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, 2007

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

Trust Division
Royalty Trust Group
Bank of America, N.A.
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 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 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 $193,816,500.

At March 10, 2008, 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	41
Item 4. Submission of Matters to a Vote of Security Holders	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	52
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	52
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	63
Item 9A. Controls and Procedures	63
PART III	66
Item 10. Directors and Executive Officers of the Registrant	66
Item 11. Executive Compensation	66
Item 12. Security Ownership of Certain Beneficial Owners and Management	67
Item 13. Certain Relationships and Related Transactions	67
Item 14. Principal Accounting Fees and Services	69
PART IV	69
Item 15. Exhibits, Financial Statement Schedules	69
Consent of Ralph E. Davis Associates
Certification required by Rule 13a-14(a)/15d-14(a)
Certification required by Rule 13a-14(b)/15d-14(b)
Summary of Reserve Report

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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 January 1, 2008, 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.

          “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 “Commission”), 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, 2008, 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 year-end market 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.

          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.

          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

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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 Dominion 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 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.

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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

          Mellon Investor Services, L.L.C. (as successor to Chemical Shareholder Services Group, Inc.) serves as 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 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

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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 2007, the Trust earned interest income on funds held for distribution and made adjustments to the cash reserve maintained for the payment of contingent and future obligations of the Trust. The deductions of the Trust consist of severance taxes and administrative expenses. In addition, each Unitholder is entitled to depletion deductions. See “Unitholder’s 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). 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 in ordinary income (to the extent of gain realized on the disposition of the property). This depletion recapture rule applies to any disposition of property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the United States Treasury Regulations govern dispositions of property after March 13, 1995. The IRS will likely take the position that a Unitholder who purchases a Unit subsequent to December 31, 1986, must recapture depletion upon the disposition of that Unit.
Non-Passive Activity Income, Credits and Loss	The income, credits and expenses of the Trust are not taken into account in computing the passive activity losses and income under Section 469 of the 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.
Tax Shelter Registration	The Trust is registered as a “tax shelter,” and its tax shelter registration number is 94-277000355. Issuance of a tax shelter registration number does not indicate that the investment in Units or the claimed tax benefits have been reviewed, examined or approved by the IRS.
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 The Trustee assumes that some Trust Units are held by a middleman, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. Bank of America, N.A., 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 U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT.

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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 1995-2006 composite income tax returns with the DOR on behalf of all Nonresident Unitholders (defined below), and intends to file a composite return for 2007 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 2007. Accordingly, no Alabama state income tax is due under the 2007 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 2007 (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 instance, legislation has been proposed in Congress in connection with the pending reauthorization of the Federal Resource Conservation and Recovery Act (“RCRA”) that would amend RCRA to reclassify certain oil and gas production wastes as “hazardous waste.” If adopted, this amendment would result in more rigorous and expensive disposal requirements. 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 and again in July 2004. It will expire in August 2009. 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 budgeted approximately $111,000 during 2008 for anticipated expenditures related to compliance with environmental laws.

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 Sequent Energy for base load gas for the period of April 1, 2005 through October 31, 2005. Any gas above the base load was sold on the spot market to various purchasers. 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. Any gas above the base load was sold on the spot market to various purchasers. 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. Any gas above the base load was sold on the spot market to various purchasers. A gas sales contract was entered into with ConocoPhillips for base load gas for the period of November 1, 2006 through March 31, 2007. Any gas above the base load was sold on the spot market to various purchasers. A gas sales contract has been entered into with Coral Energy for base load gas for the period of April 1, 2007 through October

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31, 2007. It is anticipated that any additional gas above the base load will be sold on the spot market to various purchasers. 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. Any gas above the base load was or will be sold on the spot market to various purchasers. HighMount has informed the Trustee that it anticipates negotiating a similar contract for a period beginning April 1, 2008 with a credit worthy counterparty. 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 U.S. Securities and Exchange Commission, 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.

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, 2007, 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.

          Well Count and Acreage Summary. The following table shows as of December 31, 2007, 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, if necessary, 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 that expired in July 2004. A new permit was requested and obtained for post-July 2004 and will expire in August 2009. 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, on November 25, 2005, a compressor fire decreased deliverability by approximately 3,300 MMBtu per day through December 22, 2005. Other than during this designated period of time, production from the Underlying Properties was not curtailed for any reason other than for routine maintenance in 2007.

          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.

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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.

          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

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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 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 January 1, 2008, 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. The Reserve Estimate was prepared in accordance with criteria established by the Commission.

	As of
Royalty Interests	January 1, 2008
Net Proved Natural Gas Reserves (MMcf)(a):
Developed Producing		22,597,416
Estimated Future Net Revenues (in thousands) (a)(b):
2008		17,739,646
2009		16,052,374
2010		14,073,969
2011		12,352,288
2012		10,843,028
Thereafter		70,107,429
Total	$	141,168,734
Total Discounted at 10 Percent	$	84,848,680

(a)	The estimates of reserves and future net revenues summarized in this table are based upon a price of $7.224 per Mcf, which represented the market price for gas in their fields as of December 31, 2007. 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

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effects of depreciation, depletion and federal income tax. Estimated future net revenues and discounted estimated future net revenues are not intended and should not be interpreted as representing the fair market value for the estimated reserves.

          The 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.

          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.

          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 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 2.8 Bcf in 2008 to 1.7 Bcf in 2012.

          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

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Interests, and the calculation of the standardized measure of discounted future net revenues related thereto, is contained in Note 8 of the Notes to the Financial Statements incorporated by reference in Item 8 hereof. Dominion Resources has not 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 related taxes and information regarding natural gas sales prices for the years ended December 31, 2007, December 31, 2006 and December 31, 2005.

	Year ended December 31,
	2007		2006		2005
Production attributable to the Royalty Interests (Bcf)		3.3		3.7		4.6
Weighted average property, production and related taxes (per Mcf)		.42	$	0.44	$	0.42
Average Contract Price (per Mcf)	$	6.97	$	9.12	$	6.99

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. Any gas above the base load was sold on the spot market to various purchasers. 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. Any gas above the base load was sold on the spot market to various purchasers. 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. Any gas above the base load was sold on the spot market to various purchasers. 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. Any gas above the base load was sold on the spot market to various purchasers. A gas sales contract was entered into with ConocoPhillips for base load gas for the period of November 1, 2006 through March 31, 2007. Any gas above the base load was sold on the spot market to various purchasers. A gas sales contract has been entered into with Coral Energy for base load gas for the period of April 1, 2007 through October 31, 2007. It is anticipated that any additional gas above the base load will be sold on the spot market to various purchasers. 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. Any gas above the base load was or will be sold on the spot market to various purchasers. HighMount has informed the Trustee that it anticipates negotiating a similar contract for a period beginning April 1, 2008 with a credit worthy counterparty. The foregoing information regarding the gas purchase contracts has been provided to the Trustee by Dominion Resources and HighMount Alabama.

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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 Royalty Interests). Neither the Trust nor the Unitholders will control the timing of the plugging and abandoning of any wells. Through December 31, 2007, 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

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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 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.,

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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. At the time of filing of this Form 10-K, the Trustee does not have sufficient information to make a determination as to the materiality of this litigation.

Item 4. Submission of Matters to a Vote of Security Holders. Not applicable.

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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				Distribution
	High		Low		per Unit
2007
First Quarter	$	28.00	$	22.50	$	0.690690
Second Quarter	$	27.70	$	24.00		.646984
Third Quarter	$	26.19	$	19.27		.735980
Fourth Quarter	$	24.00	$	17.20		.603337
2006
First Quarter	$	51.10	$	38.00	$	1.510931
Second Quarter	$	46.00	$	36.20		.971014
Third Quarter	$	39.40	$	27.12		.703514
Fourth Quarter	$	31.50	$	26.00		.693086

          At March 1, 2008, there were 7,850,000 Units outstanding and approximately 465 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,
	2007		2006		2005		2004		2003
Royalty Income	$	21,962,082	$	31,403,042	$	31,918,416	$	24,340,315	$	20,746,843
Distributable Income	$	20,912,169	$	30,467,067	$	31,029,034	$	23,449,768	$	19,835,642
Distributable Income per Unit	$	2.66	$	3.88	$	3.95	$	2.99	$	2.53
Distributions per Unit	$	2.68	$	3.88	$	3.95	$	2.99	$	2.53
Total Assets, December 31	$	26,676,808	$	30,692,809	$	34,838,807	$	39,946,530	$	44,820,393
Total Corpus, December 31	$	26,353,024	$	30,444,631	$	34,582,715	$	39,819,581	$	44,689,580

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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 5 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 2007 marked the thirteenth full year of the existence of the Trust. The Trust received royalty income amounting to $21,962,082 during the year ended December 31, 2007, compared to $31,403,042 for 2006 and $31,918,416 for 2005 primarily due to the decline of production in 2007 and a significant decrease in prices at beginning of 2007 from 2006. 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, 2007 increased to $1,120,031, compared to $1,028,746 for 2006 and $953,510 for 2005. Distributable income for the year ended December 31, 2007 was $20,912,169, or $2.66 per Unit, compared to $30,467,067, or $3.88 per Unit, for 2006 and $31,029,034, or $3.95 per Unit, for 2005. The increase in administrative expenses in 2007 compared to 2006 was primarily the result of higher professional fees related to Sarbanes-Oxley compliance other and other legal matters. The increase from 2005 to 2006 was primarily the result of higher professional fees related to Sarbanes-Oxley compliance.

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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, 2007, 2006 and 2005, was based on production volumes and natural gas prices for the periods from October 1, 2006 to September 30, 2007, October 1, 2005 to September 30, 2006 and October 1, 2004 to September 30, 2005, 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,
	2007		2006		2005
Production (Bcf)(1)		3.402		3.665		4.820
Production (MMBtu)(2)		3.415		3.692		4.860
Average Contract Price Received ($/MMBtu)	$	6.84	$	8.98	$	6.99
Average Index Price ($/MMBtu)	$	7.07	$	9.22	$	7.13

(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 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. Any gas above the base load was sold on the spot market to various purchasers. 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. Any gas above the base load was sold on the spot market to various purchasers. 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. Any gas above the base load was sold on the spot market to various purchasers. 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. Any gas above the base load was sold on the spot market to various purchasers. A gas sales contract was entered into with ConocoPhillips for base load gas for the period of November 1, 2006 through March 31, 2007. Any gas above the base load was sold on the spot market to various purchasers. A gas sales contract has been entered into with Coral Energy for base load gas for the period of April 1, 2007 through October 31, 2007. It is anticipated that any additional gas above the base load will be sold on the spot market to various purchasers. 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. Any gas above the base load was or will be sold on the spot market to various purchasers. HighMount has informed the Trustee that it anticipates negotiating a similar contract for a period beginning April 1, 2008 with a credit worthy counterparty. 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, 2007, 2006 and 2005, by independent petroleum engineers. The reserve quantities of 22.6 Bcf for 2007 compared to 26.9 Bcf for 2006 and compared to 33.3 Bcf for 2005, reflect a decline in reserves between 2005 and 2006 and between 2006 and 2007 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 8.”

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.

1. New Accounting Pronouncements

          In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 Accounting for Derivative Instruments and No. 140 Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. This statement resolves issues addressed in Statement 133 Implementation Issue No. D1, Application of Statement 133 to Beneficial interests in Securitized Financial Assets. This statement is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The Trust has no such financial instruments and accordingly, the adoption of this new Standard did not impact the financial statements of the Trust.

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          In March 2006, the FASB issued SFAS No. 156, Accounting for Servicing of Financial Assets — an amendment of FASB Statements No. 140 Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. This statement requires an entity to recognize a servicing asset or servicing liability each time it undertakes an obligation to service a financial asset by entering into a servicing contract in certain situations. This statement is effective as of the beginning of an entity’s first fiscal year that begins after September 15, 2006. The adoption of this statement did not have an effect on the Trust’s financial statements.

          In July 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”), Accounting for Uncertainty in Income Taxes, which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 is effective for fiscal years beginning after December 15, 2006. The adoption of this statement did not have an effect on the Trust’s financial statements.

          In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Trustee does not believe that the adoption of this statement will have a material effect on the Trust’s financial statements.

          In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities-Including an amendment of FASB Statement No. 115. This statement permits entities to choose to measure many financial instruments and certain other items at fair value. This statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. The Trustee does not believe that the adoption of this statement will have a material effect on the Trust’s financial statements.

          In December 2007 the FASB issued SFAS No. 141(R), Business Combinations. This statement 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);

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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 Trustee does not believe that the adoption of this statement will have a material effect on the Trust’s financial statements.

          In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of Accounting Research Bulletin No. 51. This statement 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 Trustee does not believe that the adoption of this statement will have a material effect on the Trust’s financial statements.

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 “Financial Statements and Supplementary Data — Notes to Financial Statements — Note 5).

          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.

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3. 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, 2007, no impairment is required.

4. 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.

5. Reserve Disclosure

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

          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.

6. 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, 2007, 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

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damages, plus court costs and attorneys fees. At the time of filing of this Form 10-K, the Trustee does not have sufficient information to make a determination as to the materiality of this litigation.

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.

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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	$	5,114,275	$	5,114,275		0		0		0
Total	$	5,114,275	$	5,114,275		0		0		0

          The above payable relates to distributions declared February 19, 2008 and payable March 10, 2008 to unitholders of record on February 29, 2008.

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 Trust. The Trust periodically holds short-term investments acquired with funds held by the Trust pending distribution to Unitholders and funds held in reserve for the payment of Trust expenses and liabilities. Because of the short-term nature of these borrowings and investments and certain limitations upon the types of such investments that may be held by the Trust, the Trustee believes that the Trust is not subject to any material interest rate risk. The Trust does not engage in transactions in foreign currencies that could expose the Trust or Unitholders to any foreign currency related market risk.

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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, 2007 and 2006, and the related consolidated statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2007. 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 consolidated financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of the Trust at December 31, 2007 and 2006, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2007, on the basis of accounting described in Note 2.

We have also 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, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 11, 2008 expressed an unqualified opinion on the Trust’s internal control over financial reporting.

DELOITTE & TOUCHE LLP

Dallas, TX
March 11, 2008

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DOMINION RESOURCES BLACK WARRIOR TRUST

FINANCIAL STATEMENTS

Statements of Assets, Liabilities and Trust Corpus

	December 31,
	2007		2006
ASSETS
Cash and cash equivalents	$	176,204	$	202,808
Royalty interests in gas properties (less accumulated amortization of $129,316,896 and $125,327,500, respectively)		26,500,604		30,490,001
Total Assets	$	26,676,808	$	30,692,809
LIABILITIES AND TRUST CORPUS
Trust expenses payable	$	323,784	$	248,178
Trust corpus (7,850,000 units of beneficial interest authorized, issued and outstanding)		26,353,024		30,444,631
Total Liabilities and Trust Corpus	$	26,676,808	$	30,692,809

Statements of Distributable Income

	Year Ended December 31,
	2007			2006			2005
Royalty income	$	21,962,082		$	31,403,042		$	31,918,416
Interest income		70,118			92,771			64,128
		22,032,200			31,495,813			31,982,544
General and administrative expenses		(1,120,031	)		(1,028,746	)		(953,510	)
Distributable income	$	20,912,169		$	30,467,067		$	31,029,034
Distributable income per unit (7,850,000 units)	$	2.66		$	3.88		$	3.95
Distributions per unit	$	2.68		$	3.88		$	3.95

Statements of Changes in Trust Corpus

	Year Ended December 31,
	2007			2006			2005
Trust corpus, beginning of period	$	30,444,631		$	34,582,715		$	39,819,581
Amortization of Royalty Interests		(3,989,396	)		(4,158,573	)		(5,171,366	)
Distributable income		20,912,169			30,467,067			31,029,034
Distributions to Unitholders		(21,014,380	)		(30,446,578	)		(31,094,534	)
Trust corpus, end of period	$	26,353,024		$	30,444,631		$	34,582,715

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

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Notes to Financial Statements
Years Ended December 31, 2007, 2006 and 2005

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.

          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 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

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(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 5).

          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.

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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, 2007, 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.

New Accounting Pronouncements

          In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments – an amendment of FASB Statements No. 133 Accounting for Derivative Instruments and No. 140 Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. This statement resolves issues addressed in Statement 133 Implementation Issue No. D1, Application of Statement 133 to Beneficial interests in Securitized Financial Assets. This statement is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The Trust has no such financial instruments and accordingly, the adoption of this new Standard did not impact the financial statements of the Trust.

          In March 2006, the FASB issued SFAS No. 156, Accounting for Servicing of Financial Assets – an amendment of FASB Statements No. 140 Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. This statement requires an entity to recognize a servicing asset or servicing liability each time it undertakes an obligation to service a financial asset by entering into a servicing contract in certain situations. This statement is effective as of the beginning of an entity’s first fiscal year that begins after September 15, 2006. The adoption of this statement did not have an effect on the Trust’s financial statements.

          In July 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”), Accounting for Uncertainty in Income Taxes, which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with SFAS No. 109, Accounting for Income

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Taxes. FIN 48 is effective for fiscal years beginning after December 15, 2006. The adoption of this statement did not have an effect on the Trust’s financial statements.

          In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Trustee does not believe that the adoption of this statement will have a material effect on the Trust’s financial statements.

          In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities-Including an amendment of FASB Statement No. 115. This statement permits entities to choose to measure many financial instruments and certain other items at fair value. This statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. The Trustee does not believe that the adoption of this statement will have a material effect on the Trust’s financial statements.

          In December 2007 the FASB issued SFAS No. 141(R), Business Combinations. This statement 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 Trustee does not believe that the adoption of this statement will have a material effect on the Trust’s financial statements.

          In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of Accounting Research Bulletin No. 51. This statement requires reporting entities to present noncontrolling (minority) interests as equity

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(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 Trustee does not believe that the adoption of this statement will have a material effect on the Trust’s financial statements.

3. Federal Income Taxes

          The Trust is a grantor trust for Federal income tax purposes. As a grantor trust, the Trust is not required to pay Federal income taxes. Accordingly, no provision for 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 Unitholder’s method of accounting and without regard to the taxable year or accounting method employed by the Trust.

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

4. Related Party Transactions

          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 2007 the fee for these services was $440,560, in the aggregate, and will increase annually by three percent. Aggregate fees paid by the Trust to Dominion Resources in 2007, 2006 and 2005 were $220,280, 427,729 and $414,054, respectively and to HighMount in 2007 were $220,280.

          Aggregate fees and expense reimbursements paid by the Trust to the Trustees in 2007, 2006 and 2005 were $48,735, $47,461 and $46,225, respectively.

5. 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 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

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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.

6. Subsequent Events

          Subsequent to December 31, 2007, the Trust declared and paid the following distribution:

Quarterly		Distribution
Record Date	Payment Date	per Unit
February 29, 2008	March 10, 2008	$	0.651500

7. 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, 2007 and 2006 (in thousands, except per Unit amounts):

	Royalty		Distributable		Distributable
Calendar Quarter	Income		Income		Income per Unit
2007
First	$	5,706	$	5,414	$	0.69
Second		5,408		5,109		0.65
Third		6,003		5,814		0.74
Fourth		4,845		4,575		0.58
	$	21,962	$	20,912	$	2.66

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	Royalty		Distributable		Distributable
Calendar Quarter	Income		Income		Income per Unit
2006
First	$	12,115	$	11,848	$	1.51
Second		7,929		7,651		0.98
Third		5,722		5,545		0.71
Fourth		5,637		5,423		0.68
	$	31,403	$	30,467	$	3.88

          Selected 2007 fourth quarter data are as follows (in thousands, except per Unit amounts):

Royalty income		4,845
Interest income		16
General and administrative expenses		(286	)
Distributable income		4,575
Distributable income per Unit	$	.58
Distributions per Unit	$	.60

          Due to revisions in estimate of reserve quantities (see Note 8), estimated amortization of royalty interests increased by approximately 135,000, increased by approximately 225,000, and increased by approximately $100,000 during the fourth quarters of 2007, 2006 and 2005, respectively. These adjustments did not have an impact on the Trust’s distributable income.

8. Supplemental Gas Disclosure (Unaudited)

          The net proved reserves attributable to the Royalty Interests have been estimated as of December 31, 2007, 2006, 2005, and January 1, 2005, by independent petroleum engineers.

          In accordance with Statement of Financial Accounting Standards No. 69, estimates of proved reserves and future net cash flows from proved reserves have been prepared using contractually guaranteed prices and end-of-period 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 rate of 10 percent. The prices for December 31, 2007 and 2006, and January 1, 2006, were $7.224, $5.973, and $9.591 per Mcf, respectively. As of February 21, 2008, published Gas prices were approximately $9.08 per Mcf. The use of such price as compared to $7.224 per Mcf, which was used to calculate the above information, would result in a larger 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

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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, 2005	39,101
Revisions of previous estimates	(1,990	)
Production (MMcf)	(4,820	)
Proved developed reserves at December 31, 2005	32,291
Revisions of previous estimates	(1,751	)
Production (MMcf)	(3,665	)
Proved developed reserves at December 31, 2006	26,875
Revisions of previous estimates	(966	)
Production (MMcf)	(3,312	)
Proved developed reserves at December 31, 2007	22,597

          All proved reserve estimates presented above at December 31, 2007, 2006, 2005, and January 1, 2005, are proved developed.

          Proved developed reserves, all located in the United States, for the Trust’s Interests are estimated quantities of coal seam gas that geological and engineering data indicate with reasonable certainty to be recoverable in future years from the coal formation under existing economic and operating conditions. 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.

          The following table sets forth the standardized measure of discounted estimated future net cash flows from proved reserves at December 31, 2007, 2006 and 2005 relating to the Trust’s Royalty Interests (thousands of dollars):

	2007			2006			2005
Future cash inflows	$	150,179		$	147,119		$	293,769
Future severance taxes		(9,010	)		(8,827	)		(17,626	)
Future net cash flows		141,169			138,292			276,143
10% annual discount for estimated timing of cash flow		(56,320	)		(53,606	)		(119,146	)
Standardized measure of discounted future net cash flows	$	84,849		$	84,686		$	156,997

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          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, 2007, 2006 and 2005 (thousands of dollars):

	2007			2006			2005
Balance at beginning of period	$	84,686		$	156,997		$	113,440
Increase (decrease) due to:
Royalty income, net of taxes		(21,962	)		(31,403	)		(31,918	)
Changes in prices		22,619			(77,654	)		88,521
Changes in estimated volumes		(8,962	)		21,047			(24,390	)
Accretion of discount		8,469			15,700			11,344
Balance at December 31	$	84,849		$	84,686		$	156,997

9. 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 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. Any gas above the base load was sold on the spot market to various purchasers. 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. Any gas above the base load was sold on the spot market to various purchasers. 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. Any gas above the base load was sold on the spot market to various purchasers. 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. Any gas above the base load was sold on the spot market to various purchasers. A gas sales contract was entered into with ConocoPhillips for base load gas for the period of November 1, 2006 through March 31, 2007. Any gas above the base load was sold on the spot market to various purchasers. A gas sales contract has been entered into with Coral Energy for base load gas for the period of April 1, 2007 through October 31, 2007. It is anticipated that any additional gas above the base load will be sold on the spot market to various purchasers. 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. Any gas above the base load was or will be sold on the spot market to various purchasers. HighMount has informed the Trustee that it anticipates negotiating a similar contract for a period beginning April 1, 2008 with a credit worthy counterparty. 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 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

          As of the end of the period covered by this report, the Trustee carried out an evaluation of the effectiveness of the design and operation of the Trust’s disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15. Based upon that evaluation, the Trustee concluded that the Trust’s disclosure controls and procedures are effective in timely alerting the Trustee to material information relating to the Trust required to be included in the Trust’s periodic filings with the Securities and Exchange Commission. In its evaluation of disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on information provided by 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 2007 that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.

Trustee’s Report on Internal Control Over Financial Reporting

          The Trustee is responsible for establishing and maintaining adequate 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, 2007. 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, 2007, has issued an attestation report on the Trust’s internal control over financial reporting, which is included herein.

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, 2007, 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 company are being made only in accordance with authorizations 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.

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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 Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, 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, 2007, and the related statements of distributable income and changes in trust corpus for the year ended December 31, 2007, 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 11, 2008 expressed an unqualified opinion on those financial statements.

DELOITTE & TOUCHE LLP

Dallas, TX
March 11, 2008

64

Item 9B. Other Information. None.

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PART III.

Item 10. Directors and Executive Officers of the Registrant. Directors and Executive Officers. The Trust has no directors or executive officers. Each of the Trustee and the Delaware Trustee is a corporate trustee that may be removed as trustee under the Trust Agreement, with or without cause, at a meeting duly called and held by the affirmative vote of Unitholders of not less than a majority of all the Units then outstanding. Any such removal of the Delaware Trustee shall be effective only at such time as a successor Delaware Trustee fulfilling the requirements of Section 3807(a) of the Delaware Code has been appointed and has accepted such appointment, and any such removal of the Trustee shall be effective only at such time as a successor Trustee has been appointed and has accepted such appointment.

          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 Bank of America, N.A., 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 Dominion Resources, the Trustee, the Delaware Trustee, Mellon Investor Service, L.L.C. (as successor to Chemical Shareholder Services Group, Inc.) (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 Dominion Resources 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 $28,858, plus an hourly charge for services in excess of a combined total of 350 hours annually at its standard rate, which is currently $125 per 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

66

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 2007, the Trustee and the Delaware Trustee received total compensation of $43,735 and $5,000, respectively.

          Compensation of the Transfer Agent. The Transfer Agent receives a transfer agency fee of $3.25 annually per account, plus $1.50 for each certificate issued and $.40 for each check issued (subject to an annual minimum of $7,200).

          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 – 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.

          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, 2008, Bank of America, N.A., the Trustee, beneficially owned no 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.

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 will be entitled to the administrative services fee. The annual fee, payable in equal quarterly installments, is currently $440,560 and will increase annually by three percent.

          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

67

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 Agreement is established in such contract at rates that do not necessarily take into account the

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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, 2007 and 2006 are:

	2007		2006
Audit Fees	$	147,500	$	125,375
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—
	$	147,500	$	125,375

          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, 2007 and 2006

Statements of Distributable Income for the years ended December 31, 2007, 2006 and 2005

Statements of Changes in Trust Corpus for the years ended December 31, 2007, 2006 and 2005

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).

70

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 27, 2007, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests as of January 1, 2007, 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 14, 2008

(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).

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 27, 2007, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests as of January 1, 2007, 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

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, 2007. We hereby further consent to the use of the report dated March 3, 2008 appearing in the Company’s Form 10-K for the year ended December 31, 2007 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 13, 2008

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 annual 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 annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3.	Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, distributable income and changes in trust corpus of the registrant as of, and for, the periods presented in this annual report;
4.	I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), or for causing such 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 annual report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my 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 annual 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 annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;

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 14, 2008

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, 2007, 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 14, 2008	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

[Insert letter from Ralph E. Davis Associates, Inc.]

DOMINION BLACK WARRIOR BASIN 1994-1

THE ROYALTY INTERESTS

ESTIMATED RESERVES AND NON ESCALATED

FUTURE NET REVENUE REMAINING

AS OF

DECEMBER 31, 2007

RALPH E. DAVIS ASSOCIATES, INC. MARCH 2008

HOUSTON, TEXAS

TABLE OF CONTENTS

ITEM

ENGINEERING LETTER

RESERVES DEFINITION

SUMMARY OF ALL RESERVES

ONE LINE SUMMARY, ALL RESERVES

BY WELL NAME AND NUMBER

1

March 3, 2008

Black Warrior Basin Trust 1994-1 c/o
Bank of America P. 0. Box 830650
Dallas, Texas 75283

Attn: Mr. Ron E. Hooper
Sr. Vice President, Royalty Management

Re: Estimated Reserves and Non Escalated Future
Net Revenue Remaining as of December 31, 2007
Dominion Black Warrior Basin 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 Basin 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.

The reserves associated with these estimates have been classified in accordance with the definitions of the Securities and Exchange Commission as found in Rule 4-10(a) of regulation S-X of the Securities Exchange Act of 1934. We have also estimated the future net revenue and discounted present value associated with these reserves as of December 31, 2007, utilizing a scenario of non escalated product prices 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:

1717 St. James Place, Suite 460 Houston, Texas 77056 Office 713-622-8955 Fax 713-626-3664 www.ralphedavis.com

Worldwide Energy Consultants Since 1924

2

Dominion Black Warrior Basin Trust 1994-1
Mr. Ron E. Hooper March 3, 2008
Page 2

Non Escalated Pricing Scenario
Estimated Reserves and Future Net Income
Net to Dominion Black Warrior Basin Trust 1994-1
As of December 31, 2007

	Total Proved
Net Remaining Sales Gas Reserves:
Gas: Mcf		22,597,416
Future Revenue:
Sales Revenue	$	150,179,484
Tax Credit Revenue		0
Total Revenue	$	150,179,484
Production Taxes	$	9,010,771
Other Deductions		0
Future Net Income	$	141,168,734
Future Net Income Discounted @ 10%	$	84,848,680

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) 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.

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.

3

Dominion Black Warrior Basin Trust 1994-1
Mr. Ron E. Hooper March 3, 2008
Page 3

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.

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 accuracy of reserve estimates is dependent upon the quality of available data and upon the independent geological and engineering interpretation of that data. Reserve estimates presented in this report are calculated using acceptable methods and procedures and are believed to be reasonable; however, future reservoir performance may justify revision of these estimates.

The anticipated producing 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.

PRICING PROVISIONS

Natural Gas - The unit price used throughout this report for natural gas is primarily based upon an initial price of $7.1909 per MMBtu for December 28, 2008, the last trading day of the year, and is representative of the price in effect for sales based upon the Sonat Tl 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 often (10.0) percent.

4

Dominion Black Warrior Basin Trust 1994-1
Mr. Ron E. Hooper March 3, 2008
Page 4

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.

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.

Alien C. Barron, P.E.
President

5

CLASSIFICATION OF RESERVES

Proved Oil and Gas Reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

1.                Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

2.                Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

3.                Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved Developed Oil and Gas Reserves

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Undeveloped Reserves

Proved undeveloped oil and gas reserves are reserves 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved 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 tests in the area and in the same reservoir.

(Classification of reserves as found in Rule 4-10(a) of Regulation S-X of the per Securities and Exchange Act)

6

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

R E S E R V E S     A N D     E C O N O M I C S

EFFECTIVE DATE: 01/2008

			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
12-2008		519.6		0.000		5908.378		5317.537		0.000		2831.562		0.00		7.244		0.000		20513.018		0.000		18871.953
12-2009		525.4		0.000		5352.181		4816.964		0.000		2565.182		0.00		7.236		0.000		18561.930		0.000		17076.984
12-2010		521.5		0.000		4696.069		4226.463		0.000		2250.564		0.00		7.231		0.000		16274.262		0.000		14972.323
12-2011		516.2		0.000		4123.480		3711.132		0.000		1976.193		0.00		7.228		0.000		14283.407		0.000		13140.730
12-2012		508.0		0.000		3620.942		3258.850		0.000		1735.471		0.00		7.225		0.000		12538.187		0.000		11535.133
12-2013		491.8		0.000		3172.821		2855.537		0.000		1520.933		0.00		7.222		0.000		10984.265		0.000		10105.527
12-2014		477.9		0.000		2785.114		2506.603		0.000		1335.461		0.00		7.220		0.000		9641.419		0.000		8870.105
12-2015		461.7		0.000		2442.962		2198.666		0.000		1171.793		0.00		7.218		0.000		8457.433		0.000		7780.835
12-2016		440.6		0.000		2136.449		1922.803		0.000		1025.293		0.00		7.216		0.000		7398.272		0.000		6806.412
12-2017		417.6		0.000		1865.188		1678.669		0.000		895.550		0.00		7.214		0.000		6460.570		0.000		5943.728
12-2018		390.7		0.000		1621.204		1459.084		0.000		779.177		0.00		7.213		0.000		5619.915		0.000		5170.324
12-2019		366.2		0.000		1411.220		1270.097		0.000		678.623		0.00		7.211		0.000		4893.702		0.000		4502.207
12-2020		333.9		0.000		1215.236		1093.713		0.000		584.949		0.00		7.210		0.000		4217.613		0.000		3880.206
12-2021		305.0		0.000		1048.531		943.678		0.000		504.717		0.00		7.209		0.000		3638.636		0.000		3347.546
12-2022		280.2		0.000		905.935		815.341		0.000		436.468		0.00		7.208		0.000		3146.171		0.000		2894.478
S TOT		1.0		0.000		42305.711		38075.145		0.000		20291.934		0.00		7.226		0.000		146628.797		0.000		134898.484
AFTER		1.0		0.000		4760.701		4284.631		0.000		2305.482		0.00		7.204		0.000		16609.799		0.000		15281.012
TOTAL		1.0		0.000		47066.410		42359.777		0.000		22597.416		0.00		7.224		0.000		163238.594		0.000		150179.484

	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$
12-2008		1132.318		0.000		0.000		17739.646		0.000		0.000		0.000		0.000		17739.646		16922.697
12-2009		1024.619		0.000		0.000		16052.374		0.000		0.000		0.000		0.000		16052.374		13933.667
12-2010		898.339		0.000		0.000		14073.969		0.000		0.000		0.000		0.000		14073.969		11105.695
12-2011		788.444		0.000		0.000		12352.288		0.000		0.000		0.000		0.000		12352.288		8860.981
12-2012		692.108		0.000		0.000		10843.028		0.000		0.000		0.000		0.000		10843.028		7071.218
12-2013		606.331		0.000		0.000		9499.192		0.000		0.000		0.000		0.000		9499.192		5631.595
12-2014		532.207		0.000		0.000		8337.898		0.000		0.000		0.000		0.000		8337.898		4493.876
12-2015		466.851		0.000		0.000		7313.992		0.000		0.000		0.000		0.000		7313.992		3583.677
12-2016		408.385		0.000		0.000		6398.025		0.000		0.000		0.000		0.000		6398.025		2849.938
12-2017		356.623		0.000		0.000		5587.104		0.000		0.000		0.000		0.000		5587.104		2262.489
12-2018		310.219		0.000		0.000		4860.104		0.000		0.000		0.000		0.000		4860.104		1789.247
12-2019		270.133		0.000		0.000		4232.075		0.000		0.000		0.000		0.000		4232.075		1416.436
12-2020		232.812		0.000		0.000		3647.394		0.000		0.000		0.000		0.000		3647.394		1109.804
12-2021		200.853		0.000		0.000		3146.693		0.000		0.000		0.000		0.000		3146.693		870.337
12-2022		173.669		0.000		0.000		2720.809		0.000		0.000		0.000		0.000		2720.809		684.230
S TOT		8093.911		0.000		0.000		126804.586		0.000		0.000		0.000		0.000		126804.586		82585.891
AFTER		916.861		0.000		0.000		14364.152		0.000		0.000		0.000		0.000		14364.152		2262.791
TOTAL		9010.771		0.000		0.000		141168.734		0.000		0.000		0.000		0.000		141168.734		84848.680

	OIL		GAS				P.W. %		P.W., M$
GROSS WELLS		0.0		531.0	LIFE, YRS.	58.08		5.00		105752.352
GROSS ULT., MB & MMF		0.000		289953.969	DISCOUNT %	10.00		10.00		84848.695
GROSS CUM., MB & MMF		0.000		242887.578	UNDISCOUNTED PAYOUT, YRS.	0.00		15.00		71179.664
GROSS RES., MB & MMF		0.000		47066.410	DISCOUNTED PAYOUT, YRS.	0.00		18.00		65056.344
NET RES., MB & MMF		0.000		22597.414	UNDISCOUNTED NET/INVEST.	0.00		20.00		61585.305
NET REVENUE, M $		0.000		163238.609	DISCOUNTED NET/INVEST.	0.00		25.00		54493.812
INITIAL PRICE, $		0.000		7.240	RATE-OF-RETURN, PCT.	100.00		40.00		41215.453
INITIAL N.I., PCT.		0.000		52.812	INITIAL W.I., PCT.	0.000		60.00		31962.566
								80.00		26651.193
								100.00		23187.062

DOMINION BLACK WARRIOR BASIN TRUST 1994-1	UNESCALATED ANALYSIS
ROYALTY INTERESTS	AS OF DECEMBER 31, 2007

									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		27.0		0.00000	%		56.87502	%		0		216,899		195,209		0		111,025		732,441		43,946		0		688,494		382,336
ALABAMA BASIC 23-14-5		14.7		0.00000	%		56.87502	%		0		77,812		70,031		0		39,830		262,750		15,765		0		246,985		166,652
ALABAMA BASIC 23-16-6		11.7		0.00000	%		56.87502	%		0		48,986		44,087		0		25,075		165,411		9,925		0		155,486		109,575
ALABAMA BASIC 26-1-7		11.6		0.00000	%		56.87502	%		0		52,041		46,837		0		26,638		175,728		10,544		0		165,184		118,088
ALABAMA BASIC 27-16-8		19.7		0.00000	%		57.20324	%		0		146,432		131,789		0		75,388		497,315		29,839		0		467,476		292,600
ALABAMA BASIC 34-3-14		19.7		0.00000	%		56.79375	%		0		97,983		88,185		0		50,083		330,388		19,823		0		310,565		184,907
ALABAMA BASIC 36-2-2		10.2		0.00000	%		58.18800	%		0		38,324		34,492		0		20,070		132,397		7,944		0		124,453		89,711
ALABAMA BASIC 36-4-1		13.5		0.00000	%		58.18800	%		0		57,839		52,055		0		30,290		199,814		11,989		0		187,825		125,303
ALABAMA BASIC 36-5-9		14.2		0.00000	%		56.26400	%		0		62,994		56,695		0		31,899		210,428		12,626		0		197,802		129,557
ALABAMA BASIC 36-9-3		13.1		0.00000	%		58.18800	%		0		63,926		57,533		0		33,478		220,844		13,251		0		207,593		142,219
ALABAMA BASIC 36-13-10		16.9		0.00000	%		58.18800	%		0		74,925		67,433		0		39,238		258,843		15,531		0		243,313		145,374
ALABAMA BASIC 36-14-11		8.8		0.00000	%		58.18800	%		0		32,319		29,087		0		16,925		111,653		6,699		0		104,954		78,365
ALABAMA BASIC 36-16-12		19.7		0.00000	%		58.18800	%		0		98,781		88,903		0		51,731		341,255		20,475		0		320,780		188,572
ALCUS 12-4-1		7.3		0.00000	%		54.84375	%		0		18,606		16,745		0		9,184		60,583		3,635		0		56,948		43,333
ALCUS 12-5-2		3.9		0.00000	%		54.19375	%		0		6,232		5,608		0		3,039		20,050		1,203		0		18,847		15,613
BAUGHMAN 18-3-2		15.6		0.00000	%		56.87500	%		0		105,995		95,396		0		54,256		357,917		21,475		0		336,442		227,216
BAUGHMAN 18-6-3		25.7		0.00000	%		56.87500	%		0		197,588		177,829		0		101,140		667,199		40,032		0		627,167		356,197
BAUGHMAN 18-7-4		21.5		0.00000	%		56.87500	%		0		126,145		113,531		0		64,571		425,958		25,557		0		400,401		234,692
BEAN 14-15-1		13.0		0.00000	%		55.76460	%		0		52,280		47,052		0		26,238		173,088		10,385		0		162,703		109,005
BIGHAM 4-13-1		8.6		0.00000	%		56.87500	%		0		46,268		41,641		0		23,683		156,234		9,374		0		146,860		115,231
CANTLEY 17-7-2		12.6		0.00000	%		56.87500	%		0		51,035		45,931		0		26,123		172,330		10,340		0		161,990		111,488
CARNLEY 18-5-3		18.2		0.00000	%		61.70528	%		0		102,453		92,207		0		56,897		375,336		22,520		0		352,815		224,380
CARNLEY 18-12-4		24.9		0.00000	%		61.70528	%		0		230,601		207,541		0		128,064		844,809		50,689		0		794,120		474,000
CARNLEY 18-14-5		25.6		0.00000	%		61.70528	%		0		329,035		296,131		0		182,729		1,205,419		72,325		0		1,133,094		696,776
CASSIDY 19-1-72		15.8		0.00000	%		48.75000	%		0		80,466		72,420		0		35,305		232,897		13,974		0		218,923		140,435
CASSIDY 19-2-73		17.3		0.00000	%		48.75000	%		0		77,376		69,638		0		33,949		223,952		13,437		0		210,515		127,823
CASSIDY 19-3-74		11.7		0.00000	%		48.75000	%		0		55,160		49,644		0		24,201		159,651		9,579		0		150,072		105,811
CASSIDY 19-6-96		14.8		0.00000	%		48.75000	%		0		69,612		62,651		0		30,542		201,480		12,089		0		189,391		123,183
CASSIDY 19-7-75		15.3		0.00000	%		48.75000	%		0		64,127		57,715		0		28,136		185,606		11,136		0		174,469		108,720
CASSIDY 19-9-76		14.3		0.00000	%		48.75000	%		0		76,014		68,413		0		33,351		220,011		13,201		0		206,811		138,424
CASSIDY 19-10-77		10.3		0.00000	%		48.75000	%		0		39,254		35,328		0		17,223		113,613		6,817		0		106,796		76,541
CASSIDY 19-11-97		18.4		0.00000	%		48.75000	%		0		72,939		65,645		0		32,002		211,109		12,667		0		198,442		114,584
CASSIDY 19-13-7B		15.7		0.00000	%		52.81250	%		0		75,890		68,301		0		36,072		237,956		14,277		0		223,679		143,541
CASSIDY 19-15-79		9.3		0.00000	%		48.75000	%		0		34,188		30,769		0		15,000		98,952		5,937		0		93,015		67,934
CASSIDY 19-16-80		11.7		0.00000	%		48.75000	%		0		55,091		49,582		0		24,171		159,453		9,567		0		149,886		105,680
CASSIDY 20-3-81		13.0		0.00000	%		48.75000	%		0		58,074		52,267		0		25,480		168,087		10,085		0		158,002		106,834
CASSIDY 20-5-82		11.8		0.00000	%		48.75000	%		0		49,225		44,302		0		21,597		142,472		8,548		0		133,924		92,649
CASSIDY 20-6-83		20.2		0.00000	%		48.75000	%		0		91,105		81,995		0		39,972		263,689		15,821		0		247,867		138,502
CASSIDY 20-7-84		12.2		0.00000	%		48.75000	%		0		50,718		45,646		0		22,252		146,794		8,808		0		137,987		94,575
CASSIDY 20-8-85		17.6		0.00000	%		48.75000	%		0		104,810		94,329		0		45,986		303,356		18,201		0		285,155		179,041
CASSIDY 20-10-86		13.2		0.00000	%		48.75000	%		0		66,431		59,787		0		29,146		192,272		11,536		0		180,736		123,345
CASSIDY 20-12-87		15.7		0.00000	%		48.75000	%		0		75,190		67,671		0		32,990		217,624		13,057		0		204367		130,371
CASSIDY 20-14-88		12.2		0.00000	%		48.75000	%		0		50,644		45,579		0		22,220		146,580		8,795		0		137,785		94,387
CASSIDY 20-16-89		4.8		0.00000	%		48.75000	%		0		12,859		11,573		0		5,642		37,217		2,233		0		34,984		29,054
CASSIDY 21-2-102		18.4		0.00000	%		48.75000	%		0		94,562		85,106		0		41,489		273,693		16,422		0		257,272		154,286
CASSIDY 21-3-116		23.2		0.00000	%		48.75000	%		0		170,472		153,425		0		74,795		493,403		29,604		0		463,798		265,767
CASSIDY 21-4-117		20.9		0.00000	%		48.75000	%		0		92,173		82,956		0		40,441		266,779		16,007		0		250,772		139,020
CASSIDY 21-6-103		20.9		0.00000	%		48.75000	%		0		121,322		109,189		0		53,230		351,145		21,069		0		330,077		191,877
CASSIDY 21-8-104		6.7		0.00000	%		48.75000	%		0		19,162		17,246		0		8,407		55,462		3,328		0		52,134		40,767
CASSIDY 21-10-105		11.8		0.00000	%		48.75000	%		0		55,852		50,267		0		24,505		161,654		9,699		0		151,955		106,042
CASSIDY 21-11-106		27.8		0.00000	%		48.75000	%		0		155,116		139,604		0		68,057		448,958		26,937		0		422,020		211,954
CASSIDY 21-14-118		11.8		0.00000	%		48.75000	%		0		51,387		46,248		0		22,546		148,730		8,924		0		139,807		97,066
CASSIDY 22-1-107		10.7		0.00000	%		48.75000	%		0		41,862		37,676		0		18,367		121,162		7,270		0		113,893		80,933
CASSIDY 22-3-108		10.6		0.00000	%		48.75000	%		0		34,777		31,300		0		15,259		100,658		6,039		0		94,618		65,754

Page No. 1 of 10 Royalty Interests Oneline 03 03 08.xls

DOMINION BLACK WARRIOR BASIN TRUST 1994-1	UNESCALATED ANALYSIS
ROYALTY INTERESTS	AS OF DECEMBER 31, 2007

									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 22-6-110		4.8		0.00000	%		48.75000	%		0		11,996		10,796		0		5,263		34,719		2,083		0		32,636		27,102
CASSIDY 22-7-111		0.8		0.00000	%		48.90418	%		0		437		394		0		193		1,270		76		0		1,194		1,153
CASSIDY 22-13-112		8.3		0.00000	%		48.75000	%		0		24,888		22,399		0		10,920		72,034		4,322		0		67,712		50,253
CASSIDY 22-14-113		14.1		0.00000	%		48.75000	%		0		50,349		45,314		0		22,091		145,727		8,744		0		136,984		86,835
CASSIDY 25-3-11		4.9		0.00000	%		48.75000	%		0		15,102		13,592		0		6,626		43,710		2,623		0		41,087		34,329
CASSIDY 25-4-66		12.1		0.00000	%		48.75000	%		0		47,853		43,068		0		20,996		138,503		8,310		0		130,192		88,919
CASSIDY 25-5-67		11.5		0.00000	%		48.75000	%		0		53,520		48,168		0		23,482		154,906		9,294		0		145,611		102,931
CASSIDY 25-6-13		8.2		0.00000	%		48.75000	%		0		28,546		25,691		0		12,524		82,621		4,957		0		77,664		58,825
CASSIDY 25-10-1		5.4		0.00000	%		48.75000	%		0		16,202		14,581		0		7,108		46,893		2,814		0		44,079		35,983
CASSIDY 25-12-14		8.7		0.00000	%		48.75000	%		0		31,937		28,743		0		14,012		92,436		5,546		0		86,890		65,122
CASSIDY 25-14-21		9.6		0.00000	%		48.75000	%		0		34,050		30,645		0		14,940		98,553		5,913		0		92,640		67,247
CASSIDY 25-15-20		4.8		0.00000	%		48.75000	%		0		12,829		11,546		0		5,629		37,131		2,228		0		34,903		28,972
CASSIDY 25-16-1		7.2		0.00000	%		48.75000	%		0		22,860		20,574		0		10,030		66,165		3,970		0		62,195		48,058
CASSIDY 26-8-122		17.3		0.00000	%		48.75000	%		0		78,397		70,557		0		34,397		226,907		13,614		0		213,292		129,359
CASSIDY 26-10-123		10.3		0.00000	%		48.75000	%		0		39,440		35,496		0		17,304		114,152		6,849		0		107,303		76,731
CASSIDY 28-1-114		11.2		0.00000	%		48.75000	%		0		47,239		42,515		0		20,726		136,725		8,203		0		128,521		90,765
CASSIDY 28-7-115		15.6		0.00000	%		48.75000	%		0		77,525		69,772		0		34,014		224,382		13,463		0		210,919		134,668
CASSIDY 28-8-131		31.3		0.00000	%		47.93020	%		0		247,680		222,912		0		106,842		704,814		42,289		0		662,525		334,865
CASSIDY 29-1-95		10.0		0.00000	%		48.75000	%		0		38,853		34,967		0		17,047		112,453		6,747		0		105,706		76,462
CASSIDY 29-2-98		10.0		0.00000	%		48.75000	%		0		39,878		35,890		0		17,496		115,420		6,925		0		108,495		78,688
CASSIDY 29-3-90		6.8		0.00000	%		48.75000	%		0		21,777		19,599		0		9,554		63,029		3,782		0		59,247		46,489
CASSIDY 29-4-91		7.6		0.00000	%		48.75000	%		0		26,589		23,930		0		11,666		76,956		4,617		0		72,339		55,821
CASSIDY 29-5-92		10.2		0.00000	%		48.75000	%		0		41,254		37,128		0		18,100		119,402		7,164		0		112,238		81,153
CASSIDY 29-6-93		9.7		0.00000	%		48.75000	%		0		37,277		33,550		0		16,355		107,893		6,474		0		101,419		74,025
CASSIDY 29-9-94		18.2		0.00000	%		48.75000	%		0		114,732		103,259		0		50,339		332,072		19,924		0		312,148		189,224
CASSIDY 29-10-99		16.2		0.00000	%		48.75000	%		0		93,344		84,010		0		40,955		270,170		16,210		0		253,959		159,205
CASSIDY 30-2-119		23.2		0.00000	%		48.75000	%		0		203,828		183,445		0		89,430		589,947		35,397		0		554,550		328,389
CASSIDY 30-4-120		22.8		0.00000	%		52.81250	%		0		126,659		113,993		0		60,203		397,142		23,829		0		373,314		207,460
CASSIDY 30-8-121		13.6		0.00000	%		46.51560	%		0		72,945		65,650		0		30,538		201,450		12,087		0		189,363		128,879
CASSIDY 30-12-15		6.5		0.00000	%		46.51560	%		0		22,704		20,434		0		9,505		62,701		3,762		0		58,939		46,855
CASSIDY 30-13-1		6.2		0.00000	%		48.75000	%		0		18,724		16,852		0		8,215		54,195		3,252		0		50,943		40,569
CASSIDY 30-14-1		8.0		0.00000	%		48.75000	%		0		25,842		23,258		0		11,338		74,795		4,488		0		70,307		53,141
CASSIDY 30-15-12		10.3		0.00000	%		48.75000	%		0		38,760		34,884		0		17,006		112,185		6,731		0		105,454		75,531
CASSIDY 31-1-17		8.9		0.00000	%		48.75000	%		0		31,663		28,497		0		13,892		91,644		5,499		0		86,146		63,838
CASSIDY 31-2-10		12.6		0.00000	%		48.75000	%		0		54,216		48,795		0		23,787		156,920		9,415		0		147,505		100,412
CASSIDY 31-3-16		6.5		0.00000	%		48.75000	%		0		20,095		18,086		0		8,817		58,162		3,490		0		54,673		43,058
CASSIDY 31-4-1		6.3		0.00000	%		48.75000	%		0		18,249		16,425		0		8,007		52,820		3,169		0		49,651		39,315
CASSIDY 31-5-1A		10.5		0.00000	%		48.75000	%		0		41,571		37,414		0		18,239		120,320		7,219		0		113,101		80,829
CASSIDY 31-6-18		10.7		0.00000	%		48.75000	%		0		44,334		39,900		0		19,451		128,316		7,699		0		120,617		86,185
CASSIDY 31-8-70		8.0		0.00000	%		48.75000	%		0		26,089		23,480		0		11,447		75,510		4,531		0		70,980		53,681
CASSIDY 31-10-124		12.0		0.00000	%		48.75000	%		0		55,079		49,571		0		24,166		159,418		9,565		0		149,852		104,398
CASSIDY 31-12-125		10.2		0.00000	%		48.75000	%		0		41,254		37,128		0		18,100		119,402		7,164		0		112,238		81,153
CASSIDY 31-14-65		12.1		0.00000	%		48.75000	%		0		48,321		43,486		0		21,201		139,856		8,391		0		131,464		89,920
CASSIDY 31-16-69		10.7		0.00000	%		48.75000	%		0		40,033		36,030		0		17,565		115,869		6,952		0		108,917		76,969
CASSIDY 32-1-101		14.5		0.00000	%		48.75000	%		0		92,813		83,532		0		40,722		268,633		16,118		0		252,515		171,644
CASSIDY 32-2-41		14.3		0.00000	%		48.75000	%		0		72,558		65,302		0		31,835		210,007		12,600		0		197,407		130,922
CASSIDY 32-4-33		6.1		0.00000	%		48.75000	%		0		18,545		16,691		0		8,137		53,675		3,221		0		50,455		40,278
CASSIDY 32-6-40		8.1		0.00000	%		48.75000	%		0		28,130		25,317		0		12,342		81,417		4,885		0		78,532		58,075
CASSIDY 32-7-39		22.4		0.00000	%		48.75000	%		0		133,131		119,817		0		58,411		385,324		23,119		0		362,205		204,921
CASSIDY 32-8-34		28.9		0.00000	%		48.75000	%		0		297,925		268,132		0		130,714		862,293		51,738		0		810,556		442,102
CASSIDY 32-9-37		25.9		0.00000	%		48.75000	%		0		236,985		213,286		0		103,977		685,914		41,155		0		644,759		365,440
CASSIDY 32-10-45		13.6		0.00000	%		48.75000	%		0		71,066		63,959		0		31,180		205,688		12,341		0		193,347		131,204
CASSIDY 32-11-35		3.3		0.00000	%		48.75000	%		0		7,123		6,410		0		3,125		20,616		1,237		0		19,379		16,924
CASSIDY 32-12-62		10.8		0.00000	%		48.75000	%		0		38,486		34,637		0		16,886		111,391		6,683		0		104,706		73,142

Page No. 2 of 10 Royalty Interests Oneline 03 03 08.xls

DOMINION BLACK WARRIOR BASIN TRUST 1994-1	UNESCALATED ANALYSIS
ROYALTY INTERESTS	AS OF DECEMBER 31, 2007

									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 32-13-46		12.1		0.00000	%		48.75000	%		0		50,155		45,140		0		22,006		145,166		8,710		0		136,456		93,659
CASSIDY 32-14-36		12.1		0.00000	%		48.75000	%		0		49,912		44,921		0		21,899		144,463		8,668		0		135,796		93,206
CASSIDY 32-15-38		16.0		0.00000	%		48.75000	%		0		93,940		84,546		0		41,216		271,892		16,314		0		255,579		166,064
CASSIDY 36-1-19		6.2		0.00000	%		48.75000	%		0		18,719		16,847		0		8,213		54,179		3,251		0		50,928		40,706
CASSIDY 36-2-1		8.3		0.00000	%		48.75000	%		0		23,606		21,246		0		10,357		68,324		4,099		0		64,225		47,404
CASSIDY 36-3-23		9.3		0.00000	%		46.75000	%		0		32,407		29,166		0		14,219		93,797		5,628		0		88,169		64,061
CASSIDY 36-4-22		14.0		0.00000	%		48.75000	%		0		66,774		60,096		0		29,297		193,265		11,596		0		181,669		120,609
CASSIDY 36-5-24		8.8		0.00000	%		48.75000	%		0		31,411		28,270		0		13,782		90,915		5,455		0		85,460		63,670
CASSIDY 36-7-25		7.5		0.00000	%		48.75000	%		0		20,251		18,226		0		8,885		58,613		3,517		0		55,096		41,663
CASSIDY 36-8-4		6.4		0.00000	%		48.75000	%		0		19,531		17,578		0		8,569		56,529		3,392		0		53,137		42,130
CASSIDY 36-9-71		6.5		0.00000	%		48.75000	%		0		19,506		17,556		0		8,558		56,458		3,387		0		53,070		41,897
CASSIDY 36-10-28		6.3		0.00000	%		48.75000	%		0		17,600		15,840		0		7,722		50,941		3,056		0		47,885		37,786
CASSIDY 36-11-27		4.6		0.00000	%		48.75000	%		0		13,589		12,230		0		5,962		39,331		2,360		0		36,971		30,795
CASSIDY 36-12-26		4.3		0.00000	%		48.75000	%		0		10,336		9,303		0		4,535		29,917		1,795		0		28,122		23,633
CASSIDY 36-13-29		9.2		0.00000	%		48.75000	%		0		41,798		37,618		0		18,339		120,977		7,259		0		113,718		85,637
CASSIDY 36-14-30		5.2		0.00000	%		48.75000	%		0		13,262		11,935		0		5,819		38,383		2,303		0		36,080		29,534
CASSIDY 36-15-31		9.8		0.00000	%		48.75000	%		0		32,520		29,268		0		14,268		94,124		5,647		0		88,477		63,202
CASSIDY 36-16-3		14.7		0.00000	%		47.91200	%		0		64,446		58,002		0		27,790		183,323		10,999		0		172,324		111,280
CASSIDY 5-2-126		20.2		0.00000	%		48.75000	%		0		142,096		127,886		0		62,345		411,274		24,676		0		386,597		233,678
CASSIDY 5-4-49		14.1		0.00000	%		48.75000	%		0		69,707		62,736		0		30,584		201,754		12,105		0		189,649		126,207
CASSIDY 5-5-50		13.6		0.00000	%		48.75000	%		0		71,066		63,959		0		31,180		205,688		12,341		0		193,347		131,204
CASSIDY 5-6-61		18.1		0.00000	%		48.75000	%		0		129,304		116,374		0		56,732		374,249		22,455		0		351,794		223,771
CASSIDY 5-11-56		10.7		0.00000	%		48.75000	%		0		45,520		40,968		0		19,972		131,749		7,905		0		123,844		88,752
CASSIDY 5-13-48		7.7		0.00000	%		48.75000	%		0		25,615		23,054		0		11,239		74,139		4,448		0		69,691		53,382
CASSIDY 5-14-57		9.3		0.00000	%		48.75000	%		0		24,155		21,739		0		10,598		69,912		4,195		0		65,718		46,602
CASSIDY 6-2-64		17.6		0.00000	%		48.75000	%		0		82,538		74,284		0		36,213		238,892		14,334		0		224,559		136,234
CASSIDY 6-3-44		10.0		0.00000	%		48.75000	%		0		39,878		35,890		0		17,496		115,420		6,925		0		108,495		78,688
CASSIDY 6-4-42		4.7		0.00000	%		48.75000	%		0		13,441		12,097		0		5,897		38,902		2,334		0		36,568		30,705
CASSIDY 6-5-43		5.9		0.00000	%		48.75000	%		0		3,904		3,514		0		1,713		11,300		678		0		10,622		8,545
CASSIDY 6-6-53		11.7		0.00000	%		48.75000	%		0		47,726		42,954		0		20,940		138,136		8,288		0		129,848		90,088
CASSIDY 6-7-129		9.3		0.00000	%		48.75000	%		0		34,321		30,889		0		15,058		99,336		5,960		0		93,375		68,720
CASSIDY 6-9-47		11.4		0.00000	%		48.75000	%		0		45,661		41,095		0		20,034		132,159		7,930		0		124,229		86,572
CASSIDY 6-10-52		8.8		0.00000	%		48.75000	%		0		32,425		29,183		0		14,227		93,850		5,631		0		88,219		65,681
CASSIDY 6-11-54		3.6		0.00000	%		48.75000	%		0		7,860		7,074		0		3,449		22,750		1,365		0		21,385		18,373
CASSIDY 6-13-51		14.3		0.00000	%		48.75000	%		0		61,275		55,147		0		26,884		177,349		10,641		0		166,708		108,532
CASSIDY 6-14-55		14.8		0.00000	%		48.75000	%		0		68,530		61,677		0		30,068		198,349		11,901		0		186,449		120,418
CASSIDY 6-16-68		9.9		0.00000	%		48.75000	%		0		29,794		26,815		0		13,072		86,234		5,174		0		81,060		56,893
CASSIDY 8-4-63		5.1		0.00000	%		48.75000	%		0		13,785		12,406		0		6,048		39,898		2,394		0		37,504		30,903
CASSIDY 8-5-60		11.4		0.00000	%		48.75000	%		0		44,529		40,076		0		19,537		128,882		7,733		0		121,149		83,739
CASSIDY 8-12-58		25.8		0.00000	%		48.75000	%		0		84,484		76,035		0		37,067		244,524		14,671		0		229,852		106,473
CASSIDY 8-13-59		26.7		0.00000	%		48.75000	%		0		133,951		120,556		0		58,771		387,700		23,262		0		364,438		183,235
CHEVRON 23-16-18		13.5		0.00000	%		56.87500	%		0		65,048		58,544		0		33,297		219,651		13,179		0		206,472		140,984
CHEVRON 24-16-16		16.8		0.00000	%		56.87500	%		0		81,180		73,062		0		41,554		274,121		16,447		0		257,674		163,499
CHEVRON 25-2-1		7.8		0.00000	%		56.87500	%		0		24,684		22,215		0		12,635		83,351		5,001		0		78,350		60,491
CHEVRON 25-8-2		11.3		0.00000	%		56.87500	%		0		44,023		39,621		0		22,534		148,653		8,919		0		139,734		98,964
CHEVRON 25-11-3		8.8		0.00000	%		56.87500	%		0		26,844		24,159		0		13,741		90,644		5,439		0		85,206		63,524
CHEVRON 26-5-9		14.1		0.00000	%		56.87500	%		0		65,937		59,343		0		33,751		222,650		13,359		0		209,291		141,109
CHEVRON 27-1-10		14.9		0.00000	%		56.87500	%		0		74,104		66,693		0		37,932		250,228		15,014		0		235,215		156,491
CHEVRON 30-10-8		9.2		0.00000	%		56.87500	%		0		25,617		23,056		0		13,113		86,503		5,190		0		81,313		59,270
CHRISTIAN 12-5-2		15.8		0.00000	%		56.87500	%		0		78,317		70,485		0		40,088		264,453		15,867		0		248,586		161,824
CLEMENTS 34-11-1		16.5		0.00000	%		56.87500	%		0		115,635		104,072		0		59,191		390,469		23,428		0		367,041		244,239
CLEMENTS 34-15-1		20.3		0.00000	%		56.87500	%		0		129,659		116,693		0		66,369		437,823		26,269		0		411,554		252,137
CLEMENTS 34-16-2		15.3		0.00000	%		56.87500	%		0		90,977		81,879		0		46,569		307,204		18,432		0		288,772		194,791
COLBURN 15-9-1		19.6		0.00000	%		56.87500	%		0		88,186		79,368		0		45,140		297,780		17,867		0		279,914		165,044

Page No. 3 of 10 Royalty Interests Oneline 03 03 08.xls

DOMINION BLACK WARRIOR BASIN TRUST 1994-1	UNESCALATED ANALYSIS
ROYALTY INTERESTS	AS OF DECEMBER 31, 2007

									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		$		$		$		$		$
COLBURN 15-15-2		45.7		0.00000	%		56.87500	%		0		317,336		285,602		0		162,436		1,071,556		64,293		0		1,007,263		413,329
CUNNINGHAM 10-1-1		58.1		0.00000	%		56.87500	%		0		652,447		587,202		0		333,971		2,203,133		132,188		0		2,070,944		810,925
CUNNINGHAM 10-2-2		32.6		0.00000	%		56.87500	%		0		219,151		197,236		0		112,178		740,014		44,401		0		695,613		343,835
CUNNINGHAM 28-15-3		17.0		0.00000	%		56.87500	%		0		104,147		93,732		0		53,310		351,675		21,100		0		330,574		215,336
CUNNINGHAM 34-8-2		16.0		0.00000	%		56.87500	%		0		85,914		77,323		0		43,977		290,108		17,406		0		272,702		177,841
CUNNINGHAM 35-12-1		17.8		0.00000	%		57.60302	%		0		83,188		74,869		0		43,127		284,497		17,070		0		267,427		163,329
DAVANT 1-12-10		12.3		0.00000	%		56.87500	%		0		63,365		57,029		0		32,435		213,967		12,838		0		201,129		143,477
DAVANT 1-13-11		14.9		0.00000	%		54.84375	%		0		89,257		80,331		0		44,057		290,631		17,438		0		273,193		184,894
DAVANT 21-16-16		23.1		0.00000	%		56.87500	%		0		189,632		170,668		0		97,068		640,333		38,420		0		601,913		359,049
DAVANT 23-2-9		22.3		0.00000	%		56.87500	%		0		121,012		108,910		0		61,943		408,623		24,517		0		384,105		220,499
DAVANT 23-7-7		12.3		0.00000	%		56.87500	%		0		39,479		35,531		0		20,208		133,311		7,999		0		125,312		84,302
DAVANT 23-13-8		19.5		0.00000	%		56.87500	%		0		87,381		78,643		0		44,728		295,061		17,704		0		277,357		163,691
DAVANT 3-1-12		16.4		0.00000	%		56.87500	%		0		111,669		100,502		0		57,161		377,076		22,625		0		354,451		236,596
DAVANT 3-2-13		25.8		0.00000	%		56.87500	%		0		180,243		162,219		0		92,262		608,630		36,518		0		572,112		319,216
DAVANT 7-4-2		1.4		0.00000	%		56.87500	%		0		1,453		1,307		0		744		4,905		294		0		4,611		4,271
DAVANT 7-5-3		6.3		0.00000	%		56.87500	%		0		15,186		13,668		0		7,774		51,281		3,077		0		48,204		38,221
DAVANT 7-11-4		22.8		0.00000	%		56.87500	%		0		106,672		96,005		0		54,603		360,203		21,612		0		338,590		184,860
DAVANT 7-12-5		12.5		0.00000	%		56.87500	%		0		35,026		31,524		0		17,929		118,274		7,096		0		111,178		73,246
DAVANT 7-13-6		28.4		0.00000	%		56.87500	%		0		194,035		174,632		0		99,322		655,204		39,312		0		615,891		327,366
DAVANT 7-14-1		20.6		0.00000	%		56.87500	%		0		73,698		66,329		0		37,724		248,359		14,932		0		233,928		129,710
DAVIS 24-7-1		20.9		0.00000	%		56.87500	%		0		114,901		103,411		0		58,815		387,990		23,279		0		364,710		215,665
DAVIS 24-8-2		11.7		0.00000	%		56.87500	%		0		46,886		42,198		0		24,000		158,322		9,499		0		148,323		104,930
DAVIS 24-9-3		21.2		0.00000	%		56.87500	%		0		96,731		87,058		0		49,514		326,633		19,598		0		307,035		175,428
DAVIS 24-10-4		15.0		0.00000	%		56.74805	%		0		76,970		69,273		0		39,311		259,327		15,560		0		243,767		162,574
DEAL 27-4-1		15.7		0.00000	%		56.87500	%		0		76,558		68,902		0		39,188		258,516		15,511		0		243,005		158,495
DEAL 27-5-2		41.3		0.00000	%		55.86750	%		0		522,269		470,043		0		262,601		1,732,320		103,939		0		1,628,380		789,942
DRUMMOND 6-1-1		2.7		0.00000	%		48.75000	%		0		5,309		4,778		0		2,329		15,365		922		0		14,443		12,870
EARNEST 15-10-2		14.2		0.00000	%		56.87500	%		0		66,522		59,869		0		34,051		224,625		13,477		0		211,147		142,213
EARNEST 15-15-5		7.3		0.00000	%		56.87500	%		0		19,586		17,627		0		10,026		66,136		3,968		0		62,168		48,091
EARNEST 15-16-4		14.5		0.00000	%		56.87500	%		0		50,776		45,699		0		25,991		171,457		10,287		0		161,170		103,537
EARNEST 24-13-1		18.0		0.00000	%		56.62111	%		0		109,323		98,391		0		55,710		367,506		22,050		0		345,455		220,022
FEDERAL 8-9-10		16.5		0.00000	%		56.87500	%		0		60,133		54,120		0		30,781		203,053		12,183		0		190,869		117,153
FEDERAL 8-16-12		11.7		0.00000	%		56.87500	%		0		46,886		42,198		0		24,000		158,322		9,499		0		148,823		104,930
FEDERAL 9-4-5		23.3		0.00000	%		56.87500	%		0		195,695		176,126		0		100,171		660,808		39,649		0		621,160		372,950
FEDERAL 9-12-7		24.9		0.00000	%		56.87500	%		0		190,440		171,396		0		97,482		643,064		38,584		0		604,480		345,596
FEDERAL 9-14-8		26.0		0.00000	%		56.87500	%		0		151,922		136,730		0		77,765		513,000		30,780		0		482,220		260,541
FGLIC 26-2-1		13.8		0.00000	%		56.87500	%		0		62,595		56,336		0		32,041		211,367		12,682		0		198,685		134,531
FGLIC 26-6-3		17.3		0 00000	%		56.87500	%		0		97,321		87,589		0		49,816		328,627		19,718		0		308,909		198,118
FIRST ALABAMA BANK 10-9-23		7.4		0.00000	%		61.70528	%		0		24,195		21,776		0		13,437		88,640		5,318		0		83,322		65,254
FIRST ALABAMA BANK 10-15-24		23.3		0.00000	%		61.70528	%		0		98,868		88,982		0		54,906		362,205		21,732		0		340,472		180,796
FIRST ALABAMA BANK 10-16-25A		17.6		0.00000	%		81.70528	%		0		94,607		85,146		0		52,540		346,593		20,796		0		325,797		208,289
FIRST ALABAMA BANK 12-1-4		17.9		0.00000	%		60.09516	%		0		101,347		91,212		0		54,814		361,597		21,696		0		339,901		216,645
FIRST ALABAMA BANK 12-2-5		12.2		0.00000	%		60.09516	%		0		48,721		43,848		0		26,351		173,830		10,430		0		163,401		114,356
FIRST ALABAMA BANK 25-1-13		16.6		0.00000	%		50.70000	%		0		148,230		133,407		0		67,637		446,189		26,771		0		419,418		283,830
FIRST ALABAMA BANK 25-2-14		8.2		0.00000	%		51.89977	%		0		25,944		23,349		0		12,118		79,942		4,796		0		75,145		56,606
FIRST ALABAMA BANK 25-4-19		15.3		0.00000	%		51.89977	%		0		97,430		87,687		0		45,509		300,215		18,013		0		282,202		189,429
FIRST ALABAMA BANK 25-7-15		9.5		0.00000	%		51.89977	%		0		34,456		31,010		0		16,094		106,171		6,370		0		99,800		73,081
FIRST ALABAMA BANK 25-10-17		15.7		0.00000	%		51.89977	%		0		85,745		77,170		0		40,051		264,208		15,853		0		248,356		161,965
FIRST ALABAMA BANK 25-11-2		10.8		0.00000	%		51.89977	%		0		43,212		38,891		0		20,184		133,150		7,989		0		125,161		89,301
FIRST ALABAMA BANK 25-12-20		16.2		0.00000	%		51.89977	%		0		108,619		97,757		0		50,736		334,692		20,082		0		314,610		208,136
FIRST ALABAMA BANK 25-14-1		16.3		0.00000	%		51.89977	%		0		78,681		70,813		0		36,752		242,443		14,547		0		227,896		143,770
FIRST ALABAMA BANK 25-15-3A		4.1		0.00000	%		51.89977	%		0		10,825		9,742		0		5,056		33,355		2,001		0		31,354		26,816
FIRST ALABAMA BANK 25-16-22		14.3		0.00000	%		51.89980	%		0		74,967		67,471		0		35,017		231,000		13,860		0		217,140		145,092
FIRST ALABAMA BANK 26-16-18		14.8		0.00000	%		63.78578	%		0		87,882		79,094		0		50,451		332,813		19,969		0		312,844		211,909

Page No. 4 of 10 Royalty Interests Oneline 03 03 08.xls

DOMINION BLACK WARRIOR BASIN TRUST 1994-1	UNESCALATED ANALYSIS
ROYALTY INTERESTS	AS OF DECEMBER 31, 2007

									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 27-9-27		6.0		0.00000	%		61.70528	%		0		38,255		34,429		0		21,245		140,147		8,409		0		131,738		111,535
FIRST ALABAMA BANK 27-16-28		5.2		0.00000	%		61.70528	%		0		8,305		7,474		0		4,612		30,424		1,825		0		28,599		22,971
FIRST ALABAMA BANK 34-1-6		19.3		0.00000	%		42.83960	%		0		128,540		115,686		0		49,559		326,932		19,616		0		307,316		195,506
FIRST ALABAMA BANK 34-12-7		23.0		0.00000	%		42.83960	%		0		169,550		152,595		0		65,371		431,239		25,874		0		405,365		243,733
FIRST ALABAMA BANK 34-13-21		25.7		0.00000	%		61.70528	%		0		136,940		123,246		0		76,049		501,680		30,101		0		471,579		256,033
FIRST ALABAMA BANK 35-2-8		7.0		0.00000	%		42.83960	%		0		12,468		11,221		0		4,807		31,712		1,903		0		29,810		22,547
FIRST ALABAMA BANK 35-3-9		14.4		0.00000	%		42.83960	%		0		76,274		68,646		0		29,406		193,997		11,640		0		182,357		125,250
FIRST ALABAMA BANK 35-5-10		10.2		0.00000	%		42.83960	%		0		39,497		35,547		0		15,228		100,457		6,027		0		94,430		69,800
FIRST NATIONAL BANK 1-3-1		21.0		0.00000	%		56.87500	%		0		102,677		92,409		0		52,558		346,712		20,803		0		325,910		188,778
FRIEDMAN 10-10-28		28.6		0.00000	%		53.54375	%		0		170,184		153,165		0		82,010		541,005		32,460		0		508,544		259,828
FRIEDMAN 10-15-29		5.3		0.00000	%		53.54375	%		0		13,880		12,492		0		6,689		44,123		2,647		0		41,476		34,132
FRIEDMAN 11-10-8		25.9		0.00000	%		53.54375	%		0		132,703		119,432		0		63,949		421,855		25,311		0		396,544		207,091
FRIEDMAN 11-11-17		32.0		0.00000	%		53.54375	%		0		182,446		164,202		0		87,920		579,986		34,799		0		545,187		260,076
FRIEDMAN 11-13-18		5.5		0.00000	%		53.54375	%		0		20,897		18,808		0		10,070		66,432		3,986		0		62,446		51,836
FRIEDMAN 12-1-9		7.8		0.00000	%		53.54375	%		0		21,063		18,956		0		10,150		66,957		4,017		0		62,939		47,646
FRIEDMAN 12-2-50		8.8		0.00000	%		53.54375	%		0		29,283		26,355		0		14,111		93,089		5,585		0		87,504		63,624
FRIEDMAN 12-8-10		5.7		0.00000	%		53.54375	%		0		10,326		9,293		0		4,976		32,825		1,969		0		30,855		23,917
FRIEDMAN 13-13-3		14.6		0.00000	%		53.54375	%		0		49,272		44,345		0		23,744		156,633		9,398		0		147,235		93,049
FRIEDMAN 14-6-33		15.6		0.00000	%		53.54375	%		0		102,843		92,559		0		49,560		326,934		19,616		0		307,317		206,644
FRIEDMAN 14-12-34		17.9		0.00000	%		53.54375	%		0		99,682		89,714		0		48,036		316,885		19,013		0		297,872		186,377
FRIEDMAN 14-13-35		14.9		0.00000	%		53.54375	%		0		73,991		66,592		0		35,656		235,213		14,113		0		221,100		145,899
FRIEDMAN 18-2-5		1.7		0.00000	%		53.54375	%		0		2,826		2,544		0		1,362		8,984		539		0		8,445		7,841
FRIEDMAN 18-3-31		11.0		0.00000	%		53.54375	%		0		58,876		52,988		0		28,372		187,164		11,230		0		175,934		128,426
FRIEDMAN 18-7-30		8.6		0.00000	%		53.54375	%		0		24,532		22,079		0		11,822		77,986		4,679		0		73,307		54,246
FRIEDMAN 18-8-2		9.5		0.00000	%		53.54375	%		0		24,865		22,379		0		11,982		79,045		4,743		0		74,302		52,881
FRIEDMAN 18-9-1		11.3		0.00000	%		53.54375	%		0		48,550		43,695		0		23,396		154,338		9,260		0		145,078		103,473
FRIEDMAN 18-15-4		33.8		0.00000	%		53.54375	%		0		282,197		253,978		0		135,989		897,090		53,825		0		843,264		417,377
FRIEDMAN 2-1-15		14.3		0.00000	%		53.54375	%		0		61,308		55,177		0		29,544		194,894		11,694		0		183,200		117,425
FRIEDMAN 2-5-42		22.8		0.00000	%		53.54375	%		0		161,474		145,327		0		77,813		513,317		30,799		0		482,518		281,202
FRIEDMAN 2-9-16		28.7		0.00000	%		55.76460	%		0		164,111		147,700		0		82,364		543,338		32,600		0		510,737		260,789
FRIEDMAN 2-12-21		17.0		0.00000	%		53.54375	%		0		85,904		77,314		0		41,397		273,085		16,385		0		256,700		160,962
FRIEDMAN 2-14-22		16.6		0.00000	%		53.54375	%		0		82,186		73,968		0		39,605		261,266		15,676		0		245,590		155,933
FRIEDMAN 22-4-52		18.0		0.00000	%		53.54375	%		0		87,297		78,567		0		42,068		277,512		16,651		0		260,861		159,775
FRIEDMAN 22-12-53		22.6		0.00000	%		53.54375	%		0		172,843		155,559		0		83,292		549,458		32,967		0		516,490		307,170
FRIEDMAN 22-14-38		12.3		0.00000	%		53.54375	%		0		25,320		22,788		0		12,202		80,491		4,829		0		75,661		47,186
FRIEDMAN 22-15-39		9.1		0.00000	%		53.54375	%		0		29,433		26,490		0		14,184		93,566		5,614		0		87,952		64,548
FRIEDMAN 22-15-54		27.7		0.00000	%		55.20937	%		0		177,076		159,368		0		87,986		580,425		34,826		0		545,600		289,055
FRIEDMAN 22-16-55		30.0		0.00000	%		53.54375	%		0		133,423		120,081		0		64,296		424,144		25,449		0		398,695		186,904
FRIEDMAN 23-4-41		13.0		0.00000	%		55.20937	%		0		102,587		92,328		0		50,974		336,263		20,176		0		316,087		229,644
FRIEDMAN 23-5-40		26.9		0.00000	%		45.87100	%		0		141,525		127,373		0		58,427		385,431		23,126		0		362,305		188,208
FRIEDMAN 3-6-23		23.8		0.00000	%		53.54375	%		0		123,721		111,349		0		59,620		393,303		23,598		0		369,705		201,986
FRIEDMAN 30-4-45		19.0		0.00000	%		54.34000	%		0		196,139		176,525		0		95,924		632,787		37,967		0		594,819		389,916
FRIEDMAN 30-5-46		12.3		0.00000	%		54.34000	%		0		96,570		86,913		0		47,229		311,557		18,693		0		292,864		214,715
FRIEDMAN 30-12-47		20.4		0.00000	%		54.34000	%		0		153,551		138,196		0		75,096		495,389		29,723		0		465,666		285,730
FRIEDMAN 30-13-48		19.8		0.00000	%		54.34000	%		0		150,481		135,433		0		73,594		485,484		29,129		0		456,355		284,389
FRIEDMAN 31-12-49		18.3		0.00000	%		54.34000	%		0		106,239		95,615		0		51,957		342,749		20,565		0		322,185		199,188
FRIEDMAN 3-15-26		10.0		0.00000	%		53.17812	%		0		31,546		28,391		0		15,098		99,598		5,976		0		93,622		66,875
FRIEDMAN 34-10-57		20.3		0.00000	%		53.54375	%		0		117,973		106,176		0		56,850		375,030		22,502		0		352,528		211,209
FRIEDMAN 34-15-58		31.8		0.00000	%		53.54375	%		0		120,971		108,874		0		58,295		384,561		23,074		0		361,487		156,687
FRIEDMAN 36-1-43		7.7		0.00000	%		54.34000	%		0		25,194		22,675		0		12,322		81,282		4,877		0		76,406		58,429
FRIEDMAN 36-3-1		11.7		0.00000	%		54.34000	%		0		48,426		43,583		0		23,683		156,233		9,374		0		146,859		102,545
FRIEDMAN 36-7-44		5.0		0.00000	%		56.26400	%		0		11,780		10,602		0		5,965		39,352		2,361		0		36,991		30,366
FRIEDMAN 36-8-2		4.9		0.00000	%		54.34000	%		0		10,204		9,184		0		4,990		32,921		1,975		0		30,945		24,857
FRIEDMAN 36-11-56		15.1		0.00000	%		56.26400	%		0		78,345		70,511		0		39,672		261,709		15,703		0		246,006		161,579

Page No. 5 of 10 Royalty Interests Oneline 03 03 08.xls

DOMINION BLACK WARRIOR BASIN TRUST 1994-1	UNESCALATED ANALYSIS
ROYALTY INTERESTS	AS OF DECEMBER 31, 2007

									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 4-8-59		35.8		0.00000	%		55.20937	%		0		253,643		228,278		0		126,031		831,399		49,884		0		781,515		366,153
FRIEDMAN 6-4-11		26.4		0.00000	%		53.54375	%		0		204,491		184,042		0		98,543		650,067		39,004		0		611,063		337,748
FRIEDMAN 6-5-12		14.6		0.00000	%		53.54375	%		0		52,196		46,977		0		25,153		165,929		9,956		0		155,973		99,435
FRIEDMAN 6-12-13		2.9		0.00000	%		53.54375	%		0		5,686		5,117		0		2,740		18,074		1,084		0		16,990		15,030
FRIEDMAN 6-13-14		3.4		0.00000	%		53.54375	%		0		6,541		5,887		0		3,152		20,794		1,248		0		19,547		16,635
FRIEDMAN-ROSENAU 2-7-2		22.0		0.00000	%		55.20937	%		0		119,499		107,549		0		59,377		391,699		23,502		0		368,197		210,323
FRIEDMAN-ROSENAU 2-15-1		17.8		0.00000	%		56.87500	%		0		71,649		64,484		0		36,675		241,938		14,516		0		227,421		137,478
FRIEDMAN-ROSENAU 2-16-3		21.9		0.00000	%		56.87500	%		0		89,881		80,893		0		46,008		303,505		18,210		0		285,295		157,169
GILBERT 15-5-1		20.6		0.00000	%		46.51560	%		0		113,767		102,390		0		47,627		314,187		18,851		0		295,336		170,677
GILBERT 15-6-3		22.0		0.00000	%		56.87500	%		0		164,603		148,143		0		84,256		555,818		33,349		0		522,469		316,084
GILBERT 15-12-2		7.9		0.00000	%		46.51560	%		0		26,942		24,247		0		11,279		74,404		4,464		0		69,940		53,275
HALLMAN 17-2-2		16.8		0.00000	%		56.87500	%		0		85,272		76,745		0		43,649		287,941		17,276		0		270,665		173,229
HALLMAN 34-8-1		12.8		0.00000	%		56.87500	%		0		63,050		56,745		0		32,274		212,902		12,774		0		200,128		139,830
HALLMAN 8-14-1		28.9		0.00000	%		56.87500	%		0		203,730		183,357		0		104,284		687,939		41,276		0		646,662		342,702
HAYES 18-13-3		9.3		0.00000	%		56.87500	%		0		36,765		33,088		0		18,819		124,144		7,449		0		116,696		87,476
HAYES 18-14-4		16.9		0.00000	%		56.87500	%		0		106,446		95,801		0		54,487		359,439		21,566		0		337,872		221,052
HAYES 7-16-2		20.2		0.00000	%		56.87500	%		0		175,335		157,801		0		89,749		592,057		35,523		0		556,534		354,780
HINDS 12-6-1		12.5		0.00000	%		56.87500	%		0		45,543		40,988		0		23,312		153,785		9,227		0		144,558		98,528
HINDS 12-7-2		16.4		0.00000	%		56.87500	%		0		81,768		73,591		0		41,855		276,109		16,567		0		259,543		165,964
HINDS 12-11-3		13.9		0.00000	%		56.87500	%		0		71,664		64,497		0		36,683		241,989		14,519		0		227,469		155,628
HINDS 14-5-4		18.1		0.00000	%		56.67500	%		0		111,077		99,970		0		56,858		375,077		22,505		0		352,573		224,389
HINDS 14-6-5		13.0		0.00000	%		56.87500	%		0		63,257		56,931		0		32,380		213,601		12,816		0		200,785		139,675
HOBSON 22-9-1		14.6		0.00000	%		56.87500	%		0		80,904		72,813		0		41,413		273,190		16,391		0		256,798		174,400
HOLMAN 10-11-1		20.3		0.00000	%		56.87500	%		0		96,013		86,412		0		49,147		324,209		19,453		0		304,757		178,224
HOLMAN 13-7-19		16.7		0.00000	%		56.87500	%		0		109,414		98,473		0		56,007		369,462		22,168		0		347,295		229,763
HOLMAN 13-11-20		18.1		0.00000	%		56.87500	%		0		121,263		109,136		0		62,071		409,471		24,568		0		384,902		247,645
HOLMAN 13-14-21		10.5		0.00000	%		56.87500	%		0		37,254		33,529		0		19,069		125,797		7,548		0		118,249		84,989
HOLMAN 13-15-22		14.3		0.00000	%		56.87500	%		0		77,189		69,470		0		39,511		260,647		15,639		0		245,008		166,843
HOLMAN 14-3-2		10.3		0.00000	%		56.87500	%		0		38,255		34,430		0		19,582		129,177		7,751		0		121,426		88,013
HOLMAN 14-4-1		14.3		0.00000	%		56.87500	%		0		67,993		61,194		0		34,804		229,593		13,776		0		215,818		145,209
HOLMAN 15-1-28		17.0		0.00000	%		45.98240	%		0		88,961		80,065		0		36,816		242,866		14,572		0		228,294		144,865
HOLMAN 15-8-25		8.4		0.00000	%		45.98240	%		0		27,905		25,115		0		11,548		76,182		4,571		0		71,611		54,074
HOLMAN 17-11-31		17.8		0.00000	%		56.87500	%		0		91,410		82,269		0		46,790		308,666		18,520		0		290,146		181,924
HOLMAN 17-12-15		17.3		0.00000	%		56.87500	%		0		99,004		89,104		0		50,678		334,311		20,059		0		314,252		201,383
HOLMAN 17-13-16		17.3		0.00000	%		56.87500	%		0		86,679		78,011		0		44,369		292,690		17,561		0		275,129		173,210
HOLMAN 18-3-2		15.3		0.00000	%		56.87500	%		0		75,427		67,884		0		38,609		254,695		15,282		0		239,413		158,082
HOLMAN 24-1-26		19.7		0.00000	%		56.87500	%		0		118,603		106,743		0		60,710		400,491		24,029		0		376,461		230,071
HOLMAN 24-3-27		16.5		0.00000	%		56.87500	%		0		95,440		85,896		0		48,853		322,274		19,336		0		302,938		197,156
HOLMAN 26-4-23		24.1		0.00000	%		49.24920	%		0		129,636		116,672		0		57,460		379,052		22,743		0		356,309		194,145
HOLMAN 26-5-29		8.2		0.00000	%		49.24920	%		0		28,765		25,888		0		12,750		84,107		5,046		0		79,060		60,452
HOLMAN 26-6-24		15.8		0.00000	%		49.24920	%		0		81,501		73,351		0		36,125		238,306		14,298		0		224,007		145,963
HOLMAN 34-6-3		21.0		0.00000	%		60.09516	%		0		135,974		122,376		0		73,542		485,142		29,109		0		456,034		277,800
HOLMAN 35-12-4		10.0		0.00000	%		56.87500	%		0		44,781		40,303		0		22,922		151,213		9,073		0		142,140		105,832
HOWELL 12-9-1		24.3		0.00000	%		56.87500	%		0		149,572		134,615		0		76,562		505,064		30,304		0		474,760		267,312
HOWELL 12-14-2		10.7		0.00000	%		56.87500	%		0		41,904		37,713		0		21,449		141,497		8,490		0		133,007		96,117
HOWELL 12-15-3		12.4		0.00000	%		56.87500	%		0		53,817		48,435		0		27,547		181,724		10,903		0		170,820		119,125
MAYFIELD 1-3-3		11.4		0.00000	%		56.87500	%		0		43,996		39,597		0		22,521		148,563		8,914		0		139,649		98,126
MAYFIELD 1-7-4		12.8		0.00000	%		56.87500	%		0		58,292		52,463		0		29,838		196,835		11,810		0		185,025		128,301
MAYFIELD 12-9-2		19.1		0.00000	%		54.51875	%		0		98,486		88,637		0		48,324		318,781		19,127		0		299,654		180,309
MAYFIELD 12-10-5		18.8		0.00000	%		56.87500	%		0		85,982		77,384		0		44,012		290,337		17,420		0		272,916		158,626
MAYFIELD 14-1-1		11.3		0.00000	%		54.51875	%		0		44,245		39,820		0		21,710		143,213		8,593		0		134,621		92,247
MAYFIELD 8-3-1		19.0		0.00000	%		55.69687	%		0		100,098		90,088		0		50,176		331,002		19,860		0		311,142		189,707
MCDANIEL 18-5-2		21.8		0.00000	%		56.55000	%		0		91,774		82,596		0		46,708		308,124		18,487		0		289,636		160,569
MCDANIEL 18-6-3		4.8		0.00000	%		56.55000	%		0		10,246		9,221		0		5,214		34,399		2,064		0		32,335		26,741

Page No. 6 of 10 Royalty Interests Oneline 03 03 08.xls

DOMINION BLACK WARRIOR BASIN TRUST 1994-1	UNESCALATED ANALYSIS
ROYALTY INTERESTS	AS OF DECEMBER 31, 2007

									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		$		$		$		$		$
MCGUIRE 26-12-6		11.3		0.00000	%		56.87500	%		0		43,601		39,241		0		22,318		147,227		8,834		0		138,394		98,290
MCGUIRE 26-13-3		12.9		0.00000	%		56.87500	%		0		55,033		49,530		0		28,170		185,832		11,150		0		174,682		119,950
MCGUIRE 26-16-1		16.3		0.00000	%		56.87500	%		0		80,330		72,297		0		41,119		271,253		16,275		0		254,978		163,889
MCGUIRE 27-9-4		13.1		0.00000	%		56.87500	%		0		52,212		46,991		0		26,726		176,305		10,578		0		165,727		112,377
MCGUIRE 34-9-5		25.8		0.00000	%		56.87500	%		0		121,356		109,220		0		62,119		409,786		24,587		0		385,199		201,189
MILLS 22-14-1		31.8		0.00000	%		56.87500	%		0		350,848		315,763		0		179,590		1,184,715		71,083		0		1,113,633		605,028
MOODY 22-6-1		32.8		0.00000	%		56.87500	%		0		300,627		270,564		0		153,883		1,015,133		60,908		0		954,225		496,251
MOORE 13-1-1		20.1		0.00000	%		45.09190	%		0		165,422		148,880		0		67,133		442,861		26,572		0		416,289		264,033
MOORE 13-9-2		13.6		0.00000	%		45.09190	%		0		67,517		60,765		0		27,400		180,753		10,845		0		169,908		116,705
NAUGHER 34-7-1		16.8		0.00000	%		60.09516	%		0		86,365		77,729		0		46,711		308,143		18,489		0		289,654		187,165
PAYNE 17-15-1		19.8		0.00000	%		56.87500	%		0		105,426		94,883		0		53,965		355,993		21,360		0		334,634		201,276
PETTUS 8-5-3		10.4		0.00000	%		56.87500	%		0		66,408		59,767		0		33,993		224,242		13,455		0		210,787		160,138
PETTUS 8-6-2		25.2		0.00000	%		56.87500	%		0		115,863		104,276		0		59,307		391,236		23,474		0		367,762		193,415
PRICE 1-1-1		7.8		0.00000	%		56.87500	%		0		20,281		18,253		0		10,381		68,483		4,109		0		64,374		48,450
RICE 2-6-1		28.1		0.00000	%		55.04687	%		0		155,920		140,328		0		77,246		509,577		30,575		0		479,002		243,871
SEALY 18-1-1		21.5		0.00000	%		56.87500	%		0		153,050		137,745		0		78,343		516,808		31,008		0		485,799		292,721
SEARCY 11-9-14		8.4		0.00000	%		56.87500	%		0		23,490		21,141		0		12,024		79,319		4,759		0		74,560		54,443
SEARCY 12-3-16		4.3		0.00000	%		56.87500	%		0		8,255		7,430		0		4,226		27,876		1,673		0		26,204		22,045
SEARCY 12-6-19		2.4		0.00000	%		56.87500	%		0		4,761		4,285		0		2,437		16,078		965		0		15,113		13,678
SEARCY 17-5-7		22.5		0.00000	%		56.87500	%		0		98,307		88,477		0		50,321		331,957		19,917		0		312,039		171,710
SEARCY 17-6-20		24.3		0.00000	%		56.87500	%		0		129,124		116,212		0		66,096		436,018		26,161		0		409,857		224,940
SEARCY 17-11-8		22.1		0.00000	%		56.87500	%		0		240,014		216,013		0		122,857		810,461		48,628		0		761,834		482,030
SEARCY 17-14-9		29.8		0.00000	%		56.87500	%		0		249,539		224,585		0		127,733		842,623		50,557		0		792,065		425,496
SEARCY 18-11-18		24.8		0.00000	%		56.87500	%		0		243,100		218,790		0		124,437		820,881		49,253		0		771,628		459,523
SEARCY 18-13-6		4.9		0.00000	%		56.87500	%		0		10,383		9,345		0		5,315		35,061		2,104		0		32,957		27,062
SEARCY 18-14-5		19.8		0.00000	%		56.87500	%		0		166,078		149,470		0		85,011		560,799		33,648		0		527,151		335,020
SEARCY 19-4-1		4.8		0.00000	%		56.87500	%		0		9,561		8,605		0		4,894		32,284		1,937		0		30,347		24,993
SEARCY 19-10-3		32.0		0.00000	%		56.87500	%		0		345,877		311,289		0		177,046		1,167,931		70,076		0		1,097,855		588,920
SEARCY 20-3-10		16.8		0.00000	%		56.87500	%		0		62,905		56,614		0		32,199		212,412		12,745		0		199,667		121,955
SEARCY 20-4-11		25.0		0.00000	%		56.87500	%		0		137,305		123,574		0		70,283		463,640		27,818		0		435,822		237,326
SEARCY 20-5-12		36.3		0.00000	%		56.87500	%		0		419,713		377,742		0		214,841		1,417,256		85,035		0		1,332,220		679,079
SEARCY 20-6-13		32.3		0.00000	%		56.87500	%		0		373,588		336,229		0		191,230		1,261,504		75,690		0		1,185,814		642,965
SEARCY 24-1-2		16.1		0.00000	%		56.87500	%		0		67,223		60,501		0		34,410		226,995		13,620		0		213,375		135,049
SEARCY 7-6-17		13.4		0.00000	%		56.87500	%		0		52,130		46,917		0		26,684		176,028		10,562		0		165,466		110,432
SEARCY 7-15-15		16.2		0.00000	%		56.87500	%		0		72,813		65,532		0		37,271		245,870		14,752		0		231,118		146,778
SESSIONS 35-8-1		6.4		0.00000	%		56.87500	%		0		21,337		19,203		0		10,922		72,048		4,323		0		67,725		54,654
SESSIONS 35-9-2		11.5		0.00000	%		56.87500	%		0		54,376		48,938		0		27,834		183,613		11,017		0		172,596		124,292
SESSIONS 35-15-3		18.3		0.00000	%		56.87500	%		0		134,745		121,270		0		68,973		454,997		27,300		0		427,697		277,016
STEDMAN 1-9-1		12.6		0.00000	%		52.81250	%		0		60,059		54,053		0		28,547		188,318		11,299		0		177,019		123,017
STEDMAN 11-1-5		13.1		0.00000	%		52.81250	%		0		64,259		57,833		0		30,543		201,485		12,089		0		189,396		130,546
STEDMAN 11-2-6		16.3		0.00000	%		52.81250	%		0		91,357		82,221		0		43,423		286,453		17,187		0		269,266		174,318
STEDMAN 11-3-24		13.8		0.00000	%		52.81250	%		0		82,496		74,246		0		39,211		258,668		15,520		0		243,148		167,920
STEDMAN 11-4-7		9.6		0.00000	%		52.81250	%		0		43,700		39,330		0		20,771		137,022		8,221		0		128,801		96,098
STEDMAN 11-5-8		8.3		0.00000	%		52.81250	%		0		26,553		23,898		0		12,621		83,259		4,996		0		78,263		58,648
STEDMAN 11-9-9		10.3		0.00000	%		52.81250	%		0		34,583		31,124		0		16,437		108,434		6,506		0		101,928		72,755
STEDMAN 1-11-3		8.8		0.00000	%		52.81250	%		0		30,094		27,084		0		14,304		94,359		5,662		0		88,698		65,839
STEDMAN 11-10-10		12.8		0.00000	%		52.81250	%		0		57,602		51,842		0		27,379		180,614		10,837		0		169,777		116,279
STEDMAN 11-12-11		15.3		0.00000	%		52.81250	%		0		73,871		66,484		0		35,112		231,626		13,898		0		217,728		141,570
STEDMAN 11-14-12		16.8		0.00000	%		52.81250	%		0		83,966		75,569		0		39,910		263,277		15,797		0		247,480		156,312
STEDMAN 11-16-13		9.6		0.00000	%		52.81250	%		0		36,267		32,641		0		17,238		113,717		6,823		0		106,894		78,700
STEDMAN 1-15-14		22.8		0.00000	%		52.81250	%		0		137,741		123,966		0		65,470		431,889		25,913		0		405,976		232,050
STEDMAN 1-16-4		16.8		0.00000	%		52.81250	%		0		83,719		75,347		0		39,793		262,502		15,750		0		246,752		155,871
STEDMAN 13-1-15		18.2		0.00000	%		52.81250	%		0		79,661		71,695		0		37,864		249,781		14,987		0		234,794		140,827
STEDMAN 13-2-16		18.7		0.00000	%		52.81250	%		0		113,077		101,769		0		53,747		354,556		21,273		0		333,283		207,003

Page No. 7 of 10 Royalty Interests Oneline 03 03 08.xls

DOMINION BLACK WARRIOR BASIN TRUST 1994-1	UNESCALATED ANALYSIS
ROYALTY INTERESTS	AS OF DECEMBER 31, 2007

									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		$		$		$		$		$
STEDMAN 13-4-17		19.3		0.00000	%		52.81250	%		0			151,365		136,228			0		71,945		474,608		28,476		0		446,131		283,435
STEDMAN 13-6-18		10.1		0.00000	%		52.81250	%		0			43,652		39,287			0		20,748		136,873		8,212		0		128,661		94,597
STEDMAN 13-9-19		18.2		0.00000	%		52.81250	%		0			120,720		108,648			0		57,379		378,520		22,711		0		355,808		226,284
STEDMAN 13-12-20		20.8		0.00000	%		52.81250	%		0			150,119		135,107			0		71,354		470,703		28,242		0		442,461		270,030
STEDMAN 13-14-21		29.1		0.00000	%		52.81250	%		0			228,005		205,205			0		108,374		714,917		42,895		0		672,022		356,742
STEDMAN 13-15-22		23.3		0.00000	%		52.81250	%		0			266,805		240,125			0		126,816		836,575		50,195		0		786,381		485,387
STOTHART 24-12-1		6.9		0.00000	%		56.13634	%		0			20,312		18,281			0		10,262		67,698		4,062		0		63,636		50,034
STOTHART 24-13-2		10.9		0.00000	%		56.50567	%		0			50,704		45,634			0		25,786		170,101		10,206		0		159,895		116,558
SULLIVAN 4-11-2		26.8		0.00000	%		56.29461	%		0			329,663		296,697			0		167,024		2,211,214		132,673		0		2,078,540		1,347,343
THORNHILL 12-13-1		10.6		0.00000	%		56.87500	%		0			41,010		36,909			0		20,992		138,481		8,309		0		130,172		91,758
TURNER 17-10-1		23.5		0.00000	%		56.87500	%		0			140,015		126,013			0		71,670		472,792		28,367		0		444,424		252,479
TURNER 17-16-1		28.0		0.00000	%		56.87500	%		0			108,269		97,442			0		55,420		365,595		21,936		0		343,659		164,744
USX 14-3-45		26.8		0.00000	%		48.75000	%		0			237,470		213,723			0		104,190		687,319		41,239		0		646,079		359,071
USX 14-5-24		16.3		0.00000	%		48.75000	%		0			71,356		64,220			0		31,307		206,528		12,392		0		194,136		120,318
USX 14-10-43		20.0		0.00000	%		47.51680	%		0			94,019		84,617			0		40,207		265,239		15,914		0		249,325		142,875
USX 14-11-25		15.3		0.00000	%		48.75000	%		0			70,587		63,528			0		30,970		204,302		12,258		0		192,044		123,027
USX 14-13-37		5.6		0.00000	%		46.51560	%		0			15,553		13,997			0		6,511		42,951		2,577		0		40,374		32,747
USX 14-14-44		13.7		0.00000	%		48.75000	%		0			78,719		70,847			0		34,538		227,840		13,670		0		214,170		145,943
USX 15-13-27		10.8		0.00000	%		48.75000	%		0			35,991		32,392			0		15,791		104,171		6,250		0		97,921		67,857
USX 16-2A-40		18.0		0.00000	%		48.75000	%		0			79,859		71,873			0		35,038		231,139		13,868		0		217,270		129,267
USX 16-4-29		19.0		0.00000	%		48.75000	%		0			83,081		74,773			0		36,452		240,465		14,428		0		226,037		130,336
USX 16-5-30		21.5		0.00000	%		48.75000	%		0			114,844		103,359			0		50,388		332,396		19,944		0		312,452		176,867
USX 16-7-31		14.7		0.00000	%		48.75000	%		0			59,577		53,619			0		26,139		172,436		10,346		0		162,090		103,543
USX 16-8-28		24.8		0.00000	%		48.75000	%		0			131,492		118,343			0		57,692		380,581		22,835		0		357,746		188,761
USX 16-11-33		32.3		0.00000	%		48.75000	%		0			245,179		220,661			0		107,572		709,630		42,578		0		667,052		326,953
USX 16-13-34		18.0		0.00000	%		48.75000	%		0			110,517		99,465			0		48,489		319,873		19,192		0		300,680		186,646
USX 16-15-35		19.3		0.00000	%		48.75000	%		0			77,302		69,572			0		33,916		223,739		13,424		0		210,315		119,318
USX 21-15-11		18.1		0.00000	%		48.75000	%		0			85,989		77,390			0		37,728		248,881		14,933		0		233,948		140,470
USX 21-16-12		18.3		0.00000	%		48.75000	%		0			72,839		65,555			0		31,958		210,822		12,649		0		198,172		115,115
USX 22-4-36		24.4		0.00000	%		48.75000	%		0			111,133		100,020			0		48,760		321,658		19,299		0		302,358		156,204
USX 22-11-13		8.4		0.00000	%		48.75000	%		0			43,799		39,420			0		19,217		126,770		7,606		0		119,164		92,200
USX 22-12-14		6.6		0.00000	%		48.75000	%		0			20,133		18,119			0		8,833		58,271		3,496		0		54,774		42,994
USX 23-4-41		19.8		0.00000	%		47.90550	%		0			141,036		126,932			0		60,807		401,133		24,068		0		377,065		232,589
USX 28-3-15		12.2		0.00000	%		48.75000	%		0			50,718		45,646			0		22,252		146,794		8,808		0		137,987		94,575
USX 28-4-16		10.3		0.00000	%		48.75000	%		0			34,236		30,812			0		15,021		99,089		5,945		0		93,144		65,529
USX 28-5-17		17.1		0.00000	%		48.75000	%		0			75,888		68,299			0		33,296		219,644		13,179		0		206,466		125,658
USX 29-8-6		17.3		0.00000	%		48.75000	%		0			81,019		72,917			0		35,547		234,496		14,070		0		220,427		134,812
USX 29-11-7		12.0		0.00000	%		48.75000	%		0			58,226		52,403			0		25,547		168,525		10,112		0		158,414		110,392
USX 29-13-9		15.7		0.00000	%		48.75000	%		0			71,459		64,313			0		31,353		206,827		12,410		0		194,417		123,030
USX 29-14-10		12.0		0.00000	%		48.75000	%		0			50,665		45,599			0		22,229		146,642		8,799		0		137,843		95,101
USX 30-9-18		14.9		0.00000	%		48.75000	%		0			69,639		62,675			0		30,554		201,558		12,093		0		189,465		122,580
USX 5-7-1		23.9		0.00000	%		48.75000	%		0			207,204		186,484			0		90,911		599,719		35,983		0		563,736		328,377
USX 5-10-2		22.2		0.00000	%		48.75000	%		0			165,443		148,898			0		72,588		478,847		28,731		0		450,116		263,455
USX 5-15-3		28.0		0.00000	%		48.75000	%		0			179,702		161,732			0		78,844		520,118		31,207		0		488,911		251,682
USX 8-6-4		15.1		0.00000	%		48.75000	%		0			99,476		89,528			0		43,645		287,917		17,275		0		270,642		182,181
USX 8-11-5		12.9		0.00000	%		48.75000	%		0			63,428		57,085			0		27,829		183,581		11,015		0		172,566		118,296
USX 8-14-39		13.5		0.00000	%		46.73630	%		0			76,587		68,928			0		32,214		212,512		12,751		0		199,761		137,349
USX 9-6-20		16.8		0.00000	%		48.75000	%		0			87,591		78,832			0		38,431		253,519		15,211		0		238,308		149,396
USX 9-7-21		35.3		0.00000	%		48.75000	%		0			431,620		388,458			0		189,373		1,249,253		74,955		0		1,174,298		600,048
USX 9-10-22		21.3		0.00000	%		48.75000	%		0			174,448		157,003			0		76,539		504,910		30,295		0		474,615		288,600
USX 9-15-23		16.5		0.00000	%		48.75000	%		0			96,223		86,601			0		42,218		278,501		16,710		0		261,791		167,954
USX 9-16-38		18.6		0.00000	%		48.75000	%		0			140,462		126,416			0		61,628		406,545		24,393		0		382,152		242,180
WEST 1-1-24		7.2		0.00000	%		52.81250	%		0			24,359		21,923			0		11,578		76,377		4,583		0		71,795		56,382
WEST 1-2-25		9.1		0.00000	%		52.81250	%		0			29,760		26,784			0		14,146		93,315		5,599		0		87,716		64,629

Page No. 8 of 10 Royalty Interests Oneline 03 03 08.xls

DOMINION BLACK WARRIOR BASIN TRUST 1994-1	UNESCALATED ANALYSIS
ROYALTY INTERESTS	AS OF DECEMBER 31, 2007

									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 1-6-39		12.7		0.00000	%		52.81250	%		0		52,590		47,331		0		24,997		164,896		9,894		0		155,003		105,777
WEST 1-8-27		7.5		0.00000	%		52.81250	%		0		23,017		20,716		0		10,941		72,172		4,330		0		67,842		52,265
WEST 1-9-28		3.5		0.00000	%		52.81250	%		0		9,042		8,138		0		4,298		28,351		1,701		0		26,650		23,317
WEST 11-1-34		9.7		0.00000	%		52.81250	%		0		22,029		19,826		0		10,471		69,072		4,144		0		64,927		45,091
WEST 11-2-35		9.2		0.00000	%		52.81250	%		0		30,474		27,426		0		14,484		95,551		5,733		0		89,818		65,803
WEST 11-4-41		31.3		0.00000	%		52.81250	%		0		281,989		253,790		0		134,033		884,183		53,051		0		831,132		434,935
WEST 11-5-42		26.8		0.00000	%		52.81250	%		0		165,094		148,584		0		78,471		517,657		31,059		0		486,597		258,187
WEST 11-8-36		11.2		0.00000	%		52.81250	%		0		36,010		32,409		0		17,116		112,911		6,775		0		106,136		73,373
WEST 1-10-29		8.3		0.00000	%		52.81250	%		0		30,061		27,055		0		14,288		94,256		5,655		0		88,601		67,425
WEST 1-11-30		7.3		0.00000	%		52.81250	%		0		21,197		19,077		0		10,075		66,463		3,988		0		62,475		48,329
WEST 11-15-37		1.1		0.00000	%		52.81250	%		0		416		375		0		198		1,305		78		0		1,226		1,167
WEST 1-13-31		12.5		0.00000	%		52.81250	%		0		54,121		48,709		0		25,724		169,698		10,182		0		159,517		109,923
WEST 1-14-32		2.5		0.00000	%		52.81250	%		0		5,773		5,195		0		2,744		18,100		1,086		0		17,014		15,398
WEST 1-16-33		0.7		0.00000	%		52.81250	%		0		1,053		948		0		501		3,303		198		0		3,105		3,010
WEST 13-1-15		15.4		0.00000	%		52.81250	%		0		56,329		50,696		0		26,774		176,621		10,597		0		166,024		103,639
WEST 13-2-16		12.9		0.00000	%		52.81250	%		0		64,071		57,664		0		30,454		200,895		12,054		0		188,842		130,803
WEST 13-4-17		25.7		0.00000	%		52.81250	%		0		172,809		155,528		0		82,138		541,847		32,511		0		509,336		279,812
WEST 13-5-3		4.0		0.00000	%		52.81250	%		0		8,765		7,888		0		4,166		27,483		1,649		0		25,834		21,996
WEST 13-6-1		7.3		0.00000	%		52.81250	%		0		22,477		20,229		0		10,684		70,478		4,229		0		66,249		51,312
WEST 13-7-38		11.8		0.00000	%		52.81250	%		0		34,193		30,773		0		16,252		107,212		6,433		0		100,779		67,347
WEST 13-8-14		18.8		0.00000	%		52.81250	%		0		80,312		72,281		0		38,173		251,820		15,109		0		236,711		139,362
WEST 13-9-9		15.2		0.00000	%		52.81250	%		0		54,394		48,954		0		25,854		170,553		10,233		0		160,320		100,492
WEST 13-11-6		19.8		0.00000	%		52.81250	%		0		112,132		100,919		0		53,298		351,593		21,096		0		330,497		198,815
WEST 13-12-4A		20.8		0.00000	%		52.81250	%		0		89,779		80,801		0		42,673		281,503		16,890		0		264,613		148,686
WEST 13-15-23		12.5		0.00000	%		52.81250	%		0		53,037		47,733		0		25,209		166,298		9,978		0		156,320		107,463
WEST 15-1-51		19.6		0.00000	%		54.84375	%		0		91,372		82,235		0		45,101		297,518		17,851		0		279,667		164,896
WEST 15-1-83		17.7		0.00000	%		52.81250	%		0		97,575		87,818		0		46,379		305,950		18,357		0		287,593		180,413
WEST 15-2-52		13.0		0.00000	%		52.81250	%		0		35,343		31,808		0		16,799		110,818		6,649		0		104,169		66,549
WEST 15-3-68		18.3		0.00000	%		45.80470	%		0		72,634		65,371		0		29,943		197,527		11,852		0		185,675		108,746
WEST 15-3-84		20.5		0.00000	%		52.81250	%		0		118,907		107,017		0		56,518		372,837		22,370		0		350,467		208,136
WEST 15-5-85		30.7		0.00000	%		52.81250	%		0		290,071		261,064		0		137,874		909,526		54,572		0		854,954		455,932
WEST 15-6-53		3.5		0.00000	%		52.81250	%		0		2,249		2,024		0		1,069		7,053		423		0		6,630		5,806
WEST 15-6-86		23.6		0.00000	%		52.81250	%		0		149,957		134,962		0		71,277		470,195		28,212		0		441,934		248,964
WEST 15-8-55		6.3		0.00000	%		52.81250	%		0		26,083		23,475		0		12,398		81,786		4,907		0		76,878		62,652
WEST 15-9-87		21.8		0.00000	%		52.81250	%		0		106,623		95,961		0		50,679		334,321		20,059		0		314,262		176,641
WEST 15-10-88		18.1		0.00000	%		52.81251	%		0		96,340		86,706		0		45,792		302,076		18,125		0		283,952		175,635
WEST 15-11-89		32.8		0.00000	%		52.81250	%		0		171,450		154,305		0		81,492		537,587		32,255		0		505,332		232,995
WEST 15-13-58		21.8		0.00000	%		52.81250	%		0		119,654		107,688		0		56,873		375,178		22,511		0		352,667		198,102
WEST 15-14-90A		21.9		0.00000	%		52.81250	%		0		125,102		112,592		0		59,463		392,261		23,536		0		368,726		212,305
WEST 15-16-91		17.7		0.00000	%		52.81250	%		0		126,338		112,804		0		59,575		393,001		23,580		0		369,421		239,254
WEST 17-12-20		9.5		0.00000	%		52.81250	%		0		23,540		21,186		0		11,189		73,810		4,429		0		69,381		47,645
WEST 17-13-21		27.3		0.00000	%		52.81250	%		0		158,654		142,788		0		75,410		497,463		29,848		0		467,615		242,706
WEST 19-1-19		28.2		0.00000	%		52.81250	%		0		124,007		111,607		0		58,942		388,829		23,330		0		365,499		186,654
WEST 19-2-10		1.3		0.00000	%		52.81250	%		0		2,016		1,815		0		958		6,323		379		0		5,943		5,585
WEST 19-3-7		1.9		0.00000	%		52.81250	%		0		2,309		2,078		0		1,098		7,240		434		0		6,806		6,239
WEST 19-6-18		20.8		0.00000	%		52.81250	%		0		165,850		149,265		0		78,830		520,028		31,202		0		488,825		302,240
WEST 19-7-1		19.0		0.00000	%		52.81250	%		0		59,804		53,824		0		28,426		187,517		11,251		0		176,266		97,653
WEST 19-8-12		25.4		0.00000	%		52.81250	%		0		188,157		169,341		0		89,433		589,970		35,398		0		554,572		310,747
WEST 19-11-13		28.7		0.00000	%		52.81250	%		0		173,622		156,259		0		82,524		544,395		32,664		0		511,732		261,296
WEST 19-12-11		11.2		0.00000	%		52.81250	%		0		106,022		97,220		0		51,344		338,707		20,322		0		318,384		242,456
WEST 21-8-71		0.0		0.00000	%		52.81250	%		0		0		0		0		0		0		0		0		0		0
WEST 23-3-93		22.3		0.00000	%		53.40400	%		0		198,001		178,201		0		95,167		627,792		37,668		0		590,124		357,643
WEST 23-5-94		9.2		0.00000	%		53.40400	%		0		47,748		42,973		0		22,949		151,391		9,083		0		142,307		108,662
WEST 23-6-95		13.4		0.00000	%		55.13947	%		0		51,061		45,955		0		25,339		167,158		10,029		0		157,128		104,267

Page No. 9 of 10 Royalty Interests Oneline 03 03 08.xls

DOMINION BLACK WARRIOR BASIN TRUST 1994-1	UNESCALATED ANALYSIS
ROYALTY INTERESTS	AS OF DECEMBER 31, 2007

									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 23-7-96		11.8		0.00000	%		53.40400	%		0		53,999		48,599		0		25,954		171,213		10,273		0		160,940		113,064
WEST 23-8-92		21.1		0.00000	%		41.72188	%		0		140,952		126,857		0		52,927		349,147		20,949		0		328,198		195,518
WEST 27-1-59		33.5		0.00000	%		52.81250	%		0		143,650		129,285		0		68,279		450,419		27,025		0		423,394		180,750
WEST 27-2-60		7.6		0.00000	%		52.81250	%		0		23,189		20,870		0		11,022		72,710		4,363		0		68,347		52,260
WEST 27-2-97		27.9		0.00000	%		53.40400	%		0		202,971		182,674		0		97,555		643,549		38,613		0		604,936		321,132
WEST 27-4-62		18.8		0.00000	%		52.81250	%		0		83,353		75,018		0		39,619		261,357		15,681		0		245,676		143,645
WEST 27-4-98		19.8		0.00000	%		53.40400	%		0		116,849		105,165		0		56,162		370,489		22,229		0		348,259		209,500
WEST 27-5-65		15.3		0.00000	%		52.81250	%		0		34,949		31,454		0		16,612		109,583		6,575		0		103,008		58,161
WEST 27-5-99		22.5		0.00000	%		53.40400	%		0		140,222		126,200		0		67,396		444,595		26,676		0		417,920		239,387
WEST 27-7-100		34.9		0.00000	%		53.40400	%		0		298,781		268,903		0		143,605		947,330		56,840		0		890,490		433,658
WEST 27-8-101		21.1		0.00000	%		53.40400	%		0		228,211		205,390		0		109,687		723,577		43,415		0		680,163		429,205
WEST 27-11-102		22.7		0.00000	%		53.87200	%		0		154,440		138,996		0		74,880		493,967		29,638		0		464,329		268,983
WEST 27-13-103		20.0		0.00000	%		53.40400	%		0		103,229		92,906		0		49,616		327,303		19,638		0		307,665		179,304
WEST 27-14-104		24.0		0.00000	%		53.40400	%		0		165,751		149,176		0		79,666		525,538		31,532		0		494,005		277,533
WEST 3-2-44		15.1		0.00000	%		53.17812	%		0		56,310		50,679		0		26,950		177,785		10,667		0		167,118		105,669
WEST 3-3-22		21.7		0.00000	%		52.81250	%		0		93,206		83,886		0		44,302		292,252		17,535		0		274,716		150,738
WEST 3-4-45		5.1		0.00000	%		52.81250	%		0		3,341		3,007		0		1,588		10,475		629		0		9,847		8,110
WEST 3-8-48		20.8		0.00000	%		52.81250	%		0		105,866		95,280		0		50,320		331,946		19,917		0		312,030		179,745
WEST 31-5-82		16.4		0.00000	%		53.87200	%		0		63,407		57,066		0		30,743		202,803		12,168		0		190,634		115,632
WEST 3-10-49		13.8	0.00000%				53.17812	%		0		54,502		49,052		0		26,085		172,076		10,325		0		161,752		106,791
WEST 3-12-67		38.0		0.00000	%		52.81250	%		0		288,496		259,647		0		137,126		904,589		54,275		0		850,314		389,780
WEST 3-13-50		34.3		0.00000	%		54.84375	%		0		179,121		161,209		0		88,413		583,241		34,994		0		548,246		246,477
WEST 33-2-112		12.6		0.00000	%		52.81250	%		0		56,876		51,188		0		27,034		178,335		10,700		0		167,635		115,904
WEST 33-3-120		22.1		0.00000	%		52.81250	%		0		92,202		82,982		0		43,825		289,103		17,346		0		271,757		147,625
WEST 33-6-114		19.9		0.00000	%		52.81250	%		0		97,631		87,868		0		46,405		306,124		18,367		0		287,757		167,856
WEST 33-8-115		26.9		0.00000	%		52.81250	%		0		178,439		160,595		0		84,814		559,502		33,570		0		525,932		280,214
WEST 33-10-116		23.4	0.00000%				52.81250	%		0		147,461		132,715		0		70,090		462,370		27,742		0		434,627		245,284
WEST 33-16-119		27.3		0.00000	%		54.84375	%		0		145,004		130,504		0		71,573		472,151		28,329		0		443,822		227,470
WEST 35-2-105		19.5		0.00000	%		53.40400	%		0		126,747		114,073		0		60,919		401,871		24,112		0		377,759		230,284
WEST 35-4-106		25.8		0.00000	%		38.92440	%		0		155,519		139,967		0		54,481		359,400		21,564		0		337,836		180,640
WEST 35-6-107		19.3		0.00000	%		53.40400	%		0		95,657		86,091		0		45,976		303,294		18,198		0		285,096		167,409
WEST 35-8-108		17.8		0.00000	%		53.40400	%		0		89,661		80,695		0		43,094		284,262		17,057		0		267,226		163,206
WEST 35-9-109		19.7		0.00000	%		53.40400	%		0		106,431		95,788		0		51,155		337,456		20,247		0		317,209		187,575
WEST 35-10-110		17.2		0.00000	%		53.40400	%		0		73,135		65,821		0		35,151		231,884		13,913		0		217,971		131,611
WEST 35-14-111		24.1		0.00000	%		53.40400	%		0		116,545		104,890		0		56,016		369,522		22,171		0		347,351		183,381
WEST 7-2-74		15.8	0.00000%				52.81250	%		0		65,017		58,515		0		30,903		203,861		12,232		0		191,630		119,811
WEST 7-3-75		14.5		0.00000	%		52.81250	%		0		60,762		54,686		0		28,881		190,521		11,431		0		179,090		116,087
WEST 7-6-76		16.4		0.00000	%		52.81250	%		0		91,833		82,650		0		43,650		287,946		17,277		0		270,669		173,840
WEST 7-8-77		12.8		0.00000	%		52.81250	%		0		46,219		41,597		0		21,968		144,920		8,695		0		136,225		90,567
WEST 7-11-78		21.3		0.00000	%		52.81250	%		0		98,559		88,703		0		46,846		309,034		18,542		0		290,492		163,886
WEST 7-12-79		15.6		0.00000	%		52.81250	%		0		79,112		71,201		0		37,603		248,059		14,884		0		233,175		151,605
WEST 7-13-80		13.0		0.00000	%		52.81250	%		0		52,675		47,408		0		25,037		165,164		9,910		0		155,255		104,282
WEST 7-15-81		12.4		0.00000	%		52.81250	%		0		54,654		49,188		0		25,978		171,368		10,282		0		161,086		111,420
WEYERHAEUSER 5-15-2		15.6		0.00000	%		55.25000	%		0		137,506		123,756		0		68,375		451,055		27,063		0		423,992		294,997
WEYERHAEUSER 5-16-1		23.3		0.00000	%		55.25000	%		0		148,616		133,755		0		73,899		467,498		29,250		0		458,248		263,190
TOTAL ALL PROPERTIES										0		46,849,513		42,164,563		0		22,486,394		149,447,082		8,966,825		0		140,480,255		84,466,354

Page No. 10 of 10 Royalty Interests Oneline 03 03 08.xls