10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2009

OR

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

Commission file number: 001-11335

Dominion Resources Black Warrior Trust

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization) 75-6461716
(I.R.S. employer
identification number)

U.S. Trust, Bank of America
Private Wealth Management
901 Main Street
17th Floor
Dallas, Texas 75202
(Address of principal executive offices; Zip Code)

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

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

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o   No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the 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 Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§232.405 of this chapter) 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 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 þ Non-accelerated filer o (Do not check if a smaller reporting company) Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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) 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 $124,030,000.

At March 1, 2010, there were 7,850,000 units of beneficial interest outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
None

TABLE OF CONTENTS

PART I	3
Item 1. Business	3
GLOSSARY	3
DESCRIPTION OF THE TRUST	6
DESCRIPTION OF UNITS	12
FEDERAL INCOME TAX CONSIDERATIONS	17
ERISA CONSIDERATIONS	22
STATE TAX CONSIDERATIONS	22
REGULATION AND PRICES	24
Item 1A. Risk Factors	28
Item 1B. Unresolved Staff Comments. None	32
Item 2. Properties	33
THE ROYALTY INTERESTS	33
Item 3. Legal Proceedings	42
Item 4. Reserved	42
PART II	43
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	43
Item 6. Selected Financial Data	43
Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations	44
Item 8. Financial Statements and Supplementary Data	51
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	51
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	62
Item 9A. Controls and Procedures	62
PART III	65
Item 10. Directors, Executive Officers and Corporate Governance	65
Item 11. Executive Compensation	65
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	66
Item 13. Certain Relationships and Related Transactions, and Director Independence	66
Item 14. Principal Accounting Fees and Services	68
PART IV	68
Item 15. Exhibits, Financial Statement Schedules	68
EX-23.1
EX-31.1
EX-32.1
EX-99.2

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PART I.

Item 1. Business.

GLOSSARY

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

     “Administrative Services Agreement” means the Administrative Services Agreement dated as of June 28, 1994, between Dominion Resources and the Trust, a copy of which is filed as an exhibit to this Form 10-K.

     “Assignment and Assumption Agreement” means the Assignment and Assumption Agreement dated as of July 31, 2007, between Dominion Resources and HighMount Alabama, a copy of which is filed as an exhibit to this Form 10-K.

     “Bcf” means billion cubic feet of natural gas.

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

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

     “Company” means HighMount Black Warrior Basin LLC, a Delaware limited liability company, as successor to Dominion Black Warrior Basin, Inc., an Alabama corporation.

     “Company Interests” means the Company’s interest in the Underlying Properties, as of June 1, 1994, not burdened by the Royalty Interests.

     “Company Interests Owner” means the Company while it owns all or part of the Company Interests and any other person or persons who acquire all or any part of the Company Interests or any operating rights therein other than a royalty, overriding royalty, production payment or net profits interest.

     “ConocoPhillips” means ConocoPhillips Corporation, successor to The River Gas Corporation.

     “Conveyance” means the Overriding Royalty Conveyance dated effective as of June 1, 1994, from the Company to the Trust, as amended by instrument dated as of November 20, 1994, copies of which are filed as exhibits to this Form 10-K.

     “Delaware Trustee” means Mellon Bank (DE) National Association.

     “Dominion Resources” means Dominion Resources, Inc., a Virginia corporation.

     “El Paso” means El Paso Merchant Energy-Gas, L.P., successor to Sonat Marketing Company.

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     “Existing Wells” means the wells producing on the Underlying Properties as of June 1, 1994.

     “Gas” means natural gas produced and sold from the Underlying Properties.

     “Gas Purchase Agreement” means the Gas Purchase Agreement dated as of May 3, 1994, between the Company and El Paso, as successor to Sonat Marketing, as amended by instruments effective as of April 1, 1996, May 16, 1996, April 9, 1998, July 1, 1999, July 1, 2000, July 1, 2001 and July 1, 2002.

     “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 Code and the Treasury Regulations thereunder.

     “Gross Proceeds” means the aggregate amounts received by the Company Interests Owner attributable to the Company Interests from the sale of Subject Gas at the central delivery points in the gathering system for the Underlying Properties.

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

     “HighMount” means HighMount Exploration & Production LLC, a Delaware limited liability company, which is indirectly wholly-owned by Loews Corporation.

     “HighMount Alabama” means HighMount Exploration & Production Alabama LLC, a Delaware limited liability company, which is wholly-owned by HighMount.

     “Index Price” means the price published by Inside FERC Gas Market Report in its first issue of the month which posts prices for the beginning of such month for “Prices of Spot Gas Delivered to Pipelines — Southern Natural Gas Co. — Louisiana — Index,” for such month.

     “Mcf” means thousand cubic feet of natural gas. Natural gas volumes are stated herein at the legal pressure base of 14.65 or 14.73 pounds per square inch absolute, as the case may be, at 60 degrees Fahrenheit.

     “MMBtu” means million British Thermal Unit. As used herein, 992 MMBtu is deemed to be the Btu content of 1 MMcf.

     “MMcf” means million cubic feet of natural gas. As used herein, 1 MMcf is assumed to have a Btu content of 1008 MMBtu.

     “Net revenue interest” means Working Interest or mineral interest less any applicable royalties, overriding royalties or similar burdens on production prior to the Royalty Interests.

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

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     “Prospectus” means the prospectus dated June 21, 1994, as supplemented by the final prospectus supplement dated June 1, 1995, relating to the offer and sale of the Units, and forming a part of Dominion Resources’ Registration Statement on Form S-3 (No. 33-53513).

     “Ralph E. Davis & Associates” means Ralph E. Davis & Associates, independent petroleum engineers.

     “Reserve Estimate” means the estimated net proved reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests as of December 31, 2009, prepared by Ralph E. Davis & Associates.

     “Royalty Interests” means the overriding royalty interests conveyed to the Trust pursuant to the Conveyance entitling the holder thereof to 65 percent of the Gross Proceeds derived from the Company Interests.

     “Sonat Marketing” means Sonat Marketing Company, a Delaware Corporation.

     “Subject Gas” means Gas attributable to the Company Interests.

     “Treasury Regulations” means the United States treasury regulations promulgated under the Code.

     “Trust” means Dominion Resources Black Warrior Trust, a Delaware business trust formed pursuant to the Trust Agreement.

     “Trust Agreement” means the Trust Agreement dated as of May 31, 1994, among the Company, as grantor, Dominion Resources, the Delaware Trustee and the Trustee, as amended by instrument dated as of June 27, 1994, copies of which are filed as exhibits to this Form 10-K.

     “Trustee” means Bank of America, N.A., as successor to NationsBank of Texas, N.A. References in this Form 10-K to U.S. Trust, Bank of America Private Wealth Management also describe the legal entity Bank of America, N.A.

     “Underlying Properties” means the natural gas properties in which the Company has an interest located in the Black Warrior Basin, Tuscaloosa County, Alabama insofar as such properties include the Pottsville Formation.

     “Unitholder” means a holder of Units evidencing beneficial interest in the Trust.

     “Units” means the 7,850,000 units of beneficial interest issued by, and evidencing the entire beneficial interest in, the Trust.

     “Working Interest” generally refers to the lessee’s interest in an oil, gas or mineral lease which entitles the owner to receive a specified percentage of oil and gas production, but requires the owner of such Working Interest to bear such specified percentage of the costs to explore for, develop, produce and market such oil and gas.

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DESCRIPTION OF THE TRUST

     Dominion Resources Black Warrior Trust is a Delaware business trust formed under the Delaware Business Trust Act, Title 12, Chapter 38 of the Delaware Code, Section 3801 et seq. (the “Delaware Code”). The following information is subject to the detailed provisions of the Trust Agreement and the Conveyance, copies of which 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 the material provisions of the Trust Agreement.

Creation and Organization of the Trust

     The Trust was initially created by the filing of its Certificate of Trust with the Delaware Secretary of State on May 31, 1994. In accordance with the Trust Agreement, the Company contributed $1,000 as the initial corpus of the Trust. On June 28, 1994, the Royalty Interests were conveyed to the Trust by the Company pursuant to the Conveyance, in consideration for the issuance to the Company of all 7,850,000 of the authorized Units in the Trust. The Company transferred all the Units to its parent, Dominion Energy, Inc., a Virginia corporation (“Dominion Energy”), which in turn transferred all the Units to its parent, Dominion Resources. Dominion Resources sold an aggregate of 6,904,000 Units to the public through various underwriters (the “Underwriters”) in June and August 1994 in the initial public offering of the Units (the “Initial Public Offering”) and sold the remaining 946,000 Units to the public through certain of the Underwriters in June 1995 pursuant to Post-Effective Amendment No. 1 to the Form S-3 Registration Statement relating to the Units (the “Secondary Public Offering” and, collectively with the Initial Public Offering, the “Public Offerings”).

     On July 31, 2007, subsidiaries of HighMount purchased certain assets from subsidiaries of Dominion Resources, including all of the equity interests in the Company which owns the interests in the Underlying Properties that are burdened by the Trusts’ Royalty Interests. The Trust continues to have ownership in the Royalty Interests burdening the Underlying Properties and such sale did not affect that ownership. In connection with the sale, Dominion Resources assigned its rights and obligations under the Trust Agreement governing the Trust and the Administrative Services Agreement to HighMount Alabama, a subsidiary of HighMount.

Assets of the Trust

     The only assets of the Trust, other than cash and temporary investments being held for the payment of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests. The Royalty Interests consist of overriding royalty interests burdening the Company’s interest in the Underlying Properties. The Royalty Interests generally entitle the Trust to receive 65 percent of the Company’s Gross Proceeds. The Royalty Interests are non-operating interests and bear only expenses related to property, production and related taxes (including severance taxes). See “Properties—The Royalty Interests.”

Duties and Limited Powers of the Trustee and the Delaware Trustee

     Under the Trust Agreement, the Trustee has all powers to collect the payments attributable to the Royalty Interests and to pay all expenses, liabilities and obligations of the Trust. The Trustee has the discretion to establish a cash reserve for the payment of any liability

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that is contingent or uncertain in amount or that otherwise is not currently due and payable. The Trustee is entitled to cause the Trust to borrow money from any source, including from the entity serving as Trustee (provided that the entity serving as Trustee shall not be obligated to lend to the Trust), to pay expenses, liabilities and obligations that cannot be paid out of cash held by the Trust. To secure payment of any such indebtedness (including any indebtedness to the 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 Trustee, must be similar to the terms that the Trustee would grant to a similarly-situated commercial customer with whom it did not have a fiduciary relationship, and the Trustee 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 Delaware Trustee has only such powers as are set forth in the Trust Agreement or are required by law and is not empowered to take part in the management of the Trust.

     The Royalty Interests are passive in nature and neither the Trustee nor the Delaware Trustee has any control over or any responsibility relating to the operation of the Underlying Properties. The Company does not have any contractual commitment to the Trust to develop further the Underlying Properties or to maintain its ownership interest in any of the Underlying Properties. The Company may sell the Company Interests subject to and burdened by the Royalty Interests and, absent certain conditions having been met, with the continuing benefit of HighMount Alabama’s assurances. For a description of the Underlying Properties, the Royalty Interests and other information relating to such properties, see “Properties—The Royalty Interests.”

     The Trust Agreement authorizes the Trustee to take such action as in its judgment is necessary, desirable or advisable to best achieve the purposes of the Trust. The Trustee is empowered by the Trust Agreement to employ consultants and agents (including the Company) and to make payments of all fees for services or expenses out of the assets 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 the 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 production or the proceeds of production from the Underlying Properties, which, with respect to the Trust, are free of any operating rights, expenses or obligations. 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 deposit 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 and cash proceeds therefrom 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 provided the interest rate paid equals the interest rate paid by the Trustee on similar deposits.

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     The Trust has no employees. Administrative functions are performed by the Trustee.

Resignation of Trustees

     The Trustee and the Delaware Trustee may resign at any time upon 60 days’ prior written notice or be removed, with or without cause, by a vote of not less than a majority of the outstanding Units, provided in each case that a successor trustee has been appointed and has accepted its appointment. Any successor must be a bank or trust company meeting certain requirements, including having capital, surplus and undivided profits of at least $100,000,000, in the case of the Trustee, and $20,000,000, in the case of the Delaware Trustee.

Transfer of Royalty Interests

     Prior to the termination of the Trust, the Trustee is not authorized to sell or otherwise dispose of all or any part of the Royalty Interests. The Trustee is authorized and directed to sell and convey the Royalty Interests without Unitholder approval upon termination of the Trust. No Unitholder approval for sales or dispositions upon termination is required even though they may constitute a disposition of all or substantially all the assets of the Trust. Any sales upon termination may be made to HighMount Alabama or its affiliates. See “—Termination and Liquidation of the Trust.”

Liabilities of the Trust

     Because of the passive nature of the Trust assets and the restrictions on the activities of the Trustee, the only liabilities the Trust has incurred are those for routine administrative expenses, such as trusteeship fees and accounting, engineering, legal and other professional fees and the administrative services fee paid to HighMount Alabama. 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 Tax Considerations.”

Liabilities of the Trustee and the Delaware Trustee

     Each of the Trustee and the Delaware Trustee may act in its discretion and is personally or individually liable only for fraud or acts or omissions in bad faith or that constitute gross negligence (and for taxes, fees and other charges on, based on or measured by any fees, commissions or compensation received pursuant to the Trust Agreement) 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 Trustee and the Delaware Trustee (and their respective agents) is indemnified by HighMount Alabama and from the Trust assets for certain environmental liabilities, and for any other liability, expense, claim, damage or other loss incurred in performing its duties, unless resulting from gross negligence, fraud or bad faith (each of the Trustee and the Delaware Trustee is 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; provided that the Trustee and the Delaware Trustee are generally required to first be indemnified from the Trust assets before seeking indemnification from HighMount Alabama. HighMount Alabama also has agreed to indemnify the Trustee and the Delaware Trustee against liabilities under certain securities laws. Neither the Trustee nor the Delaware Trustee is entitled to

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indemnification from Unitholders (except in connection with lost or destroyed Unit certificates). Insofar as indemnification for liabilities arising under the Securities Act of 1933, as amended (the “Securities Act”), is permitted to the Trustee pursuant to the foregoing provisions, the Trustee has been informed that in the opinion of the Securities and Exchange Commission (the “SEC”), such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable.

Termination and Liquidation of the Trust

     The Trust will terminate upon the occurrence of: (i) an affirmative vote of the holders of not less than 66 percent of the outstanding Units to terminate the Trust; (ii) such time as the ratio of the cash amounts received by the Trust attributable to the Royalty Interests in any calendar quarter to administrative costs of the Trust for such calendar quarter is less than 1.2 to 1.0 for two consecutive calendar quarters; or (iii) March 1 of any year if it is determined, based on a reserve report as of December 31 of the prior year prepared by a firm of independent petroleum engineers mutually selected by the Trustee and the Company, that the net present value (discounted at 10 percent) of estimated future net revenues from proved reserves attributable to the Royalty Interests is equal to or less than $5 million (as applicable, the “Termination Date”). Upon such occurrence causing the Trust to terminate, the remaining assets of the Trust will be sold, the net proceeds of the sale will be distributed to Unitholders and the Trust will be wound up and a certificate of cancellation filed.

     Upon the termination of the Trust, the Trustee will use its best efforts to sell any remaining Royalty Interests then owned by the Trust for cash pursuant to the procedures described in the Trust Agreement. The Trustee will retain a nationally recognized investment banking firm (the “Advisor”) on behalf of the Trust who will assist the Trustee in selling the remaining Royalty Interests. The Company has the right, but not the obligation, within 60 days following the Termination Date, to 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 the Company, the Trustee will decide, based on the recommendation of the Advisor, to either (i) accept such offer (in which case no sale to the Company will be made unless a fairness opinion is given by the Advisor that the purchase price is fair to Unitholders) or (ii) defer action on the offer for approximately 60 days and seek to locate other buyers for the remaining Royalty Interests. If the Trustee defers action on the Company’s offer, the offer will be deemed withdrawn and the Trustee will then use its best efforts, assisted by the Advisor, to locate other buyers for the Royalty Interests. At the end of the 120-day period following the Termination Date, the Trustee is required to notify the Company of the highest of any other offers acceptable to the Trustee (which must be an all-cash offer) received during such period (such price, net of any commissions or other fees payable by the Trust, the “Highest Acceptable Offer”). The Company then has the right (whether or not it made an initial offer), but not the obligation, to purchase all remaining Royalty Interests for a cash purchase price computed as follows: (i) if the Highest Acceptable Offer is more than 105 percent of the Company’s original offer (or if the Company 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 the Company’s original 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 the Company to submit another offer for consideration by the Trustee and may accept or reject such offer.

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

     In the event that the Company does not purchase the Royalty Interests, the Trustee may accept any offer for all or any part of the Royalty Interests as it deems to be in the best interests of the Trust and Unitholders and may continue, for up to one calendar year after the Termination Date, to attempt to locate a buyer or buyers of the remaining Royalty Interests in order to sell such interests in an orderly fashion. If the 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 a public auction, which sale may be to the Company or any of its affiliates.

     The Company’s purchase rights, as described above, may be exercised by the Company and each of its successors in interest and assigns. The Company’s purchase rights are fully assignable by the Company to any person or entity. 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 Trust may terminate without Unitholder approval. Unitholders are not entitled to any rights of appraisal or similar rights in connection with the termination of the Trust. The sale of the remaining Royalty Interests and the termination of the Trust will be taxable events to the Unitholders. Generally, a Unitholder will realize gain or loss equal to the difference between the amount realized on the sale and 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. Other federal and state tax issues concerning the Trust are discussed herein under “Business – Federal Income Tax Considerations” and “Business – 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 Royalty Interests and the termination of the Trust.

Arbitration and Actions by Unitholders

     Pursuant to the Trust Agreement and the Assignment and Assumption Agreement, any dispute, controversy or claim that may arise between or among HighMount Alabama or the Company, on the one hand, and the Trustee, the Delaware Trustee or the Trust, on the other hand, in connection with or otherwise relating to the Trust Agreement or the Conveyance or the application, implementation, validity or breach thereof or any provision thereof, shall be settled by final and binding arbitration in Dallas, Texas in accordance with the Rules of Practice and Procedure for the arbitration of commercial disputes of Judicial Arbitration & Mediation Services, Inc. (or any successor thereto) then in effect. The Administrative Services Agreement also includes a provision that will require HighMount Alabama and the Trustee and the Trust to submit any dispute regarding such contract to alternative dispute resolution before litigating such matter.

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     The Trust Agreement requires under certain circumstances that the Trustee and the Trust pursue any claims against HighMount Alabama and the Company with respect to any breach by HighMount Alabama and the Company of the terms of the Conveyance or the Trust Agreement (and requires that any such claims be brought in arbitration), without the joinder of any Unitholder. The Trust Agreement does not provide for any procedure allowing Unitholders to bring an action on their own behalf to enforce the rights of the Trust under the Conveyance and, except in the case of the failure of the Trustee to enforce certain performance obligations of HighMount Alabama to the Trust, does not provide for any procedure allowing Unitholders to direct the Trustee to bring an action on behalf of the Trust to enforce the Trust’s rights under the Conveyance. Each Unitholder has a statutory right, however, under Section 3816 of the Delaware Code to bring a derivative action in the Delaware Court of Chancery on behalf of the Trust to enforce the rights of the Trust if the Trustee has refused to bring the action or if an effort to cause the Trustee to bring the action is not likely to succeed. The procedures for the arbitration of disputes enumerated in the Trust Agreement neither bar nor restrict the statutory right of any Unitholder under Section 3816 of the Delaware Code to bring a derivative action.

     Pursuant to Section 3816 of the Delaware Code, a plaintiff in a derivative action must be a beneficial owner at the time such action is brought and (i) at the time of the transaction subject to such complaint or (ii) the Unitholder’s status as a beneficial owner must have devolved upon it by operation of law or pursuant to the terms of the governing instrument of the Trust from a person or entity who was a beneficial owner at the time of the transaction giving rise to the complaint. If a derivative action is successful, in whole or in part, or if anything is received by the Trust as a result of a judgment, compromise or settlement of any such action, the Delaware Chancery Court may award the plaintiff reasonable expenses, including reasonable attorney’s fees. If any award is so received by the plaintiff, the Delaware Chancery Court will make such award of the plaintiff’s expenses payable out of those proceeds and direct the plaintiff to remit to the Trust the remainder thereof. If the proceeds are insufficient to reimburse the plaintiff’s reasonable expenses in bringing the derivative action, the Delaware Chancery Court may direct that any such award of the plaintiff’s expenses or a portion thereof be paid by the Trust. The rights of Unitholders to bring a derivative action on behalf of the Trust provided pursuant to the Trust Agreement and Section 3816 of the Delaware Code are substantially similar to the derivative rights afforded stockholders under Section 327 of Chapter 8 of the Delaware General Corporation Law and applicable Delaware case law.

     In the event that any Unitholder was successful in bringing a derivative action on behalf of the Trust to enforce rights on behalf of the Trust against HighMount Alabama or the Company, then such Unitholder could, on behalf of the Trust, pursue such rights against HighMount Alabama or the Company, as the case may be, in the Delaware Chancery Court. The Trust Agreement does not require, and expressly provides that it shall not be construed to require, arbitration of a claim or dispute solely between the Trustee and the Delaware Trustee or of any claim or dispute brought by any person or entity, including, without limitation, any Unitholder (whether in its own right or through a derivative action in the right of the Trust) who is not a party to the Trust Agreement.

     The right of a Unitholder to bring a derivative action on behalf of the Trust with respect to HighMount Alabama’s obligation to cure certain deficiencies under the Trust Agreement is subject to the restriction that such right may only be exercised by Unitholders owning of record not less than 25 percent of the Units then outstanding (treated as a single class) and then only

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absent action by the Trustee to enforce any such obligation within 10 days following receipt by the Trustee of a written request served upon the Trustee by such Unitholders to take such action. In such an event, Unitholders owning of record not less than 25 percent of the Units then outstanding may, acting as a single class and on behalf of the Trust, seek to enforce such obligations. See “Properties—The Royalty Interests— HighMount Alabama’s Assurances.”

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 7,850,000 Units outstanding. The Trust may not issue additional Units.

Distributions and Income Computations

     The Trustee determines for each calendar 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 attributable to production from the Royalty Interests during such calendar quarter, provided that such cash is received by the Trust on or before the last business day prior to the 45th day following the end of such calendar quarter, plus the amount of interest expected by the Trustee to be earned on such cash proceeds during the period between the date of receipt by the Trust of such cash proceeds and the date of payment to the Unitholders of such Quarterly Distribution Amount, plus all other cash receipts of the Trust during such calendar quarter (to the extent not distributed or held for future distribution as a Special Distribution Amount (as defined herein) or included in the previous Quarterly Distribution Amount) (which might include 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 calendar quarter and not taken into account in determining a prior Quarterly Distribution Amount, subject to adjustments for changes made by the Trustee during such calendar quarter in any cash reserves established for the payment of contingent or future obligations of the Trust. An amount that is not included in the Quarterly Distribution Amount for a calendar quarter because such amount is received by the Trust after the last business day prior to the 45th day following the end of such calendar quarter shall be included in the Quarterly Distribution Amount for the next calendar quarter. The Quarterly Distribution Amount for each calendar quarter will be payable to Unitholders of record on the 60th day following the end of such calendar quarter, unless such day is not a business day in which case the record date will be the next business day thereafter. The Trustee will distribute the Quarterly Distribution Amount for each calendar quarter on or prior to 70 days after the end of such calendar quarter to each person who was a Unitholder of record on the record date for such calendar quarter.

     The Royalty Interests will be sold in whole or in part upon termination of the Trust. Any proceeds from sales of the Royalty Interests, plus any interest expected by the Trustee to be earned thereon, less liabilities and expenses of the Trust and amounts used for cash reserves, will be distributed to Unitholders of record on the record date established for such distribution. A special distribution will be made of undistributed cash proceeds and other amounts received by the Trust aggregating in excess of $10,000,000, plus the amount of interest expected by the Trustee to be earned on such cash proceeds during the period between the date of receipt by the

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Trust of such cash proceeds and the date of payment to the Unitholders of such special distribution (a “Special Distribution Amount”). The record date for distribution of a Special Distribution Amount will be the 15th day following receipt of amounts aggregating a Special Distribution Amount by the Trust (unless such day is not a business day in which case the record date will be the next business day thereafter) unless such day is within 10 days prior to 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. Distributions to Unitholders will be no later than 15 days after the Special Distribution Amount record date.

Conditional Right of Repurchase

     The Trust Agreement provides that Dominion Resources (and any of its successors and affiliates) has the right to repurchase all (but not less than all) outstanding Units at any time at which 15 percent or less of the outstanding Units are owned by persons or entities other than Dominion Resources and its affiliates. Subject to the following sentence, any such repurchase would be at a price equal to the greater of (i) the highest price at which Dominion Resources or any of its affiliates acquired Units during the 90 days immediately preceding the date (the “Determination Date”) that is three New York Stock Exchange (“NYSE”) trading days prior to the date on which notice of such exercise is delivered to the Unitholders and (ii) the average closing price of Units on the NYSE for the 30 trading days immediately preceding the Determination Date. If Dominion Resources or any of its affiliates acquires Units (other than an acquisition from Dominion Resources or any affiliate) during the period that is three NYSE trading days after the Determination Date at a price per Unit greater than that at which an acquisition was made during the 90-day period referred to in clause (i) of the preceding sentence, then for purposes of clause (i) of the preceding sentence the highest price used therein will be such greater price. Any such repurchase would be conducted in accordance with applicable federal and state securities laws.

     In the event that Dominion Resources elects to purchase all Units, Dominion Resources and the Trustee will, prior to the date fixed for purchase, give all Unitholders of record not less than 15 days’ nor more than 60 days’ written notice specifying the time and place of such repurchase, calling upon each such Unitholder to surrender to Dominion Resources on the repurchase date at the place designated in such notice its certificate or certificates representing the number of Units specified in such notice of repurchase. On or after the repurchase date, each holder of Units to be repurchased must present and surrender its certificates for such Units to Dominion Resources at the place designated in such notice and thereupon the purchase price of such Units will be paid to or on the order of the person or entity whose name appears on such certificate or certificates as the owner thereof. In no event may fewer than all of the outstanding Units represented by the certificates be repurchased (except for any Units held by Dominion Resources and any of its affiliates).

     If Dominion Resources and the Trustee give a notice of repurchase and if, on or before the date fixed for repurchase, the funds necessary for such repurchase are set aside by Dominion Resources, separate and apart from its other funds in trust for the pro rata benefit of the holders of the Units so noticed for repurchase, then, notwithstanding that any certificate for such Units has not been surrendered, at the close of business on the repurchase date the holders of such Units shall cease to be Unitholders and shall have no interest in or claims against Dominion Resources, the Company, the Trust, the Delaware Trustee or the Trustee by virtue thereof and

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shall have no voting or other rights with respect to such Units, except the right to receive the purchase price payable upon such repurchase, without interest thereon and without any other distributions for record dates after the date of notice of repurchase, upon surrender (and endorsement, if required by Dominion Resources) of their certificates, and the Units evidenced thereby shall no longer be held of record in the names of such Unitholders. Subject to applicable escheat laws, any monies so set aside by Dominion Resources and unclaimed at the end of two years from the repurchase date shall revert to the general funds of Dominion Resources. After such reversion, the holders of such Units so noticed for repurchase could look only to the general funds of Dominion Resources for the payment of the purchase price. Any interest accrued on funds so deposited would be paid to Dominion Resources from time to time as requested by Dominion Resources.

     If Dominion Resources exercises and consummates its right of repurchase, then, at its option, it may cause the Trust to be terminated by providing written notice thereof to the Trustee and the Delaware Trustee. Within 30 days following written notice of Dominion Resources’ decision to terminate the Trust, the Trustee must cause any remaining Royalty Interests (and, subject to the rights of Unitholders with respect to the receipt of distributions for which a record date has been determined, all proceeds of production attributable to the Royalty Interests) and any other assets of the Trust to be conveyed to Dominion Resources or its assignee (subject to the right of such trustees to create reasonable reserves in connection with the liquidation of the Trust).

     Dominion Resources assigned its rights under the Trust Agreement to HighMount Alabama pursuant to the Assignment and Assumption Agreement.

Possible Divestiture of Units

     The Trust Agreement imposes no restrictions based on nationality or other status of Unitholders. The Trust Agreement provides, however, 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 will 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, subject to a maximum retention period of two years or such shorter period as shall be permitted by applicable laws.

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Periodic Reports

     The Trustee causes a reserve report to be prepared for the Trust (by a firm of independent petroleum engineers mutually selected by the Trustee and the Company) each year showing estimated proved natural gas reserves and other reserve information attributable to the Royalty Interests as of December 31 of such year. Such reserve reports show estimated future net revenues and the net present value (discounted at 10 percent) of the estimated future net revenues (using the average market price over the prior 12-month period or applicable contract price as of December 31 as appropriate) from proved reserves attributable to the Royalty Interests. The costs of the reserve reports are paid by the Trust and constitute an administrative expense. The Trustee also provides to HighMount Alabama and the Company, within 15 days after the end of each calendar quarter, a written itemized report showing all administrative costs of the Trust paid during such quarter.

     Within 75 days following the end of each of the first three calendar quarters of each calendar year, the Trustee mails to each person or entity who was a Unitholder of record (i) on the record date for each such calendar quarter and (ii) on a Special Distribution Amount record date occurring during such quarter, if any, a report showing in reasonable detail the assets, liabilities, receipts and disbursements of the Trust for such calendar quarter. Within 120 days following the end of each fiscal year, the Trustee mails to Unitholders of record as of a date to be selected by the Trustee an annual report containing audited financial statements, including reserve information relating to the Trust and the Royalty Interests.

     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 person or entity who was a Unitholder of record (i) on the record date for each such calendar quarter and (ii) on a Special Distribution Amount record date occurring during such quarter, if any, a report that shows in reasonable detail information to permit each Unitholder to make all calculations reasonably necessary for tax purposes. The Trustee treats all income, credits and deductions recognized during each calendar quarter during the term of the Trust 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 page 22 regarding certain reporting requirements imposed upon middlemen under Treasury Regulations 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, and upon reasonable prior notice, to examine and inspect records of the Trust and the Trustee and the Delaware Trustee.

Voting Rights of Unitholders

     While Unitholders have certain voting rights as provided in the Trust Agreement, such rights differ from and are more limited than those of stockholders of a corporation for profit. For example, there is no requirement for annual meetings of Unitholders or for annual or other periodic reelection of the Trustee.

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     Meetings of Unitholders may be called by the Trustee or by Unitholders owning not less than 10 percent of the outstanding Units. In addition, the Delaware Trustee may call such a meeting but only for the purpose of appointing a successor to it upon its resignation. All meetings of Unitholders will be held in Dallas, Texas. Written notice of every such meeting setting forth the time and place of the meeting and the matters proposed to be acted upon will be given not more than 60 days nor less than 20 days before such meeting is to be held to all of the Unitholders of record at the close of business on a record date selected by the Trustee, which record date will not be more than 60 days before the date of such meeting. The presence in person or by proxy of Unitholders representing a majority of the outstanding Units is necessary to constitute a quorum. Each Unitholder is entitled to one vote for each Unit owned by such Unitholder. The Trustee will call such meetings to consider amendments, waivers, consents and other changes relating to the Conveyance, if requested in writing by the Company or HighMount Alabama. No matter other than that stated in the notice of the Unitholder meeting will be voted on and no action by the Unitholders may be taken without a meeting.

     Generally, amendments to the Trust Agreement require approval of a majority of the outstanding Units (except that amendments of required voting percentages requires approval of at least 80 percent of the outstanding Units), but no provision of the Trust Agreement may be amended that would (i) increase the power of the Trustee or the Delaware Trustee to engage in business or investment activities or (ii) alter the rights of the Unitholders as among themselves. Without the written consent of HighMount Alabama and the approval of not less than 66 2/3 percent of the outstanding Units, no provision of the Trust Agreement may be amended with respect to (a) the sale or disposition of all or any part of the Trust estate, including the Royalty Interests, except as specifically provided in the Trust Agreement; (b) termination of the Trust and the disposition of Trust assets upon liquidation of the Trust; or (c) the Company’s right of first refusal with respect to the purchase of any remaining Royalty Interests upon termination of the Trust. Without the written consent of HighMount Alabama and the approval of a majority of the outstanding Units, no amendment may be made to the Trust Agreement that would alter HighMount Alabama’s conditional right to repurchase all outstanding Units at any time at which 15 percent or less of the outstanding Units is owned by persons or entities other than HighMount Alabama or its affiliates. Additionally, any amendment that increases the obligations, duties or liabilities of or affects the rights of the Trustee or the Delaware Trustee must be consented to by such entity. The Trustee, the Delaware Trustee, HighMount Alabama and the Company may, without approval of 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 interests of Unitholders. In addition, (i) HighMount Alabama may direct the Trustee to change the name of the Trust without approval of Unitholders and (ii) in the event that a business purpose of the Trust is found or deemed to exist by any taxing or other authority on which finding any taxation authority might rely, the Trustee is authorized to amend or delete and, subject to the receipt of an opinion of counsel reasonably satisfactory to the Trustee, the Trustee, the Delaware Trustee, HighMount Alabama and the Company will amend or delete any provision of the Trust Agreement or take such other action as may be necessary to eliminate such business purpose, without approval of Unitholders. Removal of the Trustee and the Delaware Trustee, approval of amendments, waivers, consents and other changes relating to the Conveyance and the approval of the merger or consolidation of the Trust into one or more entities require approval of a majority of the outstanding Units. Except as set forth under “Description of the Trust—Termination and

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Liquidation of the Trust,” all other actions may be approved by a majority vote of the Units represented at a meeting at which a quorum is present or represented.

Liability of Unitholders

     Consistent with Delaware law, the Trust Agreement provides that Unitholders will have the same limitation on liability as is accorded under Delaware law 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

     BNY Mellon Shareholder Services served as transfer agent and registrar for the Units until May 31, 2009. Subsequent to that date, American Stock Transfer & Trust Company became the transfer agent and registrar for the Units.

Website/SEC Filings

     The Trust maintains an Internet Website at www.dom-dominionblackwarriortrust.com, and will provide 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 such material is filed with or furnished to the SEC.

FEDERAL INCOME TAX CONSIDERATIONS

     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 section entitled “Federal Income Tax Consequences” appearing in the Prospectus sets forth a discussion of the material federal income tax matters of general application of the acquisition, ownership and sale of the Units acquired in the Public Offerings 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 section of the 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 Offerings, Dominion Resources and the Underwriters received certain opinions of special counsel (“Special Counsel”) to Dominion Resources (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 either of the Public Offerings. Each of these opinions was based on provisions of the Code existing as of June 28, 1994, with respect to the opinions given in connection with the Initial Public Offering, and as of June 8, 1995, with respect to the opinions given in connection with the Secondary Public Offering, and existing and proposed regulations thereunder, administrative rulings and court decisions as of such dates, all of which are subject to changes that may or may not be retroactively applied. Some of the applicable provisions of the Code have not been interpreted by the courts or the Internal Revenue Service (“IRS”). In addition, such opinions were based on various

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representations as to factual matters made by the Company and Dominion Resources in connection with the Public Offerings. In addition, such opinions were expressly limited in their application to investors purchasing Units in each of such Public Offerings and, as a result, provide no assurance to investors not purchasing Units in one of the Public Offerings.

     Neither the Trustee, the Delaware Trustee, nor counsel to the 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 Offerings, no ruling was requested by Dominion Resources, as the sponsor of the Trust, the Trustee or the Delaware Trustee from the IRS with respect to any matter affecting the Trust or Unitholders. No assurance can be provided that the opinions of Special Counsel (which do not bind the IRS) will not be challenged by the IRS or will be sustained by a court if so challenged.

Summary of Certain Federal Income Tax Consequences

     The following summary of certain federal income tax consequences of acquiring, owning and disposing of Units is based on the opinions of Special Counsel to Dominion Resources on federal income tax matters, which are set forth in the Prospectus, and is qualified in its entirety by express reference to the sections of the Prospectus identified in the first paragraph of this “Federal Income Tax Considerations” section. Although the Trustee 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 address the tax issues potentially affecting Unitholders acquiring Units other than by purchase through either of the Public Offerings. 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 each such Unitholder’s taxable year and method of accounting and without regard to the taxable year or method of accounting employed by the Trust.

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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.
Treatment of the Royalty Interests	Each Royalty Interest is a nonoperating economic interest in an Underlying Property because it is a right to a fixed percentage of the gross proceeds from the sale of gas as, if and when produced from such properties, the right endures for the economic life of the burdened reserves and the right is not required to bear any cost of developing or producing such gas.
Unitholder’s Depletion Allowance	Each Unitholder is entitled to amortize the cost of the Units through cost depletion over the life of the Royalty Interests 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 Royalty Interests 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.

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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 Code, 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 Treasury Regulations govern dispositions of property after March 13, 1995. The IRS likely will 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 Code 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 and 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 third paragraph under “Description of Units—Periodic Reports.”

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WHFIT Reporting Requirements Some Trust Units are held by middlemen, as such term is broadly defined in 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: 56-0906609, 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 Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.dom-dominionblackwarriortrust.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 Treasury Regulations with respect to such Trust Units, including the issuance of IRS Forms 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.

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ERISA CONSIDERATIONS

     The section entitled “ERISA Considerations” appearing in the Prospectus sets forth certain information regarding the applicability of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), and the Code to pension, profit-sharing and other employee benefit plans and to individual retirement accounts (collectively, “Qualified Plans”). A copy of this section of the 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 Code 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.

Alabama Income Tax

     All revenues attributable to the Royalty Interests are derived from sources within the State of Alabama. Alabama imposes an income tax on individuals, corporations (subject to certain exceptions for S corporations) and certain other entities that are residents of, conduct business in, or derive income from sources within Alabama. Under general rules of application, both resident and nonresident Unitholders would be required to file annual Alabama income tax returns and pay Alabama income taxes with respect to any income received from the Trust and would be subject to penalties for failure to comply with those rules.

     The Alabama Department of Revenue (the “DOR”) has issued a letter ruling that permits the Trust to file a “composite income tax return” on behalf of all Unitholders who are not residents of Alabama. The filing of the composite income tax return and acceptance of the return by DOR will relieve those nonresident Unitholders of any obligation to file Alabama state income tax returns. The Trust filed for each of the years 1995-2008 composite income tax returns with the DOR on behalf of all Nonresident Unitholders (defined below), and intends to file a composite return for 2009 and each year thereafter for so long as the composite return does not report any taxable income for Alabama state income tax purposes. Based on certain assumptions, the composite income tax return to be filed by the Trust on behalf of Nonresident Unitholders will show a net taxable loss for 2009. Accordingly, no Alabama state income tax is due under the 2009 return.

     No assurance can be given, however, that the DOR will accept the assumptions used by the Trust in preparing and filing the composite income tax return for any year and determining the composite taxable income or loss thereunder for Alabama state income tax purposes. If all or a portion of those assumptions are not acceptable to the DOR, the DOR may require the Trust to recompute and refile one or more composite income tax returns based on different assumptions

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acceptable to the DOR. If the composite income tax return for 2009 (or any other tax year) as initially filed by the Trust is not accepted as filed by the DOR, the Trust may decide not to refile a composite income tax return either (i) because the Trust would have net Alabama taxable income for that year as a result of the assumptions required by the DOR or (ii) because the refiling of the composite income tax return imposes an unreasonable burden on the Trust in the judgment of the Trustee (based on its sole discretion). In that event, each Nonresident Unitholder would be required to file a separate Alabama state income tax return and pay any Alabama state income tax due as well as any penalties and interest due thereon. For purposes of the filing of the composite income tax return for any taxable year, “Nonresident Unitholders” will consist of those Unitholders to whom the Trust has provided an individualized tax information letter (together with its tax information booklet) for such tax year that shows a mailing address outside the State of Alabama. All other Unitholders will be treated by the Trust for purposes of the filing of the composite income tax return as “Resident Unitholders.”

     The filing of the composite income tax return by the Trust does not relieve any resident of the State of Alabama or any Resident Unitholder from the obligation to file an Alabama state income tax return individually (and pay Alabama state income tax thereon, if any) with respect to the revenues and expenses attributable to the Royalty Interests. In light of the foregoing, each Unitholder should consult his tax adviser regarding the requirements for filing state income tax returns for his state of residence and Alabama.

Alabama Business Privilege Tax

     Alabama previously imposed a franchise tax on domestic corporations and foreign corporations doing business in Alabama, under a broad definition of “corporation” in the state constitution, based on the amount of a corporation’s “capital employed” in the state. In reliance upon the representations and assumptions set forth in the Prospectus and on a private letter ruling issued June 10, 1994, by the DOR as to the offering of the Units, special Alabama tax counsel to the Company opined in connection with each of the Public Offerings that the Trust was not subject to Alabama franchise tax. Although the Alabama Commissioner of Revenue has the authority to revoke retroactively DOR rulings under certain limited circumstances, special Alabama tax counsel did not believe, based on the above representations and assumptions, that those circumstances existed with respect to the Company’s private letter ruling. HighMount Alabama agreed to indemnify the Trust against any resulting Alabama franchise tax imposed on the Trust.

     In 2000, the Alabama franchise tax was repealed and replaced with the Alabama business privilege tax (the “BPT”), which imposes an annual privilege tax on corporations, limited liability entities, and disregarded entities (as those terms are statutorily defined in Alabama’s tax code) doing business in Alabama or organized under Alabama law. The DOR issued a revenue ruling in 2002 holding that the BPT applied to a grantor trust. Therefore, the Trust files BPT returns and pays the applicable tax.

Alabama Severance Taxes

     Alabama levies severance taxes on the removal of certain natural resources. Statewide severance taxes are collected from oil, gas, coal, forest products and iron ore. Additional severance taxes are collected by certain counties on oil, gas, coal, stone, rock, clay, sand and

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gravel. Therefore, the Trust, as owner of the Royalty Interests, bears its proportionate share of Alabama state and county severance taxes. To the extent there is an increase in the amount of severance taxes, the cash distribution amount payable to Unitholders will decrease.

Other Alabama Taxes

     The Trust has been structured to cause the Units to be treated as interests in intangible personal property rather than as interests in real property for certain Alabama state law purposes, other than income and business privilege taxation. If the Units are held to be real property or as interests in real property under the laws of Alabama, Unitholders could be subject to Alabama probate laws, and estate and similar taxes, whether or not they are residents of Alabama.

REGULATION AND PRICES

Regulation of Natural Gas

     Certain aspects of production, transportation, marketing and sale of natural gas from the Underlying Properties may be subject to federal and state governmental regulation, including regulation of transportation tariffs charged by pipelines, taxes, the prevention of waste, the conservation of natural gas, pollution controls and various other matters.

     Sales of natural gas produced from the Underlying Properties are considered 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 the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act and the Natural Gas Policy Act of 1978. In past years, FERC has adopted regulatory policy changes that have affected the transportation of natural gas from the wellhead to the market. Interstate pipelines no longer perform a merchant function. Gas producers now sell gas to end users or market accumulators rather than into the system supply of an interstate pipeline who would then resell it. Transportation of gas on interstate pipelines is now on an “open access” basis and interstate pipelines have been required to unbundle their services with the result that customers now only pay for the services they require. The interstate pipeline connected to the gathering system for the Underlying Properties is subject to the regulations described above.

     On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978 or FERC rules, regulations or orders thereunder. In the past, Congress has been very active in the area of natural gas regulation. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on the Underlying Properties and the Trust.

     The State Oil and Gas Board of Alabama regulates the production of natural gas, including requirements for obtaining drilling permits, the method of developing new fields, provisions for the unitization or pooling of natural gas properties, the spacing, operation,

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plugging and abandonment of wells and the prevention of waste of natural gas resources. The rate of production may be regulated, and the maximum daily production allowable from natural gas wells may be established on a market demand or conservation basis or both. Reductions in allowable production may extend the timing of recovery of reserves. Although the Trust is not aware of any pending or contemplated proceedings to change allowable rates of production from the Underlying Properties, there can be no assurances made that such changes will not be made. The Unitholders and the Trust will not have any control over such changes. Reductions in the allowable production from the Underlying Properties could affect the timing or amount of distributions to Unitholders.

Environmental Regulation

     Operations on the Underlying Properties associated with the production of natural gas are subject to numerous federal and state laws, rules and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment. Such laws, rules and regulations require the acquisition of certain permits, impose substantial liabilities for pollution resulting from exploration and production operations and may also restrict air or other pollution resulting from operations. It is possible that federal and state environmental laws and regulations will become more stringent in the future. For example, there is an increased focus by local, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change. Various regulatory bodies have announced their intent to regulate GHG emissions. It is impossible to predict what the precise effect additional regulation or legislation, or enforcement policies thereunder, could have on the operation of the Underlying Properties. However, any costs or expenses incurred by the Company 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, will be borne by the Company and not the Trust, and such costs and expenses will not be deducted in calculating Gross Proceeds. Such costs and expenses may, however, be taken into account by the Company in exercising its rights to abandon a well and may accelerate the termination of the Trust. See “Properties—The Royalty Interests—Sale and Abandonment of Underlying Properties” and “Properties—Description of the Trust—Termination and Liquidation of the Trust.”

     Water from the operations on the Underlying Properties is discharged into the Black Warrior River pursuant to a National Pollutant Discharge Elimination System permit issued by the Alabama Department of Environmental Management (“ADEM”). ADEM initially issued five permits in connection with the Underlying Properties, which were consolidated into one permit in February 1994. The ADEM permit was renewed in 1999, again in 2004, and a timely renewal application was submitted in 2009. The 2004 permit is administratively extended until such time as ADEM reviews and issues a renewal permit. It generally authorizes water disposal based upon the Black Warrior River’s minimum flow rate and maximum chloride level. The Company has advised the Trust that since 1987 water disposal from the Underlying Properties has not been disrupted.

     While the Company has informed the Trust that it believes the Underlying Properties are in material compliance with all environmental laws and regulations, such regulations have generally become more stringent and costly over time. As a royalty holder, the Trust may not be directly subject to increased costs; however, such costs may be taken into account by the Company in exercising its rights to abandon a well, which may accelerate the termination of the

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Trust. The Company has informed the Trust that it has not budgeted any money during 2010 for expenditures related to environmental remediation.

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 natural gas industry is highly competitive in all of its phases. The Company encounters competition from major oil and gas companies, independent oil and gas concerns and individual oil and gas producers and operators. Many of these competitors have greater financial and other resources than the Company. Competition may also be presented by alternative fuel sources, including heating oil, other fossil fuels and wind energy.

     Demand for natural gas production has historically been seasonal in nature and prices for natural gas fluctuate accordingly. Unseasonably warm weather and the ability of markets to access storage can cause the demand for natural gas to decrease, resulting in lower prices received by producers than when demand is higher due to seasonal weather factors. Such price fluctuations and the continuation of/return to low prices for natural gas will directly impact Trust distributions, estimates of reserves attributable to the Royalty Interests and estimated future net revenue from reserves attributable to the Royalty Interests.

     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 and the Company. 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. Additionally, lower natural gas prices may reduce the amount of gas that is economic to develop or produce from the Underlying Properties. In view of the many uncertainties affecting the supply and demand for natural gas and natural gas prices, the Trustee is unable to make reliable predictions of future gas prices, production or demand or the overall effect they will have on the Trust.

     The Trust’s revenues and distributions to Unitholders will be primarily dependent on the sales prices for Gas produced from the Underlying Properties and the quantities of Gas sold. Natural gas prices have historically been volatile and are likely to continue to be volatile. Price volatility and the risk of production curtailment make it difficult to estimate the future levels of cash distributions to Unitholders or the value of the Units. Since the termination of the Gas Purchase Agreement, a gas sales contract was entered into with SCANA Energy for base load gas for the period of November 1, 2005 through March 31, 2006. Separate gas sales contracts were entered into with Coral Energy and South Carolina Pipeline Company for the period of April 1, 2006 through October 31, 2006. A gas sales contract was entered into with ConocoPhillips for base load gas for the period of November 1, 2006 through March 31, 2007. A gas sales contract was entered into with Coral Energy for base load gas for the period of April 1, 2007 through October 31, 2007. A gas sales contract was entered into with BP Energy for base load gas for the period of November 1, 2007 through March 31, 2008. Gas sales contracts were entered into with Atmos, BP Energy and ConocoPhillips for base load gas for the period April 1, 2008 through October 31, 2008. Gas sales contracts were entered into with Atmos, BP Energy, Chevron and Sequent for base load gas for the period November 1, 2008 through March

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31, 2009. Gas sales contracts were entered into with Atmos, BP Energy, Chevron, ConocoPhillips and Sequent for base load gas for the period April 1, 2009 through October 31, 2009. Gas sales contracts were entered into with Atmos, BP Energy, Chevron and ConocoPhillips for base load gas for the period November 1, 2009 through March 31, 2010. During the terms of the above-mentioned contracts, any gas above the base load was sold on the spot market to various purchasers. The foregoing information regarding the gas purchase contracts has been provided to the Trustee by Dominion Resources and HighMount Alabama.

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Item 1A. Risk Factors.

Risks Related to the Oil and Gas Industry

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

     The Trust’s quarterly distributions are highly dependent upon the prices realized from the sale of crude oil and natural gas and a material decrease in such prices could reduce the amount of cash distributions paid to Unitholders. Crude oil and natural gas prices can fluctuate widely on a quarter-to-quarter 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 producing regions, especially the Middle East;

• worldwide economic conditions;

• weather conditions;

• the supply and price of domestic and foreign crude oil or natural gas;

• the level of consumer demand;

• the price and availability of alternative fuels;

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

• the effect of worldwide energy conservation measures; and

• the nature and extent of governmental regulation and taxation.

     When crude oil and natural gas prices decline, the Trust is affected in two ways. First, net royalties are 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 crude oil and natural gas price movements, and this reduces the predictability of future cash distributions to Unitholders.

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

     The value of the Units will depend upon, among other things, the reserves attributable to the Royalty Interests in the Underlying Properties. The calculations of proved reserves included in this Annual Report on 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 crude oil and natural gas and the future prices of crude oil and 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;

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• 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 overriding royalty interests and does not own a specific percentage of the crude oil or natural gas reserves. Ultimately, actual production, revenues and expenditures for the Underlying Properties, and therefore actual net proceeds payable to the Trust, will vary from estimates, and those variations could be material. Results of drilling, testing and production after the date of those estimates may require substantial downward revisions or write-downs of reserves.

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

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

Risks Related to the Trust and Ownership of the Units

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

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

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the market value of the Units over time. Eventually, the Royalty Interests will cease to produce in commercial quantities and the Trust will, therefore, cease to receive any distributions of net proceeds therefrom.

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 the Company or any future operator to conduct its operations, discharge its obligations, deal with regulatory agencies or comply with laws, rules and regulations, including environmental laws and regulations, in a proper manner could have an adverse effect on the net proceeds payable to the Trust. Neither the Company nor any future operators developing the Underlying Properties are under any obligation to continue operations on the Underlying Properties. Neither the Trustee nor the Unitholders have the right to replace an operator.

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

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

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

     The Company, as the operator developing the Underlying Properties, may at any time transfer all or part of its interest in any Underlying Property 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 of the Trust, but the net proceeds from the transferred property will be calculated separately and paid by the transferee. The transferee will be responsible for all of the transferor’s obligations relating to calculating, reporting and paying to the Trust the net overriding royalties from the transferred property, and the transferor will have no continuing obligation to the Trust for that property.

The obligations of HighMount Alabama to pay certain amounts if they are not paid by the Company may terminate upon a sale by the Company of its interests in the Underlying Properties or a sale by HighMount Alabama of its equity ownership interest in the Company.

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     HighMount Alabama has agreed to assume Dominion Resources’ obligations in the Trust Agreement to pay (i) all liabilities and operating and capital expenses that any Company Interests Owner becomes obligated to pay as a result of the Company Interests Owner’s obligations under the Conveyance and (ii) the obligations of the Company to indemnify the Trust and the Trustees for certain environmental liabilities. HighMount Alabama’s obligations will terminate, among other times, upon (i) the sale or other transfer by the Company of all or substantially all of its interest in the Underlying Properties or (ii) the sale or other transfer of a majority of HighMount Alabama’s direct or indirect equity ownership interests in the Company. However, in these circumstances, HighMount Alabama’s obligations will terminate only if (a) the transferee has a specified credit rating or the transferee, together with any affiliate that guarantees its obligations, does not have a rating assigned to its unsecured long-term debt from a nationally recognized statistical rating organization but has a specified net worth or (b) the transferee is approved by a majority of the Unitholders.

The Company may abandon the Underlying Properties, thereby terminating the related Royalty Interest payable to the Trust.

     The Company, as the operator developing the Underlying Properties, or any transferee thereof, may abandon any well or lease without the consent of the Trust or the Unitholders if it reasonably believes that the well or property can no longer produce in commercially economic quantities. This could result in the termination of the Royalty Interest relating to the abandoned well or lease.

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

     The Trustee must sell the Royalty Interests if the holders of 66% or more of the Units approve the sale or vote to terminate the Trust. The Trustee must also sell the Royalty Interests if the ratio of cash amounts received by the Trust attributable to the Royalty Interests in any calendar quarter to administrative costs of the Trust for such calendar quarter is less than 1.2 to 1.0 for two consecutive calendar quarters or if the net present value (discounted at 10 percent) of estimated future net revenues from proved reserves attributable to the Royalty Interests is equal to or less than $5 million. Sale of all of the Royalty Interests will terminate the Trust. The net proceeds of any sale will be distributed to Unitholders. “Business – Description of the Trust – Termination and Liquidation of the Trust” discusses the tax consequences that may result to Unitholders in the event Trust assets are sold and the Trust is terminated.

     Unitholders have limited voting rights.

     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.

     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

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royalty trusts by the SEC, the financial statements of the Trust differ from GAAP financial statements because revenues are not accrued in the month of production and cash reserves may be established for specified contingencies and deducted, which could not be accrued in GAAP financial statements.

     Unitholders May Lack Limited Liability.

     Consistent with Delaware law, the Trust Agreement provides that the Unitholders will have the same limitation on 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.

     Cash held by the Trustee is not insured by the Federal Deposit Insurance Corporation, and future royalty income may be subject to risks relating to the creditworthiness of third parties.

     Currently, cash held by the Trustee as a reserve for liabilities and for the payment of expenses and distributions to Unitholders is 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. Each Unitholder should independently assess the creditworthiness of Bank of American, 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 Trust’s future royalty income, however, may be subject to risks relating to the creditworthiness of the operators of the Underlying Properties and other purchasers of the natural gas produced from the Underlying Properties, as well as risks associated with fluctuations in the price of natural gas.

Item 1B. Unresolved Staff Comments. None.

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Item 2. Properties.

THE ROYALTY INTERESTS

     The Royalty Interests held by the Trust generally entitle the Trust to receive 65 percent of Gross Proceeds. 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 Alabama, so as to give notice of the Royalty Interests to creditors, and any transferees will 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 Alabama law.

     The following description of the material provisions of the Conveyance and the Trust Agreement is subject to and qualified by the more detailed provisions of the Conveyance and the Trust Agreement included as exhibits to this Form 10-K.

The Underlying Properties

     Black Warrior Basin. The Black Warrior Basin covers 6,000 square miles in west central Alabama and contains seven Pennsylvania-age multi-seam coal groups in the Pottsville formation: the Black Creek, Mary Lee, Pratt, Cobb, Gwin, Utley and Brookwood coal groups. The Pottsville coal formation ranges from the surface to a depth of 4,100 feet.

     Wells in the Black Warrior Basin produce natural gas from coal seam formations that have production characteristics materially different from conventional natural gas wells. The primary factor affecting recovery of gas reserves from coal seams in the Black Warrior Basin is the lowering of reservoir pressure through “dewatering” operations. In a typical coal seam gas well on the Underlying Properties, average daily natural gas production generally will increase as wells are “dewatered” until natural gas production reaches a “peak” at which time natural gas production will decline. The amount of time necessary to “dewater” a well and cause it to reach its peak production, and the ultimate level of a well’s peak production, are difficult to estimate. Since all of the 532 wells included in the Underlying Properties were producing by mid-1991, the Company believes that production from such wells is currently past its peak and will decline over the term of the Trust.

     The Royalty Interests were conveyed by the Company to the Trust out of the Company Interests. The Existing Wells are operated by Dominion Black Warrior Basin, Inc. in accordance with the Operating Agreement. See “—Operation of Properties.” The Underlying Properties comprise 34,212 gross acres of land in an area approximately 5 miles wide and 23 miles long located on the Tuscaloosa to Bankhead Lake portion of the Black Warrior Basin. Initial production began in December 1988 and consisted of eight wells. The Company acquired its interest in the Underlying Properties in December 1992. As of December 31, 2009, the Underlying Properties contained 532 wells that were producing gas, all of which were drilled prior to 1993.

     On July 31, 2007, subsidiaries of HighMount purchased certain assets from subsidiaries of Dominion Resources, including all of the equity interests in the Company which owns the interests in the Underlying Properties that are burdened by the Trusts’ Royalty Interests. The Trust continues to have ownership in the Royalty Interests burdening the Underlying Properties

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and such sale did not affect that ownership. In connection with the sale, Dominion Resources assigned its rights and obligations under the Trust Agreement governing the Trust and the Administrative Services Agreement to HighMount Alabama, a subsidiary of HighMount.

     Present Activities – Well Count and Acreage Summary. The following table shows as of December 31, 2009, the gross and net producing wells and acres for the Company Interests. The Net wells and acres are determined by multiplying the Gross Wells or acres by the Company Interests Owner’s Working Interest in the wells or acres.

	Number of Wells				Acres
	Gross		Net		Gross		Net
Company Interests		532		519		34,212		33,363

     Royalty Interests, Company Interests and Retained Interests. On June 1, 1994, the effective date of the Conveyance, the Company had an average aggregate Working Interest in the Existing Wells of approximately 98 percent, and an average aggregate net revenue interest of approximately 80 percent in the Existing Wells. The Company has not sold or otherwise disposed of any of its interest in the Company Interests since June 1, 1994. The Royalty Interests are entitled to approximately 52 percent of the net revenue from natural gas produced and sold from the Underlying Properties, and the interests (the “Retained Interests”) of the Company in the Underlying Properties (after giving effect to the Royalty Interests) entitle the Company to receive approximately 28 percent of the net revenue from the natural gas produced and sold from the Underlying Properties. As a Working Interest owner in the Underlying Properties, the Company is responsible for an average of approximately 98 percent of the operating costs of the Existing Wells.

     The Royalty Interests do not burden (i) royalties and other obligations, expressed or implied, under oil or natural gas leases, (ii) the overriding royalties and other burdens created by the Company’s predecessors in title, or (iii) the Working Interests owned by other individual Working Interest owners.

     Water Removal and Disposal. Water from the wells located on the Underlying Properties is pumped from the wellhead to one of five water disposal systems, each with two ponds, where the water is analyzed and chemically treated to remove impurities prior to discharge into the Black Warrior River. Water from the operations on the Underlying Properties is discharged into the Black Warrior River pursuant to a National Pollutant Discharge Elimination System permit issued by ADEM. The ADEM permit was renewed in 2004 and a timely renewal application was submitted in 2009. The 2004 permit is administratively extended until such time as ADEM reviews and issues a renewal permit. The ADEM permit generally authorizes water disposal based upon the Black Warrior River’s minimum flow rate and maximum chloride level. The Company has advised the Trust that, since 1987, water disposal from the Underlying Properties has not been disrupted. Although the facilities of the Company have the capacity to store several days of water production, if water disposal into the Black Warrior River is disrupted, natural gas production from the wells on the Underlying Properties would be curtailed during the period of such disruption. See “Business—Regulation and Prices—Environmental Regulation.”

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     Curtailments. The Company has advised the Trust that during 2009 production from the Underlying Properties was not curtailed for any reason other than for routine maintenance.

     Federal Lands. Approximately one percent (360 acres) of the Underlying Properties are leases on land held by the federal government. Royalty payments due to the U.S. government for natural gas produced from federal lands included in the Underlying Properties must be calculated in conformance with a Working Interest owner’s interpretation of regulations issued by the Minerals Management Service (“MMS”). 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 Trust is subject to certain rules of the Bureau of Land Management under which the holding of interests in leases by persons other than citizens, nationals and legal resident aliens of the United States (“Eligible Citizens”) are limited. As a result, non-Eligible Citizens are prohibited from owning Units. If any Units are acquired by persons or entities not constituting Eligible Citizens, such Unitholders may be required to sell such Units pursuant to a procedure set forth in the Trust Agreement. See “Business—Description of the Trust—Possible Divestiture of Units.”

     Additional Wells. Well spacing rules, which are in effect in Alabama, generally govern the space between wells drilled to the same productive formation and are promulgated in order to prevent waste and confiscation of property. Pursuant to such rules, the Existing Wells are located on 40- to 80-acre spacing units. Exceptions or changes to these rules may be granted by the applicable regulatory agency upon application of an interested party following notice to other interested parties if, in the agency’s opinion, good reasons exist therefor after consideration of evidence presented by the applicant and any opponents. The Company has informed the Trust that it is not aware of any plans to change spacing regulations with respect to the Underlying Properties in Alabama. No assurances can be made, however, that exceptions or changes will not be made in the future.

     The Company and its affiliates or unrelated third parties may acquire interests in properties adjoining the Underlying Properties. It is possible that wells drilled on adjoining properties would drain reserves attributable to the Underlying Properties.

     The Company has agreed for the term of the Trust not to consent to, cooperate with, assist in or conduct infill drilling (except as required by law) on any of the Underlying Properties in which the Company owned an interest as of June 1, 1994. Although the Company believes that it is unlikely that any additional wells will be drilled, if the Operating Agreement is terminated, the Company cannot prevent one of the other owners of an interest in the Underlying Properties from drilling additional wells on the Underlying Properties. Additional wells, if drilled, could recover a portion of the reserves otherwise producible from wells burdened by the Company Interests, thereby reducing the Gross Proceeds attributable to the Royalty Interests.

The Royalty Interests

     Summary of Conveyance. The Conveyance has been filed as an exhibit to this Form 10-K. The following summary of the material terms of the Conveyance is qualified in its entirety by reference to the terms thereof as set forth in such exhibit.

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     Expenses Borne by Royalty Interests. The Royalty Interests are non-operating, non-expense bearing interests, except for their share of property, production and related taxes, including severance taxes. Accordingly, owners of the Royalty Interests are not liable or responsible for costs or liabilities incurred by the Working Interest owners in connection with the production of Gas from the Underlying Properties.

     Operating Standard. The Company Interests Owner is obligated to conduct and carry on, as would a reasonably prudent operator, or cause to be so conducted or carried on, the development, maintenance and operation of the Company Interests.

     Infill Drilling. The Company Interests Owner has agreed not to consent to, cooperate with, assist in or conduct any infill drilling on the Underlying Properties, except as required by law.

     Pratt Recompletions. To recover behind pipe reserves, the Company Interests Owner recompleted certain of the Existing Wells to the Pratt coal seam prior to March 31, 1997.

     Right to Take In-Kind. The owner of the Royalty Interests has no right to take production in-kind.

     Pooling and Unitization. The Company Interests Owner has certain pooling and unitization rights.

     Right to Assign Company Interests. The Company Interests Owner has the right to assign all or any part of the Company Interests, subject to the Royalty Interests and the terms and provisions of the Conveyance. If any such assignment is made of part, but not all, of such interests, then effective as of the date of such assignment, the assignee will be required to make a separate computation of Gross Proceeds attributable to the assigned interests.

     Sale or Assignment of Royalty Interests. In certain situations, the Trust may sell or dispose of all or a part of the Royalty Interests, in which case the Trust would receive the proceeds therefrom and distribute such proceeds to the Unitholders, net of any amounts held as a reserve. See “Business—Description of the Trust—Transfer of Royalty Interests” and “Business—Description of the Trust—Duties and Limited Powers of the Trustee and the Delaware Trustee.”

     Books and Records. The Company Interests Owner is required to maintain books and records sufficient to determine the amounts payable with respect to the Royalty Interests.

     Computation and Payment. The Royalty Interests entitle the Trust to receive 65 percent of the Gross Proceeds. The Royalty Interests bear their proportionate share of property, production and related taxes (including severance taxes). The definitions, formulas and accounting procedures and other terms governing the computation of the Royalty Interests are set forth in the Conveyance.

     The Company Interests Owner is required, pursuant to the Conveyance, to pay to the Trust amounts received by the Company Interests Owner from the sale of Subject Gas attributable to the Royalty Interests. Under the Conveyance, the amounts payable by the Company Interests Owner with respect to the Royalty Interests are computed with respect to

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each calendar quarter ending prior to termination of the Trust, and such amounts are paid to the Trust not later than the last business day before the 45th day following the end of each calendar quarter. The amounts paid to the Trust do not include interest on any amounts payable with respect to the Royalty Interests that are held by the Company Interests Owner prior to payment to the Trust. The Company Interests Owner is entitled to retain all amounts attributable to the Retained Interests. The Company Interests Owner deducts from the payment to the Trust the Royalty Interests’ share of property, production and related taxes (including severance taxes) and pays the same on behalf of the Trust.

Reserve Estimate

     Reserve Estimate. The following table summarizes net proved reserves estimated as of December 31, 2009, and certain related information for the Royalty Interests from the Reserve Estimate prepared by Ralph E. Davis & Associates. The natural gas reserves were estimated by Ralph E. Davis & Associates by applying volumetric and decline curve analyses. All of such reserves constitute proved developed gas reserves located in the United States. The Reserve Estimate was prepared in accordance with criteria established by the Commission.

Summary of Gas Reserves as of December 31, 2009 Based on Average Fiscal-Year Prices

	December 31, 2009
Net Proved (MMcf) (a):
Developed		15,750
Undeveloped		0
Total Proved		15,750
Estimated Future Net Revenues (in thousands) (a)(b):
2010	$	7,336
2011		6,428
2012		5,631
2013		4,922
2014		4,268
Thereafter		23,252
Total	$	51,837
Total Discounted at 10 Percent	$	32,525

(a)

The estimates of reserves and future net revenues summarized in this table are based upon a price of $3.70 per Mcf, which represented the average market price for gas in their fields during the 12-month period prior to December 31, 2009, determined as an unweighted arithmetic average of the first day of the month price for each month within such period. This price may not be the most representative price for estimating reserves or related future net revenues data.

(b)

Estimated future net revenues are defined as the total revenues attributable to the Royalty Interests for gas production less the relevant share of production, property and related taxes (including severance taxes). Overhead costs have not been included, nor have the effects of depreciation, depletion and federal income tax. Estimated future net revenues

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and discounted estimated future net revenues are not intended and should not be interpreted as representing the fair market value for the estimated reserves.

     The reserve data set forth herein, which was prepared by Ralph E. Davis & Associates in a manner customary in the industry, is an estimate only, and actual quantities, rates of production and sales prices for natural gas are likely to differ from the estimated amounts set forth herein, and such differences could be significant. Allen C. Barron is the technical person primarily responsible for overseeing the preparation of the reserves estimates. Mr. Barron graduated from The University of Houston in 1968 with a Bachelor of Science degree in Chemical Engineering with a Petroleum Engineering option. Mr. Barron is a licensed professional engineer in the State of Texas with over thirty years experience in conducting evaluations and engineering studies of U.S. oil and gas fields and international energy assets.

     There are many uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production. Reserve engineering is a subjective process of estimating underground accumulations of natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of the geological and engineering evaluation of that data. Results of testing and production subsequent to the date of an estimate may justify revision of such estimate. Further, reserve estimates for any given property may vary from engineer to engineer even though each engineer bases his estimate on common data and utilizes techniques and principles customary in the industry.

     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 from HighMount and provides such information to Ralph E. Davis & Associates, 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.

     For properties with short production histories, reserve estimates in many instances are based upon volumetric calculations and upon analogy to similar types of production or producing fields. Relative to many conventional natural gas producing properties, coal seam gas producing properties in general, and the Underlying Properties in particular, have short production histories. In addition, there are no significant coal seam reservoirs that have been produced to depletion that can be used as analogies to the Underlying Properties.

     The discounted estimated future net revenues shown herein were prepared using guidelines established by the Commission and may not be representative of the market value for the estimated reserves.

     The reserves attributable to the Royalty Interests are expected to decline substantially during the term of the Trust, and a portion of each cash distribution made by the Trust will, therefore, be analogous to a return of capital. As a result, cash distributions will decrease

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materially over time. For example, based upon the production estimates set forth in the Reserve Estimate, annual production attributable to the Royalty Interests is estimated to decline from 2.2 Bcf in 2010 to 1.3 Bcf in 2014.

     Drilling and other exploratory and development activities. Detailed information concerning the number of wells on royalty properties is not generally available to the owner of Royalty Interests. Consequently, the Registrant does not have information that would be disclosed by a company with oil and gas operations, such as an accurate count of the number of wells located on the Underlying Properties, the number of exploratory or development wells drilled on the Underlying Properties during the periods presented by this report, or the number of wells in process or other present activities on the Underlying Properties, and the Registrant cannot readily obtain such information.

     Miscellaneous. Ralph E. Davis & Associates has delivered to the Trust the Reserve Estimate, a summary of which is included as an exhibit to this Form 10-K. Information concerning historical changes in net proved developed reserves attributable to the Royalty Interests, and the calculation of the standardized measure of discounted future net revenues related thereto, is contained in Note 9 of the Notes to the Financial Statements incorporated by reference in Item 8 hereof. Neither the Company nor Highmount Alabama has filed reserve estimates covering the Royalty Interests with any other federal authority or agency.

Natural Gas Sales Prices and Production

     The following table sets forth the actual net production volumes attributable to the Royalty Interests, weighted average property, production and information regarding natural gas sales prices for the years ended December 31, 2009, December 31, 2008 and December 31, 2007.

	Year ended December 31,
	2009		2008		2007
Production attributable to the Royalty Interests (Bcf)		2.7		3.1		3.3
Weighted average property, production (per Mcf)	$	0.24	$	0.54	$	0.42
Average Sales Price or Contract Price, as applicable (per Mcf)	$	4.03	$	9.20	$	6.97

Gas Purchase Agreement

     El Paso, successor to Sonat Marketing, was required under the Gas Purchase Agreement to purchase the Gas produced from the Underlying Properties until such agreement was terminated, effective January 31, 2004.

     Contracts were secured from two purchasers, ConocoPhillips and Coral Energy Resources, L.P., for the base load gas for the period of November 1, 2004 through March 31, 2005. A gas sales contract was entered into with Sequent Energy for base load gas for the period of April 1, 2005 through October 31, 2005. A gas sales contract was entered into with SCANA Energy for base load gas for the period of November 1, 2005 through March 31, 2006. Separate

39

gas sales contracts were entered into with Coral Energy and South Carolina Pipeline Company for base load gas for the period of April 1, 2006 through October 31, 2006. A gas sales contract was entered into with ConocoPhillips for base load gas for the period of November 1, 2006 through March 31, 2007. A gas sales contract was entered into with Coral Energy for base load gas for the period of April 1, 2007 through October 31, 2007. A gas sales contract was entered into with BP Energy for base load gas for the period of November 1, 2007 through March 31, 2008. Gas sales contracts were entered into with Atmos, BP Energy and ConocoPhillips for base load gas for the period April 1, 2008 through October 31, 2008. Gas sales contracts were entered into with Atmos, BP Energy, Chevron and Sequent for base load gas for the period November 1, 2008 through March 31, 2009. Gas sales contracts were entered into with Atmos, BP Energy, Chevron, ConocoPhillips and Sequent for base load gas for the period April 1, 2009 through October 31, 2009. Gas sales contracts were entered into with Atmos, BP Energy, Chevron and ConocoPhillips for base load gas for the period November 1, 2009 through March 31, 2010. During the terms of the above-mentioned contracts, any gas above the base load was sold on the spot market to various purchasers. The foregoing information regarding the gas purchase contracts has been provided to the Trustee by Dominion Resources and HighMount Alabama.

Operation of Properties

     No Control by Trust. Under the terms of the Conveyance, neither the Trustees nor Unitholders will be able to influence or control the operation or future development of the Underlying Properties. Unitholders will therefore be reliant on the Company and the other Working Interest owners to make all decisions regarding operations on the Underlying Properties. The Trust will not be able to appoint or control the appointment of operators.

     The Conveyance does not prohibit the transfer of the Underlying Properties by the Company, subject to and burdened by the Royalty Interests. The Company and the other Working Interest owners of the Underlying Properties will have the right, subject to certain restrictions, to abandon any well or lease on the Underlying Properties under certain circumstances. Upon abandonment of any such well or lease, that portion of the Royalty Interests relating thereto will be extinguished. See “—Sale and Abandonment of Underlying Properties.”

     Operating Agreement. Pursuant to the Operating Agreement, ConocoPhillips operated and maintained the Underlying Properties for the Company and the other Working Interest owners until January 1, 2003. As amended October 30, 1996, the Operating Agreement had a three-year term and was to be automatically renewed for additional one-year periods unless either party provided written notice to the other party of its desire to terminate the Operating Agreement before the end of the current calendar year. On December 27, 2000, Dominion Resources notified ConocoPhillips that it was terminating the automatic one-year extension of the agreement. As such, the Operating Agreement was amended effective January 1, 2003 naming Dominion Black Warrior Basin, Inc. as the operator of the Underlying Properties.

Sale and Abandonment of Underlying Properties

     The Company has the right to abandon any well or lease included in the Underlying Properties if, in its opinion, acting as would a reasonably prudent operator, such well or lease is not capable of producing Gas in commercial quantities (determined before giving effect to the

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Royalty Interests). Neither the Trust nor the Unitholders will control the timing of the plugging and abandoning of any wells. Through December 31, 2009, none of the wells included in the Underlying Properties had been plugged and abandoned.

     The Company may sell its interest in the Underlying Properties, subject to and burdened by the Royalty Interests, without the consent of the Trust or Unitholders. Under the Trust Agreement, the Company has certain rights (but not the obligation) to purchase the Royalty Interests upon termination of the Trust. See “Business—Description of the Trust—Termination and Liquidation of the Trust.”

HighMount Alabama’s Assurances

     Pursuant to the Assignment and Assumption Agreement, HighMount Alabama agreed to assume the obligations of Dominion Resources pursuant to the Trust Agreement to cause each of the following obligations to be paid in full when due: (i) all liabilities and operating and capital expenses that any Company Interests Owner becomes obligated to pay as a result of such Company Interests Owner’s obligations under the Conveyance and (ii) the obligations of the Company to indemnify the Trust, the Trustee and the Delaware Trustee for certain environmental liabilities under the Trust Agreement (collectively, the “Payment Obligations”).

     The Trustee may, at any time after the tenth day following receipt by HighMount Alabama of written notice from the Trustee that a Payment Obligation has not been paid when due, make demand of HighMount Alabama for payment stating the amount due. HighMount Alabama is obligated to cure any failure to pay the obligation within 10 days following receipt of the foregoing demand. After written request of the Unitholders owning of record not less than 25 percent of the Units then outstanding served upon the Trustee, and absent action by the Trustee within 10 days following receipt by the Trustee of such written request to enforce such obligations for the benefit of the Trust, such Unitholders may, acting as a single class and on behalf of the Trust, seek to enforce HighMount Alabama’s performance obligations.

     All of HighMount Alabama’s obligations will terminate upon: (i) the termination and cancellation of the Trust, (ii) the sale or other transfer by the Company of all or substantially all of the Company’s interest in the Underlying Properties subject to the terms of the Trust Agreement and (iii) the sale or other transfer of a majority of HighMount Alabama’s direct or indirect equity ownership interest in the Company; provided that, with respect to clauses (ii) and (iii) above, HighMount Alabama’s obligations will terminate only if: (a) the transferee has a specified credit rating or the transferee together with an affiliate that guarantees the transferee’s obligations has not less than a specified net worth or (b) the transferee is approved by the holders of a majority of the outstanding Units; and provided further, that in the case of clauses (ii) or (iii) above the transferee also unconditionally agrees in writing, in form and substance reasonably satisfactory to the Trustee, to assume HighMount Alabama’s remaining obligations under the Trust Agreement with respect to the assets transferred and under the Administrative Services Agreement.

Title to Properties

     Alabama counsel to the Company has opined that the Company’s title to its interest in the Underlying Properties, and the Trust’s title to the Royalty Interests, are good and defensible in

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accordance with standards generally accepted in the natural gas industry, subject to such exceptions that, in the opinion of Alabama counsel, are not so material as to detract substantially from the use or value of the Company Interests or the Royalty Interests.

     Although the matter is not entirely free from doubt, Alabama counsel has opined that the Royalty Interests constitute interests in real property under Alabama law. Consistent therewith, the Conveyance states that the Royalty Interests constitute real property interests. The Company has recorded the Conveyance in the appropriate real property records of Alabama in accordance with local recordation provisions. If, during the term of the Trust, the Company or any Company Interests Owner becomes involved as a debtor in bankruptcy proceedings under the Federal Bankruptcy Code, it is not entirely clear that the Royalty Interests would be treated as real property interests under the laws of Alabama.

Item 3. Legal Proceedings.

     The Trustee has been informed by the Company that the Trust has been named as a defendant in an action, styled Southwest Royalties, Inc. v. Dominion Black Warrior Basin, Inc., et al., filed in the Circuit Court of Fayette County Alabama on October 5, 2007 regarding the quieting of title in certain oil and gas rights related to property in Fayette and Tuscaloosa Counties in Alabama. The plaintiff alleges that defendants are knowingly producing gas in violation of the deeds in question. The plaintiff is also alleging conversion of gas, continuing trespass by defendants on plaintiff’s property, and suppression of material facts by defendants, and plaintiff is requesting an accounting, injunctive relief and compensatory and punitive damages, plus court costs and attorneys fees. The Trustee does not believe this litigation will have a material effect on the Trust’s financial statements.

Item 4. Reserved.

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PART II.

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. The Units in the Trust are listed and traded on the NYSE under the symbol “DOM.” The following table sets forth, for the periods indicated, the high and low sales prices per Unit on the NYSE and the amount of quarterly cash distributions per Unit paid by the Trust.

	Price
	High		Low		Distribution per Unit
2009
First Quarter	$	20.49	$	11.25	$	0.578705
Second Quarter	$	19.95	$	14.70	$	0.359399
Third Quarter	$	17.05	$	13.73	$	0.264913
Fourth Quarter	$	16.78	$	14.01	$	0.246351
2008
First Quarter	$	23.05	$	15.25	$	0.651500
Second Quarter	$	27.50	$	21.06	$	0.710735
Third Quarter	$	25.99	$	20.00	$	0.972063
Fourth Quarter	$	22.31	$	12.00	$	0.910488

     At March 1, 2010, there were 7,850,000 Units outstanding and approximately 412 Unitholders of record.

     The Trust has no equity compensation plans and has not repurchased 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	$	12,425,827	$	26,537,428	$	21,962,082	$	31,403,042	$	31,918,416
Distributable Income	$	11,197,573	$	25,644,510	$	20,912,169	$	30,467,067	$	31,029,034
Distributable Income per Unit	$	1.43	$	3.27	$	2.66	$	3.88	$	3.95
Distributions per Unit	$	1.45	$	3.24	$	2.68	$	3.88	$	3.95
Total Assets, December 31	$	19,513,673	$	23,055,462	$	26,676,808	$	30,692,809	$	34,838,807
Total Corpus, December 31	$	19,345,951	$	22,941,064	$	26,353,024	$	30,444,631	$	34,582,715

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Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations. The Trust collects the proceeds attributable to the Royalty Interests and makes quarterly cash distributions to Unitholders. The only assets of the Trust, other than cash and cash equivalents being held for the payment of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests. The Royalty Interests owned by the Trust burden the interest in the Underlying Properties that is owned by the Company.

     The Royalty Interests consist of overriding royalty interests burdening the Company’s interest in the Underlying Properties. The Royalty Interests generally entitle the Trust to receive 65 percent of the Gross Proceeds (as defined below) during the preceding calendar quarter. The Royalty Interests are non-operating interests and bear only expenses related to property, production and related taxes (including severance taxes). Gross Proceeds consist generally of the aggregate amounts received by the Company attributable to the interests of the Company in the Underlying Properties from the sale of coal seam gas at the central delivery points in the gathering system for the Underlying Properties.

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

     The amount of distributable income of the Trust for any calendar year may differ from the amount of cash available for distribution to the Unitholders in such year due to differences in the treatment of the expenses of the Trust and the determination of those amounts. The financial statements of the Trust are prepared on a modified cash basis pursuant to which the expenses of the Trust are recognized when they are paid or reserves are established whereas royalty income is recognized when received by the Trust. 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 paid by the Trust during such year. The amount of cash available for distribution to Unitholders is determined after adjustment for changes in reserves for unpaid liabilities in accordance with the provisions of the Trust Agreement. See Note 6 to the financial statements of the Trust appearing elsewhere in this Form 10-K for additional information regarding the determination of the amount of cash available for distribution to Unitholders.

     The year 2009 marked the fifteenth full year of the existence of the Trust. The Trust received royalty income amounting to $12,425,827 during the year ended December 31, 2009, compared to $26,537,428 for 2008 and $21,962,082 for 2007, declining primarily due to lower production and significantly lower prices for natural gas. The royalty income received by the Trust was net of the Royalty Interests’ allocable share of property, production and related taxes. Administrative expenses during the year ended December 31, 2009 increased to $1,232,893, compared to $931,256 for 2008 and $1,120,031 for 2007. Distributable income for the year ended December 31, 2009 was $11,197,573 or $1.43 per Unit, compared to $25,644,510, or $3.27 per Unit, for 2008 and $20,912,169, or $2.66 per Unit, for 2007. The increase in administrative expenses in 2009 compared to 2008 was primarily the result of a significant increases for professional expenses relating to compliance with The Sarbanes Oxley Act of 2002. The decrease in administrative expenses in 2008 compared to 2007 was primarily the result of a decrease in the number of Unitholders.

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     Royalty income to the Trust is attributable to the sale of depleting assets. All of the Underlying Properties burdened by the Royalty Interests consist of producing properties. Accordingly, the proved reserves attributable to the Company’s interest in the Underlying Properties are expected to decline substantially during the term of the Trust and a portion of each cash distribution made by the Trust will, therefore, be analogous to a return of capital. Accordingly, cash yields attributable to the Units are expected to decline over the term of the Trust. The changes in royalty income and distributable income noted in the preceding paragraph were due primarily to changes in the average prices received for gas attributable to the Royalty Interests as summarized in the table below.

     Royalty Income received by the Trust in a given calendar year will generally reflect the proceeds from the sale of gas produced from the Underlying Properties during the first three quarters of that year and the fourth quarter of the preceding calendar year due to the timing of the receipt of these revenues. 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 periods from October 1, 2008 to September 30, 2009, October 1, 2007 to September 30, 2008 and October 1, 2006 to September 30, 2007, respectively.

     The following table sets forth the production volumes attributable to the Trust’s Royalty Interests and the average sales Price and Index Price for such production for the periods indicated. These Assets are mature natural gas properties and production should decline in the latter years.

	For 12 Months Ended
	September 30,
	2009		2008		2007
Production (Bcf)(1)		2.758		3.098		3.402
Production (MMBtu)(2)		2.761		3.104		3.415
Average Sales or Contract Price Received ($/MMBtu)	$	4.79	$	9.10	$	6.84
Average Index Price ($/MMBtu)	$	4.46	$	9.35	$	7.07

(1)	Billion cubic feet of natural gas.
(2)	Trillion British Thermal Units.

     The information in this Form 10-K concerning production and prices relating to the Royalty Interests is based on information prepared and furnished by the Company to the Trustee. The Trustee has no control over and no responsibility relating to the operation of or accounting for the Underlying Properties.

     El Paso, successor to Sonat Marketing, was required under the Gas Purchase Agreement to purchase the Gas produced from the Underlying Properties until such agreement was terminated, effective January 31, 2004.

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     Contracts were secured from various purchasers following termination of the Gas Purchase Agreement. A gas sales contract was entered into with SCANA Energy for base load gas for the period of November 1, 2005 through March 31, 2006. Separate gas sales contracts were entered into with Coral Energy and South Carolina Pipeline Company for base load gas for the period of April 1, 2006 through October 31, 2006. A gas sales contract was entered into with ConocoPhillips for base load gas for the period of November 1, 2006 through March 31, 2007. A gas sales contract was entered into with Coral Energy for base load gas for the period of April 1, 2007 through October 31, 2007. A gas sales contract was entered into with BP Energy for base load gas for the period of November 1, 2007 through March 31, 2008. Gas sales contracts were entered into with Atmos, BP Energy and ConocoPhillips for base load gas for the period April 1, 2008 through October 31, 2008. Gas sales contracts were entered into with Atmos, BP Energy, Chevron and Sequent for base load gas for the period November 1, 2008 through March 31, 2009. Gas sales contracts were entered into with Atmos, BP Energy, Chevron, ConocoPhillips and Sequent for base load gas for the period April 1, 2009 through October 31, 2009. Gas sales contracts were entered into with Atmos, BP Energy, Chevron and ConocoPhillips for base load gas for the period November 1, 2009 through March 31, 2010. During the terms of the above-mentioned contracts, any gas above the base load was sold on the spot market to various purchasers. The foregoing information regarding the gas purchase contracts has been provided to the Trustee by Dominion Resources and HighMount Alabama.

     The net proved reserves attributable to the Royalty Interests have been estimated as of December 31, 2009, 2008 and 2007, by independent petroleum engineers. The reserve quantities of 15.7 Bcf for 2009 compared to 19.8 Bcf for 2008 and compared to 22.6 Bcf for 2007, reflect a decline in reserves between 2007 and 2008 and between 2008 and 2009 as a result of production and a significant change in prices which affects the change in quantities. See “Financial Statements and Supplementary Data — Notes to Financial Statements— Note 9.”

Critical Accounting Policies and Estimates

     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.

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1. Basis of Accounting

     The financial statements of the Trust are prepared on a modified cash basis and are not intended to present financial position and results of operations in conformity with accounting principles generally accepted in the United States of America. Preparation of the Trust’s financial statements on such basis includes the following:

• Royalty income and interest income are recorded in the period in which amounts are received by the Trust rather than in the period of production and accrual, respectively.

• General and administrative expenses are recorded based on liabilities paid and cash reserves established out of cash received.

• Amortization of the Royalty Interests is calculated on a unit-of-production basis and charged directly to Trust corpus based upon when revenues are received.

• Distributions to Unitholders are recorded when declared by the Trustee (see “Financial Statements and Supplementary Data — Notes to Financial Statements — Note 6).

     The financial statements of the Trust differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America because royalty income is not accrued in the period of production, general and administrative expenses recorded are based on liabilities paid and cash reserves established rather than on an accrual basis, and amortization of the Royalty Interests is not charged against operating results. The comprehensive basis of accounting other than accounting principles generally accepted in the United States of America corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

2. Impairment

     The net amount of Royalty Interests in gas properties is limited to the fair value of these assets, which would likely be measured by discounting projected cash flows. If the net cost of Royalty Interests in gas properties exceeds the aggregate of these amounts, an impairment provision is recorded and charged to the Trust corpus. As of December 31, 2009, no impairment is required.

3. 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 twelve-month period ended September 30th in that calendar year.

4. Reserve Disclosure

     Independent petroleum engineers estimate the net proved reserves attributable to the Royalty Interest. In accordance with FASB guidance, estimates of future net revenues from proved reserves have been prepared using year-end contractual gas prices and related costs. Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and the timing of development of non-producing reserves. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.

     Detailed information concerning the number of wells on royalty properties is not generally available to the owner of royalty interests. Consequently, the Registrant does not have information that would be disclosed by a company with oil and gas operations, such as an accurate count of the number of wells located on the Underlying Properties, the number of exploratory or development wells drilled on the Underlying Properties during the periods presented by this report, or the number of wells in process or other present activities on the Underlying Properties, and the Registrant cannot readily obtain such information.

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5. 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. The Trustee is aware of no such items as of December 31, 2009, other than as stated below.

     The Trustee has been informed by the Company that the Trust has been named as a defendant in an action, styled Southwest Royalties, Inc. v. Dominion Black Warrior Basin, Inc., et al., filed in the Circuit Court of Fayette County Alabama on October 5, 2007 regarding the quieting of title in certain oil and gas rights related to property in Fayette and Tuscaloosa Counties in Alabama. The plaintiff alleges that defendants are knowingly producing gas in violation of the deeds in question. The plaintiff is also alleging conversion of gas, continuing trespass by defendants on plaintiff’s property, and suppression of material facts by defendants, and plaintiff is requesting an accounting, injunctive relief and compensatory and punitive damages, plus court costs and attorneys fees. The Trustee does not believe this litigation will have a material effect on the Trust’s financial statements.

New Accounting Pronouncements

     In June 2009, the Financial Accounting Standards Board (“FASB”) issued guidance effective July 1, 2009 that requires all then-existing non-SEC accounting and reporting standards to be superseded by the FASB Accounting Standards Codification (the “Codification”), the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Previous references to then-existing non-SEC accounting and reporting standards were removed and are reflected in the Trust’s footnotes herein.

     In December 2007 the FASB issued guidance that requires the acquiring entity in a business combination to recognize the full fair value of assets acquired and liabilities assumed in the transaction (whether a full or partial acquisition); establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; requires expensing of most transaction and restructuring costs; and requires the acquirer to disclose to investors and other users all of the information needed to evaluate and understand the nature and financial effect of the business combination. This statement applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. The adoption of this standard did not have an effect on the Trust’s financial statements.

     In December 2007, the FASB issued guidance which requires reporting entities to present noncontrolling (minority) interests as equity (as opposed to as a liability or mezzanine equity) and provides guidance on the accounting for transactions between an entity and noncontrolling interests. This statement applies prospectively as of January 1, 2009, except for the presentation and disclosure requirements which will be applied retrospectively for all periods presented. The adoption of this standard did not have an effect on the Trust’s financial statements.

     In March 2008, the FASB issued guidance effective for fiscal years and interim periods beginning after November 15, 2008, with early adoption allowed, that amends and expands the disclosure requirements for derivatives and hedging activities with the intent to provide users of financial statements with an enhanced understanding of an entity’s use of derivative instruments and the effect of those derivative instruments on an entity’s financial statements. The adoption of this standard did not have an effect on the Trust’s financial statements.

     In April 2009, the FASB issued guidance that amends the other-than-temporary impairment guidance in U.S. GAAP for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. This guidance does not amend existing recognition and measurement guidance related to other-than-temporary impairments of equity securities. This statement is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The adoption of this standard did not have an effect on the Trust’s financial statements.

     In April 2009, the FASB issued guidance to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. The adoption of this standard did not have an effect on the Trust’s financial statements.

     In May 2009, the FASB issued guidance which establishes accounting and reporting standards for events that occur after the balance sheet date but before the financial statements are issued or are available to be issued. This guidance was effective for the Trust for the period ended June 30, 2009 and the adoption did not have an impact on the Trust’s financial statements.

     In June 2009, the FASB issued guidance which changes the way entities account for securitizations. The new standard is effective for the Trust on January 1, 2010 and the adoption is not expected to have a significant impact on the Trust’s financial statements.

     In June 2009, the FASB issued guidance which changes the way entities account for special-purpose entities. The new standard is effective for the Trust on January 1, 2010 and the adoption is not expected to have a significant impact on the Trust’s financial statements.

     In September 2009, the FASB made several revisions to guidance that are intended to align the requirements for oil and gas reporting under GAAP with the SEC. Key provisions include expanding the definition of “oil-and-gas-producing activities” to include nontraditional resources in reserves, amending the definition of “proved oil and gas reserves” to change the pricing used to estimate reserves, providing guidance on “geographic area” with respect to disclosure of information about significant reserves, and clarifying disclosures required for equity method investments. The revised standard is effective for the Trust for the period ended December 31, 2009. Refer to Note 9 of the Notes to Financial Statements for required disclosures.

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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. See the earlier discussions in Item 7 for the discussion of the operations and cash inflows and outflows of the Trust.

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

			Payments Due by Period
			Less than 1		1 - 3		3-5		More than
Contractual Obligations	Total		Year		Years		Years		5 Years
Distribution declared subsequent to year end	$	2,137,720	$	2,137,720		0		0		0
Total	$	2,137,720	$	2,137,720		0		0		0

     The above payable relates to distributions declared February 19, 2010 and payable March 11, 2010 to Unitholders of record on March 1, 2010.

Forward-Looking Statements

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

Item 7A. Quantitative and Qualitative Disclosures About Market Risk. The Trust invests in no derivative financial instruments and has no foreign operations or long-term debt instruments. 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

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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 which may be held by the Trust, the Trustee believes that the Trust is not subject to any material interest rate risk. Funds held by the Trust pending distribution to Unitholders and in reserve for the payment of Trust expenses and liabilities are invested in Bank of America, N.A. 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. 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. Additionally, the Trust’s future royalty income may be subject to risks relating to the creditworthiness of the operators of the Underlying Properties and other purchasers of crude oil and natural gas produced from the Underlying Properties, as well as risks associated with fluctuations in the price of crude oil and natural gas. See “Item 1A — Risk Factors — Cash held by the Trustee is not insured by the Federal Deposit Insurance Corporation, and future royalty income may be subject to risks relating to the creditworthiness of third parties.” The Trust does not engage in transactions in foreign currencies which could expose the Trust or Unitholders to any foreign currency related market risk. 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.

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Item 8. Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Unit Holders of Dominion Resources Black Warrior Trust and
Bank of America, N.A., Trustee:

We have audited the accompanying statements of assets, liabilities, and trust corpus of Dominion Resources Black Warrior Trust (“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 three years in the period ended December 31, 2009. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audits.

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

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

In our opinion, such financial statements present fairly, in all material respects, the assets, liabilities, and trust corpus of the Dominion Resources Black Warrior Trust at December 31, 2009 and 2008, and the distributable income and 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.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Trust’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 16, 2010 expressed an unqualified opinion on the Trust’s internal control over financial reporting.

DELOITTE & TOUCHE LLP

Austin, TX
March 16, 2010

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DOMINION RESOURCES BLACK WARRIOR TRUST

FINANCIAL STATEMENTS

Statements of Assets, Liabilities and Trust Corpus

	December 31,
	2009		2008
ASSETS
Cash and cash equivalents	$	13,123	$	139,764
Royalty interests in gas properties (less accumulated amortization of $136,316,950 and $132,901,802, respectively)		19,500,550		22,915,698
Total Assets	$	19,513,673	$	23,055,462
LIABILITIES AND TRUST CORPUS
Trust expenses payable	$	167,722	$	114,398
Trust corpus (7,850,000 units of beneficial interest authorized, issued and outstanding)		19,345,951		22,941,064
Total Liabilities and Trust Corpus	$	19,513,673	$	23,055,462

Statements of Distributable Income

	Year Ended December 31,
	2009			2008			2007
Royalty income	$	12,425,827		$	26,537,428		$	21,962,082
Interest income		4,639			38,338			70,118
		12,430,466			26,575,766			22,032,200
General and administrative expenses		(1,232,893	)		(931,256	)		(1,120,031	)
Distributable income	$	11,197,573		$	25,644,510		$	20,912,169
Distributable income per unit (7,850,000 units)	$	1.43		$	3.27		$	2.66
Distributions per unit	$	1.45		$	3.24		$	2.68

Statements of Changes in Trust Corpus

	Year Ended December 31,
	2009			2008			2007
Trust corpus, beginning of period	$	22,941,064		$	26,353,024		$	30,444,631
Amortization of Royalty Interests		(3,415,148	)		(3,584,906	)		(3,989,396	)
Distributable income		11,197,573			25,644,510			20,912,169
Distributions to Unitholders		(11,377,538	)		(25,471,564	)		(21,014,380	)
	$	19,345,951		$	22,941,064		$	26,353,024

The accompanying notes are an integral part of these financial statements.

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Notes to Financial Statements
Years Ended December 31, 2009, 2008 and 2007

1. Trust Organization and Provisions

     Dominion Resources Black Warrior Trust (the “Trust”) was formed as a Delaware business trust pursuant to the terms of the Trust Agreement of Dominion Resources Black Warrior Trust (as amended, the “Trust Agreement”), entered into effective as of May 31, 1994, among Dominion Black Warrior Basin, Inc., an Alabama corporation, as trustor; Dominion Resources, Inc., a Virginia corporation (“Dominion Resources”); and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.), a national banking association (the “Trustee”); and Mellon Bank (DE) National Association, a national banking association (the “Delaware Trustee”), as trustees. The Trustees are independent financial institutions. 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.

     The Trust is a grantor trust formed to acquire and hold certain overriding royalty interests (the “Royalty Interests”) burdening proved natural gas properties located in the Pottsville coal formation of the Black Warrior Basin, Tuscaloosa County, Alabama (the “Underlying Properties”) owned by HighMount Black Warrior Basin LLC, a Delaware limited liability company, as successor to Dominion Black Warrior Basin, Inc. (the “Company”). The Trust was initially created by the filing of its Certificate of Trust with the Delaware Secretary of State on May 31, 1994. In accordance with the Trust Agreement, the Company contributed $1,000 as the initial corpus of the Trust. On June 28, 1994, the Royalty Interests were conveyed to the Trust by the Company pursuant to the Overriding Royalty Conveyance (the “Conveyance”), effective as of June 1, 1994, from the Company to the Trust, in consideration for all the 7,850,000 authorized units of beneficial interest (“Units”) in the Trust. The Company transferred all the Units to its parent, Dominion Energy, Inc., a Virginia corporation (“Dominion Energy”), which in turn transferred all the Units to its parent, Dominion Resources, Inc., a Virginia corporation (“Dominion Resources”), which sold an aggregate of 6,904,000 Units to the public through various underwriters (the “Underwriters”) in June and August 1994 and the remaining 946,000 Units through certain of the Underwriters in June 1995.

     The Trustee has all 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 or are required by law and is not empowered to otherwise manage or take part in the management of the Trust. The Royalty Interests are passive in nature and neither the Trustee nor the Delaware Trustee has any control over, or any responsibility relating to, the operation of the Underlying Properties or the Company’s interest therein.

     The Trust is subject to termination under certain circumstances described in the Trust Agreement. Upon the termination of the Trust, all Trust assets will be sold and the net proceeds therefrom distributed to Unitholders.

     The only assets of the Trust, other than cash and temporary investments being held for the payment of expenses and liabilities and for distribution to Unitholders, are the Royalty

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Interests. The Royalty Interests consist of overriding royalty interests burdening the Company’s interest in the Underlying Properties. The Royalty Interests generally entitle the Trust to receive 65 percent of the Company’s Gross Proceeds (as defined below). The Royalty Interests are non-operating interests and bear only expenses related to property, production and related taxes (including severance taxes). “Gross Proceeds” consist generally of the aggregate amounts received by the Company attributable to the interests of the Company in the Underlying Properties from the sale of coal seam gas at the central delivery points in the gathering system for the Underlying Properties. The definitions, formulas and accounting procedures and other terms governing the computation of the Royalty Interests are set forth in the Conveyance.

     Because of the passive nature of the Trust and the restrictions and limitations on the powers and activities of the Trustee contained in the Trust Agreement, the Trustee does not consider any of the officers and employees of the Trustee to be “officers” or “executive officers” of the Trust as such terms are defined under applicable rules and regulations adopted under the Securities Exchange Act of 1934.

     On July 31, 2007, subsidiaries of HighMount purchased certain assets from subsidiaries of Dominion Resources, including all of the equity interests in the Company which owns the interests in the Underlying Properties that are burdened by the Trusts’ Royalty Interests. The Trust continues to have ownership in the Royalty Interests burdening the Underlying Properties and such sale did not affect that ownership. In connection with the sale, Dominion Resources assigned its rights and obligations under the Trust Agreement governing the Trust and the Administrative Services Agreement to HighMount Alabama, a subsidiary of HighMount.

2. Basis of Accounting

     The financial statements of the Trust are prepared on a modified cash basis and are not intended to present financial position and results of operations in conformity with accounting principles generally accepted in the United States of America. Preparation of the Trust’s financial statements on such basis includes the following:

• Royalty income and interest income are recorded in the period in which amounts are received by the Trust rather than in the period of production and accrual, respectively.

• General and administrative expenses are recorded based on liabilities paid and cash reserves established out of cash received.

• Amortization of the Royalty Interests is calculated on a unit-of-production basis and charged directly to Trust corpus based upon when revenues are received.

• Distributions to Unitholders are recorded when declared by the Trustee (see Note 6).

     The financial statements of the Trust differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America because royalty income is not accrued in the period of production, general and administrative expenses recorded are based on liabilities paid and cash reserves established rather than on an accrual basis, and amortization of the Royalty Interests is not charged against operating results. The comprehensive basis of accounting other than accounting principles generally accepted in

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the United States of America corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

Use of Estimates

     The preparation of financial statements in conformity with the basis of accounting described above requires management to make estimates and assumptions that affect reported amounts of certain assets, liabilities, revenues and expenses as of and for the reporting periods. Actual results may differ from such estimates.

Impairment

     The net amount of Royalty Interests in Gas properties is limited to the fair value of these assets, which would likely be measured by discounting projected cash flows. If the net cost of Royalty Interests in Gas properties exceeds the aggregate of these amounts, an impairment provision is recorded and charged to the Trust corpus. As of December 31, 2009, no impairment is required.

Distributable Income Per Unit

     Basic distributable income per unit is computed by dividing distributable income by the weighted average units outstanding. Distributable income per unit assuming dilution is computed by dividing distributable income by the weighted average number of units and equivalent units outstanding. The Trust had no equivalent units outstanding for any period presented, thus basic distributable income per unit and diluted distributable income per unit are the same.

3. New Accounting Pronouncements

     In June 2009, the Financial Accounting Standards Board (“FASB”) issued guidance effective July 1, 2009 that requires all then-existing non-SEC accounting and reporting standards to be superseded by the FASB Accounting Standards Codification (the “Codification”), the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Previous references to then-existing non-SEC accounting and reporting standards were removed and are reflected in the Trust’s footnotes herein.

     In December 2007 the FASB issued guidance that requires the acquiring entity in a business combination to recognize the full fair value of assets acquired and liabilities assumed in the transaction (whether a full or partial acquisition); establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; requires expensing of most transaction and restructuring costs; and requires the acquirer to disclose to investors and other users all of the information needed to evaluate and understand the nature and financial effect of the business combination. This statement applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. The adoption of this standard did not have an effect on the Trust’s financial statements.

     In December 2007, the FASB issued guidance which requires reporting entities to present noncontrolling (minority) interests as equity (as opposed to as a liability or mezzanine equity)

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and provides guidance on the accounting for transactions between an entity and noncontrolling interests. This statement applies prospectively as of January 1, 2009, except for the presentation and disclosure requirements which will be applied retrospectively for all periods presented. The adoption of this standard did not have an effect on the Trust’s financial statements.

     In March 2008, the FASB issued guidance effective for fiscal years and interim periods beginning after November 15, 2008, with early adoption allowed, that amends and expands the disclosure requirements for derivatives and hedging activities with the intent to provide users of financial statements with an enhanced understanding of an entity’s use of derivative instruments and the effect of those derivative instruments on an entity’s financial statements. The adoption of this standard did not have an effect on the Trust’s financial statements.

     In April 2009, the FASB issued guidance that amends the other-than-temporary impairment guidance in U.S. GAAP for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. This guidance does not amend existing recognition and measurement guidance related to other-than-temporary impairments of equity securities. This statement is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The adoption of this standard did not have an effect on the Trust’s financial statements.

     In April 2009, the FASB issued guidance to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. The adoption of this standard did not have an effect on the Trust’s financial statements.

     In May 2009, the FASB issued guidance which establishes accounting and reporting standards for events that occur after the balance sheet date but before the financial statements are issued or are available to be issued. This guidance was effective for the Trust for the period ended June 30, 2009 and the adoption did not have an impact on the Trust’s financial statements.

     In June 2009, the FASB issued guidance which changes the way entities account for securitizations. The new standard is effective for the Trust on January 1, 2010 and the adoption is not expected to have a significant impact on the Trust’s financial statements.

     In June 2009, the FASB issued guidance which changes the way entities account for special-purpose entities. The new standard is effective for the Trust on January 1, 2010 and the adoption is not expected to have a significant impact on the Trust’s financial statements.

     In September 2009, the FASB made several revisions to guidance that are intended to align the requirements for oil and gas reporting under GAAP with the SEC. Key provisions include expanding the definition of “oil-and-gas-producing activities” to include nontraditional resources in reserves, amending the definition of “proved oil and gas reserves” to change the pricing used to estimate reserves, providing guidance on “geographic area” with respect to disclosure of information about significant reserves, and clarifying disclosures required for equity method investments. The revised standard is effective for the Trust for the period ended December 31, 2009. Refer to Note 9 of the Notes to Financial Statements for required disclosures.

4. 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 federal 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

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Unitholder’s method of accounting and without regard to the taxable year or accounting method employed by the Trust.

Some Trust Units are held by middlemen, as such term is broadly defined in the 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: 56-0906609, 901 Main Street, 17th Floor, Dallas, Texas 75202, telephone number (214) 209-2400, is the representative of the Trust that will provide tax information beginning with the 2008 tax year in accordance with applicable Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.dom-dominionblackwarriortrust.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 Treasury Regulations with respect to such Trust Units, including the issuance of IRS Forms 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.

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

5. Related Party Transactions

     Until July 2007, Dominion Resources provided accounting, bookkeeping and informational services to the Trust in accordance with an Administrative Services Agreement dated effective June 1, 1994, after which HighMount Alabama assumed this function. During 2009 the fee for these services was $463,987 and will increase annually by three percent. Fees paid by the Trust to HighMount in 2008 were $450,473 and aggregate fees paid by the Trust to HighMount and Dominion Resources in 2007 were $440,560.

     Aggregate fees and expense reimbursements paid by the Trust to the Trustees in 2009, 2008 and 2007 were $51,399, $50,047 and $48,735, respectively.

6. Distributions to Unitholders

     The Trustee determines for each calendar 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 attributable to production from the Royalty Interests during such quarter, provided that such cash is received by the Trust on or before the last business day prior to the 45th day following the end of such calendar quarter, plus the amount of interest expected by the Trustee to be earned on such cash proceeds during the period between the date of receipt by the Trust of such cash proceeds and the date of payment to the Unitholders of such Quarterly Distribution Amount, plus all other cash receipts of the Trust during such quarter (to the extent not distributed or held for future distribution as a Special Distribution Amount (as defined below) or included in the previous Quarterly Distribution Amount) (which might include sales proceeds not sufficient in amount to qualify for a special distribution as described in the next paragraph), over the liabilities of the Trust paid during such

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quarter and not taken into account in determining a prior Quarterly Distribution Amount, 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. An amount that is not included in the Quarterly Distribution Amount for a calendar quarter because such amount is received by the Trust after the last business day prior to the 45th day following the end of such calendar quarter will be included in the Quarterly Distribution Amount for the next calendar quarter. The Quarterly Distribution Amount for each quarter will be payable to Unitholders of record on the 60th day following the end of such calendar quarter unless such day is not a business day in which case the record date is the next business day thereafter. The Trustee will distribute the Quarterly Distribution Amount for each quarter on or prior to 70 days after the end of such calendar quarter to each person who was a Unitholder of record on the record date for such calendar quarter.

     The Royalty Interests may be sold under certain circumstances and will be sold following termination of the Trust. A special distribution will be made of undistributed net sales proceeds and other amounts received by the Trust aggregating in excess of $10 million (a “Special Distribution Amount”). The record date for a Special Distribution Amount will be the 15th day following the receipt by the Trust of amounts aggregating a Special Distribution Amount (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 or less prior to the record date for a Quarterly Distribution Amount, in which case the record date for the Special Distribution Amount will be the same as the record date for the Quarterly Distribution Amount. Distribution to Unitholders of a Special Distribution Amount will be made no later than 15 days after the Special Distribution Amount record date.

7. Subsequent Events

     Subsequent to December 31, 2009, the Trust declared and paid the following distribution:

Quarterly		Distribution
Record Date	Payment Date	per Unit
March 1, 2010	March 11, 2010	$	0.272321

8. Quarterly Financial Data (Unaudited)

     The following table sets forth the royalty income, distributable income and distributable income per Unit of the Trust for each quarter in the years ended December 31, 2009 and 2008 (in thousands, except per Unit amounts):

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					Distributable
Calendar Quarter	Royalty Income		Distributable Income		Income per Unit
2009
First	$	4,773	$	4,362	$	0.56
Second		3,171		2,855		0.36
Third		2,319		2,105		0.27
Fourth		2,163		1,876		0.24
	$	12,426	$	11,198	$	1.43
2008
First	$	5,436	$	5,182	$	0.66
Second		5,922		5,636		0.72
Third		7,900		7,721		0.98
Fourth		7,279		7,106		0.91
	$	26,537	$	25,645	$	3.27

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

Royalty income	$	2,163
Interest income	$	1
General and administrative expenses		($288	)
Distributable income	$	1,876
Distributable income per Unit	$	0.24
Distributions per Unit	$	0.24

     Due to revisions in estimate of reserve quantities (see Note 9), estimated amortization of royalty interests increased by approximately $222,943, decreased by approximately $48,747 and increased by approximately $135,000, during the fourth quarters of 2009, 2008 and 2007, respectively. These adjustments did not have an impact on the Trust’s distributable income.

9. Supplemental Gas Disclosure (Unaudited)

     The net proved reserves attributable to the Royalty Interests have been estimated as of December 31, 2009, 2008, 2007, and January 1, 2007, by independent petroleum engineers.

     In accordance with FASB guidance, estimates of proved reserves and future net cash flows from proved reserves have been prepared using contractually guaranteed prices and average natural gas prices, and related costs. The standardized measure of future net cash flows from the gas reserves is calculated based on discounting such future net cash flows at an annual

59

rate of 10 percent. The average price for December 31, 2009, and the year-end prices for December 31, 2008 and December 31, 2007, were $3.699, $5.714, and $7.224 per Mcf, respectively. As of February 26, 2010, published Gas prices were approximately $4.82 per Mcf. The use of such price as compared to $3.70 per Mcf, which was used to calculate the below information, would result in a higher standardized measure of discounted future net cash flows for Gas.

     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 original estimates.

     Detailed information concerning the number of wells on royalty properties is not generally available to the owner of royalty interests. Consequently, the Registrant does not have information that would be disclosed by a company with oil and gas operations, such as an accurate count of the number of wells located on the Underlying Properties, the number of exploratory or development wells drilled on the Underlying Properties during the periods presented by this report, or the number of wells in process or other present activities on the Underlying Properties, and the Registrant cannot readily obtain such information.

     The reserve estimates for the Royalty Interests are based on a percentage share of the Company’s Gross Proceeds payable to the Trust of 65 percent.

Proved developed reserves at January 1, 2007	26,875
Revisions of previous estimates	(966	)
Production (MMcf)	(3,312	)
Proved developed reserves at December 31, 2007	22,597
Revisions of previous estimates	301
Production (MMcf)	(3,098	)
Proved developed reserves at December 31, 2008	19,800
Revisions of previous estimates	(1,292	)
Production (MMcf)	(2,758	)
Proved developed reserves at December 31, 2009	15,750

     All proved reserve estimates presented above at December 31, 2009, 2008, 2007 and January 1, 2007, are proved developed.

     Proved reserves, all located in the United States, for the Trust’s Interests are those quantities of coal seam gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The Trust’s proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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     The following table sets forth the standardized measure of discounted estimated future net cash flows from proved reserves at December 31, 2009, 2008 and 2007 relating to the Trust’s Royalty Interests (thousands of dollars):

	2009			2008			2007
Future cash inflows	$	55,145		$	102,862		$	150,179
Future severance taxes		(3,309	)		(6,171	)		(9,010	)
Future net cash flows		51,836			96,691			141,169
10% annual discount for estimated timing of cash flow		(19,311	)		(39,321	)		(56,320	)
Standardized measure of discounted future net cash flows	$	32,525		$	57,370		$	84,849

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

     The following table sets forth the changes in the present value of estimated future net cash flows from proved reserves during the period ended December 31, 2008, 2007 and 2006 (thousands of dollars):

	2009			2008			2007
Balance at beginning of period	$	57,370		$	84,849		$	84,686
Increase (decrease) due to:
Royalty income, net of taxes		(12,426	)		(26,537	)		(21,962	)
Changes in prices		(19,589	)		(21,711	)		22,619
Changes in estimated volumes		1,433			12,285			(8,962	)
Accretion of discount		5,737			8,485			8,469
Balance at December 31	$	32,525		$	57,370		$	84,849

10. Gas Purchase Agreement

     El Paso Merchant Energy–Gas, L.P. (“El Paso”), successor to Sonat Marketing Company (“Sonat Marketing”), was required under a gas purchase agreement (the “Gas Purchase Agreement”) to purchase the gas produced from the Underlying Properties until such agreement was terminated, effective January 31, 2004.

     Contracts were secured from various purchasers following termination of the Gas Purchase Agreement. A gas sales contract was entered into with SCANA Energy for base load gas for the period of November 1, 2005 through March 31, 2006. Separate gas sales contracts were entered into with Coral Energy and South Carolina Pipeline Company for base load gas for the period of April 1, 2006 through October 31, 2006. A gas sales contract was entered into with ConocoPhillips for base load gas for the period of November 1, 2006 through March 31, 2007. A gas sales contract was entered into with Coral Energy for base load gas for the period of April 1, 2007 through October 31, 2007. A gas sales contract was entered into with BP Energy for base load gas for the period of November 1, 2007 through March 31, 2008. Gas sales contracts were entered into with Atmos, BP Energy and ConocoPhillips for base load gas for the period April 1, 2008 through October 31, 2008. Gas sales contracts were entered into with Atmos, BP

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Energy, Chevron and Sequent for base load gas for the period November 1, 2008 through March 31, 2009. Gas sales contracts were entered into with Atmos, BP Energy, Chevron, ConocoPhillips and Sequent for base load gas for the period April 1, 2009 through October 31, 2009. Gas sales contracts were entered into with Atmos, BP Energy, Chevron and ConocoPhillips for base load gas for the period November 1, 2009 through March 31, 2010. During the terms of the above-mentioned contracts, any gas above the base load was sold on the spot market to various purchasers. The foregoing information regarding the gas purchase contracts has been provided to the Trustee by Dominion Resources and HighMount Alabama.

11. Contingencies

     The Trustee has been informed by the Company that the Trust has been named as a defendant in an action, styled Southwest Royalties, Inc. v. Dominion Black Warrior Basin, Inc., et al., filed in the Circuit Court of Fayette County Alabama on October 5, 2007 regarding the quieting of title in certain oil and gas rights related to property in Fayette and Tuscaloosa Counties in Alabama. The plaintiff alleges that defendants are knowingly producing gas in violation of the deeds in question. The plaintiff is also alleging conversion of gas, continuing trespass by defendants on plaintiff’s property, and suppression of material facts by defendants, and plaintiff is requesting an accounting, injunctive relief and compensatory and punitive damages, plus court costs and attorneys fees. The Trustee does not believe this litigation will have a material effect on the Trust’s financial statements.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

     As of the end of the period covered by this report, the Trustee carried out an evaluation of the effectiveness of the design and operation of the Trust’s disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15. Based upon that evaluation, the Trustee concluded that the Trust’s disclosure controls and procedures are effective in timely 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 Securities Exchange Act of 1934 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 Exchange 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 the Company.

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.

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Trustee’s Report on Internal Control Over Financial Reporting

     The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) 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 — modified cash basis (“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. The independent registered public accounting firm of Deloitte & Touche LLP, as auditors of the statements of assets, liabilities, and trust corpus, and the related statements of distributable income and changes in trust corpus for the period ended December 31, 2009, has issued an attestation report on the Trust’s internal control over financial reporting, which is included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Unit Holders of Dominion Resources Black Warrior Trust and Bank of America, N.A., Trustee

     We have audited the internal control over financial reporting of Dominion Resources Black Warrior Trust (the “Trust”) as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Trustee is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Trustee’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Trust’s internal control over financial reporting based on our audit.

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

     A trust’s internal control over financial reporting is a process designed by, or under the supervision of, the Trustee, or persons performing similar functions, and effected by the Trustee to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America and is described in Note 2 to the Trust’s financial statements. A trust’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the trust; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the modified cash basis of accounting discussed above, and that receipts and expenditures of the trust are being made only in accordance with authorizations of the Trustee; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the trust’s assets that could have a material effect on the financial statements.

     Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

     In our opinion, the Dominion Resources Black Warrior Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

     We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statements of assets, liabilities, and trust corpus of the Trust as of December 31, 2009 and the related statement of distributable income and changes in trust corpus for the year ended December 31 2009, which financial statements have been prepared on the modified cash basis of accounting as described in Note 2 to such financial statements, and our report dated March 16, 2010 expressed an unqualified opinion on those financial statements.

DELOITTE & TOUCHE LLP

Austin, TX
March 16, 2010

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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.

     Audit Committee and Nominating Committee. Because the Trust has no directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.

     Compliance with Section 16(a) of the Exchange Act. The Trust has no directors and officers and knows of no Unitholder that is a beneficial owner of more than 10 percent of the outstanding Units and is therefore unaware of any person that failed to report on a timely basis reports required by Section 16(a) of the Exchange Act.

     Code of Ethics. Because the Trust has no employees, it does not have a code of ethics. Employees of the Trustee, Bank of America, 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, Trustee, 901 Main Street, 17th Floor, Dallas, Texas 75202, Attention: Ron Hooper.

Item 11. Executive Compensation.

     Compensation Committee. Because the Trust has no directors, it does not have a compensation committee.

     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 HighMount Alabama, the Trustee, the Delaware Trustee, American Stock Transfer & Trust Company (the “Transfer Agent”) or their respective affiliates.

     Ongoing Administrative Expenses. The Trust is responsible for paying all fees, charges, expenses, disbursements and other costs incurred by the Trustee in connection with the discharge of its duties pursuant to the Trust Agreement, including, without limitation, trustee fees, engineering, audit, accounting and legal fees and expenses, printing and mailing costs, amounts reimbursed or paid to the Company or HighMount Alabama pursuant to the Trust Agreement or the Administrative Services Agreement and the out-of-pocket expenses of the Transfer Agent.

     Compensation of the Trustee. The Trust Agreement provides that the Trustee is to be compensated for its administrative services and preparation of quarterly and annual statements, out of the Trust assets, in an annual amount of $45,047, plus an hourly charge for services in excess of a combined total of 350 hours annually at its standard rate, which is currently $150 per

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hour. These service fees escalate by three percent annually. The Delaware Trustee is compensated for its administrative services, in an annual amount of $5,000, which will be paid by the Trustee. Each of the Trustee and the Delaware Trustee is 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 $10,000. If the Trustee resigns and a successor has not been appointed in accordance with the terms of the Trust Agreement within 210 days after the notice of resignation is received, the fee payable to the Trustee will increase significantly until a new trustee is appointed. During 2009, the Trustee and the Delaware Trustee received total compensation of $46,399 and $5,000, respectively.

     Compensation of the Transfer Agent. The Transfer Agent receives no annual transfer agency fee per account.

     Fees to HighMount Alabama. HighMount Alabama will receive throughout the term of the Trust an administrative services fee for accounting, bookkeeping and other administrative services relating to the Royalty Interests and the Underlying Properties as described in “Certain Relationships and Related Transactions, and Director Independence – Administrative Services Agreement.” Prior to July 2007, such services were performed by and the administrative services fee was paid to Dominion Resources.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

     Security Ownership of Certain Beneficial Owners. The Trustee knows of no Unitholder that is a beneficial owner of more than five percent of the outstanding Units.

     Security Ownership of Management. The Trust has no directors or executive officers. As of March 1, 2010, Bank of America, N.A., the Trustee, beneficially owned 10,197 units. Mellon Bank (DE) National Association, the Delaware Trustee, did not beneficially own any Units.

     Changes in Control. The Trustee knows of no arrangements the operation of which may at a subsequent date result in a change in control of the Registrant.

     Securities Authorized for Issuance Under Equity Compensation Plans. The Trust has no equity compensation plans.

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

Administrative Services Agreement

     Pursuant to the Trust Agreement, Dominion Resources and the Trust entered into the Administrative Services Agreement, pursuant to which the Trust is obligated, throughout the term of the Trust, to pay to Dominion Resources each quarter an administrative services fee for accounting, bookkeeping and other administrative services relating to the Royalty Interests and the Underlying Properties. In July 2007, HighMount Alabama assumed Dominion Resources’ obligations under the Administrative Services Agreement and is entitled to the administrative services fee. The annual fee, payable in equal quarterly installments, is currently $463,987 and will increase annually by three percent.

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     A copy of the Administrative Services Agreement is filed as an exhibit to this Form 10-K. The foregoing summary of the material provisions of the Administrative Services Agreement does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all the provisions of the Administrative Services Agreement.

HighMount Alabama’s Conditional Right of Repurchase

     Dominion Resources assigned its rights under the Trust Agreement to HighMount Alabama, including its right to repurchase all (but not less than all) outstanding Units at any time at which 15 percent or less of the outstanding Units is owned by persons or entities other than HighMount Alabama and its affiliates. Any such repurchase would generally be at a price equal to the greater of (i) the highest price at which HighMount Alabama or any of its affiliates acquired Units during the 90 days immediately preceding the Determination Date and (ii) the average closing price of Units on the NYSE for the 30 trading days immediately preceding the Determination Date. Any such repurchase would be conducted in accordance with applicable Federal and state securities laws. See “Business—Description of Units—Conditional Right of Repurchase.”

Potential Conflicts of Interest

     The interests of HighMount Alabama and its affiliates and the interests of the Trust and the Unitholders with respect to the Underlying Properties could at times be different. The following is a summary of certain conflicts of interest:

     Obligations of Company Interests Owner may exceed its share of distributions and tax credits. As a Working Interest owner in the Underlying Properties, the Company Interests Owner is responsible for an average of approximately 98 percent of the operating costs of the Existing Wells but only entitled to approximately 28 percent of the revenues therefrom, after giving effect to the Royalty Interests. Based on the Reserve Estimate, beginning in the year 2000, the projected operating costs to be borne by the Company Interests Owner were anticipated to exceed its projected share of Gross Proceeds and Section 29 tax credits (before the Section 29 tax credit expired for coal seam gas produced and sold after 2002). The terms of the Conveyance provide, however, that the Company Interests Owner will make decisions with respect to the Company Interests pursuant to the standard of a reasonably prudent operator.

     Sale or abandonment of Underlying Properties may terminate assurances. The Company Interests Owner’s interests may conflict with those of the Trust and Unitholders in situations involving the sale or abandonment of Underlying Properties. The Company Interests Owner has the right at any time to sell any of the Underlying Properties subject to the Royalty Interests and may abandon a well or lease included in the Underlying Properties if such well or lease is not capable of producing in commercial quantities, determined before giving effect to the Royalty Interests. Under certain circumstances, a sale or abandonment will effectively terminate HighMount Alabama’s assurances of the Company Interests Owner’s obligation to the Trust with respect to the Underlying Properties sold or abandoned. Such sales or abandonment may not be in the best interest of the Trust or the Unitholders.

     HighMount Alabama may profit from contracts with the Trust. The amount that HighMount Alabama may charge for services it renders under the Administrative Services

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Agreement is established in such contract at rates that do not necessarily take into account the actual cost of rendering such services by HighMount Alabama. Accordingly, HighMount Alabama may profit or suffer losses in connection with the performance of such contract.

Item 14. Principal Accounting Fees and Services.

     Fees for services performed by Deloitte & Touche LLP for the years ended December 31, 2009 and 2008 are:

	2009		2008
Audit Fees	$	182,500	$	71,000
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—
	$	182,500	$	71,000

     As referenced in Item 10 above, the Trust has no audit committee, and as a result, has no audit committee pre-approval policy with respect to fees paid to Deloitte & Touche LLP.

PART IV.

Item 15. Exhibits, Financial Statement Schedules. (a) The following documents are filed as a part of this report:

Financial Statements (included in Item 8 of this report)

Report of Independent Registered Public Accounting Firm

Statements of Assets, Liabilities and Trust Corpus as of December 31, 2009 and 2008

Statements of Distributable Income for the years ended December 31, 2009, 2008 and 2007

Statements of Changes in Trust Corpus for the years ended December 31, 2009, 2008 and 2007

Notes to Financial Statements

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.

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Exhibits

No.			Exhibit
	3.1	—	Trust Agreement of Dominion Resources Black Warrior Trust dated as of May 31, 1994, by and among Dominion Black Warrior Basin, Inc., Dominion Resources, Inc., Mellon Bank (DE) National Association and NationsBank, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 3.1 to Dominion Resources, Inc.’s Registration Statement* on Form S-3 (No. 33-53513), and incorporated herein by reference).
	3.2	—	First Amendment of Trust Agreement of Dominion Resources Black Warrior Trust dated as of June 27, 1994, by and among Dominion Black Warrior Basin, Inc., Dominion Resources, Inc., Mellon Bank (DE) National Association and NationsBank, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 3.2 to the Registrant’s Form 10-Q for the quarter ended June 30, 1994 and incorporated herein by reference).
	10.1	—	Overriding Royalty Conveyance dated as of June 28, 1994, from Dominion Black Warrior Basin, Inc. to Dominion Resources Black Warrior Trust (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 1994 and incorporated herein by reference).
	10.2	—	Administrative Services Agreement dated as of June 1, 1994, by and between Dominion Resources, Inc. and Dominion Resources Black Warrior Trust (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarter ended June 30, 1994 and incorporated herein by reference).
	10.3	—	Amendment to and Ratification of Overriding Royalty Conveyance dated as of November 20, 1994, among Dominion Black Warrior Basin, Inc., NationsBank, N.A. (as successor to NationsBank of Texas, N.A.), and Mellon Bank (DE) National Association (filed as Exhibit 10.3 to the Registrant’s Form 10-K for the year ended December 31, 1994 and incorporated herein by reference).
	10.4	—	Gas Purchase Agreement, dated as of May 3, 1994, between Sonat Marketing and the Company (filed as Exhibit 10.2 to Dominion Resources, Inc.’s Registration Statement* on Form S-3 (No. 33-53513), and incorporated herein by reference).
	10.5	—	Amendment to Gas Purchase Agreement dated May 16, 1996, between Sonat Marketing and the Company (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 1996 and incorporated herein by reference).
	10.6	—	Amendment to Gas Purchase Agreement dated April 9, 1998, between Sonat Marketing and the Company (filed as Exhibit 10.6 to the Registrant’s Form 10-K for the year ended December 31, 1998 and incorporated herein by reference).

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No.			Exhibit
	10.7	—	Amendment to Gas Purchase Agreement dated July 1, 1999, between Sonat Marketing and the Company (filed as Exhibit 10.7 to the Registrant’s Form 10-K for the year ended December 31, 1999 and incorporated herein by reference).
	10.8	—	Amendment to Gas Purchase Agreement dated July 1, 2000, between El Paso Merchant Energy-Gas, L.P., as successor to Sonat Marketing Company, and the Company (filed as an exhibit to the Registrant’s Form 10-Q for the quarter ended September 30, 2000 and incorporated herein by reference).
	10.9	—	Amendment to Gas Purchase Agreement dated July 1, 2001, between El Paso Merchant Energy-Gas, L.P., as successor to Sonat Marketing Company, and the Company (filed as an exhibit to the Registrant’s Form 10-Q for the quarter ended September 30, 2001 and incorporated herein by reference).
	10.10	—	Amendment to Gas Purchase Agreement dated July 1, 2002 between El Paso Merchant Energy-Gas, L.P., as successor to Sonat Marketing Company, and the Company (filed as an exhibit to the Registrant’s Form 10-Q for the quarter ended September 30, 2002 and incorporated herein by reference).
	10.11	—	Assignment and Assumption Agreement, dated as of July 31, 2007, between Dominion Resources and HighMount Exploration & Production Alabama LLC (filed as an exhibit to the Registrant’s Form 10-Q for the quarter ended June 30, 2007 and incorporated herein by reference).
	23.1	—	Consent of Ralph E. Davis Associates, Inc., independent petroleum engineers.
	31.1	—	Certification required by Rule 13a-14(a)/15d-14(a).
	32.1	—	Certification required by Rule 13a-14(b)/15d-14(b) and Section 906 of the Sarbanes Oxley Act of 2002.
	99.1	—	The information under the sections captioned “Federal Income Tax Consequences” and “‘ERISA’ Considerations” of the Prospectus dated June 21, 1994, which constitutes a part of the Registration Statement on Form S-3 of Dominion Resources, Inc.* (Registration No. 33-53513) and is incorporated herein by reference.
	99.2	—	Summary of Reserve Report, dated February 25, 2010, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests as of December 31, 2009, prepared by Ralph E. Davis & Associates Petroleum Engineers, independent petroleum engineers.

* On its own behalf and as sponsor of the Dominion Resources Black Warrior Trust

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SIGNATURES

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

Dominion Resources Black Warrior Trust
By:	Bank of America, N.A., Trustee
By:	/s/ Ron E. Hooper
	Ron E. Hooper
	Senior Vice President and Administrator

Date: March 16, 2010

(The Registrant has no directors or executive officers.)

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Index to Exhibits

No.			Exhibit
	3.1	—	Trust Agreement of Dominion Resources Black Warrior Trust dated as of May 31, 1994, by and among Dominion Black Warrior Basin, Inc., Dominion Resources, Inc., Mellon Bank (DE) National Association and NationsBank, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 3.1 to Dominion Resources, Inc.’s Registration Statement* on Form S-3 (No. 33-53513), and incorporated herein by reference).
	3.2	—	First Amendment of Trust Agreement of Dominion Resources Black Warrior Trust dated as of June 27, 1994, by and among Dominion Black Warrior Basin, Inc., Dominion Resources, Inc., Mellon Bank (DE) National Association and NationsBank, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 3.2 to the Registrant’s Form 10-Q for the quarter ended June 30, 1994 and incorporated herein by reference).
	10.1	—	Overriding Royalty Conveyance dated as of June 28, 1994, from Dominion Black Warrior Basin, Inc. to Dominion Resources Black Warrior Trust (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 1994 and incorporated herein by reference).
	10.2	—	Administrative Services Agreement dated as of June 1, 1994, by and between Dominion Resources, Inc. and Dominion Resources Black Warrior Trust (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarter ended June 30, 1994 and incorporated herein by reference).
	10.3	—	Amendment to and Ratification of Overriding Royalty Conveyance dated as of November 20, 1994, among Dominion Black Warrior Basin, Inc., NationsBank, N.A. (as successor to NationsBank of Texas, N.A.), and Mellon Bank (DE) National Association (filed as Exhibit 10.3 to the Registrant’s Form 10-K for the year ended December 31, 1994 and incorporated herein by reference).
	10.4	—	Gas Purchase Agreement, dated as of May 3, 1994, between Sonat Marketing and the Company (filed as Exhibit 10.2 to Dominion Resources, Inc.’s Registration Statement* on Form S-3 (No. 33-53513), and incorporated herein by reference).
	10.5	—	Amendment to Gas Purchase Agreement dated May 16, 1996, between Sonat Marketing and the Company (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 1996 and incorporated herein by reference).
	10.6	—	Amendment to Gas Purchase Agreement dated April 9, 1998, between Sonat Marketing and the Company (filed as Exhibit 10.6 to the Registrant’s Form 10-K for the year ended December 31, 1998 and incorporated herein by reference).

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No.			Exhibit
	10.7	—	Amendment to Gas Purchase Agreement dated July 1, 1999, between Sonat Marketing and the Company (filed as Exhibit 10.7 to the Registrant’s Form 10-K for the year ended December 31, 1999 and incorporated herein by reference).
	10.8	—	Amendment to Gas Purchase Agreement dated July 1, 2000, between El Paso Merchant Energy-Gas, L.P., as successor to Sonat Marketing Company, and the Company (filed as an exhibit to the Registrant’s Form 10-Q for the quarter ended September 30, 2000 and incorporated herein by reference).
	10.9	—	Amendment to Gas Purchase Agreement dated July 1, 2001, between El Paso Merchant Energy-Gas, L.P., as successor to Sonat Marketing Company, and the Company (filed as an exhibit to the Registrant’s Form 10-Q for the quarter ended September 30, 2001 and incorporated herein by reference).
	10.10	—	Amendment to Gas Purchase Agreement dated July 1, 2002 between El Paso Merchant Energy-Gas, L.P., as successor to Sonat Marketing Company, and the Company (filed as an exhibit to the Registrant’s Form 10-Q for the quarter ended September 30, 2002 and incorporated herein by reference).
	10.11	—	Assignment and Assumption Agreement, dated as of July 31, 2007, between Dominion Resources and HighMount Exploration & Production Alabama LLC (filed as an exhibit to the Registrant’s Form 10-Q for the quarter ended June 30, 2007 and incorporated herein by reference).
	23.1	—	Consent of Ralph E. Davis Associates, Inc., independent petroleum engineers.
	31.1	—	Certification required by Rule 13a-14(a)/15d-14(a).
	32.1	—	Certification required by Rule 13a-14(b)/15d-14(b) and Section 906 of the Sarbanes Oxley Act of 2002.
	99.1	—	The information under the sections captioned “Federal Income Tax Consequences” and “‘ERISA’ Considerations” of the Prospectus dated June 21, 1994, which constitutes a part of the Registration Statement on Form S-3 of Dominion Resources, Inc.* (Registration No. 33-53513) and is incorporated herein by reference.
	99.2	—	Summary of Reserve Report, dated February 25, 2010, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests as of December 31, 2009, prepared by Ralph E. Davis & Associates Petroleum Engineers, independent petroleum engineers.

* On its own behalf and as sponsor of the Dominion Resources Black Warrior Trust

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EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

Ralph E. Davis Associates, Inc. hereby consents to the reference to our firm and to its having prepared a report of DOMINION RESOURCES BLACK WARRIOR TRUST (the “Company”), and an estimate of the proved gas reserves for the fiscal year ended December 31, 2009. We hereby further consent to the use of the report dated March 16, 2010 appearing in the Company’s Form 10-K for the year ended December 31, 2009 and in all current and future registration statements of the Company that incorporate by reference such Form 10-K.

RALPH E. DAVIS ASSOCIATES, INC.
By:	/s/ Allen C. Barron
	Name:	Allen C. Barron
	Title:	President

March 16, 2010

Consultants to the Oil and Natural Gas Industries Since the 1920’s

EX-31.1

Exhibit 31.1

Certification Required by Rule 13a-14(a)
or Rule 15d-14(a)

I, Ron Hooper, certify that:

1. I have reviewed this report on Form 10-K of Dominion Resources Black Warrior Trust, for which Bank of America, N.A., acts as Trustee;

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

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

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

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

In giving the certifications in paragraphs 4 and 5 above, I have relied to the extent I consider reasonable on information provided to me by Dominion Black Warrior Basin, Inc.

Date: March 16, 2010

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

EX-32.1

Exhibit 32.1

Certification required by Rule 13a-14(b) or
Rule 15d-14(b) and Section 906 of
the Sarbanes-Oxley Act of 2002

     In connection with the Annual Report of Dominion Resources Black Warrior Trust (the “Trust”) on Form 10-K for the period ended December 31, 2009, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, not in its individual capacity but solely as the trustee of the Trust, certifies pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to its knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.

	BANK OF AMERICA, N.A., TRUSTEE FOR DOMINION RESOURCES BLACK WARRIOR TRUST
March 16, 2010	By:	/s/ Ron E. Hooper
		Ron E. Hooper,
		Senior Vice President, Royalty Management Bank of America, N.A.

A signed original of this written statement required by Section 906 has been provided to Dominion Resources Black Warrior Trust and will be retained by Dominion Resources Black Warrior Trust and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.2

Exhibit 99.2

February 25, 2010

Dominion Black Warrior Trust 1994-1
c/o U.S. Trust, Bank of America Private Wealth Management
P. O. Box 830650
Dallas, Texas 75283

Attn: Mr. Ron E. Hooper
Sr. Vice President, Trustee

Re: Estimated Reserves and Non Escalated Future
Net Revenue Remaining as of December 31, 2009
Dominion Black Warrior Trust 1994-1

Gentlemen:

At your request the firm of Ralph E. Davis Associates, Inc. of Houston, Texas has prepared an estimate of the natural gas reserves on specific leaseholds in which Dominion Black Warrior Trust 1994-1 (the Trust) has certain interests. The interests evaluated are a royalty interest ownership position applicable to specific gas properties in the Black Warrior Basin, Tuscaloosa County, Alabama. This report presents our estimate of the proved reserves anticipated to be produced from those leaseholds and remaining as of December 31, 2009.

Davis has reviewed 100% of the Trust’s proved developed properties located in the Black Warrior Basin area of Alabama. It is our opinion that these properties represent all of the Trust’s natural gas assets that may be classified as proved as per the Securities Exchange Commission directives as detailed later in this report.

The reserves associated with this review have been classified in accordance with the definitions of the Securities and Exchange Commission as found in Part 210—Form and Content of and Requirements for Financial Statements, Securities Act of 1933, Securities Exchange Act of 1934, Public Utility Holding Company Act of 1935, Investment Company Act of 1940, Investment Advisers Act of 1940, and Energy Policy and Conservation Act of 1975, under Rules of General Application § 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and Conservation Act of 1975. A summation of these definitions is included as a portion of this letter.

We have also estimated the future net revenue and discounted present value associated with these reserves as of December 31, 2009, utilizing a scenario of non-escalated product prices

Dominion Black Warrior Trust 1994-1	February 25, 2010
Mr. Ron E. Hooper, Trustee	Page 2

as well as non-escalated costs of operations, i.e., prices and costs were not escalated above current values as detailed later in this report. The present value is presented for your information and should not be construed as an estimate of the fair market value.

The results of our study may be summarized as follows:

Non Escalated Pricing Scenario
Estimated Reserves and Future Net Income
Net to Dominion Black Warrior Basin Trust 1994-1
As of December 31, 2009

	Total Proved
Net Remaining Sales Gas Reserves:
Gas: Mcf		15,749,550
Future Revenue:
Sales Revenue	$	55,145,422
Tax Credit Revenue		0
Total Revenue	$	55,145,422
Production Taxes	$	3,308,725
Other Deductions		0
Future Net Income	$	51,836,703
Future Net Income Discounted @ 10%	$	32,525,078

The Section 29 Tax Credit that was in effect in previous years is no longer applicable as of January 1, 2003.

Gas volumes are expressed in millions of standard cubic feet (MMSCF) at the official temperature and pressure bases of the areas wherein the gas reserves are located.

DATA SOURCE

Basic well and field data used in the preparation of this report were furnished by HighMount Exploration & Production LLC (HighMount), the operator, or were obtained from commercial sources. Records as they pertain to factual matters such as acreage controlled, the number and depths of wells, production history, the existence of contractual obligations to others and similar matters were accepted as presented.

RALPH E. DAVIS ASSOCIATES, INC.
Texas Registered Engineering Firm F-1529

Dominion Black Warrior Trust 1994-1	February 25, 2010
Mr. Ron E. Hooper, Trustee	Page 3

Ownership interest, operating costs and information related to contractual obligations regarding the sale of produced gas were furnished by HighMount. No physical inspection of the properties was made nor any well tests conducted.

RESERVE ESTIMATES

The estimate of reserves included in this report is based primarily upon production history, or analogy with wells in the area producing from the same or similar formations. Individual well production histories were analyzed and forecast until an anticipated economic limit. The economic limit was based upon an analysis of overall field operating costs and an appropriate daily producing rate was utilized for each individual well. The data utilized, assumptions made and methods and procedures used are considered appropriate for the estimates made and purposes for which this report was prepared.

Future production for the unit was then analyzed as it applies to the total revenue stream. Future production was forecast until the unit operations would no longer be economical, and this future point in time was then utilized as a terminus of production from the area of interest.

The reserves included in this report are estimates only and should not be construed as being exact quantities. The accuracy of the estimates is dependent upon the quality of available data and upon the independent geological and engineering interpretation of that data. The quantities presented herein are estimated reserves of natural gas that geologic and engineering data demonstrate can be recovered from known reservoirs under current economic conditions with reasonable certainty. Reserve estimates presented in this report are calculated using acceptable methods and procedures and are believed to be appropriate and reasonable; however, future reservoir performance may justify revision of these estimates.

PRODUCING RATES

For the purpose of this report, estimated reserves are scheduled for recovery primarily on the basis of actual producing rates or appropriate well test information. They were prepared giving consideration to engineering and geological data such as reservoir pressure, anticipated producing mechanisms, the number and types of completions, as well as past performance of analogous reservoirs.

These and other future rates may be subject to regulation by various agencies, changes in market demand or other factors; consequently, reserves recovered and the actual rates of recovery may vary from the estimates included herein. Scheduled dates of future well completions may vary from that provided by Highmount due to changes in market demand or the availability of materials and/or capital; however, the timing of the wells and their

RALPH E. DAVIS ASSOCIATES, INC.
Texas Registered Engineering Firm F-1529

Dominion Black Warrior Trust 1994-1	February 25, 2010
Mr. Ron E. Hooper, Trustee	Page 4

estimated rates of production are reasonable and consistent with established performance to date.

PRICING PROVISIONS

Prices utilized in the evaluation results presented in the letter portion of this report and summarized in the various tables included in this evaluation were based upon certain data furnished by the operator. Prices received for products sold, adjustments due to the BTU content of the gas, shrinkage for transportation, etc., were accepted as presented.

Natural Gas - The unit price used throughout this report for natural gas is an initial price of $3.68 per MMBTU, based upon the appropriate price in effect the first trading of each month during calendar 2009, and averaged for the year. This price is representative of the price in effect for sales based upon the Sonat T1 price on that trading day. A basis differential was applied to all sales volumes, and this differential as well as the price for gas was held constant throughout the producing life of the property. Prices for gas reserves scheduled for initial production at some future date were estimated using this same price.

FUTURE NET INCOME

Future net income is based upon gross income from future production, less appropriate taxes (production, severance, ad valorem or other). Operating costs and any estimated future capital requirements were not considered in the estimation of net income due to the Trust’s royalty ownership position. No allowance was made for depletion, depreciation, income taxes or administrative expense.

Future net income has been discounted for present worth at values ranging from 0 to 100 percent using monthly discounting. In this report the future net income is discounted at a primary rate of ten (10.0) percent.

GENERAL

HighMount Exploration & Production LLC as operator has provided access to all of its accounts, records, geological and engineering data, reports and other information as required for this investigation. The ownership interests, product classifications relating to prices and other factual data were accepted as furnished without verification.

No consideration was given in this report to either gas contract disputes including take or pay demands or gas sales imbalances.

No consideration was given in this report to potential environmental liabilities which may exist, nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices.

RALPH E. DAVIS ASSOCIATES, INC.
Texas Registered Engineering Firm F-1529

Dominion Black Warrior Trust 1994-1	February 25, 2010
Mr. Ron E. Hooper, Trustee	Page 5

The estimates of reserves and the forecasted rates of production may be subject to regulation by various agencies, changes in market demand or other factors; consequently, the volumes of reserves recovered and the actual rates of recovery may vary from the estimates included herein.

If investments or business decisions are to be made in reliance on these estimates by anyone other than our client, such person with the approval of our client is invited to arrange a visit so that he can evaluate the assumptions made and the completeness and extent of the data available on which the estimates are made.

Neither Ralph E. Davis Associates, Inc. nor its employees has any interest in the subject properties and neither the employment to make this study nor our compensation is contingent on our estimates of reserves and future income for the subject properties.

This report has been prepared for the exclusive use of Dominion Black Warrior Basin Trust 1994-1 and shall not be reproduced, distributed or made available to any other company without the written consent of Ralph E. Davis Associates, Inc. Such consent will not be unreasonably withheld if the report is utilized in its entirety.

Very truly yours,

RALPH E. DAVIS ASSOCIATES, INC.


Allen C. Barron, P.E.
President

RALPH E. DAVIS ASSOCIATES, INC.
Texas Registered Engineering Firm F-1529

SECURITIES AND EXCHANGE COMMISSION
DEFINITIONS OF RESERVES

The following information is taken from the United States Securities and Exchange Commission:

PART 210—FORM AND CONTENT OF AND REQUIREMENTS FOR FINANCIAL STATEMENTS, SECURITIES ACT OF 1933, SECURITIES EXCHANGE ACT OF 1934, PUBLIC UTILITY HOLDING COMPANY ACT OF 1935, INVESTMENT COMPANY ACT OF 1940, INVESTMENT ADVISERS ACT OF 1940, AND ENERGY POLICY AND CONSERVATION ACT OF 1975

Rules of General Application

§ 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and Conservation Act of 1975.

Reserves

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

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

Proved Oil and Gas Reserves

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

(i) The area of the reservoir considered as proved includes:

     (A) The area identified by drilling and limited by fluid contacts, if any, and

     (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

     (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

Securities and Exchange Commission	Page 2
§210.4-10 Definitions (of Reserves)
Modified, Effective 2009 for Filings of 12/31/2009 and Thereafter

     (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

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

Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Probable Reserves

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

     (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

     (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

     (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Possible Reserves

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

     (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

     (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

     (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

     (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

     (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than

Securities and Exchange Commission	Page 3
§210.4-10 Definitions (of Reserves)
Modified, Effective 2009 for Filings of 12/31/2009 and Thereafter

formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

     (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

Developed Oil and Gas Reserves

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

     (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

     (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped Oil and Gas Reserves

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

     (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

     (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

     (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

Additional Definitions:

Deterministic Estimate

The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

Probabilistic Estimate

The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

Reasonable Certainty

If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

DOMINION BLACK WARRIOR TRUST 1994-1
UNESCALATED ANALYSIS
TOTAL ROYALTY INTERESTS
TOTAL PROVED RESERVES

RESERVES AND ECONOMICS

EFFECTIVE DATE: 12/31/2009

			-----GROSS PRODUCTION-----						-----NET PRODUCTION-----				-----PRICES-----				-----OPERATIONS, M$-----
---END---	NO. OF		OIL		WELL HEAD		SALES		OIL		SALES		OIL		GAS		OIL		GAS		TAX		TOTAL
MO-YEAR	WELLS		MBBL		GAS, MMCF		GAS, MMCF		MBBL		GAS, MMCF		$/B		$/M		REVENUE		REVENUE		CREDITS		REVENUE
12-2010		475.2		0.000		4783.229		4200.153		0.000		2237.007		0.00		3.696		0.000		8266.930		0.000		7804.644
12-2011		455.7		0.000		4185.707		3675.471		0.000		1959.696		0.00		3.696		0.000		7242.794		0.000		6838.100
12-2012		434.5		0.000		3663.226		3216.678		0.000		1716.467		0.00		3.696		0.000		6344.448		0.000		5990.840
12-2013		410.6		0.000		3196.429		2806.784		0.000		1499.335		0.00		3.697		0.000		5542.487		0.000		5235.877
12-2014		380.8		0.000		2767.399		2430.053		0.000		1298.986		0.00		3.697		0.000		4802.597		0.000		4540.284
12-2015		340.2		0.000		2352.969		2066.143		0.000		1106.317		0.00		3.698		0.000		4091.231		0.000		3870.193
12-2016		297.5		0.000		1981.380		1739.850		0.000		933.040		0.00		3.699		0.000		3451.483		0.000		3267.811
12-2017		257.3		0.000		1660.303		1457.913		0.000		783.737		0.00		3.700		0.000		2900.176		0.000		2746.627
12-2018		223.2		0.000		1395.048		1224.991		0.000		659.802		0.00		3.702		0.000		2442.414		0.000		2314.472
12-2019		190.0		0.000		1161.442		1019.862		0.000		550.237		0.00		3.703		0.000		2037.715		0.000		1932.936
12-2020		164.2		0.000		975.389		856.490		0.000		462.997		0.00		3.705		0.000		1715.324		0.000		1629.743
12-2021		142.7		0.000		824.598		724.080		0.000		391.997		0.00		3.706		0.000		1452.842		0.000		1380.790
12-2022		120.0		0.000		686.596		602.900		0.000		326.838		0.00		3.708		0.000		1211.980		0.000		1151.497
12-2023		100.2		0.000		570.539		500.990		0.000		271.808		0.00		3.710		0.000		1008.503		0.000		958.305
12-2024		81.1		0.000		465.555		408.804		0.000		222.436		0.00		3.713		0.000		825.952		0.000		785.206
S TOT		1.8		0.000		30669.811		26931.162		0.000		14420.699		0.00		3.699		0.000		53336.879		0.000		50447.320
AFTER		1.8		0.000		2759.472		2423.093		0.000		1328.851		0.00		3.705		0.000		4923.945		0.000		4698.100
TOTAL		1.8		0.000		33429.281		29354.254		0.000		15749.550		0.00		3.699		0.000		58260.824		0.000		55145.422

	-------OPERATIONS, M$-------								-------CAPITAL COSTS, M$-------										10.0%
---END---	PRODUCTION		AD VALOREM		NET OPER		OPERATION		TANGIBLE		INTANG.		TOTAL		TOTAL		CASH FLOW		DISCOUNTED
---MO-YEAR---	TAXES		EXPENSES		EXPENSES		CASH FLOW		INV.		INV.		BORROW INV		EQUITY INV		BTAX, M$		BTAX, M$
12-2010		468.278		0.000		0.000		7336.363		0.000		0.000		0.000		0.000		7336.363		7004.635
12-2011		410.286		0.000		0.000		6427.813		0.000		0.000		0.000		0.000		6427.813		5579.540
12-2012		359.451		0.000		0.000		5631.393		0.000		0.000		0.000		0.000		5631.393		4443.766
12-2013		314.153		0.000		0.000		4921.726		0.000		0.000		0.000		0.000		4921.726		3530.913
12-2014		272.417		0.000		0.000		4267.867		0.000		0.000		0.000		0.000		4267.867		2783.788
12-2015		232.212		0.000		0.000		3637.982		0.000		0.000		0.000		0.000		3637.982		2157.324
12-2016		196.069		0.000		0.000		3071.743		0.000		0.000		0.000		0.000		3071.743		1656.138
12-2017		164.798		0.000		0.000		2581.829		0.000		0.000		0.000		0.000		2581.829		1265.527
12-2018		138.868		0.000		0.000		2175.603		0.000		0.000		0.000		0.000		2175.603		969.361
12-2019		115.976		0.000		0.000		1816.959		0.000		0.000		0.000		0.000		1816.959		735.936
12-2020		97.785		0.000		0.000		1531.959		0.000		0.000		0.000		0.000		1531.959		564.041
12-2021		82.847		0.000		0.000		1297.942		0.000		0.000		0.000		0.000		1297.942		434.524
12-2022		69.090		0.000		0.000		1082.407		0.000		0.000		0.000		0.000		1082.407		329.443
12-2023		57.498		0.000		0.000		900.806		0.000		0.000		0.000		0.000		900.806		249.197
12-2024		47.112		0.000		0.000		738.094		0.000		0.000		0.000		0.000		738.094		185.755
S TOT		3026.839		0.000		0.000		47420.492		0.000		0.000		0.000		0.000		47420.492		31889.889
AFTER		281.886		0.000		0.000		4416.213		0.000		0.000		0.000		0.000		4416.213		635.191
TOTAL		3308.725		0.000		0.000		51836.703		0.000		0.000		0.000		0.000		51836.703		32525.078

	OIL		GAS				P.W. %		P.W., M$
GROSS WELLS		0.0		532.0	LIFE, YRS.	42.42		5.00		39776.484
GROSS ULT., MB & MMF		0.000		193055.812	DISCOUNT %	10.00		10.00		32525.070
GROSS CUM., MB & MMF		0.000		159626.531	UNDISCOUNTED PAYOUT, YRS.	0.00		15.00		27669.428
GROSS RES., MB & MMF		0.000		33429.281	DISCOUNTED PAYOUT, YRS.	0.00		18.00		25454.299
NET RES., MB & MMF		0.000		15749.551	UNDISCOUNTED NET/INVEST.	0.00		20.00		24185.990
NET REVENUE, M$		0.000		58260.824	DISCOUNTED NET/INVEST.	0.00		25.00		21564.266
INITIAL PRICE, $		0.000		3.693	RATE-OF-RETURN, PCT.	100.00		40.00		16537.217
INITIAL N.I., PCT.		0.000		53.335	INITIAL W.I., PCT.	0.000		60.00		12942.846
								80.00		10849.019
								100.00		9473.192

RALPH E. DAVIS ASSOCIATES, INC.
TEXAS REGISTERED FIRM F-1529

BLACK WARRIOR TRUST 1994-1	RESERVES and REVENUES
TOTAL ROYALTY INTERESTS	AS OF DECEMBER 31, 2009
TOTAL PROVED RESERVES

									Gross Volumes						Net Volumes				Product		Production		Operating		Future Net Income
	Life		Working			Revenue			Oil		Wellhead Gas		Sales Gas		Oil		Sales Gas		Sales		Taxes		Expense		Undiscounted		Disc. @ 10%
Well Name & Number	Years		Interest			Interest			Bbls		Mcf		Mcf		Bbls		Mcf		$		$		$		$		$
ALABAMA BASIC 23-10- 4		28.3		0.00000	%		56.87502	%		0		285,353		250,568		0		142,511		476,671		28,600		0		448,070		216,384
ALABAMA BASIC 23-14- 5		7.0		0.00000	%		56.87502	%		0		42,110		36,977		0		21,031		70,344		4,221		0		66,123		51,165
ALABAMA BASIC 23-16- 6		5.5		0.00000	%		56.87502	%		0		30,203		26,521		0		15,084		50,453		3,027		0		47,425		38,402
ALABAMA BASIC 26- 1- 7		6.2		0.00000	%		56.87502	%		0		37,025		32,511		0		18,491		61,848		3,711		0		58,137		46,292
ALABAMA BASIC 27-16- 8		11.6		0.00000	%		57.20324	%		0		95,991		84,290		0		48,216		161,274		9,676		0		151,598		105,144
ALABAMA BASIC 34- 3-14		21.9		0.00000	%		56.79375	%		0		80,757		70,913		0		40,274		450,667		27,040		0		423,627		246,911
ALABAMA BASIC 36- 2- 2		4.6		0.00000	%		58.18800	%		0		21,479		18,860		0		10,974		36,707		2,202		0		34,505		28,687
ALABAMA BASIC 36- 4- 1		6.6		0.00000	%		58.18800	%		0		33,730		29,618		0		17,234		57,645		3,459		0		54,186		42,083
ALABAMA BASIC 36- 5- 9		6.3		0.00000	%		56.26400	%		0		32,554		28,586		0		16,084		53,797		3,228		0		50,569		39,651
ALABAMA BASIC 36- 9- 3		10.2		0.00000	%		58.18800	%		0		58,829		51,657		0		30,058		100,539		6,032		0		94,507		65,752
ALABAMA BASIC 36-13-10		13.1		0.00000	%		58.18800	%		0		73,384		64,439		0		37,496		137,983		8,279		0		129,704		83,424
ALABAMA BASIC 36-14-11		5.3		0.00000	%		58.18800	%		0		22,779		20,002		0		11,639		42,831		2,570		0		40,261		32,563
ALABAMA BASIC 36-16-12		16.3		0.00000	%		58.18800	%		0		100,090		87,889		0		51,141		188,198		11,292		0		176,906		105,436
ALCUS 12- 4- 1		4.1		0.00000	%		54.84375	%		0		14,500		12,732		0		6,983		25,697		1,542		0		24,155		20,205
ALCUS 12- 5- 2		0.0		0.00000	%		54.19375	%		0		0		0		0		0		0		0		0		0		0
BAUGHMAN 18- 3- 2		8.4		0.00000	%		56.87500	%		0		62,655		55,017		0		31,291		104,662		6,280		0		98,383		74,046
BAUGHMAN 18- 6- 3		16.3		0.00000	%		56.87500	%		0		133,236		116,994		0		66,540		244,869		14,692		0		230,177		142,606
BAUGHMAN 18- 7- 4		13.2		0.00000	%		56.87500	%		0		84,501		74,200		0		42,201		155,301		9,318		0		145,983		95,079
BEAN 14-15- 1		4.8		0.00000	%		55.76460	%		0		23,140		20,320		0		11,331		37,900		2,274		0		35,626		29,408
BIGHAM 4-13- 1		4.3		0.00000	%		56.87500	%		0		26,034		22,860		0		13,002		47,847		2,871		0		44,976		38,453
CANTLEY 17- 7- 2		1.3		0.00000	%		56.87500	%		0		4,309		3,784		0		2,152		7,919		475		0		7,444		7,039
CARNLEY 18- 5- 3		8.1		0.00000	%		61.70529	%		0		47,918		42,077		0		25,964		86,844		5,211		0		81,633		61,357
CARNLEY 18-12- 4		14.3		0.00000	%		61.70528	%		0		140,538		123,406		0		76,148		254,700		15,282		0		239,418		159,331
CARNLEY 18-14- 5		8.8		0.00000	%		61.70528	%		0		93,800		82,366		0		50,824		169,996		10,200		0		159,796		123,470
CASSIDY 19- 1-72		5.9		0.00000	%		48.75000	%		0		31,005		27,225		0		13,272		48,842		2,931		0		45,911		36,329
CASSIDY 19- 2-73		4.5		0.00000	%		48.75000	%		0		22,919		20,125		0		9,811		32,816		1,969		0		30,847		25,508
CASSIDY 19- 3-74		8.1		0.00000	%		48.75000	%		0		45,166		39,661		0		19,335		71,151		4,269		0		66,882		49,213
CASSIDY 19- 6-96		5.6		0.00000	%		48.75000	%		0		32,428		28,475		0		13,882		46,432		2,786		0		43,646		34,911
CASSIDY 19- 7-75		5.2		0.00000	%		48.75000	%		0		27,561		24,202		0		11,798		39,463		2,368		0		37,095		29,971
CASSIDY 19- 9-76		9.1		0.00000	%		48.75000	%		0		57,184		50,213		0		24,479		90,082		5,405		0		84,677		61,009
CASSIDY 19-10-77		6.3		0.00000	%		48.75000	%		0		31,020		27,239		0		13,279		48,867		2,932		0		45,935		35,585
CASSIDY 19-11-97		4.4		0.00000	%		48.75000	%		0		21,393		18,785		0		9,158		30,631		1,838		0		28,793		23,818
CASSIDY 19-13-78		13.9		0.00000	%		52.81250	%		0		88,708		77,895		0		41,138		137,599		8,256		0		129,343		79,728
CASSIDY 19-15-79		9.0		0.00000	%		48.75000	%		0		46,227		40,592		0		19,789		72,822		4,369		0		68,452		48,286
CASSIDY 19-16-80		4.0		0.00000	%		48.75000	%		0		22,388		19,659		0		9,584		32,055		1,923		0		30,132		25,568
CASSIDY 20- 3-81		8.5		0.00000	%		48.75000	%		0		50,214		44,093		0		21,495		71,898		4,314		0		67,584		48,625
CASSIDY 20- 5-82		3.3		0.00000	%		48.75000	%		0		16,516		14,503		0		7,070		23,649		1,419		0		22,230		19,345
CASSIDY 20- 6-83		4.7		0.00000	%		48.75000	%		0		23,082		20,269		0		9,881		33,050		1,983		0		31,067		25,477
CASSIDY 20- 7-84		7.8		0.00000	%		48.75000	%		0		41,303		36,268		0		17,681		65,065		3,904		0		61,161		45,301
CASSIDY 20- 8-85		13.8		0.00000	%		48.75000	%		0		98,409		86,413		0		42,126		155,025		9,301		0		145,723		92,357
CASSIDY 20-10-86		4.4		0.00000	%		48.75000	%		0		24,929		21,890		0		10,671		35,694		2,142		0		33,552		28,021
CASSIDY 20-12-87		6.2		0.00000	%		48.75000	%		0		36,565		32,107		0		15,652		52,354		3,141		0		49,213		38,577
CASSIDY 20-14-88		2.6		0.00000	%		48.75000	%		0		11,900		10,450		0		5,094		17,039		1,022		0		16,017		14,282
CASSIDY 20-16-89		0.0		0.00000	%		48.75000	%		0		0		0		0		0		0		0		0		0		0
CASSIDY 21- 2-102		7.2		0.00000	%		48.75000	%		0		40,003		35,126		0		17,124		63,017		3,781		0		59,236		45,003
CASSIDY 21- 3-116		12.9		0.00000	%		48.75000	%		0		113,713		99,851		0		48,678		162,817		9,769		0		153,048		100,562
CASSIDY 21- 4-117		14.3		0.00000	%		48.75000	%		0		79,178		69,527		0		33,894		124,731		7,484		0		117,247		69,978
CASSIDY 21- 6-103		10.3		0.00000	%		48.75000	%		0		72,949		64,056		0		31,227		104,450		6,267		0		98,183		68,080
CASSIDY 21- 8-104		1.1		0.00000	%		48.75000	%		0		4,113		3,612		0		1,761		6,480		389		0		6,091		5,794
CASSIDY 21-10-105		9.0		0.00000	%		48.75000	%		0		58,238		51,139		0		24,930		83,386		5,003		0		78,383		56,019

RALPH E. DAVIS ASSOCIATES, INC.
TEXAS REGISTERED FIRM F-1529 Page 1 of 11

BLACK WARRIOR TRUST 1994-1	RESERVES and REVENUES
TOTAL ROYALTY INTERESTS	AS OF DECEMBER 31, 2009
TOTAL PROVED RESERVES

									Gross Volumes						Net Volumes				Product		Production		Operating		Future Net Income
	Life		Working			Revenue			Oil		Wellhead Gas		Sales Gas		Oil		Sales Gas		Sales		Taxes		Expense		Undiscounted		Disc. @ 10%
Well Name & Number	Years		Interest			Interest			Bbls		Mcf		Mcf		Bbls		Mcf		$		$		$		$		$
CASSIDY 21-11-106		31.8		0.00000	%		48.75000	%		0		240,898		211,533		0		103,122		379,490		22,769		0		356,721		147,601
CASSIDY 21-14-118		8.2		0.00000	%		48.75000	%		0		49,938		43,851		0		21,377		78,669		4,720		0		73,949		54,722
CASSIDY 22- 1-107		14.3		0.00000	%		48.75000	%		0		81,819		71,845		0		35,024		128,890		7,733		0		121,156		72,701
CASSIDY 22- 3-108		3.2		0.00000	%		48.75000	%		0		14,632		12,848		0		6,264		20,950		1,257		0		19,693		17,125
CASSIDY 22- 6-110		0.0		0.00000	%		48.75000	%		0		0		0		0		0		0		0		0		0		0
CASSIDY 22- 7-111		0.0		0.00000	%		48.90418	%		0		0		0		0		0		0		0		0		0		0
CASSIDY 22-13-112		5.5		0.00000	%		48.75000	%		0		23,178		20,353		0		9,922		36,513		2,191		0		34,322		27,124
CASSIDY 22-14-113		9.4		0.00000	%		48.75000	%		0		45,799		40,216		0		19,606		72,148		4,329		0		67,819		46,819
CASSIDY 25- 3-11		1.3		0.00000	%		48.75000	%		0		5,172		4,541		0		2,214		8,147		489		0		7,659		7,242
CASSIDY 25- 4-66		3.3		0.00000	%		48.75000	%		0		16,113		14,149		0		6,897		23,071		1,384		0		21,686		18,858
CASSIDY 25- 5-67		3.3		0.00000	%		48.75000	%		0		16,888		14,829		0		7,229		24,180		1,451		0		22,729		19,811
CASSIDY 25- 6-13		3.3		0.00000	%		48.75000	%		0		15,621		13,717		0		6,687		22,367		1,342		0		21,025		18,254
CASSIDY 25-10- 1		1.0		0.00000	%		48.75000	%		0		4,314		3,788		0		1,847		6,177		371		0		5,806		5,545
CASSIDY 25-12-14		1.3		0.00000	%		48.75000	%		0		5,998		5,267		0		2,568		8,588		515		0		8,073		7,599
CASSIDY 25-14-21		5.5		0.00000	%		48.75000	%		0		30,137		26,463		0		12,901		47,475		2,849		0		44,627		35,979
CASSIDY 25-15-20		0.0		0.00000	%		48.75000	%		0		0		0		0		0		0		0		0		0		0
CASSIDY 25-16- 1		2.7		0.00000	%		48.75000	%		0		12,057		10,588		0		5,161		17,264		1,036		0		16,228		14,409
CASSIDY 26- 8-122		5.5		0.00000	%		48.75000	%		0		29,684		26,065		0		12,707		42,502		2,550		0		39,952		31,876
CASSIDY 26-10-123		2.3		0.00000	%		48.75000	%		0		10,631		9,336		0		4,551		15,222		913		0		14,309		12,957
CASSIDY 28- 1-114		17.8		0.00000	%		48.75000	%		0		110,211		96,777		0		47,179		173,617		10,417		0		163,200		89,620
CASSIDY 28- 7-115		34.1		0.00000	%		48.75000	%		0		240,967		211,593		0		103,152		379,599		22,776		0		356,823		137,955
CASSIDY 28- 8-131		31.5		0.00000	%		47.93020	%		0		345,550		303,427		0		145,433		486,446		29,187		0		457,259		202,959
CASSIDY 29- 1-95		3.2		0.00000	%		48.75000	%		0		32,277		28,342		0		13,817		50,846		3,051		0		47,795		43,351
CASSIDY 29- 2-98		4.7		0.00000	%		48.75000	%		0		22,215		19,507		0		9,510		34,995		2,100		0		32,895		27,129
CASSIDY 29- 3-90		6.2		0.00000	%		48.75000	%		0		29,005		25,470		0		12,416		45,693		2,742		0		42,951		33,363
CASSIDY 29- 4-91		1.9		0.00000	%		48.75000	%		0		8,925		7,837		0		3,820		12,778		767		0		12,012		11,030
CASSIDY 29- 5-92		6.4		0.00000	%		48.75000	%		0		32,440		28,486		0		13,887		51,103		3,066		0		48,037		37,193
CASSIDY 29- 6-93		9.8		0.00000	%		48.75000	%		0		52,734		46,305		0		22,574		83,072		4,984		0		78,088		54,013
CASSIDY 29- 9-94		8.8		0.00000	%		48.75000	%		0		67,193		59,002		0		28,763		96,208		5,772		0		90,436		66,138
CASSIDY 29-10-99		7.3		0.00000	%		48.75000	%		0		45,401		39,867		0		19,435		71,521		4,291		0		67,230		51,291
CASSIDY 30- 2-119		13.6		0.00000	%		48.75000	%		0		137,401		120,652		0		58,818		196,734		11,804		0		184,930		121,508
CASSIDY 30- 4-120		12.1		0.00000	%		52.81250	%		0		80,779		70,932		0		37,461		125,300		7,518		0		117,782		77,428
CASSIDY 30- 8-121		22.1		0.00000	%		46.51560	%		0		166,430		146,143		0		67,979		250,163		15,010		0		235,153		118,994
CASSIDY 30-12-15		5.0		0.00000	%		46.51559	%		0		29,384		25,802		0		12,002		44,167		2,650		0		41,517		34,147
CASSIDY 30-13- 1		0.8		0.00000	%		48.75000	%		0		3,493		3,067		0		1,495		5,002		300		0		4,702		4,523
CASSIDY 30-14- 1		2.4		0.00000	%		48.75000	%		0		11,120		9,764		0		4,760		17,517		1,051		0		16,466		14,854
CASSIDY 30-15-12		4.6		0.00000	%		48.75000	%		0		21,218		18,632		0		9,083		33,426		2,006		0		31,420		25,950
CASSIDY 31- 1-17		0.1		0.00000	%		48.75000	%		0		295		259		0		126		465		28		0		437		436
CASSIDY 31- 2-10		8.2		0.00000	%		48.75000	%		0		45,546		39,994		0		19,497		71,749		4,305		0		67,444		49,471
CASSIDY 31- 3-16		5.8		0.00000	%		48.75000	%		0		25,410		22,312		0		10,877		40,029		2,402		0		37,627		29,422
CASSIDY 31- 4- 1		2.4		0.00000	%		48.75000	%		0		9,601		8,431		0		4,110		15,124		907		0		14,217		12,760
CASSIDY 31- 5- 1A		6.6		0.00000	%		48.75000	%		0		40,205		35,304		0		17,211		63,335		3,800		0		59,535		46,540
CASSIDY 31- 6-18		5.1		0.00000	%		48.75000	%		0		28,661		25,168		0		12,269		41,038		2,462		0		38,576		31,378
CASSIDY 31- 8-70		3.0		0.00000	%		48.75000	%		0		13,828		12,142		0		5,919		19,799		1,188		0		18,611		16,299
CASSIDY 31-10-124		6.7		0.00000	%		48.75000	%		0		39,642		34,809		0		16,970		56,760		3,406		0		53,354		41,058
CASSIDY 31-12-125		7.3		0.00000	%		48.75000	%		0		38,277		33,611		0		16,385		60,298		3,618		0		56,680		42,551
CASSIDY 31-14-65		3.3		0.00000	%		48.75000	%		0		16,295		14,309		0		6,976		23,332		1,400		0		21,932		19,074
CASSIDY 31-16-69		2.3		0.00000	%		48.75000	%		0		10,578		9,288		0		4,528		15,146		909		0		14,237		12,887
CASSIDY 32- 1-101		6.8		0.00000	%		48.75000	%		0		49,677		43,622		0		21,265		71,129		4,268		0		66,861		52,052
CASSIDY 32- 2-41		5.4		0.00000	%		48.75000	%		0		29,739		26,114		0		12,731		46,849		2,811		0		44,038		35,617

RALPH E. DAVIS ASSOCIATES, INC.
TEXAS REGISTERED FIRM F-1529 Page 2 of 11

BLACK WARRIOR TRUST 1994-1	RESERVES and REVENUES
TOTAL ROYALTY INTERESTS	AS OF DECEMBER 31, 2009
TOTAL PROVED RESERVES

									Gross Volumes						Net Volumes				Product		Production		Operating		Future Net Income
	Life		Working			Revenue			Oil		Wellhead Gas		Sales Gas		Oil		Sales Gas		Sales		Taxes		Expense		Undiscounted		Disc. @ 10%
Well Name & Number	Years		Interest			Interest			Bbls		Mcf		Mcf		Bbls		Mcf		$		$		$		$		$
CASSIDY 32- 4-33		0.0		0.00000	%		48.75000	%		0		0		0		0		0		0		0		0		0		0
CASSIDY 32- 6-40		0.3		0.00000	%		48.75000	%		0		1,008		886		0		432		1,444		87		0		1,357		1,341
CASSIDY 32- 7-39		4.3		0.00000	%		48.75000	%		0		26,256		23,055		0		11,239		37,594		2,256		0		35,338		29,856
CASSIDY 32- 8-34		18.2		0.00000	%		48.75000	%		0		217,992		191,419		0		93,317		312,127		18,728		0		293,399		175,977
CASSIDY 32- 9-37		15.5		0.00000	%		48.75000	%		0		197,113		173,085		0		84,379		310,514		18,631		0		291,884		191,131
CASSIDY 32-10-45		5.5		0.00000	%		48.75000	%		0		34,015		29,869		0		14,561		48,704		2,922		0		45,782		36,910
CASSIDY 32-11-35		0.0		0.00000	%		48.75000	%		0		0		0		0		0		0		0		0		0		0
CASSIDY 32-12-62		0.1		0.00000	%		48.75000	%		0		293		257		0		126		462		28		0		434		432
CASSIDY 32-13-46		2.8		0.00000	%		48.75000	%		0		13,358		11,730		0		5,718		19,126		1,148		0		17,979		15,948
CASSIDY 32-14-36		6.8		0.00000	%		48.75000	%		0		35,536		31,204		0		15,212		55,979		3,359		0		52,621		40,379
CASSIDY 32-15-38		7.4		0.00000	%		48.75000	%		0		51,319		45,064		0		21,968		73,480		4,409		0		69,071		52,494
CASSIDY 36- 1-19		1.3		0.00000	%		48.75000	%		0		4,936		4,335		0		2,113		7,776		467		0		7,310		6,908
CASSIDY 36- 2- 1		3.3		0.00000	%		48.75000	%		0		14,767		12,967		0		6,322		21,144		1,269		0		19,876		17,127
CASSIDY 36- 3-23		1.9		0.00000	%		48.75000	%		0		13,974		12,271		0		5,982		22,014		1,321		0		20,693		19,285
CASSIDY 36- 4-22		7.8		0.00000	%		48.75000	%		0		49,675		43,619		0		21,264		78,253		4,695		0		73,558		55,498
CASSIDY 36- 5-24		7.9		0.00000	%		48.75000	%		0		43,138		37,879		0		18,466		67,955		4,077		0		63,878		47,162
CASSIDY 36- 7-25		2.1		0.00000	%		48.75000	%		0		8,002		7,027		0		3,426		12,606		756		0		11,850		10,779
CASSIDY 36- 8- 4		4.0		0.00000	%		48.75000	%		0		18,868		16,568		0		8,077		27,016		1,621		0		25,395		21,341
CASSIDY 36- 9-71		6.8		0.00000	%		48.75000	%		0		30,642		26,907		0		13,117		48,271		2,896		0		45,375		34,353
CASSIDY 36-10-28		0.8		0.00000	%		48.75000	%		0		3,072		2,697		0		1,315		4,839		290		0		4,548		4,375
CASSIDY 36-11-27		4.9		0.00000	%		48.75000	%		0		21,933		19,260		0		9,389		34,552		2,073		0		32,479		26,401
CASSIDY 36-12-26		0.9		0.00000	%		48.75000	%		0		3,466		3,044		0		1,484		5,460		328		0		5,132		4,920
CASSIDY 36-13-29		2.6		0.00000	%		48.75000	%		0		13,458		11,818		0		5,761		19,270		1,156		0		18,114		16,227
CASSIDY 36-14-30		0.0		0.00000	%		48.75000	%		0		0		0		0		0		0		0		0		0		0
CASSIDY 36-15-31		4.1		0.00000	%		48.75000	%		0		19,364		17,004		0		8,289		30,505		1,830		0		28,675		24,194
CASSIDY 36-16- 3		11.0		0.00000	%		47.91200	%		0		66,202		58,132		0		27,852		102,496		6,150		0		96,346		64,588
CASSIDY 5- 2-126		9.3		0.00000	%		48.75000	%		0		65,014		57,089		0		27,831		102,418		6,145		0		96,273		69,741
CASSIDY 5- 4-49		5.5		0.00000	%		48.75000	%		0		32,855		28,850		0		14,064		47,042		2,823		0		44,219		35,557
CASSIDY 5- 5-50		5.5		0.00000	%		48.75000	%		0		34,015		29,869		0		14,561		48,704		2,922		0		45,782		36,910
CASSIDY 5- 6-61		9.5		0.00000	%		48.75000	%		0		78,102		68,581		0		33,433		111,828		6,710		0		105,118		75,885
CASSIDY 5-11-56		7.3		0.00000	%		48.75000	%		0		43,638		38,318		0		18,680		62,481		3,749		0		58,733		44,298
CASSIDY 5-13-48		1.4		0.00000	%		48.75000	%		0		6,339		5,567		0		2,714		9,077		545		0		8,532		8,003
CASSIDY 5-14-57		1.2		0.00000	%		48.75000	%		0		4,738		4,160		0		2,028		6,784		407		0		6,377		6,038
CASSIDY 6- 2-64		7.0		0.00000	%		48.75000	%		0		41,465		36,411		0		17,750		59,371		3,562		0		55,808		42,413
CASSIDY 6- 3-44		6.2		0.00000	%		48.75000	%		0		33,630		29,531		0		14,396		52,978		3,179		0		49,799		39,148
CASSIDY 6- 4-42		0.4		0.00000	%		48.75000	%		0		1,708		1,500		0		731		2,445		147		0		2,299		2,254
CASSIDY 6- 5-43		0.0		0.00000	%		48.75000	%		0		0		0		0		0		0		0		0		0		0
CASSIDY 6- 6-53		9.2		0.00000	%		48.75000	%		0		55,303		48,561		0		23,674		79,184		4,751		0		74,433		52,442
CASSIDY 6- 7-129		1.7		0.00000	%		48.75000	%		0		7,567		6,644		0		3,239		10,834		650		0		10,184		9,450
CASSIDY 6- 9-47		4.2		0.00000	%		48.75000	%		0		22,633		19,874		0		9,689		32,407		1,944		0		30,462		25,635
CASSIDY 6-10-52		3.2		0.00000	%		48.75000	%		0		16,737		14,697		0		7,165		23,964		1,438		0		22,527		19,718
CASSIDY 6-11-54		0.0		0.00000	%		48.75000	%		0		0		0		0		0		0		0		0		0		0
CASSIDY 6-13-51		1.3		0.00000	%		48.75000	%		0		5,253		4,613		0		2,249		8,276		497		0		7,779		7,323
CASSIDY 6-14-55		5.6		0.00000	%		48.75000	%		0		32,323		28,383		0		13,837		46,281		2,777		0		43,504		34,796
CASSIDY 6-16-68		7.6		0.00000	%		48.75000	%		0		33,127		29,089		0		14,181		52,185		3,131		0		49,054		35,803
CASSIDY 8- 4-63		1.1		0.00000	%		48.75000	%		0		4,583		4,024		0		1,962		6,561		394		0		6,168		5,866
CASSIDY 8- 5-60		8.0		0.00000	%		48.75000	%		0		44,677		39,231		0		19,125		63,970		3,838		0		60,132		43,777
CASSIDY 8-12-58		5.9		0.00000	%		48.75000	%		0		27,385		24,046		0		11,723		39,210		2,353		0		36,857		28,571
CASSIDY 8-13-59		8.1		0.00000	%		48.75000	%		0		41,830		36,731		0		17,906		65,895		3,954		0		61,942		45,193
CHEVRON 23-16-18		6.0		0.00000	%		56.87500	%		0		33,451		29,373		0		16,706		55,879		3,353		0		52,526		41,840

RALPH E. DAVIS ASSOCIATES, INC.
TEXAS REGISTERED FIRM F-1529 Page 3 of 11

BLACK WARRIOR TRUST 1994-1	RESERVES and REVENUES
TOTAL ROYALTY INTERESTS	AS OF DECEMBER 31, 2009
TOTAL PROVED RESERVES

									Gross Volumes						Net Volumes				Product		Production		Operating		Future Net Income
	Life		Working			Revenue			Oil		Wellhead Gas		Sales Gas		Oil		Sales Gas		Sales		Taxes		Expense		Undiscounted		Disc. @ 10%
Well Name & Number	Years		Interest			Interest			Bbls		Mcf		Mcf		Bbls		Mcf		$		$		$		$		$
CHEVRON 24-16-16		11.0		0.00000	%		56.87500	%		0		65,392		57,421		0		32,658		120,182		7,211		0		112,971		77,662
CHEVRON 25- 2- 1		2.7		0.00000	%		56.87500	%		0		9,910		8,702		0		4,949		18,213		1,093		0		17,120		15,267
CHEVRON 25- 8- 2		3.8		0.00000	%		56.87500	%		0		17,521		15,385		0		8,750		29,267		1,756		0		27,511		23,478
CHEVRON 25-11- 3		4.9		0.00000	%		56.87500	%		0		22,321		19,600		0		11,148		41,023		2,461		0		38,562		31,768
CHEVRON 26- 5- 9		10.3		0.00000	%		56.87500	%		0		60,645		53,253		0		30,287		111,458		6,687		0		104,771		73,442
CHEVRON 27- 1-10		5.9		0.00000	%		56.87500	%		0		31,572		27,723		0		15,768		52,740		3,164		0		49,575		39,480
CHEVRON 30-10- 8		3.3		0.00000	%		56.87500	%		0		12,091		10,618		0		6,039		22,222		1,333		0		20,889		18,177
CHRISTIAN 12- 5- 2		7.4		0.00000	%		56.87500	%		0		42,906		37,676		0		21,428		71,673		4,300		0		67,373		51,203
CLEMENTS 34-11- 1		12.7		0.00000	%		56.87500	%		0		97,736		85,822		0		48,811		179,626		10,778		0		168,849		114,267
CLEMENTS 34-15- 1		11.3		0.00000	%		56.87500	%		0		82,794		72,701		0		41,349		138,304		8,298		0		130,005		89,724
CLEMENTS 34-16- 2		11.5		0.00000	%		56.87500	%		0		78,858		69,245		0		39,383		144,930		8,696		0		136,234		93,926
COLBURN 15- 9- 1		19.2		0.00000	%		56.87500	%		0		117,814		103,452		0		58,838		216,526		12,992		0		203,534		111,751
COLBURN 15-15- 2		30.0		0.00000	%		56.87500	%		0		273,182		239,881		0		136,433		456,340		27,380		0		428,960		195,950
CUNNINGHAM 10- 1- 1		42.3		0.00000	%		56.87500	%		0		605,040		531,285		0		302,169		1,010,695		60,642		0		950,053		392,429
CUNNINGHAM 10- 2- 2		19.6		0.00000	%		56.87500	%		0		159,671		140,207		0		79,743		266,723		16,003		0		250,720		140,415
CUNNINGHAM 28-15- 3		6.7		0.00000	%		56.87500	%		0		33,086		29,053		0		16,524		60,807		3,648		0		57,159		44,491
CUNNINGHAM 34- 8- 2		14.2		0.00000	%		56.87500	%		0		96,533		84,766		0		48,211		161,255		9,675		0		151,580		95,115
CUNNINGHAM 35-12- 1		8.7		0.00000	%		57.60302	%		0		48,489		42,578		0		24,526		82,036		4,922		0		77,114		56,082
DAVANT 1-12-10		5.4		0.00000	%		56.87500	%		0		30,894		27,128		0		15,429		51,607		3,096		0		48,511		39,516
DAVANT 1-13-11		7.4		0.00000	%		54.84375	%		0		49,556		43,515		0		23,865		79,825		4,790		0		75,036		57,550
DAVANT 21-16-16		16.8		0.00000	%		56.87500	%		0		140,064		122,990		0		69,951		257,419		15,445		0		241,974		148,558
DAVANT 23- 2- 9		10.3		0.00000	%		56.87500	%		0		62,759		55,109		0		31,343		104,837		6,290		0		98,547		68,598
DAVANT 23- 7- 7		3.5		0.00000	%		56.87500	%		0		13,518		11,870		0		6,751		24,845		1,491		0		23,354		20,157
DAVANT 23-13- 8		13.3		0.00000	%		56.87500	%		0		78,393		68,837		0		39,151		144,076		8,645		0		135,431		86,693
DAVANT 3- 1-12		8.9		0.00000	%		56.87500	%		0		66,343		58,255		0		33,133		110,823		6,649		0		104,173		77,197
DAVANT 3- 2-13		14.5		0.00000	%		56.87500	%		0		99,820		87,652		0		49,852		183,456		11,007		0		172,449		109,257
DAVANT 7- 4- 2		0.0		0.00000	%		56.87500	%		0		0		0		0		0		0		0		0		0		0
DAVANT 7- 5- 3		0.0		0.00000	%		56.87500	%		0		0		0		0		0		0		0		0		0		0
DAVANT 7-11- 4		12.8		0.00000	%		56.87500	%		0		73,672		64,692		0		36,793		135,400		8,124		0		127,276		82,345
DAVANT 7-12- 5		2.0		0.00000	%		56.87500	%		0		7,363		6,466		0		3,677		12,300		738		0		11,562		10,562
DAVANT 7-13- 6		16.9		0.00000	%		56.87500	%		0		137,520		120,756		0		68,680		229,721		13,783		0		215,938		129,275
DAVANT 7-14- 1		11.8		0.00000	%		56.87500	%		0		56,881		49,947		0		28,407		104,539		6,272		0		98,266		64,161
DAVIS 24- 7- 1		11.0		0.00000	%		56.87500	%		0		71,990		63,214		0		35,953		120,256		7,215		0		113,041		77,481
DAVIS 24- 8- 2		6.4		0.00000	%		56.87500	%		0		32,504		28,542		0		16,233		54,296		3,258		0		51,039		39,737
DAVIS 24- 9- 3		10.1		0.00000	%		56.87500	%		0		57,136		50,171		0		28,535		95,443		5,727		0		89,717		62,179
DAVIS 24-10- 4		10.8		0.00000	%		56.74805	%		0		69,137		60,709		0		34,451		115,233		6,914		0		108,319		74,383
DEAL 27- 4- 1		15.1		0.00000	%		56.87500	%		0		95,050		83,464		0		47,470		174,689		10,481		0		164,208		101,099
DEAL 27- 5- 2		42.4		0.00000	%		55.86750	%		0		624,805		548,642		0		306,512		1,127,966		67,678		0		1,060,288		450,664
DRUMMOND 6- 1- 1		0.0		0.00000	%		48.75000	%		0		0		0		0		0		0		0		0		0		0
EARNEST 15-10- 2		7.4		0.00000	%		56.87500	%		0		44,907		39,433		0		22,428		75,016		4,501		0		70,515		53,837
EARNEST 15-15- 5		1.9		0.00000	%		56.87500	%		0		7,142		6,272		0		3,567		11,931		716		0		11,215		10,289
EARNEST 15-16- 4		8.9		0.00000	%		56.87500	%		0		40,923		35,934		0		20,438		75,211		4,513		0		70,698		50,421
EARNEST 24-13- 1		8.8		0.00000	%		56.62111	%		0		57,392		50,396		0		28,535		95,443		5,727		0		89,716		65,780
FEDERAL 8- 9-10		7.2		0.00000	%		56.87500	%		0		33,493		29,410		0		16,727		61,556		3,693		0		57,863		43,990
FEDERAL 8-16-12		6.5		0.00000	%		56.87500	%		0		37,909		33,288		0		18,932		63,325		3,800		0		59,526		46,757
FEDERAL 9- 4- 5		22.5		0.00000	%		56.87500	%		0		238,566		209,485		0		119,145		398,515		23,911		0		374,604		205,959
FEDERAL 9-12- 7		16.3		0.00000	%		56.87500	%		0		132,386		116,248		0		66,116		221,146		13,269		0		207,877		126,610
FEDERAL 9-14- 8		11.4		0.00000	%		56.87500	%		0		58,963		51,776		0		29,447		108,366		6,502		0		101,864		67,883
FGLIC 26- 2- 1		12.5		0.00000	%		56.87500	%		0		72,994		64,096		0		36,455		134,154		8,049		0		126,104		82,619
FGLIC 26- 6- 3		12.9		0.00000	%		56.87500	%		0		84,961		74,604		0		42,431		156,146		9,369		0		146,777		96,582

RALPH E. DAVIS ASSOCIATES, INC.
TEXAS REGISTERED FIRM F-1529 Page 4 of 11

BLACK WARRIOR TRUST 1994-1	RESERVES and REVENUES
TOTAL ROYALTY INTERESTS	AS OF DECEMBER 31, 2009
TOTAL PROVED RESERVES

									Gross Volumes						Net Volumes				Product		Production		Operating		Future Net Income
	Life		Working			Revenue			Oil		Wellhead Gas		Sales Gas		Oil		Sales Gas		Sales		Taxes		Expense		Undiscounted		Disc. @ 10%
Well Name & Number	Years		Interest			Interest			Bbls		Mcf		Mcf		Bbls		Mcf		$		$		$		$		$
FIRST ALABAMA BANK 10- 9-23		3.8		0.00000	%		61.70528	%		0		15,453		13,570		0		8,373		28,007		1,680		0		26,326		22,434
FIRST ALABAMA BANK 10-15-24		6.1		0.00000	%		61.70528	%		0		26,395		23,178		0		14,302		47,837		2,870		0		44,967		35,260
FIRST ALABAMA BANK 10-16-25A		9.3		0.00000	%		61.70528	%		0		56,765		49,846		0		30,757		102,877		6,173		0		96,705		70,220
FIRST ALABAMA BANK 12- 1-4		8.3		0.00000	%		60.09516	%		0		49,431		43,405		0		26,084		87,247		5,235		0		82,012		61,196
FIRST ALABAMA BANK 12- 2-5		4.8		0.00000	%		60.09516	%		0		21,977		19,298		0		11,597		38,790		2,327		0		36,462		30,172
FIRST ALABAMA BANK 25- 1-13		9.7		0.00000	%		50.70000	%		0		90,210		79,214		0		40,161		134,332		8,060		0		126,272		92,825
FIRST ALABAMA BANK 25- 2-14		0.9		0.00000	%		51.89977	%		0		3,530		3,100		0		1,609		5,381		323		0		5,058		4,849
FIRST ALABAMA BANK 25- 4-19		9.2		0.00000	%		51.89977	%		0		64,887		56,978		0		29,571		108,822		6,529		0		102,293		75,237
FIRST ALABAMA BANK 25- 7-15		7.8		0.00000	%		51.89977	%		0		41,218		36,194		0		18,785		62,831		3,770		0		59,061		43,677
FIRST ALABAMA BANK 25-10-17		7.6		0.00000	%		51.89977	%		0		47,710		41,894		0		21,743		72,726		4,364		0		68,363		51,724
FIRST ALABAMA BANK 25-11-2		6.5		0.00000	%		51.89977	%		0		34,389		30,197		0		15,672		52,421		3,145		0		49,276		38,154
FIRST ALABAMA BANK 25-12-20		8.6		0.00000	%		51.89977	%		0		63,836		56,054		0		29,092		97,307		5,838		0		91,468		67,977
FIRST ALABAMA BANK 25-14-1		7.2		0.00000	%		51.89977	%		0		40,725		35,761		0		18,560		62,079		3,725		0		58,354		44,356
FIRST ALABAMA BANK 25-15-3A		0.0		0.00000	%		51.89977	%		0		0		0		0		0		0		0		0		0		0
FIRST ALABAMA BANK 25-16-22		19.5		0.00000	%		51.89980	%		0		136,666		120,006		0		62,283		208,325		12,499		0		195,825		105,166
FIRST ALABAMA BANK 26-16-18		11.3		0.00000	%		63.78578	%		0		69,416		60,954		0		38,880		143,079		8,585		0		134,494		93,683
FIRST ALABAMA BANK 27- 9-27		6.0		0.00000	%		61.70528	%		0		39,049		34,289		0		21,158		77,861		4,672		0		73,189		59,781
FIRST ALABAMA BANK 27-16-28		7.5		0.00000	%		61.70528	%		0		35,432		31,113		0		19,198		70,649		4,239		0		66,410		50,398
FIRST ALABAMA BANK 34- 1-6		11.3		0.00000	%		42.83960	%		0		82,351		72,312		0		30,978		103,616		6,217		0		97,399		68,175
FIRST ALABAMA BANK 34-12-7		14.2		0.00000	%		42.83960	%		0		115,962		101,827		0		43,622		145,907		8,754		0		137,153		89,947
FIRST ALABAMA BANK 34-13-21		14.4		0.00000	%		61.70528	%		0		92,538		81,258		0		50,140		167,709		10,063		0		157,647		98,740
FIRST ALABAMA BANK 35- 2-8		0.0		0.00000	%		42.83960	%		0		0		0		0		0		0		0		0		0		0
FIRST ALABAMA BANK 35- 3-9		12.6		0.00000	%		42.83960	%		0		79,480		69,791		0		29,898		110,025		6,602		0		103,424		69,473
FIRST ALABAMA BANK 35- 5-10		6.1		0.00000	%		42.83960	%		0		26,727		23,469		0		10,054		36,999		2,220		0		34,779		27,622
FIRST NATIONAL BANK 1- 3-1		10.4		0.00000	%		56.87500	%		0		62,174		54,595		0		31,051		103,859		6,232		0		97,628		67,355
FRIEDMAN 10-10-28		12.3		0.00000	%		53.54375	%		0		77,046		67,654		0		36,224		133,306		7,998		0		125,308		82,506
FRIEDMAN 10-15-29		4.8		0.00000	%		53.54375	%		0		21,672		19,030		0		10,190		34,082		2,045		0		32,037		26,117
FRIEDMAN 11-10- 8		10.6		0.00000	%		53.54375	%		0		53,292		46,795		0		25,056		92,206		5,532		0		86,674		58,579
FRIEDMAN 11-11-17		24.2		0.00000	%		53.54375	%		0		168,290		147,776		0		79,125		291,179		17,471		0		273,708		134,498
FRIEDMAN 11-13-18		16.3		0.00000	%		53.54375	%		0		96,838		85,034		0		45,530		167,551		10,053		0		157,498		91,752
FRIEDMAN 12- 1- 9		1.7		0.00000	%		53.54375	%		0		5,888		5,171		0		2,769		10,188		611		0		9,577		8,881
FRIEDMAN 12- 2-50		1.6		0.00000	%		53.54375	%		0		6,545		5,747		0		3,077		10,293		618		0		9,676		9,015
FRIEDMAN 12- 8-10		0.0		0.00000	%		53.54375	%		0		0		0		0		0		0		0		0		0		0
FRIEDMAN 13-13- 3		1.9		0.00000	%		53.54375	%		0		7,529		6,611		0		3,540		11,840		710		0		11,129		10,203
FRIEDMAN 14- 6-33		20.0		0.00000	%		53.54375	%		0		165,289		145,140		0		77,714		259,937		15,596		0		244,341		133,996
FRIEDMAN 14-12-34		5.4		0.00000	%		53.54375	%		0		31,170		27,370		0		14,655		53,930		3,236		0		50,694		41,475
FRIEDMAN 14-13-35		9.9		0.00000	%		53.54375	%		0		68,080		59,781		0		32,009		107,065		6,424		0		100,641		71,140
FRIEDMAN 18- 2- 5		0.0		0.00000	%		53.54375	%		0		0		0		0		0		0		0		0		0		0
FRIEDMAN 18- 3-31		5.7		0.00000	%		53.54375	%		0		29,672		26,055		0		13,951		46,663		2,800		0		43,864		35,005
FRIEDMAN 18- 7-30		8.6		0.00000	%		53.54375	%		0		38,606		33,900		0		18,151		66,798		4,008		0		62,790		44,850
FRIEDMAN 18- 8- 2		0.0		0.00000	%		53.54375	%		0		0		0		0		0		0		0		0		0		0
FRIEDMAN 18- 9- 1		8.1		0.00000	%		53.54375	%		0		38,884		34,144		0		18,282		67,278		4,037		0		63,241		46,348
FRIEDMAN 18-15- 4		21.3		0.00000	%		53.54375	%		0		212,452		186,554		0		99,888		334,106		20,046		0		314,059		173,363
FRIEDMAN 2- 1-15		2.4		0.00000	%		53.54375	%		0		10,255		9,005		0		4,822		16,127		968		0		15,159		13,629
FRIEDMAN 2- 5-42		10.3		0.00000	%		53.54375	%		0		69,985		61,454		0		32,905		110,060		6,604		0		103,456		72,326
FRIEDMAN 2- 9-16		14.6		0.00000	%		55.76460	%		0		95,877		84,190		0		46,948		157,033		9,422		0		147,611		90,668
FRIEDMAN 2-12-21		12.5		0.00000	%		53.54375	%		0		74,166		65,125		0		34,870		128,323		7,699		0		120,624		78,477
FRIEDMAN 2-14-22		5.9		0.00000	%		53.54375	%		0		31,162		27,363		0		14,651		49,006		2,940		0		46,066		36,451
FRIEDMAN 22- 4-52		8.2		0.00000	%		53.54375	%		0		48,370		42,474		0		22,742		76,068		4,564		0		71,504		52,695
FRIEDMAN 22-12-53		13.9		0.00000	%		53.54375	%		0		129,816		113,991		0		61,035		204,151		12,249		0		191,902		125,428

RALPH E. DAVIS ASSOCIATES, INC.
TEXAS REGISTERED FIRM F-1529 Page 5 of 11

BLACK WARRIOR TRUST 1994-1	RESERVES and REVENUES
TOTAL ROYALTY INTERESTS	AS OF DECEMBER 31, 2009
TOTAL PROVED RESERVES

									Gross Volumes						Net Volumes				Product		Production		Operating		Future Net Income
	Life		Working			Revenue			Oil		Wellhead Gas		Sales Gas		Oil		Sales Gas		Sales		Taxes		Expense		Undiscounted		Disc. @ 10%
Well Name & Number	Years		Interest			Interest			Bbls		Mcf		Mcf		Bbls		Mcf		$		$		$		$		$
FRIEDMAN 22-14-38		0.0		0.00000	%		53.54375	%		0		0		0		0		0		0		0		0		0		0
FRIEDMAN 22-15-39		16.5		0.00000	%		53.54375	%		0		93,087		81,739		0		43,766		146,390		8,783		0		137,607		76,993
FRIEDMAN 22-15-54		15.9		0.00000	%		55.20937	%		0		122,886		107,907		0		59,575		199,265		11,956		0		187,309		113,581
FRIEDMAN 22-16-55		14.2		0.00000	%		53.54375	%		0		82,196		72,176		0		38,646		129,262		7,756		0		121,507		73,411
FRIEDMAN 23- 4-41		14.5		0.00000	%		55.20937	%		0		139,796		122,754		0		67,772		249,401		14,964		0		234,437		154,772
FRIEDMAN 23- 5-40		7.3		0.00000	%		45.87100	%		0		43,277		38,002		0		17,432		64,149		3,849		0		60,300		45,643
FRIEDMAN 3- 6-23		16.7		0.00000	%		53.54375	%		0		107,735		94,602		0		50,653		186,405		11,184		0		175,220		102,480
FRIEDMAN 30- 4-45		11.9		0.00000	%		54.34000	%		0		127,073		111,583		0		60,634		202,809		12,169		0		190,640		133,909
FRIEDMAN 30- 5-46		6.5		0.00000	%		54.34000	%		0		50,689		44,510		0		24,187		80,900		4,854		0		76,046		60,787
FRIEDMAN 30-12-47		14.3		0.00000	%		54.34000	%		0		118,387		103,955		0		56,489		207,880		12,473		0		195,408		126,659
FRIEDMAN 30-13-48		17.9		0.00000	%		54.34000	%		0		172,823		151,756		0		82,464		275,826		16,550		0		259,277		154,248
FRIEDMAN 31-12-49		9.0		0.00000	%		54.34000	%		0		51,940		45,609		0		24,784		91,204		5,472		0		85,732		62,217
FRIEDMAN 3-15-26		1.5		0.00000	%		53.17812	%		0		5,990		5,260		0		2,797		9,355		561		0		8,794		8,215
FRIEDMAN 34-10-57		10.5		0.00000	%		53.54375	%		0		72,836		63,957		0		34,245		114,543		6,873		0		107,671		74,839
FRIEDMAN 34-15-58		13.1		0.00000	%		53.54375	%		0		67,360		59,149		0		31,670		105,932		6,356		0		99,576		60,994
FRIEDMAN 36- 1-43		6.8		0.00000	%		54.34000	%		0		29,646		26,032		0		14,146		52,056		3,123		0		48,933		37,386
FRIEDMAN 36- 3- 1		6.3		0.00000	%		54.34000	%		0		31,875		27,989		0		15,209		55,970		3,358		0		52,612		41,274
FRIEDMAN 36- 7-44		0.0		0.00000	%		56.26400	%		0		0		0		0		0		0		0		0		0		0
FRIEDMAN 36- 8- 2		0.0		0.00000	%		54.34000	%		0		0		0		0		0		0		0		0		0		0
FRIEDMAN 36-11-56		7.4		0.00000	%		56.26400	%		0		43,516		38,211		0		21,499		71,910		4,315		0		67,596		51,373
FRIEDMAN 4- 8-59		21.8		0.00000	%		55.20937	%		0		166,945		146,594		0		80,934		297,837		17,870		0		279,966		149,617
FRIEDMAN 6- 4-11		15.8		0.00000	%		53.54375	%		0		144,607		126,979		0		67,990		227,412		13,645		0		213,767		132,553
FRIEDMAN 6- 5-12		3.2		0.00000	%		53.54375	%		0		12,264		10,769		0		5,766		21,219		1,273		0		19,945		17,390
FRIEDMAN 6-12-13		0.0		0.00000	%		53.54375	%		0		0		0		0		0		0		0		0		0		0
FRIEDMAN 6-13-14		0.0		0.00000	%		53.54375	%		0		0		0		0		0		0		0		0		0		0
FRIEDMAN-ROSENAU 2- 7- 2		17.7		0.00000	%		55.20937	%		0		119,940		105,319		0		58,146		213,978		12,839		0		201,139		116,169
FRIEDMAN-ROSENAU 2-15- 1		10.0		0.00000	%		56.87500	%		0		47,637		41,830		0		23,791		87,550		5,253		0		82,297		56,855
FRIEDMAN-ROSENAU 2-16- 3		9.8		0.00000	%		56.87500	%		0		50,764		44,576		0		25,352		84,799		5,088		0		79,711		55,294
GILBERT 15- 5- 1		18.5		0.00000	%		46.51560	%		0		127,073		111,583		0		51,903		191,004		11,460		0		179,544		98,880
GILBERT 15- 6- 3		29.9		0.00000	%		56.87500	%		0		272,678		239,439		0		136,181		501,145		30,069		0		471,077		221,634
GILBERT 15-12- 2		1.6		0.00000	%		46.51560	%		0		6,738		5,917		0		2,752		10,129		608		0		9,521		8,868
HALLMAN 17- 2- 2		0.8		0.00000	%		56.87500	%		0		2,869		2,519		0		1,433		5,273		316		0		4,956		4,775
HALLMAN 34- 8- 1		9.0		0.00000	%		56.87500	%		0		52,214		45,849		0		26,077		95,962		5,758		0		90,204		65,870
HALLMAN 8-14- 1		17.4		0.00000	%		56.87500	%		0		145,589		127,842		0		72,710		243,200		14,592		0		228,608		135,791
HAYES 18-13- 3		13.8		0.00000	%		56.87500	%		0		73,931		64,919		0		36,923		135,876		8,153		0		127,723		79,636
HAYES 18-14- 4		9.0		0.00000	%		56.87500	%		0		63,413		55,683		0		31,670		105,929		6,356		0		99,573		73,190
HAYES 7-16- 2		12.3		0.00000	%		56.87500	%		0		114,831		100,833		0		57,349		191,820		11,509		0		180,311		124,571
HINDS 12- 6- 1		2.0		0.00000	%		56.87500	%		0		6,739		5,918		0		3,366		12,386		743		0		11,643		10,647
HINDS 12- 7- 2		5.6		0.00000	%		56.87500	%		0		27,425		24,082		0		13,697		45,812		2,749		0		43,064		34,511
HINDS 12-11- 3		6.4		0.00000	%		56.87500	%		0		37,427		32,864		0		18,692		62,520		3,751		0		58,769		46,268
HINDS 14- 5- 4		8.9		0.00000	%		56.87500	%		0		57,953		50,889		0		28,943		96,809		5,809		0		91,000		66,590
HINDS 14- 6- 5		4.5		0.00000	%		56.87500	%		0		19,740		17,333		0		9,858		36,279		2,177		0		34,102		28,476
HOBSON 22- 9- 1		15.9		0.00000	%		56.87500	%		0		114,322		100,386		0		57,095		190,970		11,458		0		179,512		108,149
HOLMAN 10-11- 1		39.6		0.00000	%		56.87500	%		0		264,624		232,366		0		132,158		442,044		26,523		0		415,521		144,846
HOLMAN 13- 7-19		16.9		0.00000	%		56.87500	%		0		128,277		112,640		0		64,064		235,755		14,145		0		221,609		133,784
HOLMAN 13-11-20		10.0		0.00000	%		56.87500	%		0		74,862		65,736		0		37,387		125,053		7,503		0		117,550		84,350
HOLMAN 13-14-21		5.0		0.00000	%		56.87500	%		0		20,622		18,108		0		10,299		37,900		2,274		0		35,626		29,080
HOLMAN 13-15-22		13.3		0.00000	%		56.87500	%		0		93,143		81,789		0		46,517		155,592		9,336		0		146,256		94,596
HOLMAN 14- 3- 2		3.1		0.00000	%		56.87500	%		0		13,428		11,791		0		6,706		22,432		1,346		0		21,086		18,504
HOLMAN 14- 4- 1		6.3		0.00000	%		56.87500	%		0		35,023		30,754		0		17,491		58,505		3,510		0		54,994		43,248

RALPH E. DAVIS ASSOCIATES, INC.
TEXAS REGISTERED FIRM F-1529 Page 6 of 11

BLACK WARRIOR TRUST 1994-1	RESERVES and REVENUES
TOTAL ROYALTY INTERESTS	AS OF DECEMBER 31, 2009
TOTAL PROVED RESERVES

									Gross Volumes						Net Volumes				Product		Production		Operating		Future Net Income
	Life		Working			Revenue			Oil		Wellhead Gas		Sales Gas		Oil		Sales Gas		Sales		Taxes		Expense		Undiscounted		Disc. @ 10%
Well Name & Number	Years		Interest			Interest			Bbls		Mcf		Mcf		Bbls		Mcf		$		$		$		$		$
HOLMAN 15- 1-28		11.5		0.00000	%		45.98240	%		0		79,310		69,642		0		32,023		117,845		7,071		0		110,774		73,940
HOLMAN 15- 8-25		0.3		0.00000	%		45.98240	%		0		1,097		963		0		443		1,482		89		0		1,393		1,376
HOLMAN 17-11-31		8.8		0.00000	%		56.87500	%		0		53,157		46,677		0		26,547		88,796		5,328		0		83,468		60,952
HOLMAN 17-12-15		8.9		0.00000	%		56.87500	%		0		58,525		51,391		0		29,229		97,764		5,866		0		91,898		67,247
HOLMAN 17-13-16		8.4		0.00000	%		56.87500	%		0		49,652		43,599		0		24,797		82,941		4,976		0		77,964		57,412
HOLMAN 18- 3- 2		7.1		0.00000	%		56.87500	%		0		40,689		35,729		0		20,321		67,970		4,078		0		63,891		49,107
HOLMAN 24- 1-26		22.8		0.00000	%		56.87500	%		0		161,743		142,026		0		80,778		297,261		17,836		0		279,426		144,661
HOLMAN 24- 3-27		8.5		0.00000	%		56.87500	%		0		56,398		49,523		0		28,166		94,211		5,653		0		88,559		65,790
HOLMAN 26- 4-23		9.8		0.00000	%		49.24920	%		0		60,751		53,345		0		26,272		87,875		5,272		0		82,602		58,153
HOLMAN 26- 5-29		3.6		0.00000	%		49.24920	%		0		17,976		15,785		0		7,774		26,003		1,560		0		24,442		21,116
HOLMAN 26- 6-24		7.3		0.00000	%		49.24920	%		0		44,427		39,011		0		19,213		64,263		3,856		0		60,407		46,013
HOLMAN 34- 6- 3		12.1		0.00000	%		60.09516	%		0		88,897		78,060		0		46,910		156,906		9,414		0		147,492		100,169
HOLMAN 35-12- 4		6.8		0.00000	%		56.87500	%		0		36,095		31,695		0		18,027		66,338		3,980		0		62,358		48,462
HOWELL 12- 9- 1		18.1		0.00000	%		56.87500	%		0		131,742		115,683		0		65,795		242,124		14,527		0		227,597		132,544
HOWELL 12-14- 2		4.3		0.00000	%		56.87500	%		0		17,823		15,650		0		8,901		32,756		1,965		0		30,791		25,813
HOWELL 12-15- 3		8.3		0.00000	%		56.87500	%		0		42,927		37,694		0		21,439		78,894		4,734		0		74,161		54,673
MAYFIELD 1- 3- 3		3.9		0.00000	%		56.87500	%		0		18,024		15,827		0		9,002		30,109		1,807		0		28,303		24,083
MAYFIELD 1- 7- 4		5.3		0.00000	%		56.87500	%		0		27,877		24,479		0		13,922		46,568		2,794		0		43,774		35,564
MAYFIELD 12- 9- 2		4.8		0.00000	%		54.51875	%		0		19,976		17,541		0		9,563		35,192		2,112		0		33,080		27,078
MAYFIELD 12-10- 5		0.0		0.00000	%		56.87500	%		0		0		0		0		0		0		0		0		0		0
MAYFIELD 14- 1- 1		0.0		0.00000	%		54.51875	%		0		0		0		0		0		0		0		0		0		0
MAYFIELD 8- 3- 1		15.3		0.00000	%		55.69688	%		0		101,413		89,051		0		49,598		182,522		10,951		0		171,571		105,210
MCDANIEL 18- 4- 1		0.0		0.00000	%		56.55000	%		0		0		0		0		0		0		0		0		0		0
MCDANIEL 18- 5- 2		14.9		0.00000	%		56.55000	%		0		81,378		71,458		0		40,409		148,706		8,922		0		139,784		84,332
MCDANIEL 18- 6- 3		0.0		0.00000	%		56.55000	%		0		0		0		0		0		0		0		0		0		0
MCGUIRE 26-12- 6		3.8		0.00000	%		56.87500	%		0		17,133		15,044		0		8,556		28,619		1,717		0		26,902		23,030
MCGUIRE 26-13- 3		6.8		0.00000	%		56.87500	%		0		34,625		30,404		0		17,292		63,636		3,818		0		59,818		46,533
MCGUIRE 26-16- 1		7.8		0.00000	%		56.87500	%		0		44,706		39,256		0		22,327		74,680		4,481		0		70,199		52,765
MCGUIRE 27- 9- 4		4.9		0.00000	%		56.87500	%		0		23,414		20,560		0		11,693		39,112		2,347		0		36,766		30,155
MCGUIRE 34- 9- 5		13.0		0.00000	%		56.87500	%		0		76,921		67,545		0		38,416		128,494		7,710		0		120,785		76,785
MILLS 22-14- 1		21.3		0.00000	%		56.87500	%		0		263,177		231,096		0		131,436		439,627		26,378		0		413,250		239,438
MOODY 22- 6- 1		21.3		0.00000	%		56.87500	%		0		225,953		198,409		0		112,845		377,445		22,647		0		354,798		200,137
MOORE 13- 1- 1		7.3		0.00000	%		45.09190	%		0		58,899		51,719		0		23,321		85,822		5,149		0		80,672		62,652
MOORE 13- 9- 2		10.3		0.00000	%		45.09190	%		0		73,141		64,225		0		28,960		106,574		6,394		0		100,179		69,448
NAUGHER 34- 7- 1		12.2		0.00000	%		60.09516	%		0		75,982		66,720		0		40,095		147,551		8,853		0		138,698		93,403
PAYNE 17-15- 1		11.3		0.00000	%		56.87500	%		0		67,711		59,457		0		33,816		124,443		7,467		0		116,977		79,966
PETTUS 8- 5- 3		13.1		0.00000	%		56.87500	%		0		105,408		92,559		0		52,643		176,079		10,565		0		165,515		109,652
PETTUS 8- 6- 2		8.3		0.00000	%		56.87500	%		0		41,353		36,312		0		20,652		76,001		4,560		0		71,441		52,446
PRICE 1- 1- 1		4.7		0.00000	%		56.87500	%		0		18,448		16,199		0		9,213		30,817		1,849		0		28,968		23,690
RICE 2- 6- 1		14.8		0.00000	%		55.04687	%		0		89,675		78,744		0		43,346		144,984		8,699		0		136,285		81,984
SEALY 18- 1- 1		12.1		0.00000	%		56.87500	%		0		88,819		77,992		0		44,358		163,236		9,794		0		153,442		104,831
SEARCY 11- 9-14		0.0		0.00000	%		56.87500	%		0		0		0		0		0		0		0		0		0		0
SEARCY 12- 3-16		0.0		0.00000	%		56.87500	%		0		0		0		0		0		0		0		0		0		0
SEARCY 12- 6-19		2.8		0.00000	%		56.87500	%		0		9,896		8,689		0		4,942		18,187		1,091		0		17,095		15,172
SEARCY 17- 5- 7		14.5		0.00000	%		56.87500	%		0		80,858		71,001		0		40,382		148,605		8,916		0		139,689		85,651
SEARCY 17- 6-20		22.9		0.00000	%		56.87500	%		0		157,338		138,158		0		78,578		289,166		17,350		0		271,816		139,258
SEARCY 17-11- 8		39.7		0.00000	%		56.87500	%		0		567,784		498,571		0		283,562		1,043,510		62,611		0		980,899		433,092
SEARCY 17-14- 9		39.0		0.00000	%		56.87500	%		0		437,617		384,271		0		218,554		731,021		43,861		0		687,160		281,799
SEARCY 18-11-18		28.3		0.00000	%		56.87500	%		0		316,033		277,509		0		157,833		580,826		34,850		0		545,976		276,780
SEARCY 18-13- 6		0.0		0.00000	%		56.87500	%		0		0		0		0		0		0		0		0		0		0

RALPH E. DAVIS ASSOCIATES, INC.
TEXAS REGISTERED FIRM F-1529 Page 7 of 11

BLACK WARRIOR TRUST 1994-1	RESERVES and REVENUES
TOTAL ROYALTY INTERESTS	AS OF DECEMBER 31, 2009
TOTAL PROVED RESERVES

									Gross Volumes						Net Volumes				Product		Production		Operating		Future Net Income
	Life		Working			Revenue			Oil		Wellhead Gas		Sales Gas		Oil		Sales Gas		Sales		Taxes		Expense		Undiscounted		Disc. @ 10%
Well Name & Number	Years		Interest			Interest			Bbls		Mcf		Mcf		Bbls		Mcf		$		$		$		$		$
SEARCY 18-14- 5		26.8		0.00000	%		56.87500	%		0		261,274		229,425		0		130,485		480,186		28,811		0		451,375		229,214
SEARCY 19- 4- 1		0.0		0.00000	%		56.87500	%		0		0		0		0		0		0		0		0		0		0
SEARCY 19-10- 3		30.8		0.00000	%		56.87500	%		0		408,962		359,109		0		204,244		683,155		40,989		0		642,165		314,463
SEARCY 20- 3-10		3.8		0.00000	%		56.87500	%		0		13,771		12,092		0		6,877		25,309		1,519		0		23,791		20,262
SEARCY 20- 4-11		12.5		0.00000	%		56.87500	%		0		74,723		65,614		0		37,318		137,330		8,240		0		129,090		84,930
SEARCY 20- 5-12		40.1		0.00000	%		56.87500	%		0		566,086		497,080		0		282,715		1,040,390		62,423		0		977,966		427,989
SEARCY 20- 6-13		25.7		0.00000	%		56.87500	%		0		388,351		341,011		0		193,950		713,735		42,824		0		670,911		375,329
SEARCY 24- 1- 2		6.8		0.00000	%		56.87500	%		0		30,688		26,947		0		15,326		56,400		3,384		0		53,016		40,802
SEARCY 7- 6-17		4.3		0.00000	%		56.87500	%		0		18,186		15,969		0		9,082		33,423		2,005		0		31,418		26,456
SEARCY 7-15-15		7.3		0.00000	%		56.87500	%		0		39,512		34,696		0		19,733		66,004		3,960		0		62,043		47,187
SESSIONS 35- 8- 1		5.9		0.00000	%		56.87500	%		0		26,835		23,564		0		13,402		44,827		2,690		0		42,138		33,132
SESSIONS 35- 9- 2		7.4		0.00000	%		56.87500	%		0		40,348		35,430		0		20,151		74,154		4,449		0		69,705		53,238
SESSIONS 35-15- 3		10.4		0.00000	%		56.87500	%		0		84,212		73,947		0		42,057		140,673		8,440		0		132,233		94,470
STEDMAN 1- 9- 1		5.0		0.00000	%		52.81250	%		0		27,722		24,343		0		12,856		43,000		2,580		0		40,420		33,174
STEDMAN 11- 1- 5		5.4		0.00000	%		52.81250	%		0		30,850		27,089		0		14,306		47,852		2,871		0		44,981		36,430
STEDMAN 11- 2- 6		7.8		0.00000	%		52.81250	%		0		51,184		44,944		0		23,736		79,393		4,764		0		74,629		56,095
STEDMAN 11- 3-24		6.4		0.00000	%		52.81250	%		0		42,163		37,023		0		19,553		65,401		3,924		0		61,477		48,518
STEDMAN 11- 4- 7		14.4		0.00000	%		52.81250	%		0		82,678		72,599		0		38,342		141,097		8,466		0		132,631		80,803
STEDMAN 11- 5- 8		5.7		0.00000	%		52.81250	%		0		25,491		22,384		0		11,821		39,540		2,372		0		37,168		29,269
STEDMAN 11- 9- 9		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
STEDMAN 1-11- 3		0.6		0.00000	%		52.81250	%		0		1,959		1,720		0		909		3,343		201		0		3,143		3,058
STEDMAN 11-10-10		4.9		0.00000	%		52.81250	%		0		26,555		23,318		0		12,315		41,190		2,471		0		38,719		31,827
STEDMAN 11-12-11		6.6		0.00000	%		52.81250	%		0		37,984		33,353		0		17,615		58,918		3,535		0		55,383		43,012
STEDMAN 11-14-12		11.7		0.00000	%		52.81250	%		0		71,859		63,099		0		33,324		122,633		7,358		0		115,275		77,103
STEDMAN 11-16-13		2.4		0.00000	%		52.81250	%		0		10,837		9,516		0		5,026		16,810		1,009		0		15,802		14,227
STEDMAN 1-15-14		5.2		0.00000	%		52.81250	%		0		23,570		20,697		0		10,930		40,224		2,413		0		37,811		30,694
STEDMAN 1-16- 4		5.6		0.00000	%		52.81250	%		0		29,712		26,090		0		13,779		46,088		2,765		0		43,322		34,682
STEDMAN 13- 1-15		7.6		0.00000	%		52.81250	%		0		41,645		36,568		0		19,313		64,597		3,876		0		60,721		45,292
STEDMAN 13- 2-16		9.7		0.00000	%		52.81250	%		0		68,410		60,071		0		31,725		106,113		6,367		0		99,746		71,235
STEDMAN 13- 4-17		10.9		0.00000	%		52.81250	%		0		95,928		84,234		0		44,486		148,798		8,928		0		139,870		98,416
STEDMAN 13- 6-18		3.3		0.00000	%		52.81250	%		0		16,123		14,158		0		7,477		25,009		1,501		0		23,508		20,530
STEDMAN 13- 9-19		9.7		0.00000	%		52.81250	%		0		73,446		64,493		0		34,060		113,925		6,836		0		107,090		77,040
STEDMAN 13-12-20		9.3		0.00000	%		52.81250	%		0		57,250		50,271		0		26,549		97,702		5,862		0		91,840		66,105
STEDMAN 13-14-21		18.9		0.00000	%		52.81250	%		0		159,544		140,096		0		73,988		272,276		16,337		0		255,940		147,480
STEDMAN 13-15-22		14.9		0.00000	%		52.81250	%		0		183,519		161,148		0		85,106		284,664		17,080		0		267,584		176,497
STOTHART 24-12- 1		3.8		0.00000	%		56.13633	%		0		16,819		14,769		0		8,291		27,731		1,664		0		26,067		22,185
STOTHART 24-13- 2		4.3		0.00000	%		56.50567	%		0		21,964		19,287		0		10,898		36,452		2,187		0		34,265		28,944
SULLIVAN 4-11- 2		15.2		0.00000	%		56.29461	%		0		220,784		193,870		0		109,139		365,047		21,903		0		343,145		231,656
THORNHILL 12-13- 1		0.0		0.00000	%		56.87500	%		0		0		0		0		0		0		0		0		0		0
TURNER 17-10- 1		11.4		0.00000	%		56.87500	%		0		69,797		61,288		0		34,858		128,277		7,697		0		120,580		82,089
TURNER 17-16- 1		12.3		0.00000	%		56.87500	%		0		62,641		55,005		0		31,284		104,639		6,278		0		98,361		62,345
USX 14- 3-45		16.1		0.00000	%		48.75000	%		0		166,989		146,633		0		71,484		239,099		14,346		0		224,753		138,823
USX 14- 5-24		3.9		0.00000	%		48.75000	%		0		19,469		17,096		0		8,334		27,876		1,673		0		26,204		22,158
USX 14-10-43		5.1		0.00000	%		47.51680	%		0		24,886		21,852		0		10,383		38,211		2,293		0		35,918		29,201
USX 14-11-25		7.4		0.00000	%		48.75000	%		0		42,308		37,151		0		18,111		66,648		3,999		0		62,649		47,284
USX 14-13-37		0.0		0.00000	%		46.51560	%		0		0		0		0		0		0		0		0		0		0
USX 14-14-44		6.0		0.00000	%		48.75000	%		0		40,344		35,426		0		17,270		57,766		3,466		0		54,300		43,253
USX 15-13-27		1.6		0.00000	%		48.75000	%		0		6,936		6,090		0		2,969		9,930		596		0		9,335		8,686
USX 16- 2A-40		6.8		0.00000	%		48.75000	%		0		38,770		34,044		0		16,596		55,511		3,331		0		52,180		39,756
USX 16- 4-29		0.0		0.00000	%		48.75000	%		0		0		0		0		0		0		0		0		0		0

RALPH E. DAVIS ASSOCIATES, INC.
TEXAS REGISTERED FIRM F-1529 Page 8 of 11

BLACK WARRIOR TRUST 1994-1	RESERVES and REVENUES
TOTAL ROYALTY INTERESTS	AS OF DECEMBER 31, 2009
TOTAL PROVED RESERVES

									Gross Volumes						Net Volumes				Product		Production		Operating		Future Net Income
	Life		Working			Revenue			Oil		Wellhead Gas		Sales Gas		Oil		Sales Gas		Sales		Taxes		Expense		Undiscounted		Disc. @ 10%
Well Name & Number	Years		Interest			Interest			Bbls		Mcf		Mcf		Bbls		Mcf		$		$		$		$		$
USX 16- 5-30		14.4		0.00000	%		48.75000	%		0		109,637		96,273		0		46,933		172,713		10,363		0		162,350		101,882
USX 16- 7-31		4.6		0.00000	%		48.75000	%		0		23,742		20,848		0		10,164		33,995		2,040		0		31,955		26,377
USX 16- 8-28		11.8		0.00000	%		48.75000	%		0		79,875		70,139		0		34,193		114,367		6,862		0		107,505		70,329
USX 16-11-33		18.9		0.00000	%		48.75000	%		0		177,676		156,017		0		76,059		254,401		15,264		0		239,137		135,109
USX 16-13-34		12.0		0.00000	%		48.75000	%		0		100,229		88,011		0		42,905		157,891		9,473		0		148,418		100,954
USX 16-15-35		11.3		0.00000	%		48.75000	%		0		66,078		58,023		0		28,286		104,093		6,246		0		97,847		65,072
USX 21-15-11		7.3		0.00000	%		48.75000	%		0		44,039		38,671		0		18,852		63,056		3,783		0		59,273		44,549
USX 21-16-12		6.0		0.00000	%		48.75000	%		0		31,430		27,599		0		13,454		45,002		2,700		0		42,302		33,035
USX 22- 4-36		14.0		0.00000	%		48.75000	%		0		98,557		86,543		0		42,190		141,116		8,467		0		132,649		81,608
USX 22-11-13		0.1		0.00000	%		48.75000	%		0		340		299		0		146		487		29		0		458		456
USX 22-12-14		2.5		0.00000	%		48.75000	%		0		10,278		9,026		0		4,400		16,192		972		0		15,220		13,625
USX 23- 4-41		10.7		0.00000	%		47.90550	%		0		88,353		77,583		0		37,166		124,314		7,459		0		116,855		81,716
USX 28- 3-15		3.6		0.00000	%		48.75000	%		0		18,476		16,224		0		7,909		26,455		1,587		0		24,867		21,364
USX 28- 4-16		1.2		0.00000	%		48.75000	%		0		5,010		4,400		0		2,145		7,174		430		0		6,744		6,391
USX 28- 5-17		5.1		0.00000	%		48.75000	%		0		24,675		21,667		0		10,563		38,870		2,332		0		36,538		29,679
USX 29- 8- 6		5.1		0.00000	%		48.75000	%		0		26,054		22,878		0		11,153		41,043		2,463		0		38,580		31,449
USX 29-11- 7		4.4		0.00000	%		48.75000	%		0		25,519		22,409		0		10,924		36,539		2,192		0		34,347		28,735
USX 29-13- 9		4.9		0.00000	%		48.75000	%		0		26,521		23,288		0		11,353		37,974		2,278		0		35,695		29,138
USX 29-14-10		3.6		0.00000	%		48.75000	%		0		18,612		16,343		0		7,967		26,649		1,599		0		25,050		21,530
USX 30- 9-18		6.6		0.00000	%		48.75000	%		0		36,007		31,618		0		15,414		56,723		3,403		0		53,319		41,302
USX 5- 7- 1		11.3		0.00000	%		48.75000	%		0		88,867		78,034		0		38,042		139,993		8,400		0		131,593		90,871
USX 5-10- 2		11.4		0.00000	%		48.75000	%		0		94,630		83,095		0		40,509		135,493		8,130		0		127,364		86,758
USX 5-15- 3		12.8		0.00000	%		48.75000	%		0		81,029		71,152		0		34,686		127,646		7,659		0		119,987		76,690
USX 8- 6- 4		7.3		0.00000	%		48.75000	%		0		54,471		47,831		0		23,318		77,994		4,680		0		73,314		56,398
USX 8-11- 5		8.2		0.00000	%		48.75000	%		0		54,154		47,553		0		23,182		77,539		4,652		0		72,886		53,746
USX 8-14-39		5.4		0.00000	%		46.73630	%		0		36,453		32,009		0		14,960		50,038		3,002		0		47,036		38,117
USX 9- 6-20		7.3		0.00000	%		48.75000	%		0		46,203		40,571		0		19,778		66,154		3,969		0		62,185		47,152
USX 9- 7-21		23.1		0.00000	%		48.75000	%		0		318,759		279,903		0		136,452		456,407		27,384		0		429,022		236,384
USX 9-10-22		9.8		0.00000	%		48.75000	%		0		77,699		68,227		0		33,261		122,400		7,344		0		115,056		82,943
USX 9-15-23		7.0		0.00000	%		48.75000	%		0		40,856		35,875		0		17,489		64,360		3,862		0		60,499		46,426
USX 9-16-38		10.0		0.00000	%		48.75000	%		0		86,400		75,867		0		36,985		123,709		7,423		0		116,286		83,058
WEST 1- 1-24		2.8		0.00000	%		52.81250	%		0		11,875		10,428		0		5,507		20,266		1,216		0		19,050		16,886
WEST 1- 2-25		1.4		0.00000	%		52.81250	%		0		5,713		5,017		0		2,649		8,862		532		0		8,330		7,812
WEST 1- 6-39		8.0		0.00000	%		52.81250	%		0		45,340		39,813		0		21,026		70,328		4,220		0		66,109		48,705
WEST 1- 8-27		0.4		0.00000	%		52.81250	%		0		1,565		1,375		0		726		2,428		146		0		2,283		2,238
WEST 1- 9-28		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
WEST 11- 1-34		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
WEST 11- 2-35		3.6		0.00000	%		52.81250	%		0		15,746		13,826		0		7,302		24,424		1,465		0		22,958		19,660
WEST 11- 4-41		19.8		0.00000	%		52.81250	%		0		208,095		182,728		0		96,503		322,785		19,367		0		303,418		174,423
WEST 11- 5-42		14.8		0.00000	%		52.81250	%		0		111,390		97,812		0		51,657		172,782		10,367		0		162,415		100,414
WEST 11- 8-36		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
WEST 1-10-29		2.4		0.00000	%		52.81250	%		0		9,613		8,441		0		4,458		16,406		984		0		15,421		13,890
WEST 1-11-30		0.1		0.00000	%		52.81250	%		0		301		264		0		139		466		28		0		438		437
WEST 11-15-37		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
WEST 1-13-31		8.6		0.00000	%		52.81250	%		0		47,047		41,312		0		21,818		80,290		4,817		0		75,472		55,017
WEST 1-14-32		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
WEST 1-16-33		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
WEST 13- 1-15		5.7		0.00000	%		52.81250	%		0		23,921		21,005		0		11,093		40,824		2,449		0		38,374		30,365
WEST 13- 2-16		7.5		0.00000	%		52.81250	%		0		45,975		40,371		0		21,321		71,314		4,279		0		67,035		50,691
WEST 13- 4-17		2.5		0.00000	%		52.81250	%		0		13,317		11,694		0		6,176		20,657		1,239		0		19,418		17,522

RALPH E. DAVIS ASSOCIATES, INC.
TEXAS REGISTERED FIRM F-1529 Page 9 of 11

BLACK WARRIOR TRUST 1994-1	RESERVES and REVENUES
TOTAL ROYALTY INTERESTS	AS OF DECEMBER 31, 2009
TOTAL PROVED RESERVES

									Gross Volumes						Net Volumes				Product		Production		Operating		Future Net Income
	Life		Working			Revenue			Oil		Wellhead Gas		Sales Gas		Oil		Sales Gas		Sales		Taxes		Expense		Undiscounted		Disc. @ 10%
Well Name & Number	Years		Interest			Interest			Bbls		Mcf		Mcf		Bbls		Mcf		$		$		$		$		$
WEST 13- 5- 3		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
WEST 13- 6- 1		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
WEST 13- 7-38		3.6		0.00000	%		52.81250	%		0		14,539		12,767		0		6,742		22,552		1,353		0		21,199		18,079
WEST 13- 8-14		7.7		0.00000	%		52.81250	%		0		41,563		36,497		0		19,275		64,471		3,868		0		60,602		44,977
WEST 13- 9- 9		4.6		0.00000	%		52.81250	%		0		21,155		18,576		0		9,810		32,814		1,969		0		30,845		25,428
WEST 13-11- 6		10.0		0.00000	%		52.81250	%		0		67,916		59,637		0		31,496		105,347		6,321		0		99,026		69,623
WEST 13-12- 4A		6.5		0.00000	%		52.81250	%		0		31,798		27,922		0		14,746		49,323		2,959		0		46,364		35,600
WEST 13-15-23		4.4		0.00000	%		52.81250	%		0		22,464		19,726		0		10,418		34,845		2,091		0		32,755		27,344
WEST 15- 1-51		9.1		0.00000	%		54.84375	%		0		52,222		45,856		0		25,149		84,120		5,047		0		79,072		56,509
WEST 15- 1-83		8.6		0.00000	%		52.81250	%		0		56,216		49,363		0		26,070		87,199		5,232		0		81,967		60,101
WEST 15- 2-52		0.7		0.00000	%		52.81250	%		0		2,472		2,171		0		1,147		3,835		230		0		3,605		3,494
WEST 15- 3-68		8.8		0.00000	%		45.80470	%		0		47,429		41,647		0		19,076		70,201		4,212		0		65,989		46,527
WEST 15- 3-84		15.4		0.00000	%		52.81250	%		0		121,239		106,460		0		56,224		188,058		11,284		0		176,775		107,948
WEST 15- 5-85		11.5		0.00000	%		52.81250	%		0		106,213		93,265		0		49,256		181,261		10,876		0		170,386		120,274
WEST 15- 6-53		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
WEST 15- 6-86		11.0		0.00000	%		52.81250	%		0		74,358		65,293		0		34,483		115,339		6,920		0		108,419		73,818
WEST 15- 8-55		6.1		0.00000	%		52.81250	%		0		40,634		35,680		0		18,844		63,029		3,782		0		59,247		47,387
WEST 15- 9-87		10.3		0.00000	%		52.81250	%		0		63,066		55,378		0		29,246		97,824		5,869		0		91,954		63,137
WEST 15-10-88		8.7		0.00000	%		52.81250	%		0		55,358		48,609		0		25,672		85,867		5,152		0		80,715		58,876
WEST 15-11-89		12.3		0.00000	%		52.81250	%		0		68,623		60,258		0		31,824		106,444		6,387		0		100,057		63,487
WEST 15-13-58		11.3		0.00000	%		52.81250	%		0		77,778		68,297		0		36,069		120,644		7,239		0		113,406		76,410
WEST 15-14-90A		11.3		0.00000	%		52.81250	%		0		78,422		68,862		0		36,368		121,643		7,299		0		114,345		77,271
WEST 15-16-91		6.6		0.00000	%		52.81250	%		0		43,224		37,955		0		20,045		73,766		4,426		0		69,340		54,944
WEST 17-12-20		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
WEST 17-13-21		14.8		0.00000	%		52.81250	%		0		106,042		93,116		0		49,177		164,487		9,869		0		154,617		94,881
WEST 19- 1-19		12.5		0.00000	%		52.81250	%		0		75,869		66,620		0		35,184		117,683		7,061		0		110,622		70,733
WEST 19- 2-10		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
WEST 19- 3- 7		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
WEST 19- 6-18		12.0		0.00000	%		52.81250	%		0		108,135		94,954		0		50,147		167,733		10,064		0		157,669		107,913
WEST 19- 7- 1		4.6		0.00000	%		52.81250	%		0		19,563		17,178		0		9,072		30,345		1,821		0		28,524		23,389
WEST 19- 8-12		14.8		0.00000	%		52.81250	%		0		129,360		113,591		0		59,990		200,655		12,039		0		188,616		118,897
WEST 19-11-13		30.1		0.00000	%		52.81250	%		0		263,671		231,529		0		122,276		408,991		24,539		0		384,451		169,946
WEST 19-12-11		22.0		0.00000	%		52.81250	%		0		259,106		227,521		0		120,159		401,910		24,115		0		377,795		210,575
WEST 21- 8-71		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
WEST 23- 3-93		13.8		0.00000	%		53.40400	%		0		134,618		118,208		0		63,128		211,150		12,669		0		198,481		131,246
WEST 23- 5-94		1.7		0.00000	%		53.40400	%		0		6,801		5,972		0		3,189		11,737		704		0		11,033		10,270
WEST 23- 6-95		9.7		0.00000	%		55.13947	%		0		47,983		42,134		0		23,233		85,496		5,130		0		80,366		55,946
WEST 23- 7-96		6.5		0.00000	%		53.40400	%		0		34,844		30,596		0		16,340		60,130		3,608		0		56,522		44,266
WEST 23- 8-92		9.3		0.00000	%		41.72187	%		0		80,608		70,782		0		29,532		98,777		5,927		0		92,851		66,544
WEST 27- 1-59		15.3		0.00000	%		52.81250	%		0		87,782		77,081		0		40,708		136,162		8,170		0		127,992		74,192
WEST 27- 2-60		7.7		0.00000	%		52.81250	%		0		41,043		36,040		0		19,033		63,663		3,820		0		59,844		44,371
WEST 27- 2-97		20.3		0.00000	%		53.40400	%		0		184,923		162,380		0		86,718		290,054		17,403		0		272,650		151,074
WEST 27- 4-62		9.9		0.00000	%		52.81250	%		0		50,797		44,605		0		23,557		78,794		4,728		0		74,066		50,390
WEST 27- 4-98		14.2		0.00000	%		53.40400	%		0		98,118		86,157		0		46,011		169,322		10,159		0		159,162		100,768
WEST 27- 5-65		12.3		0.00000	%		52.81250	%		0		59,006		51,813		0		27,364		100,699		6,042		0		94,657		59,759
WEST 27- 5-99		10.1		0.00000	%		53.40400	%		0		64,586		56,713		0		30,287		111,457		6,687		0		104,769		74,093
WEST 27- 7-100		22.4		0.00000	%		53.40400	%		0		226,114		198,550		0		106,034		354,662		21,280		0		333,382		179,354
WEST 27- 8-101		13.4		0.00000	%		53.40400	%		0		154,848		135,972		0		72,615		242,882		14,573		0		228,309		155,277
WEST 27-11-102		13.0		0.00000	%		53.87200	%		0		102,776		90,248		0		48,618		162,619		9,757		0		152,862		100,266
WEST 27-13-103		9.9		0.00000	%		53.40400	%		0		62,326		54,728		0		29,227		97,759		5,866		0		91,893		64,253

RALPH E. DAVIS ASSOCIATES, INC.
TEXAS REGISTERED FIRM F-1529 Page 10 of 11

BLACK WARRIOR TRUST 1994-1	RESERVES and REVENUES
TOTAL ROYALTY INTERESTS	AS OF DECEMBER 31, 2009
TOTAL PROVED RESERVES

									Gross Volumes						Net Volumes				Product		Production		Operating		Future Net Income
	Life		Working			Revenue			Oil		Wellhead Gas		Sales Gas		Oil		Sales Gas		Sales		Taxes		Expense		Undiscounted		Disc. @ 10%
Well Name & Number	Years		Interest			Interest			Bbls		Mcf		Mcf		Bbls		Mcf		$		$		$		$		$
WEST 27-14-104		14.8		0.00000	%		53.40400	%		0		126,784		111,329		0		59,454		198,862		11,932		0		186,930		117,834
WEST 3- 2-44		4.9		0.00000	%		53.17812	%		0		23,332		20,488		0		10,895		36,442		2,187		0		34,256		27,927
WEST 3- 3-22		9.3		0.00000	%		52.81250	%		0		51,829		45,511		0		24,036		80,395		4,824		0		75,571		53,045
WEST 3- 4-45		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
WEST 3- 8-48		13.3		0.00000	%		52.81250	%		0		84,815		74,476		0		39,332		131,559		7,894		0		123,666		77,909
WEST 31- 5-82		6.0		0.00000	%		53.87200	%		0		29,407		25,822		0		13,911		46,529		2,792		0		43,737		34,270
WEST 3-10-49		5.3		0.00000	%		53.17812	%		0		27,420		24,077		0		12,804		42,827		2,570		0		40,257		32,466
WEST 3-12-67		18.7		0.00000	%		52.81250	%		0		156,633		137,539		0		72,638		267,307		16,038		0		251,269		145,669
WEST 3-13-50		18.6		0.00000	%		54.84375	%		0		124,352		109,193		0		59,886		200,306		12,018		0		188,287		103,394
WEST 33- 2-112		4.8		0.00000	%		52.81250	%		0		25,346		22,257		0		11,754		39,316		2,359		0		36,957		30,546
WEST 33- 3-120		3.5		0.00000	%		52.81250	%		0		15,055		13,220		0		6,982		25,693		1,542		0		24,152		20,863
WEST 33- 6-114		9.3		0.00000	%		52.81250	%		0		56,988		50,042		0		26,428		88,397		5,304		0		83,093		58,987
WEST 33- 8-115		8.2		0.00000	%		52.81250	%		0		51,876		45,552		0		24,057		88,531		5,312		0		83,219		62,438
WEST 33-10-116		12.8		0.00000	%		52.81250	%		0		97,685		85,777		0		45,301		151,523		9,091		0		142,432		93,198
WEST 33-16-119		15.6		0.00000	%		54.84375	%		0		110,316		96,868		0		53,126		177,696		10,662		0		167,035		100,549
WEST 35- 2-105		10.8		0.00000	%		53.40400	%		0		80,864		71,007		0		37,920		126,837		7,610		0		119,226		82,995
WEST 35- 4-106		12.4		0.00000	%		38.92440	%		0		79,629		69,922		0		27,217		100,157		6,009		0		94,148		61,318
WEST 35- 6-107		9.3		0.00000	%		53.40400	%		0		56,340		49,472		0		26,420		88,371		5,302		0		83,068		58,969
WEST 35- 8-108		13.8		0.00000	%		53.40400	%		0		83,454		73,281		0		39,135		144,016		8,641		0		135,375		84,749
WEST 35- 9-109		15.8		0.00000	%		53.40400	%		0		109,820		96,433		0		51,499		189,516		11,371		0		178,145		108,047
WEST 35-10-110		7.2		0.00000	%		53.40400	%		0		37,949		33,323		0		17,796		59,523		3,571		0		55,952		42,269
WEST 35-14-111		26.9		0.00000	%		53.40400	%		0		148,587		130,474		0		69,678		256,416		15,385		0		241,031		104,563
WEST 7- 2-74		6.0		0.00000	%		52.81250	%		0		31,088		27,298		0		14,417		48,222		2,893		0		45,328		35,653
WEST 7- 3-75		15.3		0.00000	%		52.81250	%		0		91,633		80,463		0		42,495		142,136		8,528		0		133,608		78,329
WEST 7- 6-76		8.0		0.00000	%		52.81250	%		0		52,655		46,236		0		24,419		81,675		4,901		0		76,775		57,460
WEST 7- 8-77		5.2		0.00000	%		52.81250	%		0		26,213		23,018		0		12,156		40,660		2,440		0		38,221		30,986
WEST 7-11-78		6.3		0.00000	%		52.81250	%		0		30,695		26,953		0		14,235		47,612		2,857		0		44,756		34,698
WEST 7-12-79		6.4		0.00000	%		52.81250	%		0		32,755		28,762		0		15,190		55,900		3,354		0		52,546		41,041
WEST 7-13-80		4.5		0.00000	%		52.81250	%		0		22,506		19,763		0		10,437		34,910		2,095		0		32,816		27,280
WEST 7-15-81		4.6		0.00000	%		52.81250	%		0		23,858		20,950		0		11,064		37,007		2,220		0		34,787		28,901
WEYERHAEUSER 5-15- 2		8.9		0.00000	%		55.25000	%		0		80,792		70,944		0		39,196		131,104		7,866		0		123,238		92,752
WEYERHAEUSER 5-16- 1		12.0		0.00000	%		55.25000	%		0		84,461		74,165		0		40,976		137,058		8,223		0		128,834		86,080
TOTAL ALL PROPERTIES										0		33,429,281		29,354,253		0		157,495,503		55,145,422		3,308,725		0		51,836,703		32,525,078

RALPH E. DAVIS ASSOCIATES, INC.
TEXAS REGISTERED FIRM F-1529 Page 11 of 11