than 105 percent of WPC’s initial offer, the purchase price will be equal to the Highest Acceptable Offer. If no other acceptable offers are received for all Remaining Royalty Interests, the Trustee may request WPC to submit another offer for consideration by the Trustee and may accept or reject such offer. Acceptance of an offer by the Trustee shall be conditioned upon the opinion of the Advisor of the fairness of the offer.

     If a sale of the Remaining Royalty Interests is made or a definitive contract for sale of the Remaining Royalty Interests is entered into within a 150-day period following the Termination Date, the buyer of the Remaining Royalty Interests, and not the Trust or Unitholders, will be entitled to all proceeds of production attributable to the Remaining Royalty Interests following the Termination Date. All proceeds of production following the Termination Date attributable to the Remaining Royalty Interests will be deposited into a non-interest bearing account until they are paid to the buyer or otherwise distributed in accordance with the Trust Agreement.

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     In the event that WPC does not purchase the Remaining Royalty Interests, the Trustee may accept any offer for all or any part (not more than six parts) of the Remaining Royalty Interests as it deems to be in the best interests of the Trust and Unitholders and may continue, for up to one calendar year after the Termination Date, to attempt to locate a buyer or buyers of the Remaining Royalty Interests in order to sell such interests in an orderly fashion not involving a public auction. If any Remaining Royalty Interests have not been sold or a definitive agreement for sale has not been entered into by the end of such calendar year, the Trustee is required to sell the Remaining Royalty Interests at public auction to the highest cash bidder, which sale may be to WPC or any of its affiliates. Notice of such sale by auction shall be mailed at least 30 days prior to such sale to each Unitholder at his address as it appears on the ownership ledger of the Trustee.

     WPC’s purchase rights, as described, may be exercised by WPC and each of its successors-in-interest and assigns. WPC’s purchase rights are fully assignable by WPC to any person. The costs of liquidation, including the fees and expenses of the Advisor, and the Trustee’s liquidation fee will be paid by the Trust.

     The sale of the Remaining Royalty Interests following the termination of the Trust will be taxable events to the Unitholders for Federal Income tax purposes. Generally, a Unitholder will realize gain or loss equal to the difference between the amount realized on the sale of the Remaining Royalty Interests upon termination of the Trust and his adjusted basis in such Units. Gain or loss realized by a Unitholder who is not a dealer with respect to such Units and who has a holding period for the Units of more than one year will be treated as long-term capital gain or loss except to the extent of any depletion recapture amount, which must be treated as ordinary income. State tax consequences may also result to Unitholders upon the termination of the Trust and the sale of the Remaining Royalty Interests. Other Federal and state tax issues concerning the Trust are discussed herein under “Item 1—Federal Income Taxation and State Tax Considerations.” Each Unitholder should consult his own tax advisor regarding Trust tax compliance matters, including Federal and state tax implications concerning the sale of the Remaining Royalty Interests following the termination of the Trust.

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 442 infill locations designated as proved locations according to U.S. Securities and Exchange Commission (“SEC”) guidelines. As of December 31, 2009, all of these infill locations represent proved developed producing reserves, while there are no proved undeveloped locations.

     WPC has informed the Trustee that the Infill Wells reached payout in the aggregate during 2008. The Trust has received its 20 percent interest in WPC’s Infill Net Proceeds for periods after payout. However, during 2009, WPC informed the Trustee that due to the net deficit realized by the Infill Wells during the third and fourth quarters, the Infill Net Profit Costs now exceed the Infill Net Profit Gross Proceeds by approximately $32,500. The Trust will not be liable for such excess costs, and such excess costs will hereafter constitute Excess Infill Net Profit Costs until

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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. See “Item 2—Properties—The Royalty Interests” for more information generally and Note 9 to “Item 8—Financial Statements and Supplementary Data—Notes to Financial Statements” for information regarding the net proved reserves attributable to the Trust.

Liabilities of the Trust

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

Duties and Limited Powers of the Trustee

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

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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).

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, 2010, there were 9,700,000 Units outstanding. The Trust may not issue additional Units.

Distributions and Income Computations

          In accordance with the Trust Agreement, all proceeds of production attributable to the Remaining Royalty Interests will be deposited into a separate account effective as of the March 1, 2010 Termination Date. If a sale of the Remaining Royalty Interests is made or a definitive agreement for sale of the Remaining Royalty Interests is entered into within a 150-day period following the Termination Date, the buyer of the Remaining Royalty Interests, and not the Trust or the Unitholders, will be entitled to all proceeds of production attributable to the Remaining Royalty Interests following the Termination Date. Through the Termination Date, 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 a 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 45^th 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. If applicable, a

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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 15^th 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. Any applicable distribution to Unitholders would 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 1—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 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.

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          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. See also “Item 1—Federal Income Taxation, WHFIT Reporting Requirements” regarding certain reporting requirements imposed upon middlemen because the Trust is considered a WHFIT for Federal income tax purposes.

          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 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.

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Transfer Agent

          The Trustee has appointed American Stock Transfer, 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.

          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.

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Termination and Liquidation of the Trust

          In connection with the termination of the Trust and the resulting liquidation of the Trust pursuant to the provisions of the Trust Agreement, the Trust will not incur any Federal income tax liability at the Trust level as a result of the sale of the Remaining Royalty Interests or payment to Unitholders of the net proceeds from such sale. However, for Federal income tax purposes, the sale of the Remaining Royalty Interests will be taxable to the Unitholders. Each Unitholder will recognize gain or loss on such sale measured by the difference between the Unitholder’s share of the amount realized from the sale of the Remaining Royalty Interests and such Unitholder’s adjusted basis in his or her Units. The amount realized from the sale of the Remaining Royalty Interests will be allocated to Unitholders in the same manner as the Trustee allocates the income received by the Trust.

          Prior to determining the gain or loss resulting from the sale of the Remaining Royalty Interests following the liquidation of the Trust, each Unitholder should reduce his tax basis (but not below zero) in the Remaining Royalty Interests (and, correspondingly, his Units) by (1) the amount of depletion allowable with respect to the Remaining Royalty Interests through the date of the liquidation, and (2) by the amount of any return of capital, including returns of capital resulting from a reduction to the cash reserve maintained by the Trust during a quarterly period.

          Assuming a Unitholder holds his or her Units as a capital asset, gain or loss from the sale of the Remaining Royalty Interests will be treated as a capital gain or loss. If the Units have been held for more than one year, the gain or loss will constitute a long-term capital gain or loss; otherwise, the gain or loss will constitute a short-term capital gain or loss. Notwithstanding the foregoing, a Unitholder must, upon the sale of the Remaining Royalty Interests, treat as ordinary income his or her depletion recapture amount, which is an amount equal to the lesser of (i) the gain on the sale of the Remaining Royalty Interests or (ii) the sum of the prior depletion deductions taken with respect to the Remaining Royalty Interests (but not in excess of the initial basis of such Units allocated to the Remaining Royalty Interests).

          The Trust is treated as a grantor trust for Federal income tax purposes. As a result, each Unitholder will be treated as owning directly an interest in the Remaining Royalty Interests, and each Unitholder will be taxed directly on his or her pro rata share of income and deductions attributable to the Remaining Royalty Interests consistent with the Unitholder’s method of accounting and without regard to the taxable year or accounting method employed by the Trust. Since the inception of the Trust, for purposes of reporting income and deductions from the Trust, both cash and accrual-basis Unitholder’s have been allocated and treated as realizing income and incurring deductions only on the quarterly record dates for each quarter. The Trust distributes cash within 60 days after the end of each calendar quarter to Unitholder of record on the associated record date.

          Upon the termination of the Trust, the Trust Agreement provides that any purchaser of the Remaining Royalty Interests, regardless of the date of closing of the purchase, shall be entitled to all proceeds of production attributable to the Remaining Royalty Interests after the date of the termination of the Trust and neither the Trust nor the Unitholders shall be entitled to any such proceeds (the “Purchaser Allocation Proceeds”). However, in the event that all the Remaining Royalty Interests are not, for any reason, sold or a definitive agreement for sale thereof entered into prior to the 150^th day following the date of the termination of the Trust, the Purchaser Allocation Proceeds, and all amounts thereafter payable to the Trust, shall be distributed instead to the Unitholders in accordance with the provisions of the Trust Agreement.

          The proceeds from the sale of the Remaining 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. No assurances can be given as to the amount, or timing, or distributions, if any, to Unitholders of the Trust, as such amount and timing would depend in part on the amount of expenses ultimately payable by the Trust and when such expenses become payable and the net sales price of the Remaining Royalty Interests and when the sale of the Remaining Royalty Interests occurs.

          Unitholders should consult their own tax advisors regarding the Federal income tax consequences of the sale of the Remaining Royalty Interests following the termination of the Trust.

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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 2009, the Trust earned interest income on funds held for distribution. The deductions of the Trust consist of severance taxes and administrative expenses. In addition, each Unitholder is entitled to depletion deductions. See “Unitholder’s Depletion Allowance” below.
	Individuals may deduct “miscellaneous” itemized deductions (including, in general, investment expenses) only to the extent that such expenses exceed 2 percent of the individual’s adjusted gross income. Although there are exceptions to the 2 percent limitation, authority suggests that no exceptions apply to expenses passed through from a grantor trust, like the Trust.
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. Unlike cost depletion, percentage depletion is not limited to a Unitholder’s depletable tax basis in the Units. Rather, a Unitholder is entitled to a percentage depletion deduction as long as the applicable Underlying Properties generate 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

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	generally must recapture the amount deducted for depletion as 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” and “WHFIT Reporting Requirements” immediately below for additional Unitholder reporting information.
WHFIT Reporting Requirements	Some Trust Units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name, referred to herein collectively as “middlemen”). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. U.S. Trust, Bank of America Private Wealth Management, EIN: 56-0906604, 901 Main Street, 17th Floor, Dallas, Texas 75202, telephone number (214) 209-2400, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHIFT. Tax information is also posted by the Trustee at www.wtu-williamscoalseamgastrust.com. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of Unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such Trust Units, including the issuance of IRS Form 1099 and certain written tax statements. Unitholders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units.

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

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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.

          The sale of the Remaining Royalty Interests following the termination of the Trust may be taxable events to the Unitholders for state tax purposes. Unitholders should consult their own tax advisors regarding the state tax consequences of the sale of the Remaining Royalty Interests following the termination of the Trust.

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 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.

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

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

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

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

Environmental Regulation

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

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

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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. In addition, there is an increased focus by local, national and international regulatory bodies on green house gas (GHG) emissions and climate change. Various regulatory bodies have announced their intent to regulate GHG emissions.

          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 varied over the past several years. These variations were in response to stronger domestic economic conditions, relatively higher prices for alternative energy sources such as crude oil, and other factors. However, in the recent short term, decreased demand for natural gas production in the United States has generally resulted in lower natural gas prices. The existence or effect of any shortages or excesses of natural gas

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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.

The Trust terminated on March 1, 2010 and will be required to sell its remaining Royalty Interests.

          The Trust’s computed net present value of the estimated future net revenues for proved reserves attributable to the Royalty Interests computed in accordance with the Trust Agreement, using an average 2009 index price of $3.25, by the independent petroleum engineers as of December 31, 2009, was approximately $8.4 million. This calculation does not necessarily represent the fair value of the Underlying Properties. The results of this computation triggered an early termination of the Trust as of March 1, 2010 in accordance with the terms of the Trust Agreement. In accordance with the Trust Agreement, the Trustee is required to use best efforts to sell any remaining Royalty Interests for cash pursuant to the procedures described in the Trust Agreement. There can be no assurance that any sale will be on terms acceptable to all Unitholders. See “Item 1 — Description of the Trust — Termination and Liquidation of the Trust.”

The Trust will incur expenses in connection with the sale of its remaining Royalty Interests.

          The Trust will incur expenses in connection with the sale of its remaining Royalty Interests and liquidation, including fees and expenses of an investment banking firm to assist with the sale of the Trust’s remaining Royalty Interests, and the expenses could be significant.

If the Trust has not sold all the Royalty Interests by February 28, 2011, the Trustee is required to sell the remaining Royalty Interests in a public auction.

          If any remaining Royalty Interests have not been sold or a definitive agreement for sale has not been entered into by February 28, 2011, the Trustee is required to sell the remaining Royalty Interests at public auction to the highest cash bidder. A public auction might not result in as favorable a price for the Trust’s remaining Royalty Interests as an individually negotiated transaction.

Natural gas prices are volatile and fluctuate in response to a number of factors. Lower prices could reduce the price a buyer is willing to pay for the Royalty Interests resulting in a reduction of the amount paid to Unitholders upon liquidation of the Trust.

          The price a buyer is willing to pay for the Royalty Interests will be dependent upon the prices realized from the sale of natural gas and a material decrease in such prices could reduce the amount paid to Unitholders upon liquidation of the Trust. 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:

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• 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. 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. Approximately 90 percent of the natural gas produced from the WI Properties, which generates most of the natural gas produced burdened by the Trust’s Royalty Interests, is currently being sold pursuant to the Gas Purchase Contract entered into at the inception of the Trust whereby a subsidiary of Williams purchases the gas in accordance with a contractual pricing mechanism. The Gas Purchase Contract expires no later than December 2012; however, as a result of the early termination of the Trust, it will terminate upon the earlier of August 1, 2010 or the closing date of the sale of the Royalty Interests by the Trust. Under this agreement, the adverse impact on Trust revenues that would otherwise result from low natural gas prices is somewhat mitigated. When it is terminated, revenues attributable to the Royalty Interests will become increasingly susceptible to fluctuations resulting from changes in prevailing natural gas prices which may impact the price a buyer is willing to pay for the Royalty Interests.

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 and the price a buyer is willing to pay for the Royalty Interests 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.

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          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 with respect to the Royalty Interests, 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. 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.

Any distributions upon a termination and liquidation of the Trust may not equal or exceed the purchase price paid by a Unitholder for Units.

          The market price for Trust Units is based on a variety of factors outside the control of the Trustee. There is no guarantee that any distributions upon a termination and liquidation of the Trust will equal or exceed the purchase price paid by the Unitholder.

Funds held by the Trustee are not insured by the Federal Deposit Insurance Corporation.

          Currently, funds are invested in Bank of America money market accounts which are backed by the good faith and credit of Bank of America, N.A., but are not insured by the Federal Deposit Insurance Corporation (“FDIC”). Each Unitholder should independently assess the creditworthiness of Bank of America, N.A. For more information about the credit rating of Bank of America, N.A., please refer to its periodic filings with the SEC. The Trust does not lend money and has limited ability to borrow money, which the Trustee believes limits the Trust’s risk from the current tightening of credit markets.

The 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 has historically tended to be tied to recent and expected levels of cash distribution on the Units. The amounts available for distribution by the Trust varied 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 will realize if it sells those Royalty Interests to a third party buyer. There is no guarantee that distributions made to a Unitholder upon the termination and liquidation of the Trust 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 the price a buyer is willing to pay for the Royalty Interests resulting in a reduction of the amount paid to Unitholders upon liquidation of the Trust.

          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

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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 with respect to the Royalty Interests and could therefore reduce the price a buyer is willing to pay for the Royalty Interests resulting in a reduction of the amount paid to Unitholders upon liquidation of the Trust.

Terrorism and continued hostilities in the Middle East could decrease the market price of the Units or the price a buyer is willing to pay for the Royalty Interests resulting in a reduction of the amount paid to Unitholders upon liquidation of the Trust.

          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 the market price of the Units or the price a buyer is willing to pay for the Royalty Interests resulting in a reduction of the amount paid to Unitholders upon liquidation of the Trust.

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

          Neither the Trustee nor the Unitholders can influence or control the operations on, or future development of, the Underlying Properties. The failure of an operator to conduct its operations, discharge its obligations, deal with regulatory agencies or comply with laws, rules and regulations, including environmental laws and regulations, in a proper manner could have an adverse effect on the net proceeds payable with respect to the Royalty Interests. 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 owed with respect to the Royalty Interests from the transferred property, and the transferor will have no continuing obligation with respect to the Royalty Interests for that property.

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

          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.

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

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equity holders, the Trust is administered by an institutional trustee in accordance with the Trust Agreement and other organizational documents. The Trustee has extremely limited discretion in its administration of the Trust.

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

          The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States, or GAAP. Although this basis of accounting is permitted for royalty trusts by the SEC, the financial statements of the Trust differ from GAAP financial statements because, among other things, revenues are not accrued in the month of production and loss contingencies are recognized in the period in which amounts are paid by the Trust.

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 more infill wells are drilled, they could cause a reduction in amounts payable with respect to the Royalty Interests.

          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 with respect to the Royalty Interests, and the price a buyer is willing to pay for the Royalty Interests. 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 not less than 180 days preceding December 31, 2009, which comments remain unresolved.

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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 (the “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 through the Termination Date.

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

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

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          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 (now known as “BP”) entered into a joint venture under which Northwest agreed to assign to BP 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 1,116 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 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

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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, 2009 prepared by Miller and Lents, Ltd. dated February 12, 2010 (the “December 31, 2009 Reserve Report”) regarding the Federal Units in which the WI Properties participate. At December 31, 2009, the WI Properties covered 1,061 gross (111.72 net) coal seam gas wells with working interests ranging from 0.8334 percent to 75 percent, with an average working interest of approximately 10.53 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, 2009.

		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		4.47		1,308.16
San Juan 32-7	Conoco Phillips Petroleum Company		11.07		7,037.50
San Juan 32-8	Conoco Phillips Petroleum Company		8.04		4,006.74
San Juan 30-6	*Burlington Resources		4.26		2,248.92
San Juan 31-6	Conoco Phillips Petroleum Company		1.44		286.98
San Juan 29-6	Conoco Phillips Petroleum Company		5.01		1,564.96
San Juan 29-7	*Burlington Resources		1.81		1,343.47
San Juan 32-9	*Burlington Resources		1.09		393.30
Northeast Blanco	Devon Energy		0.89		420.91
Huerfano	*Burlington Resources		0.83		360.86
San Juan 29-5	Conoco Phillips Petroleum Company		0.53		213.92
San Juan 28-6	*Burlington Resources		0.25		95.42

*  Burlington Resources is a wholly-owned subsidiary of Conoco Phillips Petroleum Company

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      Well Count and Acreage Summary. The following table shows as of December 31, 2009, 2008, and 2007, 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
2009
Producing		1,102		114.4		150,988		20,681
Nonproducing		0		0		0		0
Total		1,102		114.4		150,988		20,681
2008
Producing		1,070		113.6		150,988		20,681
Nonproducing		5		0.5		0		0
Total		1,075		114.1		150,988		20,681
2007
Producing		1,086		118.7		150,988		20,681
Nonproducing		12		1.0		0		0
Total		1,098		119.7		150,988		20,681

          Of the total gross wells described above at December 31, 2009, 1,061 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 41 proved developed Fruitland formation coal seam gas wells held in areas outside of Federal Units that are not reflected in the foregoing tables. As of December 31, 2009, WPC’s working interest and net revenue interests in these wells averaged 8.46 percent and 6.91 percent, respectively.

          The Farmout Properties consist of a 35 percent net profits interest on a property farmed out to BP 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 BP. 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 BP under short-term marketing arrangements at spot market prices and is not subject to the Gas Purchase Contract. No assurance can be given, however, that BP 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, 2009, 21 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. See “— Gas Purchase Contract” for a discussion of the Gas Purchase Contract and the impact of the Price Differential on the computation of NPI Net Proceeds.

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          Most of the wells reflected in the December 31, 2009 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, 2009 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 with respect to the NPI.

          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 no payments will be received 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, no less than 20 percent of the NPI Net Proceeds (calculated before such capital costs are deducted) will be received with respect to the NPI 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 BP 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, 2009, and certain related information for the Royalty Interests and Underlying Properties from the December 31, 2009 Reserve Report prepared by Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents, Ltd. is an international oil and gas consulting firm, founded in 1948, offering services and expertise in many phases of the oil and gas industry. The firm is registered with the Texas Board of Professional Engineers and is authorized to provide professional engineering services in the State of Texas. The engineering staff assigned to the Trust are all university graduates with degrees in engineering. All are licensed professional engineers and each is a qualified reserve evaluator with over 20 years of diversified experience, including at least eight years of experience with the Trust. Mr. Stephen M. Hamburg, P.E., a vice president of Miller and Lents, Ltd., is primarily responsible for overseeing the Trust’s reserves audit. A summary of the December 31, 2009 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.

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          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. The December 31, 2009 Reserve Report was prepared in accordance with criteria established by the SEC, and as if the Trust were a going concern, and, accordingly, is based upon a first of the month contractual price received by the Trust during the 12-month period prior to December 31, 2009, of $2.63 per MMBtu before transportation charges through 2012. The Gas Purchase Contract expires no later than December 2012; and because the early termination of the Trust (resulting in the Gas Purchase Contract terminating no later than August 1, 2010) was not triggered until after December 31, 2009, the December 31, 2009 Reserve Report continues to reflect pricing under the terms of the Gas Purchase Contract through the 2012 period. Beginning in year 2013, the gas price to the former Trust interest used in the December 31, 2009 Reserve Report is $3.25 per MMBtu, based on the average first of the month Blanco Hub Index Price during the 12-month period prior to December 31, 2009. 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. The December 31, 2009 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 and based on the percentage share of Infill Net Proceeds payable to the Trust continuing at 20 percent for the remaining life of the reserves.

	Royalty		Underlying
	Interests		Properties
Net Proved Gas Reserves (Mmcf)(a)(b)		6,497		45,755
Estimated Future Net Revenues (in millions)(c)	$	6,598	$	29,675
Discounted Estimated Future Net Revenues (in millions)(c)	$	4,931	$	23,499

(a)	Although the prices utilized in preparing the estimates in this table are in accordance with criteria established by the SEC, such prices 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 applicable royalties, severance and ad valorem taxes, operating costs and future capital expenditures. 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.

          The Financial Accounting Standards Board requires supplemental disclosure for oil and gas reserves producers based on a standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. Under this disclosure, future cash inflows are computed by applying the average prices during the 12-month period prior to fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Future price changes are only considered to the extent provided by contractual arrangements in existence at year end. The standardized measure of discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future cash flows relating to proved oil and gas reserves. The SEC’s prior rules required proved reserve estimates to be calculated using prices as of the end of the period and held constant over the life of the reserves. Application of the new reserve rules resulted in the use of a lower price at December 31, 2009 for gas than would have resulted under the previous rules. Use of the new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately

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4,902 Mmcf, reflected in revisions of previous estimates in the table of changes in reserves quantities in Note 9.

          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.

          Because the process of estimating oil and gas reserves is complex and requires significant judgment, the Trustee has developed internal policies and controls for estimating reserves. The Trust does not have information that would be available to a company with oil and gas operations because detailed information is not generally available to owners of royalty interests. The Trustee gathers production information and provides such information to Miller and Lents, Ltd., who extrapolates from such information estimates of the reserves attributable to the Underlying Properties based on its expertise in the oil and gas fields where the Underlying Properties are situated, as well as publicly available information. The Trust’s policies regarding reserve estimates require proved reserves to be in compliance with the SEC definitions and guidance.

          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 Underlying Properties 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, 2009, 2008 and 2007:

	Year Ended December 31,
	2009		2008		2007
Production from the WI Properties (MMcf)(1)		2,489		5,811		5,529
Weighted average lifting costs (dollars per Mcf)	$	3.02	$	1.16	$	0.75
Weighted average sales price of gas produced from the WI Properties (dollars per Mcf)	$	5.08	$	4.96	$	3.42
Average Blanco Hub Spot Price (dollars per MMBtu)	$	3.25	$	7.21	$	5.97

(1) Production from the WI Properties is exclusive of volumes realized from unit expansion adjustments as described in Note 6 to “Item 8 — Financial Statements and Supplementary Data — Notes to Financial Statements.

          The average first of the month Blanco Hub Spot Price during the 12-month period prior to December 31, 2009 was $3.25 per MMBtu and the contractual price to the Trust was $2.63 per MMBtu as previously discussed. 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 BP 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

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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 1,091, 1,204, and 1,395 in 2009, 2008, and 2007, 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 no later than December 2012; however, as a result of the early termination of the Trust, it will expire on the earlier of August 1, 2010 or the closing date of the sale of the Royalty Interests by the Trust. The Gas Purchase Contract provided 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 continued 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 2007, 2008 and 2009, 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 until the earlier of August 1, 2010 or the closing date of the sale of the Royalty Interests by the Trust. Under this mechanism, the monthly price to be paid by WPX Gas Resources for natural gas purchased pursuant to the Gas Purchase Contract shall be (a) the $1.70 Minimum Purchase Price, less (b) any costs paid by WPX Gas Resources to gather, treat and process the gas and deliver it to specified delivery points and plus (c) under certain circumstances, additional amounts determined as described below:

(i) If the Index Price (as defined below) in any month during any Contract Year, including 2010 (through the earlier of August 1, 2010 or the closing date of the sale of the Royalty Interests by the Trust), 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

31

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 2010 (through the earlier of August 1, 2010 or the closing date of the sale of the Royalty Interests by the Trust), 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 2010 (through the earlier of August 1, 2010 or the closing date of the sale of the Royalty Interests by the Trust), 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, 2009, which is based on production volumes and natural gas prices for the twelve months ended September 30, 2009, the Index Price exceeded the Minimum Purchase Price for each month during the year. As of December 31, 2009 and 2008, 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 as such Price Credits have been fully recouped. Corresponding cash distributions to Unitholders would also be reduced.

          Subsequent to the expiration of the Primary Term of the pricing provision of the Gas Purchase Contract, which occurred on December 31, 1997, WPX Gas Resources has an annual option (which can be exercised only once during the term of the Gas Purchase Contract) to discontinue purchasing gas under the pricing provision of the Gas Purchase Contract by giving written notice of its election to pay solely the Index Price (less the costs paid by WPX Gas Resources to gather, treat and process such gas and deliver it to specified points). If WPX Gas Resources so elects to discontinue paying under the pricing provision, WPX Gas Resources will no longer be entitled to retain the Price Differential when the Index Price exceeds $1.94 per MMBtu and any accrued and unrecouped Price Credits will be extinguished. Since there is no published price in the San Juan Basin for wellhead deliveries, the wellhead price in the Gas Purchase Contract is determined by utilizing a published price that is inclusive of gathering, treating and processing costs. As used in this “Item 2. Properties — Reserve Report,” “Index Price” means 97 percent of the first of month El Paso Natural Gas Co. — San Juan Spot Price. The El Paso Natural Gas Co. — San Juan Spot Price is a posted index price per MMBtu (dry basis) published in Inside F.E.R.C.’s Gas 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 cots or other costs payable prior to the delivery points. During periods when there is a Price Differential,

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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).

          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 beyond the termination of the Trust, covers approximately 90 percent of the production from the WI Properties and commits WFS on behalf of WPX Gas Resources to gather such production (except production from 19 wells in the San Juan 29-7 unit as described below), at rates starting at $.35 per Mcf (plus a fuel reimbursement estimated to be 6.2 percent to 7.3 percent of gathered volumes on a Btu equivalent basis, and subject to increase if the CO₂ content of the gas exceeds 10 percent) and adjusted annually based on average annual price comparisons determined on the basis of the Blanco Hub Spot Price, provided that the gathering rate will be no less than $.35 per Mcf 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.

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          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)). 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, BP pays royalties based on the price it receives for production from such properties as long as the gas is purchased by nonaffiliates. The NPI Net Proceeds, a portion of which is payable to the Trust, reflects the deduction of all royalty and overriding royalty burdens. The ratio of royalties paid on Federal and Indian lands to the NPI Net Proceeds increases as the Resale Price exceeds the price under the Gas Purchase Contract.

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

          The MMS generally audits royalty payments within a 6-year period. Although WPC calculates royalty payments in accordance with its interpretation of the then applicable MMS regulations, WPC does not know

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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. The Trust’s 2007 distributions were impacted negatively by a settlement with the MMS as discussed in Note 6 to “Item 8 — Financial Statements and Supplementary Data — Notes to Financial Statements.” This settlement related to production periods through 2006.

Sale and Abandonment of Underlying Properties

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

          WPC may sell the Underlying Properties, subject to and burdened by the Royalty Interests, without the consent of Unitholders. Under the Trust Agreement, WPC has certain rights (but not obligations) to purchase the Royalty Interests upon termination of the Trust. See “Item 1—Description of the Trust—Termination and Liquidation of the Trust.”

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

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 442 infill locations designated as proved locations according to SEC guidelines. As of December 31, 2009, 442 infill locations are proved developed producing and zero locations are proved undeveloped.

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     The Infill Wells reached payout in the aggregate during 2008. The Trust has received its 20 percent interest in WPC’s Infill Net Proceeds for periods after payout. However, during 2009, WPC informed the Trustee that due to the net deficit realized by the Infill Wells during the third and fourth quarters, the Infill Net Profit Costs now exceed the Infill Net Profit Gross Proceeds by approximately $32,500. 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.

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, 2009, total proved reserves were 6,497 MMcf, comprised entirely of proved developed producing reserves.

     As of December 31, 2009 total proved reserves for the 320-acre spaced wells in the Working Interest Properties were 3,084 MMcf comprised entirely of proved developed producing reserves.

     As of December 31, 2009 total proved reserves for the infill wells in the Working Interest Properties were 453 MMcf, comprised entirely of proved developed producing reserves.

     As of December 31, 2009, total proved reserves for the Farmout Properties were 2,960 MMcf, all of which are proved developed producing.

     The following table sets fort the summary of reserves for the Royalty Trust as of December 31, 2009:

RESERVES

	Natural Gas
Reserves Category	(MMcf)
PROVED RESERVES
Developed
WI Properties		3,084
Infill Properties		453
Farmout Properties		2,960
Undeveloped
WI Properties		-0-
Infill Properties		-0-
Farmout Properties		-0-
TOTAL PROVED RESERVES		6,497

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

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proceeds from a sale of any remaining Royalty Interests that WPC may elect to purchase upon termination of the Trust ((i) through (iii) collectively, the “WPC Payment Obligations”). Williams has also agreed, to the extent not paid by WPX Gas Resources when due and payable, to pay all amounts that WPX Gas Resources is required to pay to WPC in respect of production attributable to the Royalty Interests pursuant to the terms of the Gas Purchase Contract between WPC and WPX Gas Resources (the “WPX Gas Resources Payment Obligations”). In the Confirmation Agreement, Williams expressly confirmed that its agreement to cause the WPX Gas Resources Payment Obligations to be paid in full when due shall continue in full force and effect notwithstanding the assignments by WGM of the Gas Purchase Contract and the Gas Gathering Contract.

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

Title to Properties

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

     The Underlying Properties are typically subject, in one degree or another, to one or more of the following: (i) royalties and other burdens and obligations, expressed and implied, under gas leases; (ii) overriding royalties and other burdens created by WPC or its predecessors in title; (iii) a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles; (iv) liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements; (v) pooling, unitization and communitization agreements, declarations and orders; and (vi) easements, restrictions, rights-of-way and other matters that commonly affect property. To the extent that such burdens and obligations affect WPC’s rights to production and the value of production from the 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.

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     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.

     There are no material pending proceedings to which the Trust is a party or to which any of its properties is the subject. In 2008, WPC notified the Trust that certain royalty matters were being litigated by a federal regulatory agency and another producer. WPC learned that this case was decided unfavorably to the producer in October 2009. Neither WPC nor the Trust was a party to this litigation; however, given the similarities to the Trust’s Underlying Properties, WPC and the Royalty Interests will more than likely be impacted as well. WPC is currently evaluating the negative impact to the Trust’s NPI. In addition, there are other cases pending against other producers on related issues that could potentially have a significant negative impact to future royalty income with respect to the Royalty Interests, natural gas reserves and reserve value.

Item 4.

     Reserved.

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
2009
First Quarter	$	9.00	$	3.86	$	.113811
Second Quarter	$	6.05	$	4.17	$	.065169
Third Quarter	$	5.01	$	2.77	$	.000000
Fourth Quarter	$	4.09	$	2.92	$	.022074
2008
First Quarter	$	10.20	$	8.45	$	.179608
Second Quarter	$	11.10	$	9.39	$	.187237
Third Quarter	$	11.25	$	8.73	$	.349784
Fourth Quarter	$	10.00	$	6.00	$	.755888

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     At March 1, 2010, there were 9,700,000 Units outstanding and approximately 338 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,
	2009		2008		2007		2006		2005
Royalty Income	$	2,882,120	$	15,151,993	$	9,496,151	$	13,945,315	$	14,497,187
Distributable Income	$	1,871,850	$	14,290,691	$	8,547,300	$	13,032,064	$	13,565,620
Distributable Income per Unit	$	0.19	$	1.47	$	0.88	$	1.34	$	1.40
Distributions per Unit	$	0.20	$	1.47	$	0.88	$	1.34	$	1.41
Total Assets at Year End	$	4,527,140	$	5,623,413	$	6,944,963	$	8,372,798	$	10,138,644
Total Corpus at Year End	$	4,410,799	$	5,592,220	$	6,877,977	$	8,316,439	$	10,091,169

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

Termination and Liquidation of the Trust

     With respect to the Trust termination provisions as outlined in the Trust Agreement, the net present value of the estimated future net revenues computed in accordance with the Trust Agreement, using an average 2009 index price of $3.25, by the independent petroleum engineers as of December 31, 2009 was approximately $8.4 million. The results of this computation have triggered an early termination of the Trust. Because the Trust’s computed net present value fell below the $30 million stipulated threshold as of December 31, 2009, the Trust terminated effective March 1, 2010 (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, if any, are 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 has retained Albrecht & Associates, Inc., an investment banking firm (the “Advisor”), on behalf of the Trust who will assist the Trustee in selling the remaining Royalty Interests then owned by the Trust (the “Remaining Royalty Interests”). WPC has the right, but not the obligation, to make a cash offer to purchase all Remaining Royalty Interests following termination of the Trust as described in the following paragraph.

     WPC may, within 60 days following the Termination Date, make a cash offer to purchase all of the Remaining Royalty Interests then held by the Trust. In the event such an offer is made by WPC, the Trustee will decide, based on the recommendation of the Advisor, to either (i) accept such offer (in which case no sale to WPC will be made unless a fairness opinion is given by the Advisor that the purchase price is fair to the Trust and Unitholders) or (ii) defer action on such offer. If the Trustee defers action on WPC’s offer, the offer will be deemed withdrawn and the Trustee will then use Best Efforts, assisted by the Advisor to obtain alternative offers for the Remaining Royalty Interests. At the end of a 120-day period following the Termination Date, the Trustee is required to notify WPC of the highest of any other offers (net of any commissions or other fees payable by the Trust), acceptable to the Trustee (which must be an all-cash offer), received during such period (the “Highest Acceptable Offer”). WPC then has the exclusive right (whether or not it made an initial offer), but not the obligation, to purchase all Remaining Royalty Interests for a cash purchase price computed as follows: (i) if the Highest Acceptable Offer is more than 105 percent of WPC’s initial offer (or if WPC did not make an initial offer), the purchase price will be 105 percent of the Highest Acceptable Offer, or (ii) if the Highest Acceptable Offer is equal to or less than 105 percent of WPC’s initial offer, the purchase price will be equal to the Highest Acceptable Offer. If no other acceptable offers are received for all Remaining Royalty Interests, the Trustee may request WPC to submit another offer for consideration by the Trustee and may accept or reject such offer. Acceptance of an offer by the Trustee shall be conditioned upon the opinion of the Advisor of the fairness of the offer.

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

     In the event that WPC does not purchase the Remaining Royalty Interests, the Trustee may accept any offer for all or any part (not more than six parts) of the Remaining Royalty Interests as it deems to be in the best interests of the Trust and Unitholders and may continue, for up to one calendar year after the Termination Date, to attempt to locate a buyer or buyers of the Remaining Royalty Interests in order to sell such interests in an orderly fashion not involving a public auction. If any Remaining Royalty Interests have not been sold or a definitive agreement for sale has not been entered into by the end of such calendar year, the Trustee is required to sell the Remaining Royalty Interests at public auction to the highest cash bidder, which sale may be to WPC or any of its affiliates. Notice of such sale by auction shall be mailed at least 30 days prior to such sale to each Unitholder at his address as it appears on the ownership ledger of the Trustee.

     WPC’s purchase rights, as described, may be exercised by WPC and each of its successors-in-interest and assigns. WPC’s purchase rights are fully assignable by WPC to any person. The costs of liquidation, including the fees and expenses of the Advisor, and the Trustee’s liquidation fee will be paid by the Trust.

     The sale of the Remaining Royalty Interests following the termination of the Trust will be taxable events to the Unitholders for Federal income tax purposes. Generally, a Unitholder will realize gain or loss equal to the difference between the amount realized on the sale of the Remaining Royalty Interests upon termination of the Trust and his adjusted basis in such Units. Gain or loss realized by a Unitholder who is not a dealer with respect to such Units and who has a holding period for the Units of more than one year will be treated as long-term capital gain or loss except to the extent of any depletion recapture amount, which must be treated as ordinary income. State tax consequences may also result to Unitholders upon the termination of the Trust and the sale of the Remaining Royalty Interests. Each Unitholder should consult his own tax advisor regarding Trust tax compliance matters, including Federal and state tax implications concerning the sale of the Remaining Royalty Interests following the termination of the Trust.

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”). Because of the termination of the Trust effective March 1, 2010, the Trust is not expected to continue as a going concern; however, no adjustments have been made to the carrying value or classification of the Royalty Interests as of December 31, 2009. 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 subject to the occurrence of a termination event, are recorded when declared by the Trustee (see Note 5 to “Item 8—Financial Statements and Supplementary Data—Notes to Financial Statements”).

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

     The financial statements of the Trust differ from financial statements prepared in accordance with GAAP. For example, royalty income is not accrued in the period of production, amortization of the Royalty Interests is not charged against operating results, and loss contingencies are not charged to operating results until paid. This

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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 the FASB Accounting Standards Codification Extractive Activities — Oil and Gas, estimates of future net revenues from proved reserves have been prepared using the average monthly contractual gas prices and related costs for the past calendar year. 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. As described under “— Termination and Liquidation of the Trust”, 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. The Trust is withholding an additional $100,000 for anticipated expenses relating to the termination process.

Results of Operations

     Prior to termination of the Trust, when excess cash was available, the Trust made 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. Currently, funds are invested in Bank of America money market accounts which are backed by the good faith of Bank of America, N.A., but are not insured by the Federal Deposit Insurance Corporation (“FDIC”). The Trust does not lend money and has limited ability to borrow money, which the Trustee believes limits the Trust’s risk from the current tightening of credit markets. Additional risks are described in “Item 1A — Risk Factors”.

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     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 general and administrative 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 or accrued 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 2009, royalty income received by the Trust amounted to $2,882,120 as compared to $15,151,993 and $9,496,151 for 2008 and 2007, respectively. The decrease in royalty income in 2009 compared to 2008 was primarily due to the result of lower natural gas prices, declining production levels and additional receipts from WPC’s processing of unit expansion adjustments in 2008. In the second quarter 2009, Williams notified the Trust that WPC made an overpayment of $765,816 to the Trust for the production quarter ending March 31, 2009; however, Williams waived any right to seek recoupment of the amount of the overpayment or reduce any future payments of royalty income to the Trust by the amount of the overpayment. The increase in royalty income in 2008 compared to 2007 was primarily due to an additional $3.5 million distribution received from WPC from the actualization of the unit expansions effecting the Underlying Properties. The increase was also the result of higher natural gas prices. Net production related to the royalty income received by the Trust in 2009 was 1,742,713 MMBtu as compared to 3,463,050 MMBtu (exclusive of the above described unit expansion adjustment) and 3,730,887 MMBtu in 2008 and 2007, respectively. The average net natural gas price received for royalty income in 2009 was $1.97 per MMBtu as compared to $3.05 MMBtu (exclusive of the above described unit expansion adjustment) and $2.24 MMBtu in 2008 and 2007, respectively. Interest income for 2009 was $896 as compared to $24,390 and $39,842 for 2008 and 2007. The decrease in interest income for 2009 reflects lower interest rates and less funds available for investment. The decrease in interest income for 2008 reflects lower interest rates.

     General and administrative expenses for 2009 were $1,011,166, as compared to $885,692 and $988,693 for 2008 and 2007, respectively. General and administrative expenses in 2009 were higher due to increased professional expenses compared to 2008. General and administrative expenses in 2008 were lower due to decreased Unitholder reporting costs compared to 2007.

     Distributable income for 2009 was $1,871,850 or $0.19 per Unit, compared to $14,290,691 or $1.47 per Unit for 2008, and $8,547,300 or $0.88 per Unit, for 2007. The decrease in distributable income in 2009 compared to 2008 was due to lower gas prices and lower production. The increase in distributable income in 2008 compared to 2007 was primarily due to the actualization of various unit expansions, as discussed further in Note 6 to “Item 8 — Financial Statements and Supplementary Data — Notes to Financial Statements” and due to higher gas prices.

     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 has maintained for the foreseeable future a cash reserve that will be reduced by Trust expenses in excess of royalty income.

     Royalty income received by the Trust in a given calendar year will generally reflect the sum of (i) net 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, 2009, 2008 and 2007, was based on production volumes and natural gas prices for the 12 months ended in September 30,

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2009, 2008 and 2007, respectively, as shown in the table below. The net production volumes included in the table below are for production attributable to net profits of Underlying Properties, and not for production attributable to the Royalty Interests owned by the Trust, and are net of the amount of production attributable to WPC’s royalty obligations to third parties, which are determined by contractual arrangement with such parties.

	Twelve Months Ended September 30,
	2009		2008		2007
Production, Net (MMBtu)(1)(2) WI Properties		1,817,880		4,453,132		5,008,996
Farmout Properties(3)		923,558		1,043,121		1,209,149
Infill Properties(5)		489,252		826,496		0	(5)
Average Blanco Hub Spot Price ($/MMBtu)	$	3.25	$	7.21	$	5.86
Average Net Profits Price WI Properties ($/MMBtu)(4)(5)	$	1.90	$	2.76	$	2.24

(1)	Million British Thermal Units.
(2)	Production volumes for 2008 presented above are exclusive of 6,845,010 MMBtu net production volumes related to the unit expansion adjustment as described in Note 6 to “Item 8 — Financial Statements and Supplementary Data — Notes to Financial Statements.”
(3)	Includes previously reported estimated amounts for certain months.
(4)	Total Gross Proceeds divided by Entitled W.I. Dry MMBtu for 12 months ending on September 30.
(5)	No distribution was made for Infill Properties until 2008 when the properties paid out. WPC informed the Trustee that due to the net deficit realized by the Infill Wells during the third and fourth quarters, the Infill Net Profit Costs exceeded the Infill Net Profit Gross Proceeds and received no royalty income from the Infill Properties in those periods. 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.

     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.

     As described under “— Termination and Liquidation of the Trust”, 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.

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

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.

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Tabular Disclosure of Contractual Obligations

     As shown below, the Trust had no obligations and commitments to make future contractual payments as of December 31, 2009.

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

Forward-Looking Statements

     This Annual Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, which are intended to be covered by the safe harbor created thereby. All statements other than statements of historical fact included in this Annual Report are forward-looking statements. Such statements include, without limitation, factors affecting the price of oil and natural gas contained in Item 1, “Business”; certain reserve information and other statements contained in Item 2, “Properties”; and certain statements regarding the Trust’s financial position, industry conditions, any sale of the Remaining Royalty Interests upon termination of the Trust and other matters contained in this Item 7. Although the Trustee believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been 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, prior to the termination of the Trust, generally entitled the Trust to receive a share of the net profits from natural gas production from the Underlying Properties. Consequently, the Trust’s financial results are 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 significantly impacted revenues to the Trust. Although the Gas Purchase Contract mitigates the risk to the Trust of low gas prices, it also limits the ability of the Trust to benefit from the effects of higher gas prices, particularly to the extent a balance exists in the Price Credit Account. See “Item 2 — Properties — The Royalty Interests — Gas Purchase Contract” for detailed information about the Gas Purchase Contract and its impact on the Trust and Unitholders.

     Upon receipt by the Trust, royalty income is invested in short-term investments in accordance with the Trust Agreement until its subsequent distribution to Unitholders. Currently, funds are invested in Bank of America money market accounts which are backed by the good faith and credit of Bank of America, N.A., but are not insured by the FDIC. Each Unitholder should independently assess the creditworthiness of Bank of America, N.A. For more information about the credit rating of Bank of America, N.A., please refer to its periodic filings with the SEC. The Trust does not lend money and has limited ability to borrow money, which the Trustee believes limits the Trust’s risk from the current tightening of credit markets. See “Item 1A — Risk Factors — Funds held by the Trustee are not insured by the Federal Deposit Insurance Corporation, and future royalty income may be subject to

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risks relating to the creditworthiness of third parties.” Information contained in Bank of America, N.A’s periodic filings with the SEC is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that the Trust makes with the SEC.

     The market prices of the Units are determined by the buyers and sellers on the New York Stock Exchange. The Trust does not make market on any Units and is not in any position to advise any Unitholder on any market position. Unitholders should be aware that any position of the market concerning the Units is beyond the Trust’s control and on any given day, various market conditions will affect the market of the Units.

     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, 2009 and 2008, and the related Statements of Distributable Income and Changes in Trust Corpus for each of the 3 years in the period ended December 31, 2009, 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, 2009 and 2008, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2009. 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. We were not engaged to perform an audit of the Williams Coal Seam Gas Royalty Trust’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Williams Coal Seam Gas Royalty Trust’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and 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, 2009 and 2008, and its distributable income and its changes in trust corpus for each of the three years in the period ended December 31, 2009, on the basis of accounting described in Note 2.

     The accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. As more fully described in Note 2, the computed net present value of the estimated future net revenues for proved reserves attributable to the Royalty Interests fell below the termination threshold prescribed by the Trust Agreement at December 31, 2009, triggering a termination of the Trust effective March 1, 2010. The Trust Agreement provides the Trustee a one-year period during which to sell all of the Trust’s properties before the properties are otherwise sold at auction. Accordingly, there exists substantial doubt about the Trust’s ability to continue as a going concern. The financial statements do not include any adjustments that might result from execution of the plan for termination or liquidation of the Trust’s assets.

     As discussed in Note 2 to the financial statements, the Trust has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

/s/ ERNST & YOUNG LLP  

Tulsa, Oklahoma
March 31, 2010

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Financial Statements
Williams Coal Seam Gas Royalty Trust

Statements of Assets, Liabilities and Trust Corpus

	December 31,
	2009		2008
Assets
Current assets — cash and cash equivalents	$	52,195	$	45,419
Royalty interests in oil and gas properties (less accumulated amortization of $134,091,719 and $132,988,670 at December 31, 2009 and 2008, respectively) (Note 2)		4,474,945		5,577,994
Total	$	4,527,140	$	5,623,413
Liabilities and Trust Corpus
Current liabilities — other accounts payable	$	116,341	$	31,193
Contingencies (Note 6)
Trust corpus (9,700,000 units of beneficial interest authorized and outstanding) (Note 2)		4,410,799		5,592,220
Total	$	4,527,140	$	5,623,413

Statements of Distributable Income

	Year Ended December 31,
	2009			2008			2007
Royalty income (Notes 2, 4 and 6)	$	2,882,120		$	15,151,993		$	9,496,151
Interest income		896			24,390			39,842
Total		2,883,016			15,176,383			9,535,993
General and administrative expenses (Note 4)		(1,011,166	)		(885,692	)		(988,693	)
Distributable income	$	1,871,850		$	14,290,691		$	8,547,300
Distributable income per Unit (9,700,000 units) (Note 2)	$	0.19		$	1.47		$	0.88
Distributions per Unit (Note 5)	$	0.20		$	1.47		$	0.88

Statements of Changes in Trust Corpus

	Year Ended December 31,
	2009			2008			2007
Trust corpus, beginning of year	$	5,592,220		$	6,877,977		$	8,316,439
Amortization of royalty interests (Note 2)		(1,103,049	)		(1,293,038	)		(1,440,159	)
Distributable income		1,871,850			14,290,691			8,547,300
Distributions to Unitholders (Note 5)		(1,950,222	)		(14,283,410	)		(8,545,603	)
Trust corpus, end of year	$	4,410,799		$	5,592,220		$	6,877,977

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 The Bank of New York Mellon Trust Company, N.A. (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, 2010 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 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

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“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 442 infill locations designated as proved locations according to SEC guidelines. As of December 31, 2009, all of these infill locations represent proved developed producing reserves, while there are no proved undeveloped locations.

     WPC has informed the Trustee that the Infill Wells reached payout in the aggregate during 2008. The Trust has received its 20 percent interest in WPC’s Infill Net Proceeds for the periods after payout. However, during 2009, WPC informed the Trustee that due to the net deficit realized by the Infill Wells during the third and fourth quarters, the Infill Net Profit Costs now exceed the Infill Net Profit Gross Proceeds by approximately $32,500. 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 and Future Operations

     The Trust terminated effective March 1, 2010 (the “Termination Date”), pursuant to the terms of the Trust Agreement. Cancellation of the Trust will occur following the Termination Date when all Trust assets have been sold and the net proceeds there from distributed to holders of Units in the Trust (“Unitholders”).

     The Trust Agreement required termination of the Trust in the event that when a computation is performed as of each December 31, the net present value (discounted at 10 percent) of the estimated future net revenues (calculated in accordance with criteria established by the SEC) for proved reserves attributable to the Royalty Interests but using the average monthly Blanco Hub Spot Price for the past calendar year less certain gathering costs, is equal to or less than $30 million. The net present value of the estimated future net revenues computed as described above by the independent petroleum engineers as of December 31, 2009 was approximately $8.4 million. The results of this computation triggered an early termination of the Trust.

     Because the Trust’s computed net present value fell below the $30 million stipulated threshold as of December 31, 2009, the Trust terminated effective March 1, 2010. The accompanying financial statements have been prepared on a going concern basis and do not include any adjustments, costs and expenses or other matters that might result from the outcome of this termination.

     Following termination of the Trust, the Trustee will continue to act as Trustee of the Trust until all Trust assets are sold and the net proceeds from such sales distributed to Unitholders. The Trustee will use best efforts to sell the Trust’s assets in accordance with the procedures set forth in the Trust Agreement.

     The Trustee has retained Albrecht & Associates, Inc., an investment banking firm (the “Advisor”), on behalf of the Trust who will assist the Trustee in selling the remaining Royalty Interests owned by the Trust (the “Remaining Royalty Interests”). WPC has the right, but not the obligation, to make a cash offer to purchase all Remaining Royalty Interests following termination of the Trust as described in the following paragraph.

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     WPC may, within 60 days following the Termination Date, make a cash offer to purchase all of the Remaining Royalty Interests then held by the Trust. In the event such an offer is made by WPC, the Trustee will decide, based on the recommendation of the Advisor, to either (i) accept such offer (in which case no sale to WPC will be made unless a fairness opinion is given by the Advisor that the purchase price is fair to the Trust and Unitholders) or (ii) defer action on such offer. If the Trustee defers action on WPC’s offer, the offer will be deemed withdrawn and the Trustee will then use Best Efforts, assisted by the Advisor to obtain alternative offers for the Remaining Royalty Interests. At the end of a 120-day period following the Termination Date, the Trustee is required to notify WPC of the highest of any other offers (net of any commissions or other fees payable by the Trust), acceptable to the Trustee (which must be an all-cash offer), received during such period (the “Highest Acceptable Offer”). WPC then has the exclusive right (whether or not it made an initial offer), but not the obligation, to purchase all Remaining Royalty Interests for a cash purchase price computed as follows: (i) if the Highest Acceptable Offer is more than 105 percent of WPC’s initial offer (or if WPC did not make an initial offer), the purchase price will be 105 percent of the Highest Acceptable Offer, or (ii) if the Highest Acceptable Offer is equal to or less than 105 percent of WPC’s initial offer, the purchase price will be equal to the Highest Acceptable Offer. If no other acceptable offers are received for all Remaining Royalty Interests, the Trustee may request WPC to submit another offer for consideration by the Trustee and may accept or reject such offer. Acceptance of an offer by the Trustee shall be conditioned upon the opinion of the Advisor of the fairness of the offer.

     If a sale of the Remaining Royalty Interests is made or a definitive contract for sale of the Remaining Royalty Interests is entered into within a 150-day period following the Termination Date, the buyer of the Remaining Royalty Interests, and not the Trust or Unitholders, will be entitled to all proceeds of production attributable to the Remaining Royalty Interests following the Termination Date. All proceeds of production following the Termination Date attributable to the Remaining Royalty Interests will be deposited into a non-interest bearing account until they are paid to the buyer or otherwise distributed in accordance with the Trust Agreement.

     In the event that WPC does not purchase the Remaining Royalty Interests, the Trustee may accept any offer for all or any part (not more than six parts) of the Remaining Royalty Interests as it deems to be in the best interests of the Trust and Unitholders and may continue, for up to one calendar year after the Termination Date, to attempt to locate a buyer or buyers of the Remaining Royalty Interests in order to sell such interests in an orderly fashion not involving a public auction. If any Remaining Royalty Interests have not been sold or a definitive agreement for sale has not been entered into by the end of such calendar year, the Trustee is required to sell the Remaining Royalty Interests at public auction to the highest cash bidder, which sale may be to WPC or any of its affiliates. Notice of such sale by auction shall be mailed at least 30 days prior to such sale to each Unitholder at his address as it appears on the ownership ledger of the Trustee.

     The Trust is withholding an additional $100,000 for anticipated expenses relating to this termination process.

     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 to “Item 8—Financial Statements and Supplementary Data—Notes to Financial Statements”).

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

     The financial statements of the Trust differ from financial statements prepared in accordance with GAAP. For example, royalty income is not accrued in the period of production, amortization of the Royalty Interests is not

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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 adopted new oil and gas accounting guidance (Accounting Standards Update 2010-03) in 2009 that requires valuation of reserves using an average first-day-of-the-month price. Adoption of the new rules resulted in the use of a lower price at December 31, 2009 for natural gas than would have resulted under previous rules (see further discussion in Note 9).

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 2009, 2008 and 2007 were $320,941, $311,593, and $302,518, respectively. The amount owed to WPC at December 31, 2009 was $80,235. 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 (hereinafter defined) has the right, exercisable in its sole discretion, to terminate its Minimum Purchase Price commitment under the Gas Purchase Contract prior to the expiration of the Gas Purchase Contract upon the earlier of August 1, 2010 or the closing date of the sale of the Royalty Interests by the Trust. Williams’ interest could conflict with those of the Trust and Unitholders to the extent the interests of WPX Gas Resources (hereinafter defined), under the Gas Purchase Contract, or WFS and WPX Gas Resources (hereinafter defined), 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 2009, 2008 and 2007 were $60,067, $58,497 and $56,972, respectively.

5. Distributions to Unitholders

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

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

     In addition to the regular quarterly distributions, under certain circumstances specified in the Trust Agreement (such as upon a purchase price adjustment, if any, or pursuant to the sale of a Royalty Interest) the Trust would make a special distribution (a “Special Distribution Amount”). If applicable, 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). Any applicable distribution to Unitholders of a Special Distribution Amount would be made no later than 15 days after the Special Distribution Amount record date. See Note 6 below for description of distributions in 2008 and 2007 that are not recurring.

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 the expiration of the Gas Purchase Contract upon the earlier of August 1, 2010 or the closing date of the sale of the Royalty Interests by the Trust.

     Under the pricing mechanism of the Gas Purchase Contract, when the market price was less than $1.70 per MMBtu (the “Minimum Purchase Price”), the Trust was paid the Minimum Purchase Price for the gas and an account (the “Price Credit Account”) was 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 were subject to future recoupment when the market price exceeded the Minimum Purchase Price. As of December 31, 2009 and 2008, there were no remaining unrecouped Price Credits in the Price Credit Account.

     While the terms of the Gas Purchase Agreement pricing mechanism remained in place and no balance existed in the Price Credit Account, when the market price for natural gas exceeded $1.94 per MMBtu (as was the case during all months in 2009, 2008 and 2007), the Trust received 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.

     In 2008, WPC notified the Trust that certain royalty matters were being litigated by a federal regulatory agency and another producer. WPC learned that this case was decided unfavorably to the producer in October 2009. Neither WPC nor the Trust was a party to this litigation; however, given the similarities to the Trust’s Underlying Properties, WPC and the Royalty Interests will more than likely be impacted as well. WPC is currently evaluating the negative impact to the Trust’s NPI. In addition, there are other cases pending against other producers on related issues that could potentially have a significant negative impact to future royalty income with respect to the Royalty Interests, natural gas reserves and reserve value.

     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

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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. WPC informed the Trustee in 2007 that it estimated the impact of various retroactive unit expansions to the Trust and paid the Trust an adjusted amount, based on the estimate, in the third quarter of 2007. This adjustment was the result of numerous expansions coming from the BLM that impacted the Trust’s royalty income. These expansions are retroactive to production periods beginning in 1994. WPC had previously informed the Trustee that it was researching the manner in which capital costs impacted the expansion computations. During 2008, WPC informed the Trustee that it completed its research related to past capital costs incurred pertaining to wells included in this and previous unit expansions and consistent with past application concluded that capital costs should not be considered as a reduction in computing the net proceeds due the Trust. WPC completed the accounting for these expansions which resulted in an additional $3.5 million in the Trust’s 2008 royalty income. The Trust’s 2007 royalty income considered the Trust’s $5 million portion of the CO2 settlement, which was substantially offset by a $4.8 million amount paid to the Trust by WPC for the unit expansions (actualized during 2008 as described above). The net effect on these items resulted in an approximate $180,000 decrease to the Trust’s 2007 royalty income. In the second quarter 2009, Williams notified the Trust that WPC made an overpayment of $765,816 to the Trust for the production quarter ending March 31, 2009; however, Williams waived any right to seek recoupment of the amount of the overpayment or reduce any future payments of royalty income to the Trust by the amount of the overpayment.

     The royalty income presented in the accompanying statements of distributable income is on an entitlement basis and reflects WPC’s estimated impact of the most recent BLM participating area approvals through December 31, 2009.

7. Subsequent Event

     The Trustee has evaluated events occurring subsequent to December 31, 2009 through the time of filing. Subsequent to December 31, 2009, the Trust declared the following distribution:

Quarterly Record Date	Payment Date	Distribution per Unit
February 16, 2010	March 1, 2010	$0.016972

     Subsequent to December 31, 2009, the Trustee announced that the Trust would terminate effective March 1, 2010, as described in Note 2.

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, 2009 and 2008 (in thousands, except per Unit amounts):

Calendar Quarter	Royalty Income		Distributable Income			Distributions per Unit
2009
First	$	1,393	$	1,022		$	0.113811
Second		932		666			0.065169
Third		78		(104	)		0.000000
Fourth		479		288			0.022074
TOTAL	$	2,882	$	1,872		$	0.201054
2008
First	$	2,035	$	1,739		$	0.179608
Second		2,112		1,866			0.187237
Third		3,629		3,480			0.349784
Fourth		7,376		7,206			0.755888
TOTAL	$	15,152	$	14,291		$	1.472517

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     Selected 2009 fourth quarter data are as follows (in thousands except per Unit amounts):

	2009			2008
Royalty income	$	479		$	7,376
Interest income		1			11
General and administrative expenses		(192	)		(181	)
Distributable income	$	288		$	7,206
Distributable income per Unit (9,700,000 units)	$	.03		$	.74
Distributions per Unit	$	.02		$	.76

     Royalty Income reported for the fourth quarter 2008 includes the impact of the $3.5 million unit expansion adjustment described in Note 6. During 2009 WPC notified the Trust that Royalty Income for the second quarter 2009 includes an overpayment of approximately $766,000. However, Williams waived any right to seek recoupment of the amount or reduce any future payments of royalty income to the Trust by the amount of overpayment.

9. Supplemental Oil and Gas Information (Unaudited)

     The Trust’s net profits interest entitles the Trust to a portion of the net proceeds derived from the underlying quantities of gas. Therefore, the estimated volumes net to the Trust’s interest are impacted by the level of revenue attributable to and costs deducted in calculating the net profits interest of the Trust. The net proved reserves attributable to the Royalty Interests have been estimated as of December 31, 2009, 2008 and 2007, by Miller and Lents, Ltd., independent petroleum engineers. In accordance with FASB guidance, estimates of future net revenues from proved reserves for 2008 and 2007 have been prepared using contractual gas prices and related costs in effect at year end. For 2009, estimates of future net revenues from proved reserves have been prepared using the average first-day-of-the-month price during the 12-month period prior to December 31, 2009, as discussed below. The Blanco Hub Spot Price was $5.24 and $6.43 per MMBtu at December 31, 2008, and 2007, respectively. The average first-day-of-the-month price during the 12-month period prior to December 31, 2009 was $3.25. These methodologies resulted in a weighted average wellhead price, after adjustments for certain costs and provisions of the Gas Purchase Contract, of $2.625, $3.620 and $4.215 per Mcf for 2009, 2008, and 2007, respectively. For the working interest properties, the Trust’s reserves as of December 31, 2009, are computed based on a going concern basis, thus giving effect to the Gas Purchase Contract price through December 31, 2012. Thereafter, the price used in the reserve computation reverts to the average beginning of the month Blanco Hub Spot Price to estimate the remaining quantities net to the net profits interests of the Unitholders. 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).

     The Financial Accounting Standards Board requires supplemental disclosure for oil and gas reserves producers based on a standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. Under this disclosure, future cash inflows are computed by applying the average prices during the 12-month period prior to fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Future price changes are only considered to the extent provided by contractual arrangements in existence at year end. The standardized measure of discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future cash flows relating to proved oil and gas reserves. The SEC’s prior rules required proved reserve estimates to be calculated using prices as of the end of the period and held constant over the life of the reserves. Application of the new reserve rules resulted in the use of a lower price at December 31, 2009 for gas than would have resulted under the previous rules. Use of the new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 4,902 Mmcf, reflected in revisions of previous estimates in the table below.

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     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.

	Natural Gas (MMcf)
Proved gas reserves at December 31, 2006		24,267
Production		(4,155	)
Extensions and revisions of previous estimates		1,968
Proved gas reserves at December 31, 2007		22,080
Production		(3,838	)
Extensions and revisions of previous estimates		(5,521	)
Proved gas reserves at December 31, 2008		12,721
Production		(1,871	)
Extensions and revisions of previous estimates		(4,353	)
Proved gas reserves at December 31, 2009		6,497
Proved developed oil and gas reserves at December 31, 2009		6,497

     Proved gas reserves at December 31, 2009 are comprised entirely of proved developed reserves. Proved gas reserves at December 31, 2008, include 96 MMcf of proved undeveloped reserves. The 2008 revisions of previous estimates are a result of the impact of lower prices and increased costs in calculating the quantities associated with the net profits interest as discussed above. Proved gas reserves at December 31, 2007, include 479 MMcf of proved undeveloped reserves.

     Proved oil and gas reserves are estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

     The following table sets forth the standardized measure of discounted future net revenues at December 31, 2009, 2008 and 2007 relating to proved reserves (in thousands):

	Year Ended December 31,
	2009			2008			2007
Future cash inflows	$	9,579		$	38,764		$	80,828
Future production taxes		(2,981	)		(9,261	)		(16,093	)
Future development costs		-0-			(1,098	)		(1,218	)
Future net cash flows		6,598			28,405			63,517
10% discount factor		(1,667	)		(9,340	)		(24,775	)
Standardized measure of discounted future net revenues	$	4,931		$	19,065		$	38,742

     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, 2009, 2008 and 2007 (in thousands):

	2009			2008			2007
Balance at January 1	$	19,065		$	38,742		$	33,689
Increase (decrease) due to:
Net sales of coal seam gas		(2,338	)		(10,611	)		(8,720	)
Net changes in prices and costs		(11,285	)		(4,336	)		4,240
Development costs incurred		85			176			(453	)
Changes in estimated future development cost		856			15			1,366
Extensions and revisions of previous quantity estimates		(3,321	)		(8,740	)		3,727
Accretion of discount		1,741			3,588			3,369
Other		128			231			1,525
		(14,134	)		(19,677	)		5,054
Balance at December 31	$	4,931		$	19,065		$	38,742

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

     None.

Item 9A. Controls and Procedures.

     Disclosure Controls and Procedures. The Trust maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms. In addition, the disclosure controls and procedures are designed to ensure that the information required to be disclosed by the Trust is accumulated and communicated to the Trustee to allow timely decisions regarding required disclosure. 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 recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act and are effective in ensuring that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Act of 1934 is accumulated and communicated to the Trustee to allow timely decisions regarding required disclosure. 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 2009 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, 2009. This Annual Report does not include an attestation report of the Trust’s registered public accounting firm regarding internal control over financial reporting. The Trustee’s report was not subject to attestation by the Trust’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Trust to provide only the Trustee’s report in this Annual Report.

Item 9B. Other Information.

     None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance.

     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 U.S. Trust, Bank of America Private Wealth Management, 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 2009, 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 2009 base amount of $53,918, 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 2009 of $53,918 and $6,149, respectively. The base amount of the Trustee’s fee and the amount of the Delaware Trustee’s fee for administrative services escalate at the rate of 3 percent per year. The Trustee and the Delaware Trustee are each entitled to reimbursement for out-of-pocket expenses. Upon termination of the Trust, the Trustee will receive, in addition to its out-of-pocket expenses, a termination fee in the amount of $8,000.

     The Transfer Agent receives a transfer agency fee of $5.50 annually per account (minimum of $15,000 annually), subject to change each December, based upon the change in the Producers’ Price Index as published by

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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 2009 were $32,614.

     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—Certain Relationships and Related Transactions—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 and Related Stockholder Matters.

     (a) Security Ownership of Certain Beneficial Owners. The following table sets forth as of March 1, 2010 information with respect to the only Unitholder who was known to the Trustee to be a beneficial owner of more than 5 percent of the outstanding Units.

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

(1) This information was provided to the 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, 2010, Bank of America, N.A., the Trustee, held an aggregate of 18,444 Units in various fiduciary capacities, with no investment or voting powers. As of March 1, 2010, Bank of New York Mellon Trust Company, N.A. (as successor to Chemical Bank Delaware), the Delaware Trustee, did not beneficially own any Units.

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

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Item 13. Certain Relationships and Related Transactions, and Director Independence.

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 2009 was $320,941. The amount owed to WPC at December 31, 2009 was $80,235.

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, prior to the expiration of the Gas Purchase Contract on the earlier of August 1, 2010 or the closing date of the sale of the Royalty Interests by the Trust, 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, 2009 and 2008 are:

	2009		2008
Audit Fees	$	171,000	$	168,400
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		46
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2009 and 2008		47
Statements of Distributable Income for each of the three years in the period ended		47
December 31, 2009
Statements of Changes in Trust Corpus for each of the three years in the period ended		47
December 31, 2009
Notes to Financial Statements		48-55

     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).
10.9	—	Commission and Exclusive Agency Agreement dated as of March 18, 2010 by and between Bank of America, N.A. and Albrecht & Associates, Inc.
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 31, 2010, and submitted pursuant to Rule 13a-14(a)/15d-14(a) and pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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Exhibit
Number		Exhibit
32.1	—	Certificate by Bank of America, Trustee of Williams Coal Seam Gas Royalty Trust, dated March 31, 2010, 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 February 12, 2010 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, 2009, 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
Date: March 31, 2010		Senior Vice President and Administrator

(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).

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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).
10.9	—	Commission and Exclusive Agency Agreement dated as of March 18, 2010 by and between Bank of America, N.A. and Albrecht & Associates, Inc.
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 31, 2010, 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 31, 2010, 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 February 12, 2010, 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, 2009, prepared by Miller and Lents, Ltd., independent petroleum engineers.

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EX-10.9

Exhibit 10.9

COMMISSION AND EXCLUSIVE AGENCY AGREEMENT

This Agreement is between Albrecht & Associates, Inc. (“Albrecht”) and Bank of America, N.A., as trustee for the Williams Coal Seam Gas Royalty Trust (“SELLER”).

     WHEREAS, SELLER is desirous of selling certain producing and non-producing interests in oil and gas properties as shown in Exhibit “A” attached hereto (the “Properties”) in accordance and subject to the terms of that certain Trust Agreement of SELLER as set forth in Exhibit “B” attached hereto (the “Trust Agreement”); and

     WHEREAS, Albrecht is desirous of acting as exclusive agent in the sale of the Properties and earning a performance fee (the “Fee”) from the sale thereof:

IN CONSIDERATION OF THE PREMISES AND THE FOLLOWING MUTUAL COVENANTS THE PARTIES AGREE THAT:

For a period ending February 28, 2011 (the “Term”), Albrecht shall (i) diligently solicit potential buyers of the Properties and submit to SELLER all offers received and (ii) perform those services as specifically described on Exhibit “C” attached hereto and incorporated by reference herein.

1.	During the Term, Albrecht shall be entitled to and shall receive its Fee as defined herein if the Properties are sold to any person, corporation, partnership, company, or any entity whatsoever.
2.	SELLER agrees to pay Albrecht a non-refundable retainer of $100,000 (one hundred thousand dollars) no later than five business days following the execution of this contract.
3.	At the closing of the sale of the Properties, SELLER agrees to pay to Albrecht the following Fee, based upon the total aggregate sales price received by SELLER.

$200,000 plus 1% of the aggregate sales price

	For example, if the aggregate sales price is $10,000,000 (ten million dollars), Albrecht shall receive a Fee of $300,000 (three hundred thousand dollars). If the aggregate sales price is $100,000,000 (one hundred million dollars), Albrecht shall receive a Fee of $1,200,000 (one million two hundred thousand dollars).
	The Fee shall be paid at closing of the sale of the Properties except in the event a portion of the sales price is paid on a deferred basis, in which case the Fee pyable with respect to such portion will be payable when the Fee is actually received by the Seller. The $100,000 retainer fee discussed in Paragraph 4 shall be applied against any fees due under this Paragraph 5.
4.	Other than the Fees described in Paragraph 4 and 5 above, Albrecht shall not be entitled to and shall not receive any compensation or expense reimbursement whatsoever from SELLER.

1

5.	Although Albrecht shall be the Exclusive Agent for this sale, it is expressly agreed that Albrecht has no authority to commit SELLER to accept any offer whatsoever for the Properties. SELLER shall have the sole and absolute discretion to direct the conduct of any discussions with potential buyers, to accept or reject the terms of any proposed transaction, or to consummate any such transaction.
6.	All Fees and other sums payable by SELLER to Albrecht pursuant to this Agreement shall be paid in cash, in immediately available funds. Any such sums not paid when due shall accrue interest from the date due until paid at a rate equal to the lesser of: (a) prime rate as announced from time to time by Regions Bank (or its successor), plus four percent (4%), or (b) the maximum permissible rate under applicable law.
7.	Neither party shall ever be liable to the other as the result of any alleged breach of this agreement for any damages exceeding the actual, direct, foreseeable damages incurred by the non-breaching party, together with costs and expenses, including attorneys’ fees, incurred in recovering such damages; and each party hereby expressly waives any right that it may otherwise have to recover consequential, exemplary, punitive, statutory, special, and/or indirect damages, or damages of any type other than actual, direct, foreseeable damages resulting from breach of this Agreement.
8.	SELLER hereby agrees to indemnify and hold harmless Albrecht and its affiliates, and their respective owners, officers, directors, employees, agents and representatives (collectively the “Albrecht Parties”) from any and all losses or liabilities incurred by any of the Albrecht Parties, including, but not limited to, attorneys’ fees and costs incurred in defending any claim against any of the Albrecht Parties, resulting directly or indirectly from the performance of Albrecht’s services hereunder; provided, however, such indemnification shall not apply to any portion of any such loss or liability to the extent it is found in a final judgment by a court of competent jurisdiction to have resulted primarily from (i) the bad faith, gross negligence or willful misconduct of Albrecht, or (ii) a breach of a material provision of this Agreement by Albrecht if such breach continues uncured for a period of ten (10) days after notice from SELLER to Albrecht of such breach.
9.	Albrecht shall not disclose any confidential information of SELLER to a third party unless and until such third party has executed a confidentiality agreement of a form approved and executed by SELLER.
10.	This Agreement is performable, in part, in Houston, Harris County, Texas and shall be construed and enforced in accordance with the internal laws of the State of Texas (without reference to conflict of law principles that would result in the application of the laws of any other jurisdiction).

11. This Agreement may not be amended except by an instrument in writing signed by each of the parties.

12. Albrecht may not assign this Agreement or its rights or interest hereunder in any form or manner, without the prior written consent of SELLER.

13. The date of this Agreement is March 18, 2010.

2

AGREED

Albrecht & Associates, Inc.

By:	/s/ Robert A. Albrecht	Date:	3/26/10
Name:	Robert A. Albrecht
Title:	President
SELLER
By:	Bank of America, N.A., Trustee for
	Williams Coal Seam Gas Royalty Trust	Date:	3/18/10
By:	/s/ Ron E. Hooper
Name:	Ron E. Hooper
Title:	Senior Vice President

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 31, 2010, with respect to the financial statements of the Williams Coal Seam Gas Royalty Trust included in this Annual Report (Form 10-K) for the year ended December 31, 2009.

/s/ ERNST & YOUNG LLP

Tulsa, Oklahoma
March 31, 2010

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EX-23.2

Exhibit 23.2

CONSENT OF MILLER AND LENTS, LTD.

March 31, 2010

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 February 12, 2010 for reserves as of December 31, 2009.

3. Report dated February 17, 2010 for reserves as of December 31, 2009 with respect to the termination calculation.

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

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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 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 report;
3.	Based on my knowledge, the financial statements, and other financial information included in this 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 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 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 supervision, to provided reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;
d)	disclosed in this 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

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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 31, 2010

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

69

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, 2009, 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 31, 2010	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.

70

EX-99.3

Exhibit 99.3

February 12, 2010

Mr. Ron E. Hooper
Senior Vice President
U.S. Trust, Bank of America, Trustee
Williams Coal Seam Gas Royalty Trust
901 Main Street, Suite 1700
Dallas, TX 75202

Re:	Williams Coal Seam Gas Royalty Trust
	Proved Reserves and Future Net Revenues
	As of December 31, 2009

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 estimates as of December 31, 2009 for the Underlying Properties and Royalty Interests (net to WTU) is as follows:

	Net Gas		Future Net		Present Value
	Reserves,		Revenues,		at 10 Percent
	MMcf		M$		Per Annum, M$
The Underlying Properties
Proved Developed		45,755		29,675		23,499
Proved Undeveloped		0		0		0
Total Proved		45,755		29,675		23,499
The Royalty Interests (Net to WTU)
Proved Developed		6,497		6,598		4,931
Proved Undeveloped		0		0		0
Total Proved		6,497		6,598		4,931

     Proved reserves were estimated in accordance with the definitions contained in Securities and Exchange Commission (SEC) Regulation S-X, Rule 4-10(a) as shown in the Appendix.

     In order to estimate the reserves to WTU, it was necessary to estimate the reserves attributable to (1) 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, LLC (WPC) and (2) the Royalty Interests, the variable net revenue interest

Two Houston Center • 909 Fannin Street, Suite 1300 • Houston, Texas 77010

Telephone 713-651-9455 • Telefax 713-654-9914 • email: mail@millerandlents.com

Mr. Ron E. Hooper	February 12, 2010
U.S. Trust, Bank of America, Trustee	Page 2
Williams Coal Seam Gas Royalty Trust

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, neither overhead costs (beyond the standard overhead charges for the non-operated properties) nor the effects of depreciation, depletion, and Federal Income Tax have been included. 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 WTU 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 (1) the net revenue received by WTU from the Working Interest Properties to (2) total revenues from the Working Interest Properties after deduction of severance and ad valorem taxes.

     The production forecast for the total proved reserves and future net revenues as of December 31, 2009 attributable to the Underlying Properties and to WTU is shown on Table 1. All reserves were evaluated and under the SEC 12-month average pricing scenario, no proved undeveloped reserves were economic and therefore, not included. Table 2 is a one-line summary showing the contribution of each property to the total estimated future production and net revenues.

     The estimated gas reserves for the producing wells were primarily estimated by decline curve analyses. For wells with little production history, estimates of ultimate recovery were based on analogy with other wells similarly situated in the Fruitland Coal reservoir.

     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 441 developed infill locations. WTU holds a net profits interest that entitles WTU 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 WPC, payout for the infill drilling program occurred in 2008. As the infill program continues, WTU’s net proceeds will be reduced by future accumulated capital costs.

     The gas prices and deductions for WTU are based on information provided by WPC. The gas price for the Farmout Properties is $3.249 per MMBtu based on the required SEC 12-month average Blanco Hub Spot Price. For the Working Interest Properties, the adjusted price of $2.625 per MMBtu was employed as provided in the Gas Purchase Contract. At the time of termination of WTU, which is no later than December 31, 2012, the Trust Agreement requires liquidation of assets. Because the Gas Purchase Contract will not be applicable after December 31, 2012, the gas price for the Working

Mr. Ron E. Hooper	February 12, 2010
U.S. Trust, Bank of America, Trustee	Page 3
Williams Coal Seam Gas Royalty Trust

Interest Properties in this analysis reverts to $3.249 per MMBtu, based on the 12-month average Blanco Hub Spot Price. These future production and economic calculations are included in order to provide a reasonable estimate of the future value of the assets after or at the point of termination. The WTU may terminate and assets may be liquidated before December 31, 2012 due to provisions in the WTU Trust Agreement regarding the termination present value.

     Gathering and transportation charges, taxes, treating, and other costs payable prior to the delivery points were calculated for each well and were deducted from the respective prices in order to determine the net wellhead price used in this evaluation. These deductions were held constant.

     Operating expense estimates were based on expenses incurred during 2009 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 WTU.

     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. Minor precision inconsistencies in subtotals or totals may exist in the report due to truncation or rounding of aggregated values.

     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.

     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.

Mr. Ron E. Hooper	February 12, 2010
U.S. Trust, Bank of America, Trustee	Page 4
Williams Coal Seam Gas Royalty Trust

     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. 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 25 years of relevant experience in the estimation, assessment, and evaluation of oil and gas reserves.

Yours very truly, MILLER AND LENTS, LTD. Texas Registered Engineering Firm No. F-1442
By	/s/ Stephen M. Hamburg
	Stephen M. Hamburg, P.E.
	Vice President

SMH/jj

Attachments

Appendix

Reserves Definitions In Accordance With
Securities and Exchange Commission Regulation S-X

Reserves

     Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

     Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Proved Oil and Gas Reserves

     Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

1. The area of the reservoir considered as proved includes:

a.	The area identified by drilling and limited by fluid contacts, if any, and
b.	Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

2.	In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
3.	Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
4.	Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

a.	Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
b.	The project has been approved for development by all necessary parties and entities, including governmental entities.

i

Appendix

5. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed Oil and Gas Reserves

     Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

1.	Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
2.	Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped Oil and Gas Reserves

     Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

1.	Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
2.	Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
3.	Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined below, or by other evidence using reliable technology establishing reasonable certainty.

Analogous Reservoir

     Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

1.	Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
2.	Same environment of deposition;
3.	Similar geological structure; and
4.	Same drive mechanism.

     Reservoir properties must, in aggregate, be no more favorable in the analog than in the reservoir of interest.

ii

Appendix

Probable Reserves

     Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

1.	When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
2.	Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
3.	Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
4.	See also guidelines in Items 4 and 6 under Possible Reserves.

Possible Reserves

     Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

1.	When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
2.	Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
3.	Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
4.	The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
5.	Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
6.	Pursuant to Item 3 under Proved Oil and Gas Reserves, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

iii

LIST OF ATTACHMENTS

	Table No.
Total Proved Reserves		1
One-line Summary		2

WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMICS AS OF DECEMBER 31, 2009
UNDERLYING PROPERTIES AND TRUST INTERESTS

NON-ESCALATED 12/31/2009 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%
2010		129,153		11,348		1.399		15,877		5,595		1,611		—		8,671		8,291				1,502		1,504		1,434
2011		100,978		8,846		1.393		12,325		4,747		1,248		—		6,330		5,504				1,079		1,061		918
2012		78,423		6,782		1.397		9,471		3,963		956		—		4,553		3,599				736		724		569
2013		60,542		5,208		1.390		7,238		3,292		730		—		3,217		2,311				978		1,128		800
2014		45,551		3,887		1.388		5,394		2,624		543		—		2,228		1,455				679		761		490
2015		33,642		2,814		1.395		3,926		2,013		394		—		1,519		902				458		504		295
2016		23,860		2,013		1.398		2,815		1,508		280		—		1,027		554				312		337		179
2017		17,227		1,434		1.388		1,990		1,101		197		—		692		339				219		221		106
2018		12,434		1,006		1.381		1,390		783		137		—		470		210				152		142		62
2019		8,866		700		1.354		948		535		92		—		320		130				117		92		37
2020		6,149		509		1.291		657		377		64		—		216		80				94		57		21
2021		4,063		346		1.281		443		255		44		—		145		49				65		33		11
2022		2,906		256		1.250		320		189		32		—		99		30				49		19		6
2023		2,140		184		1.289		237		147		25		—		66		18				30		10		3
2024		1,502		128		1.341		172		110		18		—		44		11				17		4		1
2025		1,020		90		1.396		125		82		14		—		29		7				8		2		0
2026		675		63		1.530		97		67		11		—		20		4				2		—		—
2027		490		49		1.617		79		57		9		—		13		2				—		—		—
2028		378		36		1.605		58		44		6		—		8		1				—		—		—
2029		263		20		1.730		35		27		4		—		5		1				—		—		—
AFTER		463		36		1.762		64		51		7		—		5		1				—		—		—
TOTAL		530,722		45,755		1.391		63,660		27,565		6,421		—		29,675		23,499				6,497		6,598		4,931

Date: 12/31/2009 This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report Table 1

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

									NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE	GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$
STATE: COLORADO
PROVED DEVELOPED RESERVES
HENDRICKSON GU B #1	13385	PLA-9	32N 10W 20G		1	6		723		221		144		0		0		0		144		122
SO UTE TRIBAL I 2	13389	PLA-9	32N 10W 17G		1	13		2,135		654		683		0		0		0		683		492
SO UTE TRIBAL J #2	13390	PLA-9	32N 10W 7G		1	4		415		127		62		0		0		0		62		55
TOTAL PROVED DEVELOPED: 160-Acre Colorado					3			3,273		1,002		888		0		0		0		888		669
CARTER UTE #101	14449	PLA-9	32N 10W 12L		1	6		850		33		32		0		0		0		32		27
CARTER UTE #106	13397	PLA-9	32N 10W 11M		1	5		731		56		59		0		0		0		59		51
CARTER UTE #107	13398	PLA-9	32N 10W 13A		1	14		2,131		204		247		0		0		0		247		174
CLARK CUMMINS GU A #1	13383	PLA-9	32N 10W 19F		1	15		2,441		738		806		0		0		0		806		560
HENDRICKSON GU A #1	13384	PLA-9	32N 10W 20F		1	0		0		0		0		0		0		0		0		0
J B GARDNER GU A #1	13386	PLA-9	32N 10W 22E		1	11		1,986		412		462		0		0		0		462		346
MONTGOMERY, M H #9	15248	PLA-9	31N 10W 12H		1	11		2,122		406		593		0		0		0		593		450
ROBIN FRAZIER GU A #1	13387	PLA-9	32N 10W 23D		1	8		1,285		255		268		0		0		0		268		215
SO UTE 10-3, 32-10	13399	PLA-9	32N 10W 10G		1	16		3,078		471		658		0		0		0		658		446
SO UTE 15-3, 32-10	13400	PLA-9	32N 10W 15K		1	11		1,668		128		132		0		0		0		132		100
SO UTE 16-2, 32-10	13401	PLA-9	32N 10W 16K		1	7		1,076		124		123		0		0		0		123		103
SO UTE TRIBAL H #2	13388	PLA-9	32N 10W 18P		1	5		566		173		96		0		0		0		96		84
SO UTE TRIBAL KK #1	13391	PLA-9	32N 10W 7M		1	4		374		115		43		0		0		0		43		38
SO UTE TRIBAL LL #1	13392	PLA-9	32N 10W 8M		1	2		210		64		26		0		0		0		26		24
SO UTE TRIBAL MM #1	13393	PLA-9	32N 10W 8B		1	5		641		196		150		0		0		0		150		129
SO UTE TRIBAL NN #1	13394	PLA-9	32N 10W 17B		1	5		644		197		117		0		0		0		117		100
SO UTE TRIBAL OO #1	13395	PLA-9	32N 10W 18B		1	2		210		64		17		0		0		0		17		16
SO UTE TRIBAL SS #1	13396	PLA-9	32N 10W 21B		1	8		962		295		235		0		0		0		235		191
TOTAL PROVED DEVELOPED: 320-Acre Colorado					18			20,976		3,932		4,064		0		0		0		4,064		3,054
TOTAL PROVED DEVELOPED: COLORADO					21			24,249		4,934		4,953		0		0		0		4,953		3,723
TOTAL PROVED RESERVES: COLORADO					21			24,249		4,934		4,953		0		0		0		4,953		3,723
STATE: NEW MEXICO
PROVED DEVELOPED RESERVES
SAN JUAN 28-6 UNIT #418S	19353	28-6	28N 6W 28		1	4		55		3		6		5		1		0		1		1
SAN JUAN 28-6 UNIT #437S	6102	28-6	28N 6W 28G		1	3		63		4		7		5		1		0		2		2
SAN JUAN 28-6 UNIT #439S	20714	28-6	28N 6W 29		1	2		34		2		4		2		0		0		1		1

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 1 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

									NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE	GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 28-6 UNIT #459S	20126	28-6	28N 6W 21I		1	1		27		2		3		2		0		0		1		1
SAN JUAN 28-6 UNIT #467S	12609	28-6	28N 6W 34C		1	0		6		0		1		1		0		0		0		0
SAN JUAN 28-6 UNIT #474S	12616	28-6	28N 6W 27E		1	2		21		1		2		2		0		0		0		0
SAN JUAN 28-6 UNIT #475S	12610	28-6	28N 6W 34P		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #201A	5403	29-6	29N 6W 6H		1	1		35		5		5		4		1		0		0		0
SAN JUAN 29-6 UNIT #202A	5404	29-6	29N 6W 6L		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #203A	5406	29-6	29N 6W 7E		1	5		495		65		65		41		7		0		17		14
SAN JUAN 29-6 UNIT #204A	5405	29-6	29N 6W 7A		1	4		316		41		45		33		5		0		6		6
SAN JUAN 29-6 UNIT #205A	6095	29-6	29N 6W 21C		1	9		1,151		151		170		83		19		0		68		54
SAN JUAN 29-6 UNIT #207A	5555	29-6	29N 6W 2D		1	7		693		91		94		57		10		0		27		22
SAN JUAN 29-6 UNIT #208A	5551	29-6	29N 6W 17E		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #209A	5552	29-6	29N 6W 17O		1	6		675		89		96		53		11		0		32		27
SAN JUAN 29-6 UNIT #210A	6093	29-6	29N 6W 20D		1	11		1,328		175		194		99		22		0		74		55
SAN JUAN 29-6 UNIT #211A	6094	29-6	29N 6W 20H		1	2		143		19		22		17		2		0		3		3
SAN JUAN 29-6 UNIT #214A	5407	29-6	29N 6W 3P		1	4		345		45		45		32		5		0		8		7
SAN JUAN 29-6 UNIT #215A	5408	29-6	29N 6W 3C		1	9		1,114		146		147		79		16		0		52		41
SAN JUAN 29-6 UNIT #216A	5410	29-6	29N 6W 4K		1	6		703		92		94		55		10		0		28		23
SAN JUAN 29-6 UNIT #217A	5411	29-6	29N 6W 5H		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #218A	5412	29-6	29N 6W 5M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #220A	6081	29-6	29N 6W 11O		1	9		1,093		144		151		79		17		0		55		43
SAN JUAN 29-6 UNIT #221A	6082	29-6	29N 6W 11E		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #236A	5553	29-6	29N 6W 18E		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #237A	5110	29-6	29N 6W 1O		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #238A	5033	29-6	29N 6W 1L		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #239A	5616	29-6	29N 6W 2B		1	1		56		7		8		7		1		0		0		0
SAN JUAN 29-6 UNIT #240A	6078	29-6	29N 6W 18P		1	4		388		51		53		34		6		0		13		12
SAN JUAN 29-6 UNIT #241A	6091	29-6	29N 6W 19I		1	11		1,473		194		222		102		25		0		95		71
SAN JUAN 29-6 UNIT #242A	5554	29-6	29N 6W 19D		1	9		1,007		132		149		79		17		0		54		42
SAN JUAN 29-6 UNIT #245A	5413	29-6	29N 6W 8D		1	3		230		30		31		24		3		0		3		3
SAN JUAN 29-6 UNIT #44A	5623	29-6	29N 6W 26N		1	4		262		30		45		26		5		0		14		13
SAN JUAN 29-6 UNIT #45A	5637	29-6	29N 6W 27A		1	7		712		94		136		57		15		0		64		54
SAN JUAN 29-6 UNIT #63A	5638	29-6	29N 6W 30H		1	7		1,053		138		205		68		23		0		114		96
SAN JUAN 29-6 UNIT #72A	6098	29-6	29N 6W 22L		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #176	707	29-7	29N 7W 22F		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #187	832	29-7	29N 7W 3M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #188	18165	29-7	29N 7W 6		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #189	8020	29-7	29N 7W 14D		1	3		82		9		18		13		2		0		3		3
SAN JUAN 29-7 UNIT #190	11717	29-7	29N 7W 16I		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #191	945	29-7	29N 7W 22J		1	0		0		0		0		0		0		0		0		0

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 2 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

									NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE	GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 29-7 UNIT #507S	6070	29-7	29N 7W 13G		1	8		629		72		139		52		15		0		72		59
SAN JUAN 29-7 UNIT #520S	6062	29-7	29N 7W 8E		1	3		96		11		20		14		2		0		4		4
SAN JUAN 29-7 UNIT #521S	6069	29-7	29N 7W 13L		1	7		510		59		109		45		12		0		51		43
SAN JUAN 29-7 UNIT #526S	12224	29-7	29N 7W 21E		1	2		39		4		12		9		1		0		2		2
SAN JUAN 29-7 UNIT #530S	6076	29-7	29N 7W 24A		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #545S	6068	29-7	29N 7W 12H		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #549S	11702	29-7	29N 7W 9M		1	4		195		22		44		24		5		0		15		13
SAN JUAN 29-7 UNIT #563S	1195	29-7	29N 7W 24L		1	7		502		58		126		42		14		0		70		60
SAN JUAN 29-7 UNIT #585S	30440	29-7	29N 7W 15P		1	2		69		8		16		12		2		0		2		2
SAN JUAN 29-7 UNIT #589	20697	29-7	29N 7W 21O		1	2		48		5		15		11		2		0		2		2
CAT DRAW COM #101S	20071	30-5	30N 5W 23P		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #201A	5722	30-5	30N 5W 19D		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #202A	1551	30-5	30N 5W 6P		1	4		574		108		120		60		13		0		46		42
SAN JUAN 30-5 UNIT #203A	9785	30-5	30N 5W 6L		1	5		742		140		157		76		17		0		64		57
SAN JUAN 30-5 UNIT #206A	5721	30-5	30N 5W 18O		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #207A	5034	30-5	30N 5W 18E		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #208A	5723	30-5	30N 5W 19P		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #209A	5781	30-5	30N 5W 30O		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #210A	5780	30-5	30N 5W 30C		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #212A	5782	30-5	30N 5W 31E		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #213A	17901	30-5	30N 5W 5A		1	4		430		81		90		52		10		0		28		25
SAN JUAN 30-5 UNIT #214A	8013	30-5	30N 5W 5E		1	2		201		38		42		30		5		0		8		7
SAN JUAN 30-5 UNIT #215A	5702	30-5	30N 5W 8H		1	1		52		10		10		9		1		0		1		1
SAN JUAN 30-5 UNIT #216A	5731	30-5	30N 5W 20D		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #217A	5734	30-5	30N 5W 21C		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #218A	5720	30-5	30N 5W 17O		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #219A	5108	30-5	30N 5W 5C		1	1		115		22		23		19		3		0		2		2
SAN JUAN 30-5 UNIT #220A	8014	30-5	30N 5W 8		1	6		838		158		175		87		19		0		69		59
SAN JUAN 30-5 UNIT #223A	5733	30-5	30N 5W 21P		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #226A	5772	30-5	30N 5W 29C		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #229A	5735	30-5	30N 5W 21J		1	0		26		5		5		4		1		0		0		0
SAN JUAN 30-5 UNIT #231A	5139	30-5	30N 5W 32M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #234A	5737	30-5	30N 5W 22D		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #237A	5052	30-5	30N 5W 16B		1	2		157		30		31		25		3		0		3		3
SAN JUAN 30-5 UNIT #239A	5716	30-5	30N 5W 15M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #240A	5738	30-5	30N 5W 22H		1	1		42		8		9		8		1		0		0		0
SAN JUAN 30-5 UNIT #241A	5739	30-5	30N 5W 23L		1	3		228		43		48		36		5		0		7		6
SAN JUAN 30-5 UNIT #243A	5718	30-5	30N 5W 15O		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #249A	5740	30-5	30N 5W 23A		1	3		227		43		49		35		5		0		9		8

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 3 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

									NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE	GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 30-5 UNIT #255A	5714	30-5	30N 5W 14M		1	1		122		23		27		19		3		0		5		5
SAN JUAN 30-5 UNIT #257A	5712	30-5	30N 5W 11M		1	5		792		149		169		81		19		0		69		60
SAN JUAN 30-5 UNIT #258A	5715	30-5	30N 5W 14G		1	2		160		30		34		24		4		0		6		6
SAN JUAN 30-5 UNIT #259A	12145	30-5	30N 5W 9L		1	3		233		44		51		36		6		0		9		8
SAN JUAN 30-5 UNIT #260A	9786	30-5	30N 5W 9L		1	8		1,313		247		266		124		30		0		113		93
SAN JUAN 30-5 UNIT #261A	5713	30-5	30N 5W 9L		1	3		491		92		104		51		12		0		42		38
SAN JUAN 30-5 UNIT #263A	12144	30-5	30N 5W 9L		1	3		284		53		63		37		7		0		19		18
SAN JUAN 30-5 UNIT #264A	5710	30-5	30N 5W 9O		1	7		982		185		195		105		22		0		69		57
SAN JUAN 30-5 UNIT #265A	5711	30-5	30N 5W 10O		1	7		1,289		242		260		115		29		0		116		97
SAN JUAN 30-5 UNIT #266A	8017	30-5	30N 5W 10		1	6		1,126		212		225		104		25		0		96		81
SAN JUAN 30-5 UNIT #267A	11794	30-5	30N 5W 24O		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #268A	11795	30-5	30N 5W 23A		1	3		244		46		53		36		6		0		11		10
SAN JUAN 30-6 UNIT #400S	6042	30-6	30N 7W 14M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #401S	6041	30-6	30N 7W 13N		1	1		92		5		9		6		1		0		1		1
SAN JUAN 30-6 UNIT #403S	5435	30-6	30N 6W 9G		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #404S	5516	30-6	30N 7W 23B		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #405S	5436	30-6	30N 6W 9M		1	2		158		8		14		11		2		0		2		2
SAN JUAN 30-6 UNIT #408S	19395	30-6	30N 6W 16		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #410S	5539	30-6	30N 6W 26A		1	4		375		19		33		20		4		0		10		8
SAN JUAN 30-6 UNIT #411S	1258	30-6	30N 7W 35K		1	1		57		3		5		4		1		0		0		0
SAN JUAN 30-6 UNIT #412S	996	30-6	30N 7W 24K		1	0		10		1		1		1		0		0		0		0
SAN JUAN 30-6 UNIT #413S	5508	30-6	30N 7W 23K		1	2		122		6		11		9		1		0		1		1
SAN JUAN 30-6 UNIT #414S	1260	30-6	30N 7W 27M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #415S	5077	30-6	30N 7W 26N		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #419S	6028	30-6	30N 7W 11H		1	2		150		7		15		10		2		0		3		3
SAN JUAN 30-6 UNIT #420S	6039	30-6	30N 7W 12G		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #422S	1261	30-6	30N 7W 33H		1	4		287		14		26		18		3		0		5		5
SAN JUAN 30-6 UNIT #423S	1782	30-6	30N 7W 28		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #424S	1723	30-6	30N 7W 33E		1	3		169		8		17		11		2		0		3		3
SAN JUAN 30-6 UNIT #425S	1322	30-6	30N 7W 35H		1	15		1,949		97		182		80		20		0		82		57
SAN JUAN 30-6 UNIT #426S	1271	30-6	30N 7W 34K		1	7		643		32		59		33		7		0		19		16
SAN JUAN 30-6 UNIT #429S	1773	30-6	30N 7W 32J		1	7		707		35		66		36		7		0		22		18
SAN JUAN 30-6 UNIT #430S	5447	30-6	30N 6W 8G		1	2		118		6		10		8		1		0		2		1
SAN JUAN 30-6 UNIT #431S	5450	30-6	30N 6W 10M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #432S	5448	30-6	30N 6W 10B		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #433S	11700	30-6	30N 6W 11K		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #434S	5469	30-6	30N 6W 12M		1	4		309		15		29		17		3		0		9		8
SAN JUAN 30-6 UNIT #435S	5484	30-6	30N 6W 13I		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #436S	5525	30-6	30N 6W 15G		1	4		323		16		28		19		3		0		6		5

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 4 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

									NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE	GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 30-6 UNIT #437S	5504	30-6	30N 6W 11H		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #438S	5468	30-6	30N 6W 12H		1	0		4		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #441S	5495	30-6	30N 6W 31A		1	2		141		7		12		8		1		0		2		2
SAN JUAN 30-6 UNIT #442S	5485	30-6	30N 6W 14P		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #443S	1206	30-6	30N 6W 36G		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #444S	19402	30-6	30N 6W 36N		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #445S	5479	30-6	30N 6W 13I		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #446S	5502	30-6	30N 6W 35N		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #450S	5437	30-6	30N 6W 7K		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #451S	5430	30-6	30N 6W 7H		1	0		5		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #452S	5438	30-6	30N 6W 8N		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #454S	5529	30-6	30N 6W 17A		1	1		69		3		6		5		1		0		0		0
SAN JUAN 30-6 UNIT #455S	5530	30-6	30N 6W 18N		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #457S	5257	30-6	30N 6W 19M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #460S	5487	30-6	30N 6W 20N		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #461S	5503	30-6	30N 7W 11M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #462S	6040	30-6	30N 7W 12M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #463S	5505	30-6	30N 7W 13H		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #465S	5507	30-6	30N 7W 15J		1	2		95		5		10		7		1		0		1		1
SAN JUAN 30-6 UNIT #466S	6051	30-6	30N 7W 22B		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #467S COM	6049	30-6	30N 7W 22M		1	2		124		3		6		4		1		0		1		1
SAN JUAN 30-6 UNIT #468S	5117	30-6	30N 7W 36K		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #471S	5488	30-6	30N 6W 21K		1	1		64		3		6		5		1		0		1		1
SAN JUAN 30-6 UNIT #473S	5535	30-6	30N 6W 22M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #475S	5493	30-6	30N 6W 27L		1	0		15		1		1		1		0		0		0		0
SAN JUAN 30-6 UNIT #476S	5541	30-6	30N 6W 28A		1	5		522		26		46		26		5		0		15		13
SAN JUAN 30-6 UNIT #477S	5130	30-6	30N 6W 28M		1	6		649		32		54		30		6		0		18		15
SAN JUAN 30-6 UNIT #478S	5137	30-6	30N 6W 29A		1	5		452		23		37		22		4		0		10		9
SAN JUAN 30-6 UNIT #479S	5542	30-6	30N 6W 29K		1	3		333		17		28		16		3		0		9		8
SAN JUAN 30-6 UNIT #481S	5431	30-6	30N 6W 30J		1	1		49		2		4		3		0		0		0		0
SAN JUAN 30-6 UNIT #483S	5500	30-6	30N 6W 34H		1	4		360		18		31		20		3		0		8		7
SAN JUAN 30-6 UNIT #484S	5499	30-6	30N 6W 34N		1	2		166		8		14		10		2		0		3		3
SAN JUAN 30-6 UNIT #485S	5116	30-6	30N 7W 36G		1	2		109		5		9		7		1		0		1		1
SAN JUAN 30-6 UNIT #486S	5143	30-6	30N 6W 23H		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #488S	5490	30-6	30N 6W 24A		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #489S	5489	30-6	30N 6W 24K		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #490S	5492	30-6	30N 6W 25H		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #491S	5491	30-6	30N 6W 25M		1	1		86		4		7		6		1		0		0		0
SAN JUAN 30-6 UNIT #493S	5131	30-6	30N 6W 32M		1	0		0		0		0		0		0		0		0		0

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 5 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

									NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE	GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 30-6 UNIT #494S	5498	30-6	30N 6W 33B		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #495S	5497	30-6	30N 6W 33K		1	4		427		21		36		22		4		0		10		9
SAN JUAN 30-6 UNIT #496S	5501	30-6	30N 6W 35G		1	0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #497S	1778	30-6	30N 7W 33I		1	0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #201A	1813	31-6	30N 6W 1		1	2		199		21		23		18		3		0		2		2
SAN JUAN 31-6 UNIT #202A	1812	31-6	30N 6W 1D		1	0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #203A	1819	31-6	30N 6W 3		1	1		49		5		6		5		1		0		0		0
SAN JUAN 31-6 UNIT #204A	1817	31-6	30N 6W 3		1	0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #205A	1821	31-6	30N 6W 4		1	0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #206A	1820	31-6	30N 6W 4		1	0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #209A	6030	31-6	30N 6W 1L		1	0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #210A	1816	31-6	30N 6W 2		1	0		16		2		2		2		0		0		0		0
SAN JUAN 31-6 UNIT #211A	1815	31-6	30N 6W 2		1	9		1,477		158		172		100		19		0		53		42
SAN JUAN 31-6 UNIT #212A	5613	31-6	30N 6W 5P		1	0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #213A	5612	31-6	30N 6W 5E		1	0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #214A	1360	31-6	31N 6W 36H		1	0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #215A	1361	31-6	31N 6W 36K		1	2		178		19		22		17		2		0		2		2
SAN JUAN 31-6 UNIT #216A	1788	31-6	31N 6W 35A		1	2		286		31		34		24		4		0		6		5
SAN JUAN 31-6 UNIT #217A	1363	31-6	31N 6W 35M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #218A	1790	31-6	31N 6W 34		1	0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #219A	1789	31-6	31N 6W 34		1	1		141		15		17		14		2		0		1		1
SAN JUAN 31-6 UNIT #223A	1377	31-6	31N 6W 32I		1	0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #229A	1386	31-6	31N 6W 28		1	2		167		18		20		15		2		0		3		3
SAN JUAN 31-6 UNIT #230A	1383	31-6	31N 6W 27A		1	4		515		55		62		43		7		0		12		11
SAN JUAN 31-6 UNIT #231A	1384	31-6	31N 6W 27E		1	0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #234A	1385	31-6	31N 6W 29L		1	1		54		6		7		5		1		0		0		0
ALLISON UNIT COM #105S	5141	32-7	32N 7W 26C		1	2		103		5		7		5		1		0		2		1
ALLISON UNIT COM #146S	5266	32-7	32N 7W 23		1	4		228		20		30		18		3		0		9		8
FEDERAL G #5 COM	5796	32-7	31N 7W 10G		1	5		378		8		13		6		1		0		6		5
MIDDLE MESA COM #3S	4769	32-7	32N 7W 33M		1	6		533		24		34		16		4		0		14		12
SAN JUAN 32-7 UNIT #202A	10784	32-7	32N 7W 18		1	6		530		94		149		60		16		0		72		62
SAN JUAN 32-7 UNIT #203A	5109	32-7	32N 7W 22M		1	2		153		27		40		23		4		0		12		12
SAN JUAN 32-7 UNIT #204A	4126	32-7	32N 7W 36C		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-7 UNIT #205A	1231	32-7	32N 7W 22M		1	11		1,772		316		464		127		50		0		287		225
SAN JUAN 32-7 UNIT #206A	719	32-7	32N 7W 27P		1	6		510		91		129		60		14		0		55		47
SAN JUAN 32-7 UNIT #207A	5812	32-7	32N 7W 27C		1	5		457		81		116		56		13		0		48		41
SAN JUAN 32-7 UNIT #208A	970	32-7	32N 7W 34B		1	3		221		39		57		33		6		0		17		15
SAN JUAN 32-7 UNIT #209A	1207	32-7	32N 7W 35A		1	5		394		70		101		47		11		0		43		38
SAN JUAN 32-7 UNIT #210A	4125	32-7	32N 7W 36K		1	3		209		37		53		33		6		0		14		13

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 6 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

									NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE	GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 32-7 UNIT #211A	648	32-7	32N 7W 35N		1	4		285		51		72		37		8		0		27		25
SAN JUAN 32-7 UNIT #213A COM	12143	32-7	31N 7W 18M		1	5		357		40		58		32		6		0		19		17
SAN JUAN 32-7 UNIT #214A	5804	32-7	32N 7W 34C		1	4		223		40		58		35		6		0		16		15
SAN JUAN 32-7 UNIT #215A	1210	32-7	32N 7W 32N		1	7		705		126		181		76		20		0		85		71
SAN JUAN 32-7 UNIT #216A	6120	32-7	31N 7W 4D		1	3		199		35		50		32		5		0		13		12
SAN JUAN 32-7 UNIT #217A	655	32-7	31N 7W 4A		1	9		960		171		246		97		27		0		122		97
SAN JUAN 32-7 UNIT #218A	1208	32-7	31N 7W 5M		1	8		849		151		227		86		24		0		116		95
SAN JUAN 32-7 UNIT #219A	6122	32-7	31N 7W 5P		1	7		799		142		205		80		22		0		103		85
SAN JUAN 32-7 UNIT #220A	6011	32-7	32N 7W 5M		1	3		178		28		42		24		5		0		14		13
SAN JUAN 32-7 UNIT #221A	694	32-7	31N 7W 8H		1	3		166		30		45		30		5		0		10		9
SAN JUAN 32-7 UNIT #222A	6008	32-7	32N 7W 20P		1	14		1,890		337		498		158		54		0		286		207
SAN JUAN 32-7 UNIT #224A COM	4795	32-7	32N 7W 21N		1	11		1,537		205		306		95		33		0		178		137
SAN JUAN 32-7 UNIT #227A COM	6010	32-7	31N 7W 18M		1	4		243		33		50		28		5		0		17		15
SAN JUAN 32-7 UNIT #228A COM	12142	32-7	31N 7W 7M		1	6		465		42		63		32		7		0		24		20
SAN JUAN 32-7 UNIT #229A	4893	32-7	31N 7W 9B		1	4		266		47		68		39		7		0		21		19
SAN JUAN 32-7 UNIT #230A	5798	32-7	31N 7W 17O		1	1		29		5		8		6		1		0		0		0
SAN JUAN 32-7 UNIT #231A	1323	32-7	31N 7W 17L		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-7 UNIT #232A	4127	32-7	31N 7W 8N		1	8		679		121		176		81		19		0		76		62
SAN JUAN 32-7 UNIT #233A	11353	32-7	32N 7W 20L		1	7		1,096		195		295		86		32		0		178		149
SAN JUAN 32-7 UNIT #234A	1229	32-7	32N 7W 32H		1	1		40		7		10		8		1		0		1		1
SAN JUAN 32-7 UNIT #235A	5811	32-7	32N 7W 29N		1	11		1,982		353		515		133		56		0		326		255
SAN JUAN 32-7 UNIT #236A	720	32-7	32N 7W 28J		1	7		751		134		193		73		21		0		100		84
SAN JUAN 32-7 UNIT #237A	721	32-7	32N 7W 28J		1	0		14		3		4		3		0		0		0		0
SAN JUAN 32-7 UNIT #238A	1211	32-7	32N 7W 29B		1	7		799		142		207		72		22		0		112		95
SAN JUAN 32-7 UNIT #240A	717	32-7	32N 7W 19J		1	10		1,379		246		364		116		39		0		209		163
SAN JUAN 32-7 UNIT #241A	718	32-7	32N 7W 21I		1	2		144		26		38		23		4		0		11		11
SAN JUAN 32-7 UNIT #242A	1212	32-7	32N 7W 33F		1	6		599		107		154		66		17		0		71		60
SAN JUAN 32-7 UNIT #243A	750	32-7	32N 7W 19C		1	10		1,226		218		327		109		35		0		183		144
SAN JUAN 32-7 UNIT #244A	5818	32-7	32N 7W 17E		1	8		770		137		211		81		23		0		107		89
SAN JUAN 32-7 UNIT #245	19416	32-7	32N 7W 17G		1	7		1,673		298		460		92		50		0		318		274
SAN JUAN 32-7 UNIT #246A	12147	32-7	32N 7W 18A		1	11		1,931		344		522		133		56		0		333		259
SAN JUAN 32-7 UNIT #247A	10788	32-7	32N 7W 7G		1	4		112		20		65		37		7		0		21		19
SAN JUAN 32-7 UNIT #248A	4389	32-7	32N 7W 8		1	8		877		156		242		85		26		0		130		107
SAN JUAN 32-7 UNIT #249A	757	32-7	32N 7W 8		1	9		1,046		186		298		95		32		0		171		139
SAN JUAN 32-7 UNIT #250A	11697	32-7	32N 7W 17K		1	8		1,170		208		315		91		34		0		191		158
RATTLESNAKE CANYON #105S	4771	32-8	32N 8W 20		1	8		1,304		55		81		34		9		0		38		31
SAN JUAN 32-8 UNIT #202A	1495	32-8	32N 8W 27M		1	4		476		53		79		39		8		0		31		28
SAN JUAN 32-8 UNIT #203A	1213	32-8	32N 8W 33G		1	1		92		10		15		12		2		0		2		2
SAN JUAN 32-8 UNIT #204A	5142	32-8	32N 8W 34L		1	5		744		83		119		55		13		0		51		45

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 7 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

									NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE	GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 32-8 UNIT #205A	1504	32-8	32N 8W 34G		1	5		633		71		102		51		11		0		40		35
SAN JUAN 32-8 UNIT #206A	5603	32-8	31N 8W 24G		1	1		67		8		11		8		1		0		1		1
SAN JUAN 32-8 UNIT #207A	5598	32-8	31N 8W 22N		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-8 UNIT #208A	4275	32-8	32N 8W 29N		1	9		2,139		238		324		115		35		0		174		139
SAN JUAN 32-8 UNIT #213A	6003	32-8	32N 8W 22N		1	7		1,208		135		201		79		22		0		100		84
SAN JUAN 32-8 UNIT #218A	1514	32-8	32N 8W 35G		1	6		981		109		159		68		17		0		74		63
SAN JUAN 32-8 UNIT #219A	1529	32-8	32N 8W 35M		1	4		478		53		79		43		9		0		27		24
SAN JUAN 32-8 UNIT #220A	5602	32-8	31N 8W 24D		1	3		317		35		50		33		5		0		11		10
SAN JUAN 32-8 UNIT #221A	5583	32-8	31N 8W 9D		1	3		383		43		59		34		6		0		18		17
SAN JUAN 32-8 UNIT #222A	5584	32-8	31N 8W 9O		1	5		605		67		91		49		10		0		33		29
SAN JUAN 32-8 UNIT #223A	5588	32-8	31N 8W 10E		1	7		1,024		114		157		72		17		0		68		58
SAN JUAN 32-8 UNIT #224A	5589	32-8	31N 8W 10P		1	4		517		58		82		43		9		0		30		27
SAN JUAN 32-8 UNIT #225A	5592	32-8	31N 8W 15E		1	2		222		25		34		23		4		0		7		7
SAN JUAN 32-8 UNIT #226A	5593	32-8	31N 8W 15P		1	2		181		20		27		19		3		0		5		5
SAN JUAN 32-8 UNIT #227A	5594	32-8	31N 8W 16E		1	0		18		2		3		2		0		0		0		0
SAN JUAN 32-8 UNIT #228A	5595	32-8	31N 8W 16O		1	5		540		60		81		48		9		0		24		21
SAN JUAN 32-8 UNIT #229A	1204	32-8	32N 8W 20E		1	7		1,182		132		199		77		22		0		101		85
SAN JUAN 32-8 UNIT #230A	1544	32-8	32N 8W 28G		1	5		662		74		104		54		11		0		39		34
SAN JUAN 32-8 UNIT #231A	1541	32-8	32N 8W 28L		1	10		1,864		208		296		117		32		0		147		115
SAN JUAN 32-8 UNIT #232A	972	32-8	32N 8W 29N		1	3		379		42		61		34		7		0		20		19
SAN JUAN 32-8 UNIT #233A	5675	32-8	32N 8W 30O		1	4		476		53		74		42		8		0		24		21
SAN JUAN 32-8 UNIT #234A	4904	32-8	31N 8W 21E		1	1		52		6		7		6		1		0		0		0
SAN JUAN 32-8 UNIT #235A	5597	32-8	31N 8W 21O		1	1		48		5		7		6		1		0		0		0
SAN JUAN 32-8 UNIT #236A	5599	32-8	31N 8W 22O		1	2		207		23		30		22		3		0		4		4
SAN JUAN 32-8 UNIT #237A	5601	32-8	31N 8W 23I		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-8 UNIT #238A	5600	32-8	31N 8W 23E		1	1		92		10		13		11		1		0		1		1
SAN JUAN 32-8 UNIT #239A	5670	32-8	31N 8W 30D		1	3		312		35		49		30		5		0		14		12
SAN JUAN 32-8 UNIT #240A	5047	32-8	31N 8W 3E		1	4		560		62		87		47		9		0		31		27
SAN JUAN 32-8 UNIT #241A	5558	32-8	31N 8W 4O		1	6		920		103		141		66		15		0		60		51
SAN JUAN 32-8 UNIT #242A	5557	32-8	31N 8W 4E		1	5		558		62		85		48		9		0		28		25
SAN JUAN 32-8 UNIT #243A	1884	32-8	31N 8W 11M		1	5		613		68		98		50		11		0		38		33
SAN JUAN 32-8 UNIT #244A	5591	32-8	31N 8W 14P		1	2		195		22		29		21		3		0		5		5
SAN JUAN 32-8 UNIT #245A	5590	32-8	31N 8W 14F		1	1		109		12		17		13		2		0		2		2
SAN JUAN 32-8 UNIT #247A	5999	32-8	32N 8W 19E		1	8		1,593		178		264		93		29		0		143		118
SAN JUAN 32-8 UNIT #248A	1885	32-8	32N 8W 11G		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-8 UNIT #249R	11696	32-8	31N 8W 3A		1	1		70		8		11		8		1		0		2		2
SAN JUAN 32-8 UNIT #250A	5048	32-8	32N 8W 33M		1	6		882		98		138		62		15		0		61		52
SAN JUAN 32-8 UNIT #253A	1887	32-8	32N 8W 27G		1	6		794		89		131		61		14		0		56		48
SAN JUAN 32-8 UNIT #254A	12149	32-8	32N 8W 23F		1	7		1,063		119		178		80		19		0		79		66

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 8 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

									NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE	GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 32-8 UNIT #255A	1867	32-8	32N 8W 24		1	5		617		69		105		52		11		0		42		36
SAN JUAN 32-8 UNIT #256A	1888	32-8	32N 8W 25		1	6		1,002		112		168		68		18		0		82		70
SAN JUAN 32-8 UNIT #257A	6000	32-8	32N 8W 19I		1	6		1,045		117		168		69		18		0		81		70
SAN JUAN 32-8 UNIT #258A	6001	32-8	32N 8W 15P		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-8 UNIT #259	6004	32-8	32N 8W 22N		1	2		157		18		27		17		3		0		6		6
SAN JUAN 32-8 UNIT #260A	5998	32-8	32N 8W 18M		1	8		1,531		171		256		91		28		0		136		113
SAN JUAN 32-8 UNIT #261A	6507	32-8	32N 8W 17D		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-8 UNIT #262A	727	32-8	32N 8W 17P		1	5		597		67		101		53		11		0		37		32
SAN JUAN 32-8 UNIT #263	19428	32-8	32N 8W 15A		1	7		849		95		147		71		16		0		60		50
SAN JUAN 32-8 UNIT #264A	11695	32-8	32N 8W 9		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-8 UNIT #265A	10792	32-8	32N 8W 14C		1	8		1,158		129		201		87		22		0		92		75
SAN JUAN 32-8 UNIT #266	10790	32-8	32N 8W 14		1	1		49		5		9		8		1		0		1		1
SAN JUAN 32-8 UNIT #267	6005	32-8	32N 8W 23I		1	7		923		103		163		72		18		0		74		62
SAN JUAN 32-9 UNIT #104S	5911	32-9	32N 10W 24G		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #201S	5935	32-9	31N 9W 2H		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #202S	5939	32-9	31N 9W 2M		1	0		14		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #215S	5992	32-9	32N 9W 10M		1	6		1,152		30		40		18		4		0		17		15
SAN JUAN 32-9 UNIT #217S	5994	32-9	32N 9W 16I		1	4		638		17		23		12		2		0		8		7
SAN JUAN 32-9 UNIT #226S	5970	32-9	32N 9W 32H		1	0		30		1		1		1		0		0		0		0
SAN JUAN 32-9 UNIT #228S	5978	32-9	32N 9W 36G		1	3		374		10		12		8		1		0		3		3
SAN JUAN 32-9 UNIT #229S	5933	32-9	32N 10W 36H		1	1		49		1		2		1		0		0		0		0
SAN JUAN 32-9 UNIT #230S	5934	32-9	32N 10W 36M		1	1		148		4		5		4		1		0		1		1
SAN JUAN 32-9 UNIT #235S	5979	32-9	32N 9W 36M		1	1		146		4		5		4		1		0		1		1
SAN JUAN 32-9 UNIT #241S	5993	32-9	32N 9W 13		1	9		2,521		66		91		32		10		0		49		40
SAN JUAN 32-9 UNIT #250S	5945	32-9	31N 9W 4G		1	1		79		2		2		2		0		0		0		0
SAN JUAN 32-9 UNIT #251S	5947	32-9	31N 9W 4M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #252S	5949	32-9	31N 9W 5A		1	1		113		3		4		3		0		0		0		0
SAN JUAN 32-9 UNIT #253S	5952	32-9	31N 9W 5M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #254S	5953	32-9	31N 9W 6A		1	1		69		2		2		2		0		0		0		0
SAN JUAN 32-9 UNIT #255S	5955	32-9	31N 9W 6L		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #257S	5957	32-9	31N 9W 8N		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #259S	5959	32-9	31N 9W 9L		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #260S	5960	32-9	31N 9W 10B		1	1		64		2		2		2		0		0		0		0
SAN JUAN 32-9 UNIT #261S	5961	32-9	31N 9W 10N		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #262S	12591	32-9	31N 9W 15A		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #268S	5859	32-9	31N 10W 1A		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #270S	5991	32-9	32N 9W 18A		1	4		612		16		21		11		2		0		7		6
SAN JUAN 32-9 UNIT #271S	1351	32-9	32N 9W 18L		1	3		440		11		15		9		2		0		4		3
SAN JUAN 32-9 UNIT #272S	12611	32-9	32N 8W 21		1	3		330		9		12		8		1		0		3		3

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 9 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

									NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE	GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 32-9 UNIT #273S	5980	32-9	32N 9W 19L		1	1		126		3		4		3		0		0		1		1
SAN JUAN 32-9 UNIT #274S	5962	32-9	32N 9W 28H		1	2		265		7		9		6		1		0		2		2
SAN JUAN 32-9 UNIT #275S	5965	32-9	32N 9W 29M		1	3		374		10		13		9		1		0		3		3
SAN JUAN 32-9 UNIT #276S	5964	32-9	32N 9W 27M		1	3		300		8		10		7		1		0		2		2
SAN JUAN 32-9 UNIT #277S	5966	32-9	32N 9W 30M		1	3		340		9		11		8		1		0		2		2
SAN JUAN 32-9 UNIT #278S	5967	32-9	32N 9W 31A		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #279S	5968	32-9	32N 9W 31M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #281S	5974	32-9	32N 9W 32K		1	0		22		1		1		1		0		0		0		0
SAN JUAN 32-9 UNIT #282S	5975	32-9	32N 9W 33G		1	2		200		5		7		5		1		0		1		1
SAN JUAN 32-9 UNIT #283S	5976	32-9	32N 9W 33L		1	2		237		6		8		6		1		0		2		1
SAN JUAN 32-9 UNIT #284S	1357	32-9	32N 10W 13A		1	4		510		13		17		10		2		0		5		4
SAN JUAN 32-9 UNIT #285S	5855	32-9	32N 10W 13N		1	4		663		17		22		12		2		0		7		6
SAN JUAN 32-9 UNIT #286S	5914	32-9	32N 10W 14A		1	6		1,015		26		32		17		3		0		11		10
SAN JUAN 32-9 UNIT #287S	5915	32-9	32N 10W 14K		1	2		365		10		12		7		1		0		3		3
SAN JUAN 32-9 UNIT #288S	5916	32-9	32N 10W 23B		1	3		445		12		15		9		2		0		4		4
SAN JUAN 32-9 UNIT #289S	5918	32-9	32N 10W 23M		1	1		104		3		3		3		0		0		0		0
SAN JUAN 32-9 UNIT #291S	5402	32-9	32N 10W 24M		1	4		455		12		15		10		2		0		4		3
SAN JUAN 32-9 UNIT #292S	5925	32-9	32N 10W 25A		1	0		22		1		1		1		0		0		0		0
SAN JUAN 32-9 UNIT #293S	5927	32-9	32N 10W 25M		1	0		36		1		1		1		0		0		0		0
SAN JUAN 32-9 UNIT #294S	5930	32-9	32N 10W 26A		1	1		128		3		4		3		0		0		1		1
SAN JUAN 32-9 UNIT #295S	5931	32-9	32N 10W 26L		1	2		181		5		6		5		1		0		1		1
SAN JUAN 32-9 UNIT #297S	5854	32-9	32N 10W 35K		1	0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #300S	5856	32-9	32N 10W 11K		1	4		574		15		18		11		2		0		5		5
SAN JUAN 32-9 UNIT #301S	5857	32-9	32N 10W 12K		1	2		261		7		9		6		1		0		2		1
SAN JUAN 32-9 UNIT #302S	12613	32-9	32N 8W 9		1	7		1,237		32		43		20		5		0		18		15
HUERFANO UNIT #144	20726	HUERFANO	27N 9W 31P		1	0		0		0		0		0		0		0		0		0
HUERFANO UNIT #255S	20727	HUERFANO	27N 9W 31M		1	0		0		0		0		0		0		0		0		0
HUERFANO UNIT #79	12186	HUERFANO	27N 10W 31P		1	0		0		0		0		0		0		0		0		0
HUERFANO UNIT #82	20756	HUERFANO	27N 10W 33D		1	4		180		24		65		32		7		0		26		23
NE BLANCO UNIT #400A	1809	NEBU	31N 6W 7		1	4		292		2		3		1		0		0		1		1
NE BLANCO UNIT #401A	5317	NEBU	30N 7W 9L		1	11		1,037		8		10		4		1		0		5		3
NE BLANCO UNIT #402A	5145	NEBU	30N 7W 5A		1	10		855		7		9		4		1		0		4		3
NE BLANCO UNIT #403A	5191	NEBU	30N 7W 5A		1	6		585		5		6		2		1		0		2		2
NE BLANCO UNIT #406A	5192	NEBU	30N 7W 5A		1	0		0		0		0		0		0		0		0		0
NE BLANCO UNIT #407A	17895	NEBU	30N 7W 21A		1	3		141		1		1		1		0		0		0		0
NE BLANCO UNIT #408A	5196	NEBU	30N 7W 5A		1	0		0		0		0		0		0		0		0		0
NE BLANCO UNIT #409A	5273	NEBU	30N 7W 10N		1	1		73		1		1		0		0		0		0		0
NE BLANCO UNIT #410A	17897	NEBU	31N 7W 9K		1	9		882		7		9		3		1		0		5		4
NE BLANCO UNIT #411A	5200	NEBU	30N 7W 5A		1	4		219		2		2		1		0		0		1		1

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 10 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

									NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE	GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$
NE BLANCO UNIT #412A	5802	NEBU	31N 7W 29N		1	11		1,157		9		12		5		1		0		6		5
NE BLANCO UNIT #413A	17899	NEBU	30N 7W 20A		1	6		422		3		4		2		0		0		1		1
NE BLANCO UNIT #415A	5207	NEBU	30N 7W 5A		1	11		1,111		9		11		4		1		0		5		4
NE BLANCO UNIT #416A	5282	NEBU	31N 7W 21A		1	5		304		2		3		2		0		0		1		1
NE BLANCO UNIT #417A	5274	NEBU	30N 7W 2M		1	3		221		2		2		1		0		0		1		1
NE BLANCO UNIT #418A	5210	NEBU	30N 7W 5A		1	5		341		3		4		2		0		0		1		1
NE BLANCO UNIT #419A	6031	NEBU	30N 7W 3N		1	5		423		3		4		2		0		0		2		1
NE BLANCO UNIT #421A	6033	NEBU	30N 7W 4P		1	3		223		2		2		1		0		0		1		1
NE BLANCO UNIT #422A	5146	NEBU	31N 7W 5A		1	6		317		2		3		2		0		0		1		1
NE BLANCO UNIT #423A	6037	NEBU	30N 7W 8J		1	4		332		3		3		2		0		0		1		1
NE BLANCO UNIT #425A	6038	NEBU	30N 7W 8N		1	15		1,445		11		15		6		2		0		8		5
NE BLANCO UNIT #426A	5231	NEBU	30N 7W 5A		1	5		334		3		3		2		0		0		1		1
NE BLANCO UNIT #427A	5148	NEBU	30N 7W 5A		1	10		836		7		8		4		1		0		3		3
NE BLANCO UNIT #428A	6018	NEBU	31N 7W 24A		1	5		338		3		4		2		0		0		1		1
NE BLANCO UNIT #429A	5150	NEBU	30N 7W 5A		1	4		357		3		3		2		0		0		1		1
NE BLANCO UNIT #430A	5245	NEBU	30N 7W 5A		1	5		332		3		3		2		0		0		1		1
NE BLANCO UNIT #433A	1000	NEBU	30N 8W 19M		1	4		214		2		2		1		0		0		1		0
NE BLANCO UNIT #434A	6017	NEBU	31N 7W 23A		1	9		766		6		8		3		1		0		4		3
NE BLANCO UNIT #435A	4894	NEBU	30N 8W 1K		1	10		992		8		9		4		1		0		4		3
NE BLANCO UNIT #436A	1149	NEBU	31N 6W 19K		1	6		415		3		4		2		0		0		2		1
NE BLANCO UNIT #437A	5251	NEBU	30N 7W 5A		1	4		213		2		2		1		0		0		1		0
NE BLANCO UNIT #438A	1160	NEBU	31N 6W 18A		1	10		1,120		9		12		4		1		0		6		5
NE BLANCO UNIT #439A	5169	NEBU	30N 7W 5A		1	2		87		1		1		1		0		0		0		0
NE BLANCO UNIT #440A	709	NEBU	31N 7W 11A		1	8		723		6		8		3		1		0		4		3
NE BLANCO UNIT #441A	1545	NEBU	30N 8W 24G		1	11		971		8		9		4		1		0		4		3
NE BLANCO UNIT #442A	17900	NEBU	31N 7W 11M		1	13		1,700		13		18		6		2		0		10		8
NE BLANCO UNIT #443A	17896	NEBU	30N 8W 24N		1	0		0		0		0		0		0		0		0		0
NE BLANCO UNIT #445A	5250	NEBU	30N 8W 5A		1	6		436		3		4		2		0		0		1		1
NE BLANCO UNIT #447A	5248	NEBU	30N 7W 5A		1	4		257		2		2		1		0		0		1		1
NE BLANCO UNIT #448A	5181	NEBU	30N 7W 5A		1	5		261		2		3		2		0		0		1		1
NE BLANCO UNIT #449A	5183	NEBU	30N 7W 5A		1	11		1,262		10		12		4		1		0		6		5
NE BLANCO UNIT #450A	5801	NEBU	31N 7W 32N		1	4		228		2		2		1		0		0		1		1
NE BLANCO UNIT #451A	6035	NEBU	30N 7W 6B		1	10		996		8		10		4		1		0		5		4
NE BLANCO UNIT #452A	5797	NEBU	31N 7W 15G		1	7		418		3		4		2		0		0		1		1
NE BLANCO UNIT #454A	6025	NEBU	31N 7W 33A		1	9		877		7		9		4		1		0		5		4
NE BLANCO UNIT #455A	5190	NEBU	30N 7W 5A		1	9		1,058		8		10		4		1		0		5		4
NE BLANCO UNIT #457A	5189	NEBU	30N 7W 5A		1	6		555		4		5		2		1		0		2		2
NE BLANCO UNIT #458A	5247	NEBU	30N 7W 5A		1	4		382		3		4		2		0		0		2		2
NE BLANCO UNIT #460A	1810	NEBU	31N 6W 7		1	10		1,055		8		11		4		1		0		6		5

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 11 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

									NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE	GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$
NE BLANCO UNIT #461A	5182	NEBU	30N 7W 5A		1	1		38		0		0		0		0		0		0		0
NE BLANCO UNIT #462A	5246	NEBU	30N 7W 5A		1	5		318		2		3		2		0		0		1		1
NE BLANCO UNIT #463A	5170	NEBU	30N 7W 5A		1	4		232		2		2		1		0		0		1		1
NE BLANCO UNIT #464A	17898	NEBU	31N 7W 10P		1	7		487		4		5		2		1		0		2		2
NE BLANCO UNIT #465A	5243	NEBU	30N 7W 5A		1	7		665		5		6		3		1		0		3		2
NE BLANCO UNIT #466A	6027	NEBU	31N 7W 34B		1	8		635		5		6		3		1		0		2		2
NE BLANCO UNIT #468A	5163	NEBU	30N 7W 5A		1	7		543		4		5		2		1		0		2		2
NE BLANCO UNIT #471A	5272	NEBU	31N 8W 25B		1	3		209		2		2		1		0		0		1		1
NE BLANCO UNIT #472A	5803	NEBU	31N 7W 29G		1	7		653		5		7		3		1		0		3		3
NE BLANCO UNIT #473A	5281	NEBU	31N 8W 36G		1	15		2,367		18		22		7		2		0		13		10
NE BLANCO UNIT #476A	5799	NEBU	31N 7W 22M		1	6		354		3		4		2		0		0		1		1
NE BLANCO UNIT #478A	5212	NEBU	30N 7W 5A		1	2		81		1		1		1		0		0		0		0
NE BLANCO UNIT #480A	5209	NEBU	30N 7W 5A		1	3		114		1		1		1		0		0		0		0
NE BLANCO UNIT #481A	5153	NEBU	31N 7W 5A		1	3		162		1		2		1		0		0		1		0
NE BLANCO UNIT #482A	4895	NEBU	31N 7W 15M		1	3		198		2		2		1		0		0		1		1
NE BLANCO UNIT #483A	5149	NEBU	31N 7W 5A		1	2		98		1		1		1		0		0		0		0
NE BLANCO UNIT #484A	4896	NEBU	31N 7W 16A		1	6		529		4		5		2		1		0		3		2
NE BLANCO UNIT #485A	6032	NEBU	30N 7W 3A		1	6		573		4		5		2		1		0		2		2
NE BLANCO UNIT #486A	1150	NEBU	31N 6W 19P		1	9		996		8		11		4		1		0		6		5
NE BLANCO UNIT #487A	5201	NEBU	30N 7W 5A		1	0		6		0		0		0		0		0		0		0
NE BLANCO UNIT #488A	6019	NEBU	31N 7W 24L		1	0		0		0		0		0		0		0		0		0
NE BLANCO UNIT #490A	5198	NEBU	30N 7W 5A		1	7		494		4		5		3		1		0		2		2
NE BLANCO UNIT #491A	5147	NEBU	31N 7W 5A		1	7		532		4		6		3		1		0		2		2
NE BLANCO UNIT #492A	5795	NEBU	31N 7W 12P		1	1		45		0		0		0		0		0		0		0
NE BLANCO UNIT #493A	6012	NEBU	31N 7W 25H		1	4		172		1		2		1		0		0		0		0
NE BLANCO UNIT #495A	1068	NEBU	31N 6W 30L		1	5		249		2		3		2		0		0		1		1
NE BLANCO UNIT #496A	1161	NEBU	31N 6W 18L		1	6		525		4		5		2		1		0		3		2
NE BLANCO UNIT #497A	1110	NEBU	31N 6W 30H		1	2		85		1		1		1		0		0		0		0
NE BLANCO UNIT #498A	5193	NEBU	30N 7W 5A		1	5		348		3		4		2		0		0		1		1
NE BLANCO UNIT #499A	1152	NEBU	31N 6W 20P		1	13		1,836		14		20		5		2		0		12		9
NE BLANCO UNIT #500A	1157	NEBU	31N 6W 20D		1	10		1,010		8		10		4		1		0		5		4
NE BLANCO UNIT #504A	1163	NEBU	31N 7W 16M		1	8		964		7		10		3		1		0		5		4
BLANCO #201A	5609	NON-UNIT	31N 8W 35		1	0		0		0		0		0		0		0		0		0
BLANCO #202A	5607	NON-UNIT	31N 8W 26I		1	0		13		2		3		3		0		0		0		0
BLANCO #203A	5610	NON-UNIT	31N 8W 35I		1	0		27		4		7		6		1		0		0		0
BLANCO #204A	5608	NON-UNIT	31N 8W 26E		1	0		0		0		0		0		0		0		0		0
BLANCO #330S	5559	NON-UNIT	31N 8W 5E		1	0		28		2		4		3		0		0		0		0
BONDS COM #100S	5140	NON-UNIT	32N 10W 15M		1	5		640		32		54		30		6		0		18		15
DECKER GAS COM A #1S	5840	NON-UNIT	32N 10W 17D		1	0		0		0		0		0		0		0		0		0

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 12 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

									NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE	GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$
EAGLE #750S	5995	NON-UNIT	32N 9W 16D		1	6		721		14		27		14		3		0		10		9
FC STATE COM #20A	6006	NON-UNIT	30N 8W 2B		1	0		0		0		0		0		0		0		0		0
JACQUEZ #331S	5582	NON-UNIT	31N 8W 6L		1	0		11		1		2		1		0		0		0		0
MOORE, WAYNE COM #2S	5268	NON-UNIT	31N 9W 16M		1	1		36		1		3		2		0		0		0		0
NORDHAUS #716S	5839	NON-UNIT	31N 9W 13H		1	0		0		0		0		0		0		0		0		0
PAYNE #201S	4128	NON-UNIT	32N 10W 20L		1	6		733		13		22		14		2		0		5		5
QUINN #336S	5596	NON-UNIT	31N 8W 17N		1	5		685		50		78		51		8		0		19		16
SAN JUAN 31 FED 3 #2A	5942	NON-UNIT	31N 9W 3M		1	1		111		16		31		24		3		0		4		3
SEYMOUR #720S	12603	NON-UNIT	31N 9W 23A		1	0		0		0		0		0		0		0		0		0
SUTER #4A	5348	NON-UNIT	32N 11W 15E		1	0		0		0		0		0		0		0		0		0
TOTAL PROVED DEVELOPED: 160-Acre New Mexico					442			162,858		14,397		19,984		8,914		2,178		0		8,892		7,354
SAN JUAN 28-5 UNIT #219	13793	28-5	28N 5W 30A		1	0		0		0		0		0		0		0		0		0
SAN JUAN 28-5 UNIT #223	13740	28-5	28N 5W 34L		1	0		0		0		0		0		0		0		0		0
SAN JUAN 28-6 UNIT #230	19631	28-6	27N 6W 2H		1	0		0		0		0		0		0		0		0		0
SAN JUAN 28-6 UNIT #232	19627	28-6	27N 6W 2G		1	0		0		0		0		0		0		0		0		0
SAN JUAN 28-6 UNIT #400	13883	28-6	28N 6W 9L		1	3		60		3		5		4		1		0		1		1
SAN JUAN 28-6 UNIT #404	14227	28-6	28N 6W 13G		1	0		0		0		0		0		0		0		0		0
SAN JUAN 28-6 UNIT #405	13884	28-6	28N 6W 18M		1	4		83		5		7		6		1		0		1		1
SAN JUAN 28-6 UNIT #406	13885	28-6	28N 6W 19M		1	3		64		4		6		5		1		0		0		0
SAN JUAN 28-6 UNIT #410	14228	28-6	28N 6W 13L		1	0		0		0		0		0		0		0		0		0
SAN JUAN 28-6 UNIT #414	13886	28-6	28N 6W 8L		1	3		53		3		5		4		1		0		0		0
SAN JUAN 28-6 UNIT #418	13757	28-6	28N 6W 28L		1	3		56		3		7		4		1		0		2		2
SAN JUAN 28-6 UNIT #421	13758	28-6	28N 6W 33A		1	3		38		2		4		3		0		0		1		1
SAN JUAN 28-6 UNIT #433	14387	28-6	28N 6W 24M		1	27		351		0		0		0		0		0		0		0
SAN JUAN 28-6 UNIT #436	14347	28-6	28N 6W 16H		1	13		270		15		31		19		3		0		9		6
SAN JUAN 28-6 UNIT #437	14456	28-6	28N 6W 28G		1	1		8		0		1		1		0		0		0		0
SAN JUAN 28-6 UNIT #438	14348	28-6	28N 6W 15K		1	2		26		4		8		7		1		0		0		0
SAN JUAN 28-6 UNIT #439	14388	28-6	28N 6W 29M		1	0		0		0		0		0		0		0		0		0
SAN JUAN 28-6 UNIT #440	13759	28-6	28N 6W 16N		1	14		315		18		36		21		4		0		11		8
SAN JUAN 28-6 UNIT #441	14389	28-6	28N 6W 17H		1	12		251		14		29		17		3		0		9		7
SAN JUAN 28-6 UNIT #448	13760	28-6	28N 6W 15A		1	0		0		0		0		0		0		0		0		0
SAN JUAN 28-6 UNIT #449	13761	28-6	27N 6W 2A		1	0		0		0		0		0		0		0		0		0
SAN JUAN 28-6 UNIT #455	13719	28-6	28N 6W 17K		1	0		0		0		0		0		0		0		0		0
SAN JUAN 28-6 UNIT #456	14229	28-6	28N 6W 19H		1	2		23		3		7		6		1		0		1		0
SAN JUAN 28-6 UNIT #457	13720	28-6	28N 6W 20B		1	0		0		0		0		0		0		0		0		0
SAN JUAN 28-6 UNIT #458	14263	28-6	28N 6W 20K		1	2		24		1		3		2		0		0		0		0
SAN JUAN 28-6 UNIT #459	13733	28-6	28N 6W 21A		1	28		931		53		105		47		12		0		46		25
SAN JUAN 28-6 UNIT #460	13721	28-6	28N 6W 21N		1	5		90		5		10		7		1		0		2		1
SAN JUAN 28-6 UNIT #461	13762	28-6	28N 6W 22H		1	11		198		30		62		41		7		0		14		10

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 13 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

									NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE	GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS	MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 28-6 UNIT #462	13732	28-6	28N 6W 22K		1	12		223		34		69		45		8		0		17		12
SAN JUAN 28-6 UNIT #467	13724	28-6	28N 6W 34L		1	17		436		25		50		26		6		0		18		12
SAN JUAN 28-6 UNIT #474	13723	28-6	28N 6W 27N		1	4		64		4		7		6		1		0		1		1
SAN JUAN 28-6 UNIT #475	13887	28-6	28N 6W 29H		1	10		242		14		21		15		2		0		4		3
SAN JUAN 29-5 UNIT #201	14367	29-5	29N 5W 27K		1	3		22		0		0		0		0		0		0		0
SAN JUAN 29-5 UNIT #203	13547	29-5	29N 5W 6B		1	22		2,087		279		421		178		47		0		197		121
SAN JUAN 29-5 UNIT #213	13597	29-5	29N 5W 22M		1	13		461		62		123		73		14		0		37		26
SAN JUAN 29-5 UNIT #217	13763	29-5	29N 5W 5L		1	2		21		0		0		0		0		0		0		0
SAN JUAN 29-5 UNIT #219	14398	29-5	29N 5W 4K		1	4		163		22		32		24		4		0		5		4
SAN JUAN 29-5 UNIT #223	13653	29-5	29N 5W 33G		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-5 UNIT #225	14391	29-5	29N 5W 6L		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-5 UNIT #226	14392	29-5	29N 5W 7N		1	8		390		52		77		50		9		0		18		14
SAN JUAN 29-5 UNIT #230	14405	29-5	29N 5W 5A		1	14		887		119		183		95		20		0		68		48
SAN JUAN 29-5 UNIT #231	14393	29-5	29N 5W 5K		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #201	13589	29-6	29N 6W 6H		1	8		1,082		142		139		75		16		0		49		40
SAN JUAN 29-6 UNIT #202	13654	29-6	29N 6W 6L		1	1		92		12		12		10		1		0		1		1
SAN JUAN 29-6 UNIT #203	13684	29-6	29N 6W 7M		1	5		499		66		67		41		7		0		18		16
SAN JUAN 29-6 UNIT #204	13655	29-6	29N 6W 7A		1	2		115		15		16		12		2		0		2		2
SAN JUAN 29-6 UNIT #205	13685	29-6	29N 6W 21K		1	8		1,009		133		155		74		17		0		64		52
SAN JUAN 29-6 UNIT #206	13548	29-6	29N 6W 4H		1	2		181		24		24		19		3		0		3		3
SAN JUAN 29-6 UNIT #207	13549	29-6	29N 6W 2F		1	10		1,411		185		195		95		22		0		78		60
SAN JUAN 29-6 UNIT #208	13587	29-6	29N 6W 17N		1	6		888		117		127		58		14		0		54		46
SAN JUAN 29-6 UNIT #209	13588	29-6	29N 6W 17B		1	0		10		1		1		1		0		0		0		0
SAN JUAN 29-6 UNIT #210	14394	29-6	29N 6W 20L		1	19		2,808		369		458		180		51		0		227		148
SAN JUAN 29-6 UNIT #211	14395	29-6	29N 6W 20H		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #213	13590	29-6	29N 6W 30H		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #214	13595	29-6	29N 6W 3A		1	3		185		24		25		20		3		0		3		2
SAN JUAN 29-6 UNIT #215	13599	29-6	29N 6W 3N		1	3		223		29		30		23		3		0		4		4
SAN JUAN 29-6 UNIT #216	13596	29-6	29N 6W 4K		1	2		122		16		17		13		2		0		2		2
SAN JUAN 29-6 UNIT #217	13612	29-6	29N 6W 5H		1	9		1,401		184		176		87		20		0		70		55
SAN JUAN 29-6 UNIT #218	13605	29-6	29N 6W 5M		1	1		65		8		9		7		1		0		1		1
SAN JUAN 29-6 UNIT #219	13593	29-6	29N 6W 10G		1	6		592		78		80		52		9		0		19		16
SAN JUAN 29-6 UNIT #220	13600	29-6	29N 6W 11A		1	1		53		7		7		6		1		0		0		0
SAN JUAN 29-6 UNIT #221	13601	29-6	29N 6W 11M		1	10		925		122		131		82		15		0		34		26
SAN JUAN 29-6 UNIT #222	13718	29-6	29N 6W 12G		1	6		555		73		77		50		9		0		19		16
SAN JUAN 29-6 UNIT #223	13611	29-6	29N 6W 12K		1	10		1,108		146		152		88		17		0		47		36
SAN JUAN 29-6 UNIT #224	13696	29-6	29N 6W 13A		1	3		295		39		41		27		5		0		9		8
SAN JUAN 29-6 UNIT #225R	13947	29-6	29N 6W 13K		1	0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #226	14396	29-6	29N 6W 14G		1	13		2,079		273		288		124		32		0		132		97

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 14 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 29-6 UNIT #227	13765	29-6	29N 6W 14N		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #229	13766	29-6	29N 6W 35M		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #230	13602	29-6	29N 6W 35A		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #231	13594	29-6	29N 6W 36A		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #233	13767	29-6	29N 6W 26N		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #235	14513	29-6	29N 6W 34A		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #236	13694	29-6	29N 6W 18K		1		4		338		44		48		33		5		0		10		9
SAN JUAN 29-6 UNIT #237	13674	29-6	29N 6W 1A		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #238	13675	29-6	29N 6W 1L		1		2		130		17		18		14		2		0		2		2
SAN JUAN 29-6 UNIT #239	13676	29-6	29N 6W 2B		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #240	13686	29-6	29N 6W 18H		1		9		1,140		150		155		82		17		0		56		44
SAN JUAN 29-6 UNIT #241	13687	29-6	29N 6W 19A		1		7		617		81		90		55		10		0		25		21
SAN JUAN 29-6 UNIT #242	13688	29-6	29N 6W 19K		1		16		1,998		263		306		141		34		0		132		90
SAN JUAN 29-6 UNIT #243	13768	29-6	29N 6W 31H		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #245	13667	29-6	29N 6W 8B		1		9		874		115		118		73		13		0		32		25
SAN JUAN 29-6 UNIT #246	14397	29-6	29N 6W 8K		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #247R	13814	29-6	29N 6W 10K		1		0		5		1		1		1		0		0		0		0
SAN JUAN 29-6 UNIT #249	13796	29-6	29N 6W 22B		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #251	13803	29-6	29N 6W 23K		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #257R	13815	29-6	29N 6W 9D		1		3		263		35		36		26		4		0		5		5
SAN JUAN 29-6 UNIT #258	13695	29-6	29N 6W 16N		1		7		937		123		134		67		15		0		53		43
SAN JUAN 29-6 UNIT #259	14399	29-6	29N 6W 9B		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #260	14400	29-6	29N 6W 16G		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #262	14401	29-6	29N 6W 21A		1		18		2,242		295		335		159		37		0		140		91
SAN JUAN 29-6 UNIT #263	13802	29-6	29N 6W 22L		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #264	13841	29-6	29N 6W 27A		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #47	4888	29-6	29N 6W 28B		1		4		269		35		44		32		5		0		8		7
SAN JUAN 29-6 UNIT #58A	7960	29-6	29N 6W 28D		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-6 UNIT #68	5779	29-6	29N 6W 29A		1		5		347		46		60		39		7		0		14		12
SAN JUAN 29-7 UNIT #186	11729	29-7	29N 7W 21A		1		3		61		7		19		13		2		0		4		3
SAN JUAN 29-7 UNIT #194	30347	29-7	29N 7W 15F		1		10		580		67		134		60		15		0		60		46
SAN JUAN 29-7 UNIT #507R	12667	29-7	29N 7W 13G		1		13		1,031		118		217		85		24		0		107		78
SAN JUAN 29-7 UNIT #519	12671	29-7	29N 7W 8B		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #520	12524	29-7	29N 7W 8E		1		1		12		1		4		3		0		0		0		0
SAN JUAN 29-7 UNIT #521	12653	29-7	29N 7W 13L		1		10		639		73		140		60		16		0		65		51
SAN JUAN 29-7 UNIT #526	11728	29-7	29N 7W 21L		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #530	13882	29-7	29N 7W 24A		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #532	14349	29-7	29N 7W 2B		1		9		296		34		73		47		8		0		18		14
SAN JUAN 29-7 UNIT #533	14464	29-7	29N 7W 3I		1		4		152		17		36		19		4		0		13		12

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 15 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 29-7 UNIT #534	12668	29-7	29N 7W 9		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #537	12669	29-7	29N 7W 22B		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #538	14402	29-7	29N 7W 26B		1		18		598		69		183		95		20		0		67		43
SAN JUAN 29-7 UNIT #540	12654	29-7	29N 7W 10A		1		6		203		23		57		30		6		0		21		18
SAN JUAN 29-7 UNIT #543	12655	29-7	29N 7W 3M		1		4		108		12		28		19		3		0		6		5
SAN JUAN 29-7 UNIT #544	12656	29-7	29N 7W 4B		1		8		549		63		136		51		15		0		70		57
SAN JUAN 29-7 UNIT #545	12657	29-7	29N 7W 12H		1		9		722		83		162		60		18		0		84		66
SAN JUAN 29-7 UNIT #547	14403	29-7	29N 7W 7B		1		13		482		55		146		72		16		0		58		41
SAN JUAN 29-7 UNIT #548	14372	29-7	29N 7W 7K		1		14		382		44		117		69		13		0		34		24
SAN JUAN 29-7 UNIT #550	12659	29-7	29N 7W 11G		1		9		566		65		141		54		16		0		71		57
SAN JUAN 29-7 UNIT #552	12652	29-7	29N 7W 12N		1		10		866		99		196		68		22		0		106		83
SAN JUAN 29-7 UNIT #553	12661	29-7	29N 7W 14H		1		12		1,221		140		280		86		31		0		163		123
SAN JUAN 29-7 UNIT #554	12662	29-7	29N 7W 14M		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #559	14404	29-7	29N 7W 22N		1		1		17		2		5		4		1		0		0		0
SAN JUAN 29-7 UNIT #560	12663	29-7	29N 7W 23G		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #562	12664	29-7	29N 7W 24B		1		6		348		40		82		35		9		0		38		33
SAN JUAN 29-7 UNIT #563	12665	29-7	29N 7W 24L		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #565	14231	29-7	29N 7W 26N		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #577	14232	29-7	29N 7W 35P		1		0		0		0		0		0		0		0		0		0
SAN JUAN 29-7 UNIT #580	14465	29-7	29N 7W 1B		1		23		2,295		263		460		160		51		0		248		152
SAN JUAN 29-7 UNIT #582	12666	29-7	29N 7W 2M		1		20		2,225		255		544		145		61		0		339		225
SAN JUAN 29-7 UNIT #583	12670	29-7	29N 7W 6K		1		2		45		5		10		8		1		0		1		1
SAN JUAN 29-7 UNIT #585	12211	29-7	29N 7W 15G		1		5		204		23		61		28		7		0		26		23
SAN JUAN 29-7 UNIT #92R	12025	29-7	29N 7W 16M		1		1		16		2		5		4		1		0		0		0
CAT DRAW COM #101	20070	30-5	30N 5W 23G		1		0		31		1		2		1		0		0		0		0
SAN JUAN 30-5 UNIT #201	13550	30-5	30N 5W 19N		1		5		570		107		103		67		11		0		24		21
SAN JUAN 30-5 UNIT #202	13551	30-5	30N 5W 6H		1		3		239		45		50		34		6		0		10		10
SAN JUAN 30-5 UNIT #203	13607	30-5	30N 5W 6L		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #204	13726	30-5	30N 5W 7G		1		1		55		10		11		10		1		0		0		0
SAN JUAN 30-5 UNIT #205	13772	30-5	30N 5W 7K		1		1		57		11		12		10		1		0		1		1
SAN JUAN 30-5 UNIT #206	13711	30-5	30N 5W 18G		1		3		226		43		45		34		5		0		6		6
SAN JUAN 30-5 UNIT #207	13727	30-5	30N 5W 18I		1		5		500		94		98		66		11		0		21		19
SAN JUAN 30-5 UNIT #208	13665	30-5	30N 5W 19H		1		8		1,146		216		218		120		24		0		74		60
SAN JUAN 30-5 UNIT #209	13606	30-5	30N 5W 30A		1		2		177		33		33		25		4		0		4		4
SAN JUAN 30-5 UNIT #210	13682	30-5	30N 5W 30M		1		2		222		42		41		30		5		0		6		5
SAN JUAN 30-5 UNIT #211	13683	30-5	30N 5W 31B		1		3		233		44		45		35		5		0		5		5
SAN JUAN 30-5 UNIT #212	13617	30-5	30N 5W 31N		1		2		201		38		39		31		4		0		4		3
SAN JUAN 30-5 UNIT #213R	16986	30-5	30N 5W 5H		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #214	16987	30-5	30N 5W 5N		1		2		169		32		35		24		4		0		7		7

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 16 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 30-5 UNIT #215	13660	30-5	30N 5W 8H		1		3		251		47		51		35		6		0		11		10
SAN JUAN 30-5 UNIT #216R	13943	30-5	30N 5W 20L		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #217	13614	30-5	30N 5W 21L		1		1		122		23		23		18		3		0		3		2
SAN JUAN 30-5 UNIT #218	13659	30-5	30N 5W 17A		1		5		598		112		121		72		13		0		35		31
SAN JUAN 30-5 UNIT #219R	17250	30-5	30N 5W 5L		1		1		114		22		23		18		3		0		3		3
SAN JUAN 30-5 UNIT #220R	15532	30-5	30N 5W 8N		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #223	13677	30-5	30N 5W 20B		1		1		55		10		11		9		1		0		1		1
SAN JUAN 30-5 UNIT #224	12576	30-5	30N 5W 17		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #225	14406	30-5	30N 5W 29G		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #226	13670	30-5	30N 5W 29M		1		4		441		83		86		58		10		0		19		17
SAN JUAN 30-5 UNIT #227	13672	30-5	30N 5W 28A		1		1		79		15		16		13		2		0		1		1
SAN JUAN 30-5 UNIT #228	14407	30-5	30N 5W 28L		1		1		71		13		14		12		2		0		1		1
SAN JUAN 30-5 UNIT #229	13673	30-5	30N 5W 21G		1		2		174		33		35		26		4		0		5		5
SAN JUAN 30-5 UNIT #230	14366	30-5	30N 5W 32A		1		3		244		46		51		36		6		0		9		9
SAN JUAN 30-5 UNIT #231	14409	30-5	30N 5W 32M		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #232	14408	30-5	30N 5W 33D		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #233	14443	30-5	30N 5W 33K		1		1		93		18		20		16		2		0		1		1
SAN JUAN 30-5 UNIT #234	14410	30-5	30N 5W 22M		1		4		438		82		93		56		10		0		26		24
SAN JUAN 30-5 UNIT #235	14411	30-5	30N 5W 27B		1		0		5		1		1		1		0		0		0		0
SAN JUAN 30-5 UNIT #236	14412	30-5	30N 5W 27K		1		2		134		25		29		23		3		0		3		3
SAN JUAN 30-5 UNIT #237R	6123	30-5	30N 5W 16B		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #238	14414	30-5	30N 5W 34H		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #239	13949	30-5	30N 5W 15M		1		1		98		19		20		16		2		0		2		2
SAN JUAN 30-5 UNIT #240	14415	30-5	30N 5W 22H		1		0		24		5		5		4		1		0		0		0
SAN JUAN 30-5 UNIT #241	14416	30-5	30N 5W 23L		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #242	14444	30-5	30N 5W 34L		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #243	14069	30-5	30N 5W 15G		1		3		381		72		79		49		9		0		21		19
SAN JUAN 30-5 UNIT #246	13948	30-5	30N 5W 26L		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-5 UNIT #249	14068	30-5	30N 5W 23A		1		3		252		47		54		36		6		0		12		11
SAN JUAN 30-5 UNIT #255	13842	30-5	30N 5W 14M		1		3		293		55		62		40		7		0		15		14
SAN JUAN 30-5 UNIT #257	14025	30-5	30N 5W 11M		1		5		710		134		147		78		16		0		53		46
SAN JUAN 30-5 UNIT #258	14026	30-5	30N 5W 14G		1		6		858		161		182		90		20		0		72		61
SAN JUAN 30-5 UNIT #259	8011	30-5	30N 5W 9L		1		2		207		39		45		32		5		0		8		7
SAN JUAN 30-5 UNIT #260	12646	30-5	30N 5W 9L		1		4		470		89		94		53		10		0		30		27
SAN JUAN 30-5 UNIT #261	5424	30-5	30N 5W 9B		1		4		445		84		98		58		11		0		30		26
SAN JUAN 30-5 UNIT #262	8012	30-5	30N 5W 9L		1		2		164		31		35		24		4		0		7		7
SAN JUAN 30-5 UNIT #263	5425	30-5	30N 5W 9L		1		2		239		45		53		33		6		0		14		13
SAN JUAN 30-5 UNIT #264	12619	30-5	30N 5W 9G		1		4		470		88		95		53		11		0		32		29
SAN JUAN 30-5 UNIT #265	15533	30-5	30N 5W 10G		1		5		860		162		174		85		19		0		70		61

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 17 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 30-5 UNIT #266	15534	30-5	30N 5W 10M		1		5		677		127		135		73		15		0		46		40
SAN JUAN 30-5 UNIT #267	5046	30-5	30N 5W 23A		1		2		226		42		50		32		6		0		12		11
SAN JUAN 30-5 UNIT #268	10177	30-5	30N 5W 23A		1		1		64		12		14		11		2		0		2		2
SAN JUAN 30-6 UNIT #400	14164	30-6	30N 7W 14M		1		13		1,903		95		155		69		17		0		69		50
SAN JUAN 30-6 UNIT #401R	14165	30-6	30N 7W 13N		1		8		1,073		54		85		41		9		0		35		29
SAN JUAN 30-6 UNIT #403	13648	30-6	30N 6W 9G		1		11		1,359		68		119		56		13		0		50		38
SAN JUAN 30-6 UNIT #404R	14459	30-6	30N 7W 23B		1		12		2,312		115		190		71		21		0		98		75
SAN JUAN 30-6 UNIT #405	13580	30-6	30N 6W 9M		1		4		335		17		29		19		3		0		7		7
SAN JUAN 30-6 UNIT #406R	14167	30-6	30N 7W 15F		1		5		489		24		43		26		5		0		12		11
SAN JUAN 30-6 UNIT #407	13559	30-6	30N 6W 16H		1		7		858		43		72		35		8		0		28		24
SAN JUAN 30-6 UNIT #408	13558	30-6	30N 6W 16L		1		6		796		40		66		31		7		0		27		23
SAN JUAN 30-6 UNIT #409	14168	30-6	30N 7W 25I		1		11		1,916		96		155		64		17		0		74		56
SAN JUAN 30-6 UNIT #410	14211	30-6	30N 6W 26A		1		3		205		10		17		12		2		0		3		3
SAN JUAN 30-6 UNIT #411	14169	30-6	30N 7W 27A		1		3		294		15		25		16		3		0		6		6
SAN JUAN 30-6 UNIT #412	14170	30-6	30N 7W 24A		1		6		685		34		58		30		7		0		22		18
SAN JUAN 30-6 UNIT #413R	14171	30-6	30N 7W 23K		1		11		1,772		88		142		64		16		0		62		47
SAN JUAN 30-6 UNIT #414	14172	30-6	30N 7W 35K		1		1		81		4		8		6		1		0		1		1
SAN JUAN 30-6 UNIT #415	14173	30-6	30N 7W 26N		1		9		1,239		62		107		47		12		0		49		39
SAN JUAN 30-6 UNIT #416	14174	30-6	30N 7W 24K		1		12		2,137		107		169		70		19		0		80		60
SAN JUAN 30-6 UNIT #417	14175	30-6	30N 7W 25G		1		6		687		34		54		29		6		0		18		16
SAN JUAN 30-6 UNIT #418	14176	30-6	30N 7W 26B		1		10		1,619		81		128		58		14		0		56		43
SAN JUAN 30-6 UNIT #419	14177	30-6	30N 7W 11H		1		1		86		4		7		6		1		0		1		1
SAN JUAN 30-6 UNIT #420	14178	30-6	30N 7W 12G		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #421	14179	30-6	30N 7W 34G		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #422	14264	30-6	30N 7W 27M		1		4		265		13		25		17		3		0		5		5
SAN JUAN 30-6 UNIT #423	14462	30-6	30N 7W 28A		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #424	14463	30-6	30N 7W 33K		1		2		111		6		11		8		1		0		1		1
SAN JUAN 30-6 UNIT #425	14385	30-6	30N 7W 33H		1		14		1,757		88		166		74		18		0		73		52
SAN JUAN 30-6 UNIT #426	14180	30-6	30N 7W 34K		1		5		539		27		49		25		5		0		19		16
SAN JUAN 30-6 UNIT #427	14181	30-6	30N 7W 35H		1		3		290		14		26		16		3		0		7		6
SAN JUAN 30-6 UNIT #428	14358	30-6	30N 7W 28N		1		3		240		12		23		15		3		0		5		5
SAN JUAN 30-6 UNIT #429	14359	30-6	30N 7W 22H		1		3		274		14		27		16		3		0		8		8
SAN JUAN 30-6 UNIT #430	13543	30-6	30N 6W 8G		1		5		564		28		48		25		5		0		18		16
SAN JUAN 30-6 UNIT #431	13544	30-6	30N 6W 10M		1		12		1,802		90		154		65		17		0		72		54
SAN JUAN 30-6 UNIT #432	13545	30-6	30N 6W 10B		1		6		638		32		58		32		6		0		20		16
SAN JUAN 30-6 UNIT #433	14182	30-6	30N 6W 11K		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #434	14183	30-6	30N 6W 12M		1		5		546		27		48		25		5		0		18		16
SAN JUAN 30-6 UNIT #435	14184	30-6	30N 6W 13I		1		6		609		30		56		30		6		0		20		17
SAN JUAN 30-6 UNIT #436	14185	30-6	30N 6W 15G		1		10		1,435		72		124		55		14		0		56		43

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 18 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 30-6 UNIT #437	14186	30-6	30N 6W 11H		1		13		1,535		77		140		65		16		0		59		43
SAN JUAN 30-6 UNIT #438	14187	30-6	30N 6W 12H		1		15		2,530		126		237		84		26		0		126		90
SAN JUAN 30-6 UNIT #439	14188	30-6	30N 6W 14M		1		6		587		29		49		30		5		0		14		12
SAN JUAN 30-6 UNIT #440	14189	30-6	30N 6W 15N		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #441	14190	30-6	30N 6W 31A		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #442	13568	30-6	30N 6W 14P		1		9		1,219		61		103		49		11		0		43		34
SAN JUAN 30-6 UNIT #443	13532	30-6	30N 6W 36G		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #444	14208	30-6	30N 6W 36I		1		6		565		28		50		28		6		0		16		14
SAN JUAN 30-6 UNIT #445	14209	30-6	30N 6W 13I		1		6		636		32		55		31		6		0		17		14
SAN JUAN 30-6 UNIT #446	14204	30-6	30N 6W 35N		1		6		654		33		56		32		6		0		18		15
SAN JUAN 30-6 UNIT #447	14206	30-6	30N 7W 31G		1		5		325		16		40		24		5		0		12		11
SAN JUAN 30-6 UNIT #450	13536	30-6	30N 6W 7K		1		9		1,113		56		94		46		10		0		38		30
SAN JUAN 30-6 UNIT #451	13534	30-6	30N 6W 7H		1		11		1,469		73		129		57		14		0		58		44
SAN JUAN 30-6 UNIT #452	13535	30-6	30N 6W 8N		1		2		121		6		10		7		1		0		1		1
SAN JUAN 30-6 UNIT #453	14191	30-6	30N 6W 17K		1		4		368		18		31		20		3		0		8		7
SAN JUAN 30-6 UNIT #454	14192	30-6	30N 6W 17A		1		8		1,060		53		86		41		10		0		36		29
SAN JUAN 30-6 UNIT #455	14161	30-6	30N 6W 18N		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #456	13537	30-6	30N 6W 18A		1		8		1,238		62		106		44		12		0		50		41
SAN JUAN 30-6 UNIT #457	14193	30-6	30N 6W 19M		1		11		1,914		96		153		65		17		0		71		54
SAN JUAN 30-6 UNIT #458	14194	30-6	30N 6W 19H		1		4		468		23		38		22		4		0		11		10
SAN JUAN 30-6 UNIT #459	14195	30-6	30N 6W 20L		1		8		973		49		80		42		9		0		29		23
SAN JUAN 30-6 UNIT #460	14162	30-6	30N 6W 20N		1		7		806		40		64		36		7		0		21		18
SAN JUAN 30-6 UNIT #461	14251	30-6	30N 7W 11M		1		3		254		13		22		15		2		0		5		4
SAN JUAN 30-6 UNIT #462	14196	30-6	30N 7W 12M		1		12		1,612		80		145		63		16		0		66		49
SAN JUAN 30-6 UNIT #463	14197	30-6	30N 7W 13H		1		5		571		29		49		27		5		0		17		15
SAN JUAN 30-6 UNIT #464	14198	30-6	30N 7W 14B		1		5		415		21		39		24		4		0		11		10
SAN JUAN 30-6 UNIT #465	14199	30-6	30N 6W 15J		1		8		1,033		52		87		42		10		0		35		28
SAN JUAN 30-6 UNIT #466	14200	30-6	30N 7W 22B		1		6		589		29		49		29		5		0		14		12
SAN JUAN 30-6 UNIT #467 COM	4496	30-6	30N 5W 22A		1		2		156		4		8		6		1		0		1		1
SAN JUAN 30-6 UNIT #468	14252	30-6	30N 7W 36K		1		9		1,340		67		113		49		13		0		51		41
SAN JUAN 30-6 UNIT #470	14253	30-6	30N 6W 21G		1		9		1,073		54		87		47		10		0		31		24
SAN JUAN 30-6 UNIT #471	14254	30-6	30N 6W 21K		1		7		833		42		67		35		7		0		24		20
SAN JUAN 30-6 UNIT #472	14255	30-6	30N 6W 22A		1		1		65		3		5		5		1		0		0		0
SAN JUAN 30-6 UNIT #473	14256	30-6	30N 6W 22M		1		2		177		9		15		9		2		0		4		4
SAN JUAN 30-6 UNIT #474	14257	30-6	30N 6W 27B		1		11		1,463		73		118		57		13		0		48		37
SAN JUAN 30-6 UNIT #475	14258	30-6	30N 6W 27L		1		13		2,060		103		168		72		19		0		77		57
SAN JUAN 30-6 UNIT #476	14163	30-6	30N 6W 28A		1		7		845		42		67		38		7		0		22		18
SAN JUAN 30-6 UNIT #477	14210	30-6	30N 6W 28M		1		10		1,485		74		121		55		14		0		53		41
SAN JUAN 30-6 UNIT #478	14205	30-6	30N 6W 29A		1		9		1,232		62		103		48		12		0		44		35

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 19 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 30-6 UNIT #479	14259	30-6	30N 6W 29K		1		2		124		6		10		7		1		0		1		1
SAN JUAN 30-6 UNIT #480	14260	30-6	30N 6W 30A		1		4		323		16		27		17		3		0		7		6
SAN JUAN 30-6 UNIT #481	14261	30-6	30N 6W 30J		1		14		2,244		112		179		78		20		0		81		58
SAN JUAN 30-6 UNIT #482	14266	30-6	30N 6W 31N		1		15		2,439		122		195		87		22		0		87		60
SAN JUAN 30-6 UNIT #483	14207	30-6	30N 6W 34H		1		4		329		16		29		20		3		0		6		6
SAN JUAN 30-6 UNIT #484	14249	30-6	30N 6W 34N		1		1		99		5		8		7		1		0		1		1
SAN JUAN 30-6 UNIT #485	14233	30-6	30N 7W 36G		1		6		756		38		60		32		7		0		21		18
SAN JUAN 30-6 UNIT #486	14234	30-6	30N 6W 23H		1		8		981		49		84		42		9		0		33		26
SAN JUAN 30-6 UNIT #487	14235	30-6	30N 6W 23N		1		10		1,303		65		110		53		12		0		45		35
SAN JUAN 30-6 UNIT #488	14236	30-6	30N 6W 24A		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #489	14237	30-6	30N 6W 24K		1		6		773		39		67		31		7		0		28		24
SAN JUAN 30-6 UNIT #490	14238	30-6	30N 6W 25H		1		3		268		13		24		15		3		0		6		5
SAN JUAN 30-6 UNIT #491	14239	30-6	30N 6W 25M		1		6		736		37		62		32		7		0		23		19
SAN JUAN 30-6 UNIT #492	14240	30-6	30N 6W 26K		1		4		351		18		30		21		3		0		6		6
SAN JUAN 30-6 UNIT #493	14241	30-6	30N 6W 32M		1		5		486		24		41		24		5		0		12		10
SAN JUAN 30-6 UNIT #494	14242	30-6	30N 6W 33B		1		11		1,768		88		148		64		16		0		68		51
SAN JUAN 30-6 UNIT #495	14243	30-6	30N 6W 33K		1		6		655		33		53		30		6		0		18		15
SAN JUAN 30-6 UNIT #496	14244	30-6	30N 6W 35G		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #497	14245	30-6	30N 7W 29M		1		4		239		12		30		20		3		0		7		6
SAN JUAN 30-6 UNIT #498R	13946	30-6	30N 7W 30G		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #499	14247	30-6	30N 7W 30L		1		0		0		0		0		0		0		0		0		0
SAN JUAN 30-6 UNIT #500	14417	30-6	30N 7W 31L		1		1		61		9		22		19		3		0		1		1
SAN JUAN 30-6 UNIT #501	14248	30-6	30N 6W 32G		1		6		575		29		46		28		5		0		13		11
SAN JUAN 31-6 UNIT #201	13540	31-6	30N 6W 1H		1		1		109		12		13		10		1		0		1		1
SAN JUAN 31-6 UNIT #202	13552	31-6	30N 6W 1K		1		8		1,122		120		130		82		14		0		33		27
SAN JUAN 31-6 UNIT #203	13539	31-6	30N 6W 3A		1		1		57		6		7		6		1		0		0		0
SAN JUAN 31-6 UNIT #204	13541	31-6	30N 6W 3N		1		6		837		90		92		62		10		0		20		17
SAN JUAN 31-6 UNIT #205R	12574	31-6	30N 6W 4G		1		0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #206	13542	31-6	30N 6W 4N		1		3		303		32		33		25		4		0		4		4
SAN JUAN 31-6 UNIT #207	13533	31-6	30N 6W 6B		1		0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #208	14213	31-6	30N 6W 6K		1		0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #209	14214	31-6	30N 7W 1L		1		0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #210	13618	31-6	30N 6W 2B		1		6		1,011		108		117		71		13		0		33		28
SAN JUAN 31-6 UNIT #211	13553	31-6	30N 6W 2N		1		7		1,072		115		121		77		13		0		31		25
SAN JUAN 31-6 UNIT #212	13615	31-6	30N 6W 5H		1		6		739		79		83		58		9		0		15		13
SAN JUAN 31-6 UNIT #213	13554	31-6	30N 6W 5K		1		5		596		64		64		47		7		0		10		9
SAN JUAN 31-6 UNIT #214	13646	31-6	31N 6W 36H		1		0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #215	13616	31-6	31N 6W 36K		1		1		121		13		14		12		2		0		1		1
SAN JUAN 31-6 UNIT #216	13647	31-6	31N 6W 35A		1		0		0		0		0		0		0		0		0		0

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 20 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 31-6 UNIT #217	13609	31-6	31N 6W 35M		1		0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #218	13671	31-6	31N 6W 34H		1		1		96		10		11		9		1		0		1		1
SAN JUAN 31-6 UNIT #219	13608	31-6	31N 6W 34K		1		9		1,402		150		164		102		18		0		44		34
SAN JUAN 31-6 UNIT #220R	18278	31-6	31N 6W 33A		1		0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #221	13656	31-6	31N 6W 33K		1		0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #222	13666	31-6	31N 6W 32H		1		3		275		29		33		25		4		0		5		4
SAN JUAN 31-6 UNIT #223	13613	31-6	31N 6W 21I		1		5		618		66		70		49		8		0		13		12
SAN JUAN 31-6 UNIT #224	13691	31-6	31N 6W 31A		1		1		47		5		6		5		1		0		0		0
SAN JUAN 31-6 UNIT #225R	13697	31-6	31N 6W 31K		1		1		150		16		17		14		2		0		1		1
SAN JUAN 31-6 UNIT #228	14419	31-6	31N 6W 28I		1		8		1,159		124		141		89		16		0		37		29
SAN JUAN 31-6 UNIT #229R	18279	31-6	31N		1		0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #230	13555	31-6	31N 6W 27A		1		5		621		66		74		49		8		0		16		14
SAN JUAN 31-6 UNIT #231R	17256	31-6	31N 6W 27		1		0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #232	13692	31-6	30N 7W 1G		1		0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #233	13693	31-6	31N 6W 29H		1		0		0		0		0		0		0		0		0		0
SAN JUAN 31-6 UNIT #234R	14007	31-6	31N 6W 29L		1		0		0		0		0		0		0		0		0		0
ALLISON UNIT COM #105	13888	32-7	32N 7W 26G		1		7		732		33		48		19		5		0		24		20
ALLISON UNIT COM #146	4750	32-7	32N 7W 23D		1		12		1,399		125		185		64		20		0		101		77
FEDERAL G #4 COM	4755	32-7	31N 7W 10G		1		3		168		4		6		4		1		0		1		1
GRASSY CANYON UNIT #3	4762	32-7	32N 7W 31B		1		10		1,033		71		106		40		11		0		54		43
MIDDLE MESA COM #3	4768	32-7	32N 7W 33M		1		4		377		17		23		11		2		0		9		8
SAN JUAN 32-7 UNIT #202R	10783	32-7	32N 7W 18		1		8		1,164		207		325		89		35		0		201		168
SAN JUAN 32-7 UNIT #203R	12467	32-7	32N 7W 22H		1		13		1,570		280		405		146		44		0		215		157
SAN JUAN 32-7 UNIT #204	13546	32-7	32N 7W 36B		1		6		566		101		142		63		15		0		63		54
SAN JUAN 32-7 UNIT #205	12471	32-7	32N 7W 22M		1		5		514		92		133		54		14		0		65		57
SAN JUAN 32-7 UNIT #206	12647	32-7	32N 7W 27H		1		5		378		67		97		50		10		0		37		32
SAN JUAN 32-7 UNIT #207	13698	32-7	32N 7W 27K		1		8		885		158		227		87		25		0		115		94
SAN JUAN 32-7 UNIT #208	13710	32-7	32N 7W 34B		1		7		857		153		219		81		24		0		114		95
SAN JUAN 32-7 UNIT #209	13640	32-7	32N 7W 35A		1		9		998		178		251		96		27		0		127		102
SAN JUAN 32-7 UNIT #210	13598	32-7	32N 7W 36L		1		8		871		155		218		90		24		0		105		85
SAN JUAN 32-7 UNIT #211R	12642	32-7	32N 7W 35N		1		4		267		48		68		38		7		0		22		20
SAN JUAN 32-7 UNIT #213 COM	4832	32-7	31N 7W 7M		1		7		510		57		84		43		9		0		32		26
SAN JUAN 32-7 UNIT #214	13717	32-7	32N 7W 34N		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-7 UNIT #215	13700	32-7	32N 7W 32N		1		9		968		172		249		99		27		0		123		98
SAN JUAN 32-7 UNIT #216	14422	32-7	31N 7W 4N		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-7 UNIT #217	13701	32-7	31N 7W 4A		1		2		73		13		19		15		2		0		2		2
SAN JUAN 32-7 UNIT #218	13702	32-7	31N 7W 5M		1		8		781		139		205		88		22		0		95		76
SAN JUAN 32-7 UNIT #219	13703	32-7	31N 7W 5K		1		9		855		152		218		92		24		0		102		82
SAN JUAN 32-7 UNIT #220 COM	4835	32-7	31N 7W 5M		1		12		1,320		206		304		113		33		0		159		119

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 21 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 32-7 UNIT #221	13704	32-7	31N 7W 8H		1		3		188		33		49		28		5		0		15		14
SAN JUAN 32-7 UNIT #222	14423	32-7	32N 7W 20H		1		5		335		60		88		47		10		0		32		28
SAN JUAN 32-7 UNIT #224 COM	4792	32-7	32N 7W 21N		1		10		1,078		144		212		78		23		0		111		88
SAN JUAN 32-7 UNIT #227 COM	4843	32-7	31N 7W 18M		1		4		294		39		56		33		6		0		17		15
SAN JUAN 32-7 UNIT #228 COM	4816	32-7	31N 7W 7G		1		9		1,051		96		140		52		15		0		73		58
SAN JUAN 32-7 UNIT #229	13729	32-7	31N 7W 9B		1		3		192		34		49		30		5		0		14		13
SAN JUAN 32-7 UNIT #230	12620	32-7	31N 7W 17G		1		9		982		175		252		100		27		0		125		99
SAN JUAN 32-7 UNIT #231	13664	32-7	31N 7W 17L		1		2		87		15		23		18		2		0		2		2
SAN JUAN 32-7 UNIT #232	13705	32-7	31N 7W 8N		1		2		100		18		26		19		3		0		5		5
SAN JUAN 32-7 UNIT #233	14452	32-7	32N 7W 20L		1		5		415		74		109		51		12		0		46		40
SAN JUAN 32-7 UNIT #234	14425	32-7	32N 7W 32H		1		6		521		93		133		61		14		0		58		49
SAN JUAN 32-7 UNIT #235	14426	32-7	32N 7W 29N		1		7		1,025		183		264		83		28		0		152		128
SAN JUAN 32-7 UNIT #236	14453	32-7	32N 7W 28N		1		4		273		49		70		37		8		0		25		23
SAN JUAN 32-7 UNIT #237	14454	32-7	32N 7W 28H		1		8		798		142		205		82		22		0		100		82
SAN JUAN 32-7 UNIT #238	14455	32-7	32N 7W 29B		1		9		1,366		243		356		104		38		0		214		173
SAN JUAN 32-7 UNIT #240	12579	32-7	32N 7W 20H		1		9		917		163		246		93		27		0		126		102
SAN JUAN 32-7 UNIT #241	12580	32-7	32N 7W 21G		1		9		1,220		217		324		99		35		0		190		155
SAN JUAN 32-7 UNIT #242	12643	32-7	32N 7W 33F		1		5		449		80		115		49		12		0		53		47
SAN JUAN 32-7 UNIT #243	17813	32-7	32N 7W 7L		1		7		443		79		117		66		13		0		39		33
SAN JUAN 32-7 UNIT #244	15582	32-7	32N 7W 17N		1		10		1,061		189		289		111		31		0		148		114
SAN JUAN 32-7 UNIT #245A	755	32-7	32N 7W 17P		1		19		4,125		735		1,100		244		119		0		737		500
SAN JUAN 32-7 UNIT #246	740	32-7	32N 7W 18L		1		10		1,496		266		405		116		44		0		245		194
SAN JUAN 32-7 UNIT #247	10786	32-7	32N 7W 7N		1		7		339		60		195		72		21		0		103		85
SAN JUAN 32-7 UNIT #248	759	32-7	32N 7W 8C		1		7		584		104		161		69		17		0		74		63
SAN JUAN 32-7 UNIT #249	760	32-7	32N 7W 9L		1		6		549		98		149		66		16		0		67		57
SAN JUAN 32-7 UNIT #250	12139	32-7	32N 7W 17N		1		7		278		49		160		65		17		0		78		66
YAGER N COM #5	4873	32-7	31N 7W 3N		1		5		367		8		12		7		1		0		4		4
RATTLESNAKE CANYON #105	4770	32-8	32N 8W 20H		1		6		885		37		57		25		6		0		26		22
SAN JUAN 32-8 UNIT #202	13657	32-8	32N 8W 27M		1		8		1,299		145		209		88		23		0		98		81
SAN JUAN 32-8 UNIT #203	14507	32-8	32N 8W 33G		1		5		714		80		115		56		12		0		46		40
SAN JUAN 32-8 UNIT #204	14508	32-8	32N 8W 34L		1		5		568		63		90		47		10		0		33		29
SAN JUAN 32-8 UNIT #205	14511	32-8	32N 8W 34G		1		5		599		67		96		48		10		0		38		34
SAN JUAN 32-8 UNIT #206	14445	32-8	31N 8W 24G		1		3		264		29		40		28		4		0		7		6
SAN JUAN 32-8 UNIT #207	13591	32-8	31N 8W 22N		1		7		1,015		113		142		76		15		0		51		42
SAN JUAN 32-8 UNIT #208	13557	32-8	32N 8W 29N		1		5		707		79		106		57		11		0		38		33
SAN JUAN 32-8 UNIT #213	12648	32-8	32N 8W 22N		1		2		216		24		36		24		4		0		8		8
SAN JUAN 32-8 UNIT #218	14509	32-8	32N 8W 35G		1		7		1,150		128		191		75		21		0		95		80
SAN JUAN 32-8 UNIT #219	14510	32-8	32N 8W 35M		1		7		1,150		128		188		81		20		0		87		72
SAN JUAN 32-8 UNIT #220	13706	32-8	31N 8W 24L		1		2		201		22		29		22		3		0		4		4

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 22 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 32-8 UNIT #221	13642	32-8	31N 8W 9M		1		4		449		50		67		39		7		0		20		18
SAN JUAN 32-8 UNIT #222	13658	32-8	31N 8W 9A		1		5		545		61		82		51		9		0		23		20
SAN JUAN 32-8 UNIT #223	13643	32-8	31N 8W 10N		1		2		204		23		30		22		3		0		5		4
SAN JUAN 32-8 UNIT #224	13644	32-8	31N 8W 10B		1		12		1,803		201		281		130		30		0		121		90
SAN JUAN 32-8 UNIT #225	14427	32-8	31N 8W 15M		1		11		1,679		187		249		119		27		0		103		78
SAN JUAN 32-8 UNIT #226	13707	32-8	31N 8W 15A		1		6		706		79		106		60		11		0		35		30
SAN JUAN 32-8 UNIT #227	14428	32-8	31N 8W 16L		1		4		387		43		55		39		6		0		10		9
SAN JUAN 32-8 UNIT #228	14429	32-8	31N 8W 16G		1		4		434		48		66		40		7		0		19		17
SAN JUAN 32-8 UNIT #229	13708	32-8	32N 8W 20E		1		5		685		76		110		54		12		0		45		39
SAN JUAN 32-8 UNIT #230	13716	32-8	32N 8W 28G		1		8		1,490		166		237		92		26		0		119		98
SAN JUAN 32-8 UNIT #231	13715	32-8	32N 8W 28L		1		5		757		84		114		57		12		0		45		39
SAN JUAN 32-8 UNIT #232	13709	32-8	32N 8W 29H		1		8		1,410		157		216		88		23		0		104		86
SAN JUAN 32-8 UNIT #233	13712	32-8	32N 8W 30G		1		8		1,724		192		268		96		29		0		143		117
SAN JUAN 32-8 UNIT #234	14430	32-8	31N 8W 21M		1		4		485		54		65		44		7		0		14		12
SAN JUAN 32-8 UNIT #235	14431	32-8	31N 8W 21G		1		3		285		32		41		27		4		0		9		9
SAN JUAN 32-8 UNIT #236	14432	32-8	31N 8W 22H		1		10		1,522		170		223		110		24		0		88		68
SAN JUAN 32-8 UNIT #237	13645	32-8	31N 8W 23G		1		4		461		51		68		45		7		0		15		13
SAN JUAN 32-8 UNIT #238	13652	32-8	31N 8W 23N		1		6		796		89		115		63		12		0		39		33
SAN JUAN 32-8 UNIT #239	13714	32-8	32N 8W 30M		1		6		835		93		127		68		14		0		45		38
SAN JUAN 32-8 UNIT #240	13725	32-8	31N 8W 3K		1		7		977		109		149		75		16		0		58		48
SAN JUAN 32-8 UNIT #241	13713	32-8	31N 8W 4A		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-8 UNIT #242	14433	32-8	31N 8W 4M		1		5		598		67		93		56		10		0		27		23
SAN JUAN 32-8 UNIT #243	14434	32-8	31N 8W 11M		1		6		674		75		107		60		12		0		35		30
SAN JUAN 32-8 UNIT #244	13730	32-8	31N 8W 14G		1		8		1,058		118		164		84		18		0		63		51
SAN JUAN 32-8 UNIT #245	14435	32-8	31N 8W 14K		1		6		789		88		117		62		13		0		42		36
SAN JUAN 32-8 UNIT #247	12555	32-8	32N 8W 19L		1		7		1,155		129		186		78		20		0		88		73
SAN JUAN 32-8 UNIT #248	14436	32-8	31N 8W 11G		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-8 UNIT #249	14437	32-8	31N 8W 3A		1		3		315		35		50		31		5		0		14		12
SAN JUAN 32-8 UNIT #250	13731	32-8	32N 8W 33M		1		6		849		95		128		65		14		0		49		41
SAN JUAN 32-8 UNIT #253	12649	32-8	32N 8W 27G		1		4		360		40		60		36		6		0		18		16
SAN JUAN 32-8 UNIT #254	14084	32-8	32N 8W 22M		1		4		442		49		74		40		8		0		26		23
SAN JUAN 32-8 UNIT #255	1874	32-8	32N 8W 24H		1		1		59		7		10		8		1		0		1		1
SAN JUAN 32-8 UNIT #256	19424	32-8	32N 8W 25		1		6		1,005		112		168		69		18		0		80		68
SAN JUAN 32-8 UNIT #257	16981	32-8	32N 8W 19A		1		7		1,236		138		206		77		22		0		106		90
SAN JUAN 32-8 UNIT #258	19425	32-8	32N 8W 15L		1		3		294		33		49		34		5		0		10		9
SAN JUAN 32-8 UNIT #259A	5043	32-8	32N 8W 22N		1		5		601		67		101		49		11		0		41		37
SAN JUAN 32-8 UNIT #260	19426	32-8	32N 8W 18K		1		5		707		79		118		53		13		0		52		46
SAN JUAN 32-8 UNIT #261	17021	32-8	32N 8W 17M		1		4		334		37		57		36		6		0		14		13
SAN JUAN 32-8 UNIT #262	19427	32-8	32N 8W 17H		1		5		577		64		99		53		11		0		35		30

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 23 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 32-8 UNIT #263A	6002	32-8	32N 8W 15P		1		9		1,538		171		266		101		29		0		136		109
SAN JUAN 32-8 UNIT #264	11694	32-8	32N 8W 9		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-8 UNIT #265	10789	32-8	32N 8W 14K		1		5		567		63		97		47		10		0		39		35
SAN JUAN 32-8 UNIT #266A	10791	32-8	32N 8W 14J		1		0		19		2		4		3		0		0		0		0
SAN JUAN 32-8 UNIT #267A	10123	32-8	32N 8W 23I		1		9		1,425		159		237		103		26		0		109		86
SAN JUAN 32-8 UNIT #36	15041	32-8	32N 8W 25G		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #104	14466	32-9	32N 10W 24G		1		2		274		7		9		6		1		0		2		2
SAN JUAN 32-9 UNIT #105	14467	32-9	31N 9W 18G		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #201	14438	32-9	31N 9W 2H		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #202	14439	32-9	31N 9W 2M		1		0		16		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #209	14273	32-9	31N 10W 2G		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #210	14274	32-9	31N 10W 2N		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #215	14468	32-9	32N 9W 10M		1		6		1,127		29		39		18		4		0		17		14
SAN JUAN 32-9 UNIT #217	14275	32-9	32N 9W 16G		1		6		1,066		28		37		19		4		0		14		12
SAN JUAN 32-9 UNIT #220	14000	32-9	31N 10W 11b		1		21		5,143		134		161		70		17		0		74		46
SAN JUAN 32-9 UNIT #221	12458	32-9	31N 10W 11		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #222	12556	32-9	31N 10W 12		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #223	12459	32-9	31N 10W 12		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #226	14469	32-9	32N 9W 32H		1		0		15		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #228	14440	32-9	32N 9W 36G		1		4		490		13		16		10		2		0		4		4
SAN JUAN 32-9 UNIT #229	14267	32-9	32N 10W 36H		1		2		260		7		9		6		1		0		2		2
SAN JUAN 32-9 UNIT #230	14470	32-9	32N 10W 36M		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #235	14450	32-9	32N 9W 36M		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #241	19430	32-9	32N 9W 13M		1		7		1,215		32		45		20		5		0		20		17
SAN JUAN 32-9 UNIT #242	766	32-9	32N 9W 14L		1		4		604		16		22		12		2		0		8		7
SAN JUAN 32-9 UNIT #250	14268	32-9	31N 9W 4G		1		4		479		13		16		10		2		0		4		4
SAN JUAN 32-9 UNIT #251	14269	32-9	31N 9W 4M		1		6		1,017		27		32		18		3		0		10		9
SAN JUAN 32-9 UNIT #252	14471	32-9	31N 9W 5A		1		5		685		18		21		13		2		0		6		5
SAN JUAN 32-9 UNIT #253	14472	32-9	31N 9W 5M		1		2		261		7		8		6		1		0		1		1
SAN JUAN 32-9 UNIT #254	14473	32-9	31N 9W 6A		1		0		33		1		1		1		0		0		0		0
SAN JUAN 32-9 UNIT #255	14474	32-9	31N 9W 6L		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #257	14475	32-9	31N 9W 8N		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #258	14476	32-9	31N 9W 9A		1		2		160		4		5		4		1		0		1		1
SAN JUAN 32-9 UNIT #259	14477	32-9	31N 9W 9L		1		6		914		24		28		16		3		0		8		7
SAN JUAN 32-9 UNIT #260	14270	32-9	31N 9W 10B		1		1		52		1		2		1		0		0		0		0
SAN JUAN 32-9 UNIT #261	14271	32-9	31N 9W 10N		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #262	14478	32-9	31N 9W 15A		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #263	14479	32-9	31N 9W 15F		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #264	14480	32-9	31N 9W 17H		1		0		0		0		0		0		0		0		0		0

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 24 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
SAN JUAN 32-9 UNIT #268	14482	32-9	31N 9W 1A		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #269	14483	32-9	31N 10W 1L		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #270	14484	32-9	32N 9W 18A		1		5		837		22		28		15		3		0		10		9
SAN JUAN 32-9 UNIT #271	14485	32-9	32N 9W 18L		1		8		1,645		43		54		25		6		0		23		19
SAN JUAN 32-9 UNIT #272	5838	32-9	32N 9W 21		1		6		1,048		27		38		18		4		0		15		13
SAN JUAN 32-9 UNIT #273	14486	32-9	32N 9W 19L		1		2		248		6		8		6		1		0		2		2
SAN JUAN 32-9 UNIT #274	14272	32-9	32N 9W 28H		1		3		432		11		15		9		2		0		4		4
SAN JUAN 32-9 UNIT #275	14487	32-9	32N 9W 29M		1		2		182		5		6		5		1		0		1		1
SAN JUAN 32-9 UNIT #276	14344	32-9	32N 9W 27M		1		4		533		14		18		11		2		0		5		5
SAN JUAN 32-9 UNIT #277	14488	32-9	32N 9W 30M		1		1		120		3		4		3		0		0		1		1
SAN JUAN 32-9 UNIT #278	14489	32-9	32N 9W 31A		1		4		458		12		15		10		2		0		3		3
SAN JUAN 32-9 UNIT #279	14490	32-9	32N 9W 31M		1		1		136		4		4		3		0		0		1		1
SAN JUAN 32-9 UNIT #281	14491	32-9	32N 9W 32K		1		0		15		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #282	14345	32-9	32N 9W 33G		1		1		111		3		4		3		0		0		0		0
SAN JUAN 32-9 UNIT #283	14346	32-9	32N 9W 33L		1		3		456		12		15		9		2		0		4		4
SAN JUAN 32-9 UNIT #284	14492	32-9	32N 10W 13A		1		5		740		19		25		14		3		0		8		7
SAN JUAN 32-9 UNIT #285	14493	32-9	32N 10W 13N		1		6		1,033		27		33		18		4		0		12		10
SAN JUAN 32-9 UNIT #286	14494	32-9	32N 10W 14A		1		2		253		7		8		5		1		0		2		2
SAN JUAN 32-9 UNIT #287	14495	32-9	32N 10W 14K		1		3		525		14		16		10		2		0		5		4
SAN JUAN 32-9 UNIT #288	14496	32-9	32N 10W 23B		1		4		801		21		26		13		3		0		10		9
SAN JUAN 32-9 UNIT #289	14497	32-9	32N 10W 23M		1		3		380		10		12		8		1		0		3		3
SAN JUAN 32-9 UNIT #291	14498	32-9	32N 10W 24M		1		4		492		13		17		11		2		0		4		4
SAN JUAN 32-9 UNIT #292	14499	32-9	32N 10W 25A		1		3		375		10		13		8		1		0		3		3
SAN JUAN 32-9 UNIT #293	14500	32-9	32N 10W 25M		1		2		293		8		10		7		1		0		2		2
SAN JUAN 32-9 UNIT #294	14501	32-9	32N 10W 26A		1		3		321		8		11		8		1		0		2		2
SAN JUAN 32-9 UNIT #295	14502	32-9	32N 10W 26L		1		4		467		12		16		10		2		0		4		4
SAN JUAN 32-9 UNIT #296	13928	32-9	32N 10W 35B		1		1		128		3		3		3		0		0		0		0
SAN JUAN 32-9 UNIT #297	13929	32-9	32N 10W 35K		1		0		0		0		0		0		0		0		0		0
SAN JUAN 32-9 UNIT #300	14503	32-9	32N 10W 11K		1		2		339		9		11		7		1		0		3		3
SAN JUAN 32-9 UNIT #301	14504	32-9	32N 10W 12K		1		4		623		16		21		12		2		0		6		5
SAN JUAN 32-9 UNIT #302	15548	32-9	32N 9W 9K		1		2		250		7		8		6		1		0		2		1
SAN JUAN 32-9 UNIT #303 COM	12172	32-9	31N 10W 12A		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #118 COM	4765	HUERFANO	27N 10W 30J		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #12	14215	HUERFANO	26N 10W 4M		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #138	17003	HUERFANO	26N 9W 22		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #14R	14218	HUERFANO	26N 10W 5L		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #18 COM	16974	HUERFANO	27N 10W 32M		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #182	17019	HUERFANO	26N 9W 28		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #19	14221	HUERFANO	26N 10W 5B		1		1		21		3		8		6		1		0		1		1

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 25 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
HUERFANO UNIT #22	14216	HUERFANO	27N 10W 33M		1		6		144		19		51		37		6		0		8		7
HUERFANO UNIT #223	14004	HUERFANO	26N 10W 4F		1		6		149		20		53		38		6		0		9		8
HUERFANO UNIT #231	17004	HUERFANO	26N 9W 6D		1		5		174		23		47		35		5		0		7		6
HUERFANO UNIT #237	17005	HUERFANO	26N 9W 17		1		0		7		1		2		2		0		0		0		0
HUERFANO UNIT #24	14222	HUERFANO	27N 10W 29M		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #255	17006	HUERFANO	27N 9W 31		1		17		851		115		234		138		25		0		70		46
HUERFANO UNIT #257	17007	HUERFANO	27N 10W 36		1		2		52		7		14		11		2		0		2		1
HUERFANO UNIT #258S	2326	HUERFANO	27N 10W 36A		1		3		101		14		27		21		3		0		4		3
HUERFANO UNIT #259	13989	HUERFANO	26N 10W 6C		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #282	14512	HUERFANO	27N 10W 31H		1		3		80		11		29		21		3		0		5		5
HUERFANO UNIT #286	14202	HUERFANO	27N 10W 35A		1		9		263		35		94		60		10		0		24		18
HUERFANO UNIT #34	22682	HUERFANO	26N 9W 8M		1		2		31		4		14		11		2		0		2		2
HUERFANO UNIT #37	22681	HUERFANO	26N 9W 18A		1		4		83		11		38		25		4		0		9		8
HUERFANO UNIT #46	13951	HUERFANO	26N 9W 23K		1		15		488		66		177		101		19		0		57		39
HUERFANO UNIT #500	17008	HUERFANO	26N 9W 20M		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #501	17009	HUERFANO	26N 9W 20		1		11		464		63		127		80		14		0		33		25
HUERFANO UNIT #502	17010	HUERFANO	26N 9W 21		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #503	13987	HUERFANO	26N 9W 21H		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #504	17011	HUERFANO	26N 9W 22		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #505	17012	HUERFANO	26N 9W 30		1		2		49		7		14		11		1		0		1		1
HUERFANO UNIT #507	17013	HUERFANO	26N 9W 27		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #508	13985	HUERFANO	26N 9W 26K		1		15		515		69		184		104		20		0		59		40
HUERFANO UNIT #509	13999	HUERFANO	27N 10W 30D		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #518 COM	17014	HUERFANO	26N 9W 16		1		6		200		10		21		16		2		0		3		2
HUERFANO UNIT #520	17015	HUERFANO	26N 9W 17		1		4		113		15		31		25		3		0		3		2
HUERFANO UNIT #521	17016	HUERFANO	27N 10W 35		1		16		726		98		197		122		21		0		53		35
HUERFANO UNIT #522	17017	HUERFANO	27N 9W 31		1		22		1,188		160		333		182		36		0		115		69
HUERFANO UNIT #523	14008	HUERFANO	26N 9W 23B		1		7		242		33		68		49		7		0		12		9
HUERFANO UNIT #528	12464	HUERFANO	26N 10W 6		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #549	13950	HUERFANO	27N 10W 33A		1		5		144		19		51		34		6		0		12		10
HUERFANO UNIT #55	14223	HUERFANO	26N 9W 27H		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #550	17018	HUERFANO	27N 10W 29		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #551 COM	4766	HUERFANO	26N 9W 16A		1		1		39		2		4		3		0		0		0		0
HUERFANO UNIT #59	13952	HUERFANO	26N 9W 26B		1		1		18		2		6		5		1		0		0		0
HUERFANO UNIT #6	14377	HUERFANO	27N 10W 31M		1		0		0		0		0		0		0		0		0		0
HUERFANO UNIT #600	706	HUERFANO	27N 10W 19A		1		1		13		2		4		3		0		0		0		0
HUERFANO UNIT #70	14224	HUERFANO	26N 10W 8C		1		0		5		1		2		1		0		0		0		0
HUERFANO UNIT #74	13988	HUERFANO	27N 10W 19M		1		0		0		0		0		0		0		0		0		0
NE BLANCO UNIT #400R	14350	NEBU	31N 6W 7L		1		6		507		4		5		2		1		0		2		2

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 26 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
NE BLANCO UNIT #401	14278	NEBU	30N 7W 9L		1		9		844		7		8		3		1		0		4		3
NE BLANCO UNIT #402	13561	NEBU	30N 7W 5A		1		10		1,021		8		11		4		1		0		5		4
NE BLANCO UNIT #403R	14279	NEBU	30N 7W 9G		1		7		638		5		6		3		1		0		3		2
NE BLANCO UNIT #404R	14280	NEBU	31N 7W 34E		1		10		1,079		8		11		4		1		0		6		5
NE BLANCO UNIT #406	13560	NEBU	31N 7W 22B		1		8		643		5		7		3		1		0		3		3
NE BLANCO UNIT #407	14281	NEBU	30N 7W 21A		1		7		601		5		6		3		1		0		2		2
NE BLANCO UNIT #408	13562	NEBU	31N 7W 20A		1		7		493		4		5		3		1		0		2		2
NE BLANCO UNIT #409	14282	NEBU	30N 7W 10N		1		9		784		6		7		3		1		0		3		3
NE BLANCO UNIT #410	14283	NEBU	31N 7W 9K		1		7		644		5		7		3		1		0		3		3
NE BLANCO UNIT #411	14284	NEBU	30N 7W 10G		1		11		1,004		8		10		4		1		0		4		3
NE BLANCO UNIT #412	14285	NEBU	31N 7W 29N		1		11		1,238		10		13		4		1		0		7		5
NE BLANCO UNIT #413R	14286	NEBU	30N 7W 20A		1		9		816		6		8		4		1		0		3		3
NE BLANCO UNIT #414	13569	NEBU	31N 7W 30H		1		9		804		6		8		3		1		0		4		3
NE BLANCO UNIT #415	14287	NEBU	30N 7W 2G		1		11		956		7		9		4		1		0		4		3
NE BLANCO UNIT #416	13563	NEBU	31N 7W 21A		1		3		174		1		2		1		0		0		0		0
NE BLANCO UNIT #417	14288	NEBU	30N 7W 2M		1		15		1,959		15		19		6		2		0		10		7
NE BLANCO UNIT #418	14289	NEBU	31N 7W 28M		1		12		1,176		9		12		5		1		0		6		4
NE BLANCO UNIT #419	14290	NEBU	30N 7W 3N		1		13		1,460		11		14		5		2		0		7		5
NE BLANCO UNIT #420	13564	NEBU	31N 7W 28B		1		0		0		0		0		0		0		0		0		0
NE BLANCO UNIT #421R	14291	NEBU	30N 7W 4P		1		10		1,178		9		11		4		1		0		6		4
NE BLANCO UNIT #422	13570	NEBU	31N 7W 20N		1		15		1,288		10		13		6		1		0		6		4
NE BLANCO UNIT #423R	14292	NEBU	30N 7W 8J		1		7		737		6		7		3		1		0		3		3
NE BLANCO UNIT #424	14293	NEBU	30N 7W 4F		1		10		1,120		9		12		4		1		0		6		5
NE BLANCO UNIT #425R	14294	NEBU	30N 7W 8N		1		9		951		7		9		4		1		0		5		4
NE BLANCO UNIT #426	14262	NEBU	31N 6W 6L		1		7		600		5		6		3		1		0		3		2
NE BLANCO UNIT #427R	14295	NEBU	30N 7W 16M		1		5		345		3		3		2		0		0		1		1
NE BLANCO UNIT #428	13571	NEBU	31N 7W 24A		1		7		614		5		6		3		1		0		3		3
NE BLANCO UNIT #429R	14296	NEBU	30N 7W 17B		1		4		313		2		3		2		0		0		1		1
NE BLANCO UNIT #430	13565	NEBU	30N 7W 5L		1		12		858		7		9		4		1		0		4		3
NE BLANCO UNIT #431	14297	NEBU	30N 7W 17O		1		6		581		5		6		2		1		0		2		2
NE BLANCO UNIT #432	13566	NEBU	30N 7W 7A		1		11		1,019		8		11		4		1		0		5		4
NE BLANCO UNIT #433	14298	NEBU	30N 7W 19M		1		0		0		0		0		0		0		0		0		0
NE BLANCO UNIT #434	14299	NEBU	31N 7W 23K		1		14		1,868		15		19		6		2		0		11		8
NE BLANCO UNIT #435	14300	NEBU	30N 8W 1K		1		5		299		2		3		2		0		0		1		1
NE BLANCO UNIT #436	13572	NEBU	31N 6W 19G		1		7		467		4		5		2		1		0		2		2
NE BLANCO UNIT #437	14301	NEBU	30N 8W 12N		1		6		409		3		4		2		0		0		1		1
NE BLANCO UNIT #438	14361	NEBU	31N 6W 18A		1		2		77		1		1		1		0		0		0		0
NE BLANCO UNIT #439	14302	NEBU	30N 8W 13M		1		16		2,043		16		19		7		2		0		11		7
NE BLANCO UNIT #440	13573	NEBU	31N 7W 11A		1		6		449		3		5		2		1		0		2		2

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 27 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
NE BLANCO UNIT #441R	14303	NEBU	30N 8W 24G		1		7		463		4		4		2		0		0		1		1
NE BLANCO UNIT #442	14304	NEBU	31N 7W 11M		1		8		723		6		8		3		1		0		4		3
NE BLANCO UNIT #443	14305	NEBU	30N 8W 24N		1		12		920		7		9		4		1		0		3		3
NE BLANCO UNIT #444	14362	NEBU	31N 7W 23A		1		6		496		4		5		2		1		0		2		2
NE BLANCO UNIT #445	14306	NEBU	31N 8W 25M		1		5		377		3		4		2		0		0		1		1
NE BLANCO UNIT #446	14307	NEBU	31N 7W 33K		1		8		473		4		5		3		1		0		1		1
NE BLANCO UNIT #447	14308	NEBU	31N 8W 36K		1		7		599		5		6		3		1		0		2		2
NE BLANCO UNIT #448	13567	NEBU	31N 7W 32G		1		9		659		5		7		3		1		0		3		2
NE BLANCO UNIT #449	14309	NEBU	31N 7W 19M		1		7		520		4		5		3		1		0		2		1
NE BLANCO UNIT #450	14310	NEBU	31N 7W 32N		1		6		395		3		4		2		0		0		1		1
NE BLANCO UNIT #451	14311	NEBU	30N 7W 6B		1		8		670		5		6		3		1		0		3		2
NE BLANCO UNIT #452	13574	NEBU	31N 7W 15G		1		2		74		1		1		1		0		0		0		0
NE BLANCO UNIT #453	14312	NEBU	30N 7W 6M		1		7		505		4		5		2		1		0		2		1
NE BLANCO UNIT #454	14313	NEBU	31N 7W 33A		1		17		1,811		14		19		7		2		0		10		7
NE BLANCO UNIT #455	14314	NEBU	31N 7W 31B		1		17		2,623		20		25		7		3		0		15		10
NE BLANCO UNIT #456	13575	NEBU	31N 7W 26H		1		6		366		3		4		2		0		0		1		1
NE BLANCO UNIT #457	14315	NEBU	31N 7W 31E		1		6		510		4		5		2		1		0		2		2
NE BLANCO UNIT #458	13576	NEBU	31N 7W 13A		1		3		193		2		2		1		0		0		1		1
NE BLANCO UNIT #459	14316	NEBU	31N 7W 19G		1		16		2,215		17		21		7		2		0		12		8
NE BLANCO UNIT #460	14351	NEBU	31N 6W 7A		1		12		1,380		11		14		5		2		0		8		6
NE BLANCO UNIT #461	14317	NEBU	30N 7W 12D		1		4		270		2		3		2		0		0		1		1
NE BLANCO UNIT #462	14318	NEBU	31N 7W 1N		1		7		745		6		8		3		1		0		4		3
NE BLANCO UNIT #463	14319	NEBU	30N 7W 18J		1		5		327		3		3		2		0		0		1		1
NE BLANCO UNIT #464	13577	NEBU	31N 7W 10P		1		1		57		0		1		0		0		0		0		0
NE BLANCO UNIT #465	14320	NEBU	30N 8W 1A		1		7		616		5		6		3		1		0		3		2
NE BLANCO UNIT #466	14321	NEBU	31N 7W 34B		1		5		306		2		3		2		0		0		1		1
NE BLANCO UNIT #467	14322	NEBU	30N 8W 12A		1		6		450		3		4		2		0		0		2		1
NE BLANCO UNIT #468	14323	NEBU	31N 7W 35A		1		6		450		4		5		2		1		0		2		2
NE BLANCO UNIT #469	14324	NEBU	30N 8W 13A		1		10		1,193		9		11		4		1		0		6		5
NE BLANCO UNIT #470	14352	NEBU	31N 7W 27H		1		3		153		1		2		1		0		0		0		0
NE BLANCO UNIT #471	14325	NEBU	31N 8W 25B		1		8		883		7		8		3		1		0		4		3
NE BLANCO UNIT #472	14326	NEBU	31N 7W 29G		1		8		554		4		6		3		1		0		2		2
NE BLANCO UNIT #473	14327	NEBU	31N 8W 36G		1		5		447		3		4		2		0		0		2		2
NE BLANCO UNIT #474	14353	NEBU	31N 7W 26M		1		7		435		3		5		3		0		0		1		1
NE BLANCO UNIT #475	14328	NEBU	30N 7W 19K		1		4		230		2		2		1		0		0		1		0
NE BLANCO UNIT #476	14329	NEBU	31N 7W 22M		1		10		851		7		9		4		1		0		4		3
NE BLANCO UNIT #477	14379	NEBU	30N 7W 29H		1		3		136		1		1		1		0		0		0		0
NE BLANCO UNIT #478	14330	NEBU	31N 7W 21M		1		10		887		7		9		4		1		0		4		3
NE BLANCO UNIT #479R	13942	NEBU	30N 7W 20C		1		6		460		4		4		2		0		0		2		1

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 28 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
NE BLANCO UNIT #480	14332	NEBU	31N 7W 14L		1		13		1,165		9		12		5		1		0		6		4
NE BLANCO UNIT #481	14333	NEBU	31N 7W 36N		1		6		466		4		4		2		0		0		2		1
NE BLANCO UNIT #482	14334	NEBU	31N 7W 15M		1		9		995		8		10		4		1		0		5		4
NE BLANCO UNIT #483	14335	NEBU	31N 7W 36G		1		3		179		1		2		1		0		0		0		0
NE BLANCO UNIT #484	14336	NEBU	31N 7W 16A		1		3		179		1		2		1		0		0		1		0
NE BLANCO UNIT #485	14337	NEBU	30N 7W 3A		1		2		84		1		1		1		0		0		0		0
NE BLANCO UNIT #486	14338	NEBU	31N 6W 19K		1		7		682		5		7		3		1		0		4		3
NE BLANCO UNIT #487	14339	NEBU	31N 7W 35L		1		14		1,732		13		18		6		2		0		10		7
NE BLANCO UNIT #488	14340	NEBU	31N 7W 24L		1		10		1,307		10		14		4		1		0		8		6
NE BLANCO UNIT #489	14364	NEBU	31N 7W 12L		1		1		33		0		0		0		0		0		0		0
NE BLANCO UNIT #490	14363	NEBU	31N 7W 14H		1		10		812		6		8		4		1		0		4		3
NE BLANCO UNIT #491	14368	NEBU	31N 7W 25J		1		4		236		2		3		2		0		0		1		1
NE BLANCO UNIT #492	14354	NEBU	31N 7W 12B		1		5		359		3		4		2		0		0		2		1
NE BLANCO UNIT #493	14380	NEBU	31N 7W 25H		1		8		538		4		6		3		1		0		2		2
NE BLANCO UNIT #494	14341	NEBU	31N 7W 27N		1		16		1,328		10		14		6		1		0		6		4
NE BLANCO UNIT #495	14381	NEBU	31N 6W 30L		1		2		70		1		1		1		0		0		0		0
NE BLANCO UNIT #496	14355	NEBU	31N 6W 18L		1		6		467		4		5		2		1		0		2		2
NE BLANCO UNIT #497	14382	NEBU	31N 6W 30H		1		11		868		7		9		4		1		0		4		3
NE BLANCO UNIT #498	14365	NEBU	31N 7W 13L		1		5		377		3		4		2		0		0		2		1
NE BLANCO UNIT #499	14383	NEBU	31N 6W 20P		1		8		687		5		7		3		1		0		4		3
NE BLANCO UNIT #500	14356	NEBU	31N 6W 20D		1		8		637		5		7		3		1		0		3		2
NE BLANCO UNIT #504	14342	NEBU	31N 7W 16M		1		5		316		2		3		2		0		0		1		1
NE BLANCO UNIT #505	14384	NEBU	30N 7W 21C		1		10		868		7		8		4		1		0		3		3
BARNES GAS COM F #1	14369	NON-UNIT	32N 11W 26K		1		0		0		0		0		0		0		0		0		0
BLANCO #201	13592	NON-UNIT	31N 8W 35L		1		5		751		111		182		109		20		0		53		46
BLANCO #202	13651	NON-UNIT	31N 8W 26G		1		9		1,410		208		358		192		39		0		127		100
BLANCO #203	13649	NON-UNIT	31N 8W 35A		1		4		386		57		95		70		10		0		14		13
BLANCO #204R	14451	NON-UNIT	31N 8W 26M		1		4		382		56		97		69		10		0		18		16
BLANCO #330	14219	NON-UNIT	31N 8W 5N		1		7		1,245		91		155		77		17		0		61		51
BONDS COM #100	14220	NON-UNIT	32N 10W 15M		1		11		2,334		116		200		82		22		0		97		75
DECKER GAS COM A #1	14370	NON-UNIT	32N 10W 17L		1		7		1,051		77		129		68		14		0		47		40
EAGLE #750	14375	NON-UNIT	32N 9W 16M		1		3		337		7		10		7		1		0		2		2
FC BARNES #1	14371	NON-UNIT	32N 11W 15N		1		0		0		0		0		0		0		0		0		0
FC FEE COM #2	14277	NON-UNIT	32N 11W 30K		1		0		0		0		0		0		0		0		0		0
FC STATE COM #19	14276	NON-UNIT	30N 9W 36G		1		0		0		0		0		0		0		0		0		0
FC STATE COM #20	12651	NON-UNIT	30N 8W 2B		1		6		853		15		25		14		3		0		8		7
HEIZER #100	14203	NON-UNIT	32N 10W 15G		1		10		2,192		1		2		1		0		0		1		1
HUBBARD GAS COM A #1	14250	NON-UNIT	32N 11W 30H		1		0		0		0		0		0		0		0		0		0
JACQUEZ #331	14343	NON-UNIT	31N 8W 6L		1		4		425		32		55		33		6		0		15		14

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 29 of 30

WILLIAMS PRODUCTION CO. MILLER AND LENTS, LTD.

FRUITLAND COAL RESERVES
UNDERLYING PROPERTIES/WILLIAMS COAL SEAM GAS ROYALTY TRUST
RESERVES AND ECONOMIC SUMMARY
PROVED RESERVES AS OF DECEMBER 31, 2009

										NET		REVENUE		OPER.		ADV&SEV				BFIT NET		10% DISC
						LIFE		GROSS GAS		GAS		TO INT.		EXPENSE		TAXES		CAPITAL		REVENUE		REVENUE
LEASE NAME	PROPID	UNIT	LOCATION	WELLS		YEARS		MMCF		MMCF		M$		M$		M$		M$		M$		M$
KEYS GAS COM G #1R	14212	NON-UNIT	32N 10W 27K		1		0		0		0		0		0		0		0		0		0
MOORE, WAYNE COM #2	14442	NON-UNIT	31N 9W 16M		1		2		127		5		9		7		1		0		1		1
NORDHAUS #716	14360	NON-UNIT	31N 9W 13H		1		4		540		39		66		42		7		0		17		15
PAYNE #201	14225	NON-UNIT	32N 10W 20L		1		1		103		2		3		2		0		0		0		0
QUINN #336	14226	NON-UNIT	31N 8W 17N		1		0		0		0		0		0		0		0		0		0
SAN JUAN 31 FED 3 #2	14418	NON-UNIT	31N 9W 3M		1		5		646		96		165		103		18		0		44		38
SEYMOUR #720	14357	NON-UNIT	31N 9W 23A		1		5		716		52		82		51		9		0		22		19
STATE GAS COM AA #1	14441	NON-UNIT	30N 8W 36K		1		11		1,285		25		46		26		5		0		15		11
TOTAL PROVED DEVELOPED: 320-Acre New Mexico					660				343,616		26,424		38,724		18,650		4,242		0		15,831		12,422
TOTAL PROVED DEVELOPED: NEW MEXICO					1102				506,473		40,821		58,708		27,565		6,420		0		24,723		19,776
PROVED UNDEVELOPED RESERVES
TOTAL PROVED UNDEVELOPED: 160-Acre New Mexico					0				0		0		0		0		0		0		0		0
TOTAL PROVED UNDEVELOPED: 320-Acre New Mexico					0				0		0		0		0		0		0		0		0
TOTAL PROVED UNDEVELOPED: NEW MEXICO					0				0		0		0		0		0		0		0		0
TOTAL PROVED RESERVES: NEW MEXICO					1102				506,473		40,821		58,708		27,565		6,420		0		24,723		19,776
TOTAL PROVED RESERVES					1123				530,722		45,755		63,661		27,565		6,420		0		29,675		23,499

		Table 2
Date: 12/31/2009	This page is a part of a Miller and Lents, Ltd. (TREF No. F-1442) report and should not be used independently of the report	Page 30 of 30