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

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

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

     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.

     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.

     “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

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,

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

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

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.

     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

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

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

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.

          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.

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.

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.

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

		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

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.

          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

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

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:

	•		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.

          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

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

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.

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.

          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

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

      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.

          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.

          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

          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 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

          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

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

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,

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.

          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

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.

     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

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.

     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

     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.

     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

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”.

     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,

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

     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.

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

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.

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.

Tulsa, Oklahoma
March 31, 2010

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

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

“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.

     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

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.

     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

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

     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.

     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

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.

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

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)

     (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.

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.

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).

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.

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.

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.

(The Registrant has no directors or executive officers.)

INDEX TO EXHIBITS

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

Exhibit
Number				Description
10.7		___		Amendment #3 to the Gas Gathering and Treating Agreement dated as of October 1, 1993, by and between Williams Field Services Company and Williams Gas Marketing Company (filed as Exhibit 10.7 to the Registrant’s Form 10-K for the year ended December 31, 1993 and incorporated herein by reference).
10.8		___		Confirmation Agreement effective as of May 1, 1995 by and among Williams Production Company, The Williams Companies, Inc. and Williams Coal Seam Gas Royalty Trust (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 1995 and incorporated herein by reference).
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.