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                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                   ----------

                                   FORM 10-K

(MARK ONE)

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

                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

                                       OR

    [ ]   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 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  X   No
                                              ---     ---

      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.  X
                             ---

      Indicate by a check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act). Yes  X   No
                                           ---     ---

      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 $148,457,786.

      At March 1, 2003, there were 7,850,000 units of beneficial interest
outstanding.

                       DOCUMENTS INCORPORATED BY REFERENCE
                                      None.


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<PAGE>
                                TABLE OF CONTENTS


<Table>
<Caption>
                                                                                                     PAGE
                                                                                                     ----
<S>                                                                                                  <C>
PART I ...........................................................................................    1
  Item 1. Business ...............................................................................    1
    GLOSSARY .....................................................................................    1
    DESCRIPTION OF THE TRUST .....................................................................    4
            Creation and Organization of the Trust ...............................................    4
            Assets of the Trust ..................................................................    4
            Duties and Limited Powers of the Trustee and the Delaware Trustee ....................    4
            Resignation of Trustees ..............................................................    5
            Transfer of Royalty Interests ........................................................    5
            Liabilities of the Trust .............................................................    6
            Liabilities of the Trustee and the Delaware Trustee ..................................    6
            Termination and Liquidation of the Trust .............................................    6
            Arbitration and Actions by Unitholders ...............................................    7
    DESCRIPTION OF UNITS .........................................................................    9
            Distributions and Income Computations ................................................    9
            Conditional Right of Repurchase ......................................................   10
            Possible Divestiture of Units ........................................................   11
            Periodic Reports .....................................................................   11
            Voting Rights of Unitholders .........................................................   12
            Liability of Unitholders .............................................................   12
            Transfer Agent .......................................................................   13
            Website/SEC Filings ..................................................................   13
    FEDERAL INCOME TAX CONSIDERATIONS ............................................................   13
            Summary of Certain Federal Income Tax Consequences ...................................   13
    ERISA CONSIDERATIONS .........................................................................   18
    STATE TAX CONSIDERATIONS .....................................................................   18
            Alabama Income Tax ...................................................................   18
            Alabama Business Privilege Tax .......................................................   19
            Alabama Severance Taxes ..............................................................   20
            Other Alabama Taxes ..................................................................   20
    REGULATION AND PRICES ........................................................................   20
            Regulation of Natural Gas ............................................................   20
            Environmental Regulation .............................................................   21
            Competition, Markets and Prices ......................................................   21
  Item 2. Properties .............................................................................   23
    THE ROYALTY INTERESTS ........................................................................   23
            The Underlying Properties ............................................................   23
            The Royalty Interests ................................................................   25
            Reserve Estimate .....................................................................   26
            Natural Gas Sales Prices and Production ..............................................   27
            Gas Purchase Agreement ...............................................................   27
            Operation of Properties ..............................................................   29
            Sale and Abandonment of Underlying Properties ........................................   30
            Dominion Resources's Assurances ......................................................   30
            Title to Properties ..................................................................   30
  Item 3. Legal Proceedings ......................................................................   31
  Item 4. Submission of Matters to a Vote of Security Holders ....................................   31

PART II ..........................................................................................   31
  Item 5. Market for Registrant's Common Equity and Related Stockholder Matters ..................   31
  Item 6. Selected Financial Data ................................................................   31
  Item 7. Trustee's Discussion and Analysis of Financial Condition and Results of Operations .....   32
            Critical Accounting Policies and Estimates ...........................................   34
            Liquidity and Capital Resources ......................................................   36
            Off-Balance Sheet Arrangements .......................................................   36
</Table>


                                       i

<PAGE>

<Table>
<S>                                                                                                 <C>
             Tabular Disclosure of Contractual Obligations .......................................   36
             Forward-Looking Statements ..........................................................   36
  Item 7A. Quantitative and Qualitative Disclosures About Market Risk ............................   37
  Item 8. Financial Statements and Supplementary Data ............................................   38
  Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ...   48

PART III .........................................................................................   48
  Item 10. Directors and Executive Officers of the Registrant ....................................   48
  Item 11. Executive Compensation ................................................................   48
  Item 12. Security Ownership of Certain Beneficial Owners and Management ........................   49
  Item 13. Certain Relationships and Related Transactions ........................................   49
             Administrative Services Agreement ...................................................   49
             Dominion Resources's Conditional Right of Repurchase ................................   49
             Potential Conflicts of Interest .....................................................   49
  Item 14. Controls and Procedures ...............................................................   50

PART IV ..........................................................................................   50
  Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K .......................   50
             Financial Statements ................................................................   50
             Financial Statement Schedules .......................................................   50
             Exhibits ............................................................................   50
             Reports on Form 8-K .................................................................   50
</Table>


                                       ii

<PAGE>
                                     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.

       "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 Dominion Black Warrior Basin, Inc., an Alabama
corporation and a wholly-owned indirect subsidiary of Dominion Resources.

       "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.

       "Contract Price" means the price at which, pursuant to the Gas Purchase
Agreement, El Paso Merchant Energy - Gas, L.P., as successor to Sonat Marketing,
is obligated to purchase the Subject Gas at the central delivery points in the
gathering system for the Underlying Properties. Pursuant to an amendment to the
Gas Purchase Agreement, effective January 1, 2000 through December 31, 2000, the
Monthly Base Quantity was divided into two categories, a fixed price quantity
and the indexed price quantity. The price for each fixed price quantity was
$2.45 per MMBtu. The price for each indexed price quantity was the sum of the
Index Price and the Premium (as defined in such amendment), provided that such
price would in no event be less than the Minimum Price nor more than the Maximum
Price. Pursuant to a Gas Purchase Agreement amendment, effective January 1, 2001
through December 31, 2001, the Contract Price for each month equaled (a) for
quantities of Gas equal to or less than 25% of the Monthly Base Quantity, $3.97
per MMBtu, (b) for quantities of Gas over and above 25% of the Monthly Base
Quantity up to 75% of the Monthly Base Quantity, the sum of the Index Price and
Premium, which Price could not be less than a floor of $3.00 per MMBtu and could
not be greater than a ceiling of $5.30 per MMBtu, (c) for quantities of Gas over
and above 75% of the Monthly Base Quantity up to the Monthly Base Quantity, the
sum of the Index Price and Premium, and (d) for quantities of Gas in excess of
the Monthly Base Quantity, the sum of the Index Price and $0.02 per MMBtu.
Pursuant to a Gas Purchase Agreement amendment, effective January 1, 2002
through December 31, 2002, the Contract Price for each month equaled (a) for
quantities of Gas up to and including the applicable Monthly Fixed Price
Quantity, $3.70 per MMBtu, and (b) for quantities of Gas over and above the
Monthly Fixed Price Quantity up to the Monthly Base Quantity, the sum of (i) the
Index Price and (ii) a premium per MMBtu, ranging from $.05 to $.07, multiplied
by 0.9826, the wet/dry conversion factor. Pursuant to that same Gas Purchase
Agreement amendment, commencing January 1, 2002, the Contract Price for
quantities of Gas over and above the Monthly Base Quantity equaled the sum of
(i) the Index Price and (ii) $.02 per MMBtu, multiplied by 0.9826, the wet/dry
conversion factor. Pursuant to the same Gas Purchase Agreement amendment,
commencing January 1, 2003, the price for quantities up to and including the
Monthly Base Quantity shall be the sum of (i) the Index Price and (ii) a premium
per MMBtu, ranging from $.05 to $.07, multiplied by 0.9826, the wet/dry
conversion factor. Pursuant to the July 1, 2002 Gas Purchase Agreement
amendment, effective January 1, 2003, the price payable by El Paso for each
MMBtu of Gas produced up to and including the applicable monthly specified base
quantity during each month shall be divided into two categories, a Fixed Price
Quantity and an Index Price Quantity (as defined therein). Until December 31,
2003, the price payable by El Paso for each MMBtu of Gas produced up to and
including the applicable monthly Fixed


                                        1


<PAGE>
Price Quantity shall be $3.68 per MMBtu. The price payable by El Paso for each
MMBtu of gas produced in excess of the applicable monthly Fixed Price Quantity
and up to and including the applicable monthly Index Price Quantity shall be the
sum of (i) the Index Price and (ii) a premium per MMBtu, ranging from $.05 to
$.07, multiplied by 0.9826, the wet/dry conversion factor. Commencing January 1,
2004, the pricing formula for the Index Price Quantity described in the
immediately preceding sentence shall apply to the entire Monthly Base Quantity.
Also effective January 1, 2004, the price payable by El Paso for gas production
in excess of the specified Monthly Base Quantity each month shall be the sum of
the Index Price and $.02 per MMBtu, multiplied by 0.9826, the wet/dry conversion
factor. Prices are subject to negotiation and arbitration at the request of
either party if they are unable to reach agreement.

       "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.

       "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.

       "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.

       "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.

       "Maximum Price" means, for the periods from January 1, 2000 through
December 31, 2000, January 1, 2001 through December 31, 2001, and January 1,
2002 through December 31, 2002, $2.82 per MMBtu, $5.30 per MMBtu, and $5.30 per
MMBtu, respectively.

       "Minimum Price" means, for the periods from January 1, 2000 through
December 31, 2000, January 1, 2001 through December 31, 2001, and January 1,
2002 through December 31, 2002, $2.20 per MMBtu, $3.00 per MMBtu, and $3.70 per
MMBtu, respectively.

       "MMcf" means million cubic feet of natural gas. As used herein, 1 MMcf is
assumed to have a Btu content of 1004 MMBtu.

       "MMBtu" means million Btu. As used herein, 990 MMBtu is deemed to be the
Btu content of 1 MMcf.

       "Monthly Base Quantity" means the volumes of natural gas designated as
such in the Gas Purchase Agreement.


                                        2


<PAGE>
       "Monthly Fixed Price Quantity" means the volumes of natural gas
designated as such from time to time in the Gas Purchase Agreement.

       "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.

       "Phillips Petroleum" means Phillips Petroleum Corporation, successor to
The River Gas Corporation.

       "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's 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, 2003, 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.

       "Section 29 tax credit" means the tax credits for federal income tax
purposes pursuant to Section 29 of the Code to an owner of coal seam gas
production, which tax credits are generated upon the sale of such production.

       "Sonat Marketing" means Sonat Marketing Company, a Delaware Corporation.

       "Subject Gas" means Gas attributable to the Company Interests.

       "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.

       "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.

       "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.

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


                                        3


<PAGE>
                            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., 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").


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 (as defined in the glossary). 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."

       The Company has advised the Trustee that all the production attributable
to the Underlying Properties is from the Pottsville coal formation and until
January 1, 2003 constitutes coal seam gas that entitled the owners of such
production, provided certain requirements were met, to tax credits pursuant to
Section 29 of the Code, upon the production and sale of such gas (to the extent
the Section 29 credit is available and not expired). See "--Federal Income Tax
Considerations."


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 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 which the Trustee would
grant to a similarly



                                        4

<PAGE>
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 Dominion Resources's assurances and the Gas Purchase Agreement. 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, Dominion Energy and Dominion Resources) 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 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.

       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 Dominion Resources or its
affiliates. See "--Termination and Liquidation of the Trust."



                                        5

<PAGE>
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 Dominion Resources. If a court were to hold
that the Trust is taxable as a corporation, then the Trust would incur
substantial federal income tax liabilities. See also "--State Tax
Considerations--Alabama Franchise Tax."


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 which 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 Dominion Resources 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 which
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 Trust
assets before seeking indemnification from Dominion Resources. Dominion
Resources also has agreed to indemnify the Trustee and the Delaware Trustee
against certain securities laws' liabilities. Neither the Trustee nor the
Delaware Trustee is entitled to 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 2/3 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 (a) estimated future net revenues from proved reserves attributable to the
Royalty Interests plus (b) the amount of all remaining Section 29 tax credits
attributable to the Royalty Interests, is equal to or less than $5 million (as
applicable, the "Termination Date"). Upon such occurrence, the remaining assets
of the Trust will be sold, the net proceeds of the sale will be distributed to
the 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 the 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


                                        6

<PAGE>
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.

       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.


ARBITRATION AND ACTIONS BY UNITHOLDERS

       Pursuant to the Trust Agreement, any dispute, controversy or claim that
may arise between or among Dominion Resources 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 Dominion Resources and the Trustee and
the Trust to submit any dispute regarding such contract to alternative dispute
resolution before litigating such matter.

       The Trust Agreement requires under certain circumstances that the Trustee
and the Trust pursue any claims against Dominion Resources and the Company with
respect to any breach by Dominion Resources 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 Dominion Resources 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



                                        7

<PAGE>
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 the 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
Dominion Resources or the Company, then such Unitholder could, on behalf of the
Trust, pursue such rights against Dominion Resources 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 Dominion Resources'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
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--Dominion Resources's Assurances."


                                        8


<PAGE>
                              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 24, 2003, 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 which 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 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.

       Gross income attributable to cash being distributed in most cases will be
reported for federal income tax purposes by the Unitholder who receives such
distributions assuming that such Unitholder is the owner of record on the
applicable record date. In certain circumstances, however, a Unitholder will not
receive the cash giving rise to such income. For example, the Trustee maintains
a cash reserve, and is authorized to borrow money under certain conditions, in
order to pay or provide for the payment of Trust liabilities. Income associated
with the cash used to increase that reserve or to repay that loan must be
reported by the Unitholder, even though that cash is not distributed to him.
Likewise, if a portion of a cash distribution is attributable to a reduction in
the cash reserve maintained by the Trustee, such cash is treated as a reduction
to the Unitholders' basis in his Units and is not treated as taxable income to
such Unitholder (assuming such Unitholder's basis exceeds the amount of the
distribution of cash reserve).


                                        9

<PAGE>
CONDITIONAL RIGHT OF REPURCHASE

       Dominion Resources (and any of its successor 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") which is 3 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 3 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 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 2
years from the repurchase date shall revert to the general funds of Dominion
Resources, after which 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.

       In the event that 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's 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).


                                       10


<PAGE>
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 2 years or such shorter period as shall
be permitted by applicable laws.


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 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 Dominion Resources 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 which shows in reasonable detail the assets and
liabilities and 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 which includes reserve
information relating to the Trust and the Royalty Interests. See "--Federal
Income Tax Considerations" for rules related to taking Section 29 credits.

       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 which 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 upon reasonable prior notice to examine
and inspect records of the Trust and the Trustee and the Delaware Trustee.



                                       11

<PAGE>
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 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 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 Resources. 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 Dominion Resources 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
Dominion Resources and the approval of a majority of the outstanding Units, no
amendment may be made to the Trust Agreement that would alter Dominion
Resources'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 Dominion Resources 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, Dominion Resources and the Company
may, without approval of the Unitholders, from time to time supplement or amend
the Trust Agreement in order to cure any ambiguity or to correct or supplement
any defective or inconsistent provisions, provided such supplement or amendment
is not adverse to the interests of the Unitholders. In addition, (i) Dominion
Resources may direct the Trustee to change the name of the Trust without
approval of the 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, Dominion
Resources 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 the 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.

LIABILITY OF UNITHOLDERS

       Consistent with Delaware law, the Trust Agreement provides that the
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.


                                       12

<PAGE>
TRANSFER AGENT

       Mellon Investor Services 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
it files with or furnishes such material 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 sections entitled "Federal Income Tax Consequences" and "Risk
Factors--Tax Considerations" appearing in the Prospectus set forth,
respectively, 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 sections 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 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 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.

       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


                                       13

<PAGE>
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.


     Coalseam gas produced and sold after December 31, 2002 will no longer
generate Section 29 tax credits unless the applicability of the Section 29 tax
credits are extended by Congress. Accordingly all discussion of Section 29 tax
credits are applicable only to those credits carried through December 31, 2002.


Classification and Taxation of the
    Trust................................   The Trust is a grantor trust 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.

Limits on Deductions and Credits.........   Generally, a taxpayer was entitled
                                            to claim deductions and tax credits
                                            generated by an investment only if
                                            the investment has economic
                                            substance. The application of this
                                            principle in the context of the
                                            production and sale of
                                            nonconventional fuels (like coal
                                            seam gas) that generated the Section
                                            29 tax credit is uncertain because
                                            such application has not been
                                            addressed either by a court or the
                                            IRS. An investment has economic
                                            substance if the investor could
                                            demonstrate that there was
                                            reasonable possibility of deriving
                                            an economic profit from the
                                            investment in excess of a de minimis
                                            amount, apart from tax benefits. In
                                            many cases, economic profit had been
                                            computed by comparing the taxpayer's
                                            total cash investment to the total
                                            cash reasonably expected to be
                                            received by the taxpayer as a result
                                            of the investment (a "Pre-Tax Profit
                                            Objective"). At the time of the
                                            Public Offerings, Special Counsel to
                                            Dominion Resources expressed the
                                            opinion (only in connection with the
                                            Public Offerings) that the ownership
                                            of Units purchased in either of the
                                            Public Offerings, which ownership is
                                            not subject to puts, calls or other
                                            risk allocation devices, has
                                            economic substance even if the owner
                                            has no Pre- Tax Profit Objective. No
                                            assurance is given either by the
                                            Trustee or counsel to the Trustee to
                                            a purchaser of Units in or following
                                            the Public Offerings as to whether
                                            (and to what extent) such purchaser
                                            is or will be entitled to claim
                                            deductions and the Section 29 tax
                                            credit generated with respect to
                                            such Units.

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.

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 2002,
                                            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


                                       14


<PAGE>
                                            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.

Section 29 Tax Credits ..................   Unitholders were entitled, provided
                                            certain requirements were met, to
                                            claim tax credits pursuant to
                                            Section 29 of the Code with respect
                                            to sales of coal seam gas production
                                            attributable to the Royalty
                                            Interests that was produced from the
                                            Existing Wells, the gross income
                                            from which was included in their
                                            taxable income. The Section 29 tax
                                            credit provided to a taxpayer a
                                            dollar-for-dollar reduction in his
                                            regular federal income tax liability
                                            and, therefore, generally provided
                                            to him a greater benefit than a
                                            deduction, which merely reduces the
                                            amount of his taxable income. For a
                                            Unitholder who owned the same Units
                                            of record on all four quarterly
                                            record dates during 2002, the
                                            available Section 29 tax credit is
                                            approximately $.858564 per Unit,
                                            based on the first estimate of the
                                            GNP implicit price deflator
                                            published by the Bureau of Economic
                                            Analysis.

                                            The availability of Section 29 tax
                                            credits is dependent upon meeting a
                                            number of requirements, many of
                                            which are factual in nature. The
                                            Company and Dominion Resources
                                            represented only in connection with
                                            the Public Offerings that those
                                            factual requirements were met. At
                                            the time of each of the Public
                                            Offerings, Special Counsel opined as
                                            to those requirements that are
                                            statutory or legal in nature. If any
                                            of the factual requirements are not
                                            met, or the opinion not followed,
                                            some or all of the expected Section
                                            29 tax credits may not be available.

                                            Production from coal seam gas wells
                                            drilled after December 31, 1979 and
                                            prior to January 1, 1993, qualifies
                                            for the Section 29 credit, so long
                                            as the wells are certified by the
                                            Federal Energy Regulatory Commission
                                            ("FERC"). For a discussion of the
                                            well certification requirement and
                                            its impact on the wells included
                                            within the Underlying Properties,
                                            see Note 3 to the Financial
                                            Statements.

                                            The Section 29 credit is calculated
                                            annually based on each year's
                                            qualified production throughout the
                                            year 2002. Coal seam gas produced
                                            and sold after December 31, 2002,
                                            will no longer generate a Section 29
                                            credit unless applicability of the
                                            Section 29 credit is extended by
                                            Congress. Legislation currently is
                                            proposed to extend the Section 29
                                            credit retroactively to January 1,
                                            2003. Of course, there can be no
                                            assurance that such legislation will
                                            be passed and, if passed, will be
                                            effective retroactively to January
                                            1, 2003.

Limits on Unitholder's Use of
    Section 29 Credits...................   The Section 29 credit is based on
                                            the Unitholder's pro rata share of
                                            qualifying production. It can be
                                            used only to the extent that a
                                            Unitholder's regular tax liability
                                            exceeds the Unitholder's tentative
                                            minimum tax liability after the
                                            regular tax liability has been
                                            reduced by the foreign tax credit
                                            and certain other nonrefundable
                                            personal credits. Any part of the
                                            Section 29 credit not allowed for
                                            the tax year solely because of this
                                            alternative minimum tax limitation
                                            is subject to certain carryover
                                            provisions relating to the
                                            alternative minimum tax calculation.
                                            Except for


                                       15


<PAGE>
                                            the foregoing, there are no Code
                                            provisions that allow for the
                                            carryback or carryforward of Section
                                            29 credits in any other
                                            circumstances. As the carryforward
                                            of unused Section 29 credits is
                                            related to the alternative minimum
                                            tax calculation for succeeding
                                            years, carryforwards should be
                                            allowed even if the Section 29
                                            credit is not extended after 2002.

Quarterly Allocations of Section 29
    Credits..............................   Under the Code, a Unitholder was
                                            entitled to Section 29 tax credits
                                            only to the extent that he was an
                                            owner of the economic interest at
                                            the time the coal seam gas was
                                            produced. The Trustee allocates the
                                            income received by the Trust for a
                                            quarter, and the Section 29 tax
                                            credit allocable to such income, to
                                            Unitholders of record on the
                                            quarterly record date for such
                                            quarter. Such an allocation may be
                                            challenged by the IRS, but any
                                            challenge is likely to have a
                                            material adverse effect only if
                                            successful and only for Unitholders
                                            who do not own Units for a full
                                            quarter for each record date,
                                            particularly Unitholders who acquire
                                            Units shortly before a record date
                                            and sell shortly after a record
                                            date. At the time of each of the
                                            Public Offerings, Special Counsel
                                            declined to express an opinion as to
                                            whether the IRS would accept
                                            quarterly allocations or would
                                            require income, credits and
                                            deductions of the Trust to be
                                            determined and allocated daily based
                                            on ownership at the time of
                                            production or on some other basis.

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. No depletion allowances
                                            were available to Unitholders in
                                            respect of production from the
                                            Royalty Interests prior to June 28,
                                            1994.

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 Service 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.


                                       16


<PAGE>
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. Section 29 tax credits
                                            generated by an investment in Units
                                            could be utilized to offset regular
                                            tax liability on income from any
                                            source whether active or passive,
                                            subject to other limitations
                                            discussed herein or arising from the
                                            individual tax circumstances of each
                                            Unitholder. See "Limits on
                                            Unitholder's Use of Credits" above.

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.

Substantial Understatement
    Penalty .............................   Section 6662 of the Code imposes a
                                            penalty in certain circumstances for
                                            a substantial understatement of
                                            taxes if a taxpayer's tax liability
                                            is understated by more than the
                                            greater of (i) 10 percent of the
                                            taxes required to be shown on the
                                            return or (ii) $5,000 ($10,000 for
                                            most corporations). The penalty
                                            (which is not deductible) is 20
                                            percent of the understatement.

                                            Except in the case of
                                            understatements attributable to "tax
                                            shelter" items, which are subject to
                                            special rules discussed below, an
                                            item of understatement will not give
                                            rise to the penalty if: (i) there is
                                            or was "substantial authority" for
                                            the taxpayer's treatment of the
                                            item, (ii) all the facts relevant to
                                            the tax treatment of the item are
                                            adequately disclosed on the return
                                            or on a statement attached to the
                                            return and there is a reasonable
                                            basis for the tax treatment of such
                                            item, or (iii) there is reasonable
                                            cause and the taxpayer acted in good
                                            faith.

                                            In the case of understatements
                                            attributable to "tax shelter" items
                                            by noncorporate taxpayers, the
                                            substantial understatement penalty
                                            may be avoided only if: (i) the
                                            taxpayer establishes that, in
                                            addition to having substantial
                                            authority for his position, he
                                            reasonably believed that the
                                            treatment claimed was more likely
                                            than not the proper treatment of the
                                            item, or (ii) there is reasonable
                                            cause and the taxpayer acted in good
                                            faith. In the case of
                                            understatements attributable to "tax
                                            shelter" items by corporate
                                            taxpayers, effective for
                                            transactions occurring after
                                            December 8, 1994, the substantial
                                            authority and reasonable belief
                                            exception does not apply.
                                            Accordingly, in a transaction
                                            occurring after December 8, 1994, if
                                            a corporate taxpayer has a
                                            substantial understatement
                                            attributable to a "tax shelter"
                                            item, penalties apply unless the
                                            corporate taxpayer can show
                                            reasonable cause and good faith. For
                                            transactions involving corporate
                                            taxpayers and substantial
                                            understatements attributable to "tax
                                            shelter" items occurring before
                                            December 9, 1994, the rules
                                            applicable to noncorporate taxpayers
                                            apply. A "tax shelter" item is an
                                            item (e.g., income, gain, loss,
                                            deduction, credit) attributable to a
                                            partnership or other entity, any
                                            investment plan or arrangement, or
                                            any other plan or arrangement, if a
                                            significant purpose of such
                                            partnership, entity, plan or
                                            arrangement is the avoidance or
                                            evasion of income tax. For
                                            transactions entered into before
                                            August 6, 1997, the relevant
                                            standard is whether tax


                                       17

<PAGE>
                                            avoidance or evasion of income tax
                                            was the principal purpose of the
                                            entity, plan, or arrangement.

                                            No assurance is given either by the
                                            Trustee or counsel to the Trustee as
                                            to the possible application of this
                                            penalty or any other penalties, in
                                            part because such application
                                            depends largely upon the individual
                                            circumstances under which the Units
                                            were acquired. As a result,
                                            purchasers of Units in and after the
                                            Public Offerings should consult with
                                            their personal tax advisors.

Unitholder Reporting
    Information .........................   The Trustee furnishes to Unitholders
                                            tax information concerning royalty
                                            income, depletion and the Section 29
                                            tax credits 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."

                                            Unless the final information issued
                                            by the U.S. Treasury Department at
                                            the end of March regarding the
                                            amount of the Section 29 credit for
                                            2002 differs materially from the
                                            Trustee's estimate, the final
                                            information will be contained in the
                                            next quarterly report. However, to
                                            the extent the final information
                                            issued by the U.S. Treasury
                                            Department causes the tax credit
                                            amounts for 2002 to differ
                                            materially from the Trustee's
                                            estimates contained in the 2002 Tax
                                            Information booklet, the Trustee
                                            will promptly mail final tax credit
                                            information to each affected
                                            Unitholder.

                              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, and the Code to pension,
profit-sharing and other employee benefit plans and to individual retirement
accounts (collectively, "Qualified Plans"). A copy of sections 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 with 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
THE 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


                                       18

<PAGE>
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.

       Alabama tax counsel has advised the Trust that the Alabama Department of
Revenue (the "DOR") will permit the Trust to file a "composite income tax
return" on behalf of all Unitholders who are not residents of Alabama, and that
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 1995-2001
composite income tax returns with the DOR on behalf of all Nonresident
Unitholders (defined below), and intends to file a composite return for 2002 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 2002. Accordingly,
no Alabama state income tax is due under the 2002 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 acceptable to the
DOR. If the composite income tax return for 2002 (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 which 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.
Dominion Resources agreed to indemnify the Trust against any resulting Alabama
franchise tax imposed on the Trust.

       The Alabama franchise tax has been repealed and replaced with the Alabama
business privilege tax, which levies 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 business
privilege tax applied to a grantor trust. The DOR had previously issued a
revenue ruling holding that the business privilege tax did not apply to a
grantor trust, but that revenue ruling was revoked. Although the Trust is a
grantor trust, it may not be subject to the business privilege tax because it
was not subject to the repealed Alabama franchise tax pursuant to the
aforementioned private letter ruling



                                       19

<PAGE>
and because it is entitled to be indemnified by Dominion Resources under a
contract entered into before 1999 for any Alabama franchise tax. The Trust paid
no business privilege tax in 2002. The Trust intends to obtain confirmation in
2003 that it is not subject to the business privilege 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 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 ("NGA") 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.

       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, 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.


                                       20

<PAGE>
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 5 permits in connection with the Underlying
Properties which were consolidated into one permit in February 1994. The ADEM
permit was renewed in 1999 and will expire in July 2004. 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 Trust. The Company has informed the Trust that it estimates that it plans to
expend approximately $58,000 during 2003 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 and other fossil fuels.

       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 any continuation of a depressed market 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.


                                       21

<PAGE>
       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
produce from the Underlying Properties.

       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. Gas is sold
pursuant to the Gas Purchase Agreement, which contains hedging features that may
to some extent mitigate the negative effects of such volatility but may limit
the benefits Unitholders realize from higher natural gas prices. See
"Properties--The Royalty Interests--Gas Purchase Agreement."


                                       22


<PAGE>
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 7 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 River Gas 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 8 wells. The Company acquired its interest in the
Underlying Properties in December 1992. As of December 31, 2002, the Underlying
Properties contained 532 wells that were producing gas, all of which were
drilled prior to 1993.

       Well Count and Acreage Summary. The following table shows as of December
31, 2002, 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.

<Table>
<Caption>
                                           NUMBER OF
                                             WELLS                  ACRES
                                        ---------------       ------------------
                                        GROSS       NET       GROSS        NET
                                        -----       ---       ------      ------
<S>                                     <C>         <C>       <C>         <C>
     Company Interests.............      532        519       34,212      33,391
</Table>

       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



                                       23

<PAGE>
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 5 water disposal
systems, each with 2 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 will expire in July 2004. 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."

       Curtailments. The Company has advised the Trust that, during 2002,
production from the Underlying Properties was not curtailed for any reason other
than for routine maintenance.

       Federal Lands. Approximately one percent (360 acres) of the Underlying
Properties are leases on land held by the federal government. Royalty payments
due to the U.S. government for natural gas produced from federal lands included
in the Underlying Properties must be calculated in conformance with a working
interest owner's interpretation of regulations issued by the Minerals Management
Service ("MMS"). MMS regulations cover both valuation standards, which establish
the basis for placing a value on production, and cost allowances, which define
those post-production costs that are deductible by the lessee.

       The Trust is subject to certain rules of the Bureau of Land Management
under which the holding of interests in leases by persons other than citizens,
nationals and legal resident aliens of the United States ("Eligible Citizens")
are limited. As a result, non-Eligible Citizens are prohibited from owning
Units. If any Units are acquired by persons or entities not constituting
Eligible Citizens, such Unitholders may be required to sell such Units pursuant
to a procedure set forth in the Trust Agreement. See "Business--Description of
the Trust--Possible Divestiture of Units."

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

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

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


                                       24


<PAGE>
of the reserves otherwise producible from wells burdened by the Company
Interests, thereby reducing the Gross Proceeds attributable to the Royalty
Interests.

       If additional wells are drilled, Section 29 credits will not be generated
from production attributable to such additional wells unless the Section 29
credit is extended and the drilling requirement is changed.

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. To the extent that production from the recompleted
wells qualifies for the Section 29 tax credit, such production is taken into
account by the Trustee when computing the Tax Credit per Unit furnished annually
to the Unitholders.

       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."

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

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

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


                                       25


<PAGE>
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 which 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, 2003, 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.

<Table>
<Caption>
                                                                        AS OF
     ROYALTY INTERESTS                                             JANUARY 1, 2003
     -----------------                                             ---------------
<S>                                                                <C>
     Net Proved Natural Gas Reserves (MMcf)(a)(b):
          Developed Producing...................................         42,585
     Estimated Future Net Revenues (in thousands) (a)(c):
          2003..................................................       $ 19,586
          2004..................................................         18,261
          2005..................................................         15,900
          2006..................................................         13,865
          2007..................................................         12,070
          Thereafter............................................         84,388
                                                                       --------
               Total............................................       $164,070
                                                                       ========
               Total Discounted at 10 Percent...................       $ 95,563
                                                                       ========
</Table>

----------

(a)  The estimates of reserves and future net revenues summarized in this table
     are based upon an unescalated price of $3.862 through December 31, 2003,
     which was the price being received by the Company under the Gas Purchase
     Agreement as of January 1, 2003. After December 31, 2003, the price of
     $4.133 per Mcf was utilized which represented the market price for gas in
     their fields as of December 31, 2002. This price may not be the most
     representative price for estimating reserves or related future net revenues
     data. See "--Gas Purchase Agreement."

(b)  As discussed in "Business--Federal Income Tax Considerations", coal seam
     gas produced and sold after December 31, 2002, will no longer generate a
     Section 29 credit unless applicability of the Section 29 credit is extended
     by Congress.

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


                                       26

<PAGE>
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 which 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 5.4 Bcf in 2003 to 3.6 Bcf in 2006.

       Ralph E. Davis & Associates has delivered to the Trust the Reserve
Estimate, a summary of which is included as an exhibit to this Form 10-K.
Information concerning historical changes in net proved developed reserves
attributable to the Royalty Interests, and the calculation of the standardized
measure of discounted future net revenues related thereto, is contained in Note
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, 2002, December 31, 2001 and December 31, 2000.

<Table>
<Caption>
                                                   YEAR ENDED           YEAR ENDED           YEAR ENDED
                                                DECEMBER 31, 2002    DECEMBER 31, 2001    DECEMBER 31, 2000
                                                -----------------    -----------------    -----------------
<S>                                             <C>                  <C>                  <C>
Production attributable to the Royalty
   Interests (Bcf) ..........................           6.1                  7.0                  8.0
Weighted average property, production and
   related taxes (per Mcf) ..................         $ .15                $ .16                $ .15
Average Contract Price (per Mcf) ............         $3.70                $2.99                $2.71
</Table>

GAS PURCHASE AGREEMENT

       El Paso Merchant Energy - Gas, L.P. ("El Paso"), successor to Sonat
Marketing Company ("Sonat Marketing"), is required under the Gas Purchase
Agreement to purchase the gas produced from the Underlying Properties for as
long as reserves on the Underlying Properties produce natural gas. Under the
agreement, Sonat Marketing (as predecessor to El Paso under the Gas Purchase
Agreement) was, in past years, obligated to purchase up to a specified monthly
base quantity of gas for a contract price equal to the Index Price plus a
specified premium (between $.05 and $.07 per MMBtu) over the Index Price. Until
December 31, 1998, the Contract Price paid was subject to a minimum price of
$1.85 per MMBtu and a maximum price of $2.63 per MMBtu. Beginning effective
January 1, 1999, the Contract Price paid was subject to a minimum price of $2.16
per MMBtu and a maximum price of $3.07 per MMBtu. Beginning effective January 1,
2000 through December 31, 2000 the price paid on Index Price Quantities to a
minimum price of $2.20 and a maximum price of $2.82. Prior to April 1, 1996,
Sonat Marketing was obligated to purchase gas production in excess of the
specified monthly base quantities at the Index Price. Effective April 1, 1996
through December 31, 1998, the price paid for such gas production in excess of
the specified monthly base quantities was the Index Price plus $.02. Effective
January 1, 1999


                                       27

<PAGE>
through December 31, 2000, the price paid gas production in excess of the
specified monthly basis quantities was the Index Price plus $.02. The Index
Price, which is determined on a monthly basis, is Southern Natural Gas Company's
posted index price for deliveries of gas in Louisiana.

       Effective January 1, 2001 through December 31, 2001, the price payable by
El Paso for each MMBtu of the base quantity specified for each month was divided
into three categories, a fixed price quantity, an index price quantity subject
to a floor and ceiling price (the "Collared Index Quantity"), and an index price
quantity not subject to a floor or ceiling price (the "Non-Collared Index
Quantity"). The price paid for each MMBtu of fixed price quantity was $3.97 per
MMBtu. For the amount of gas sold in excess of the fixed price quantity, the
price for each MMBtu of gas sold up to the Collared Index Quantity was the Index
Price, provided that the price payable each month would in no event be less than
$3.00 per MMBtu nor more than $5.30 per MMBtu. For the amount of gas sold in
excess of the fixed price quantity plus the Collared Index Quantity, the price
for each MMBtu of gas sold was the sum of (a) the Index Price and (b) a premium
per MMBtu (ranging from $.05 to $.07). The price payable by El Paso for each
MMBtu of gas production in excess of the specified monthly base quantity each
month was the sum of the Index Price plus $.02. Pursuant to a Gas Purchase
Agreement amendment, effective January 1, 2002 through December 31, 2002, the
price payable by El Paso for each MMBtu for each month was (a) for quantities of
Gas up to and including the applicable Monthly Fixed Price Quantity, $3.70 per
MMBtu, and (b) for quantities of Gas over and above the Monthly Fixed Price
Quantity up to the Monthly Base Quantity, the sum of (i) the Index Price and
(ii) a premium per MMBtu, ranging from $.05 to $.07, multiplied by 0.9826, the
wet/dry conversion factor. Pursuant to that same Gas Purchase Agreement
amendment, commencing January 1, 2002, the price payable by El Paso for each
MMBtu over and above the Monthly Base Quantity equaled the sum of (i) the Index
Price and (ii) $.02 per MMBtu, multiplied by 0.9826, the wet/dry conversion
factor. Pursuant to the same Gas Purchase Agreement amendment, commencing
January 1, 2003, the price for quantities up to and including the Monthly Base
Quantity shall be the sum of (i) the Index Price and (ii) a premium per MMBtu,
ranging from $.05 to $.07, multiplied by 0.9826, the wet/dry conversion factor.
Pursuant to the same Gas Purchase Agreement amendment, commencing January 1,
2003, the price for quantities up to and including the Monthly Base Quantity
shall be the sum of (i) the Index Price and (ii) a premium per MMBtu, ranging
from $.05 to $.07, multiplied by 0.9826, the wet/dry conversion factor. Pursuant
to the July 1, 2002 Gas Purchase Agreement amendment, effective January 1, 2003,
the price payable by El Paso for each MMBtu of gas produced up to and including
the applicable monthly specified base quantity during each month shall be
divided into two categories, a Fixed Price quantity and an Index Price Quantity.
Until December 31, 2003, the price payable by El Paso for each MMBtu of gas
produced up to and including the applicable monthly Fixed Price Quantity shall
be $3.68 per MMBtu. The price payable by El Paso for each MMBtu of gas produced
in excess of the applicable monthly Fixed Price Quantity and up to and including
the applicable monthly Index Price Quantity shall be the sum of (i) the Index
Price and (ii) a premium per MMBtu, ranging from $.05 to $.07, multiplied by
0.9826, the wet/dry conversion factor. Commencing January 1, 2004, the pricing
formula for the Index Price Quantity described in the immediately preceding
sentence shall apply to the entire monthly base quantity. Also effective January
1, 2004, the price payable by El Paso for gas production in excess of the
specified monthly base quantity each month shall be the sum of the Index Price
and $.02 per MMBtu, multiplied by 0.9826, the wet/dry conversion factor.

       El Paso's obligation to purchase gas pursuant to the Gas Purchase
Agreement (as well as the Company's obligation to sell such natural gas) may be
suspended to the extent affected by the occurrence of any event not within the
control of the affected party that renders the affected party unable to perform
its obligations under the Gas Purchase Agreement if the event could not have
been prevented by the exercise of reasonable diligence including: acts of God,
strikes, lockouts or other industrial disturbances, acts of the public enemy,
wars, blockades, insurrections, riots, epidemics, landslides, lightning,
earthquakes, fires, storms, floods, washouts, arrests and restraints of
governments and people, civil disturbances, explosions, breakage or accident to
machinery or lines of pipe, the necessity for maintenance of or making repairs
or alterations to machinery or lines of pipe, freezing of wells or lines of
pipe, partial or entire failure of wells, curtailment, interruption or other
unavailability of transportation, inability to acquire or delay in acquiring at
reasonable cost and by the exercise of reasonable diligence, servitudes, rights
of way, grants, permits, permissions, licenses, materials or supplies that are
required to enable the affected party to perform its obligations. Following any
such event, the affected party's obligations under the Gas Purchase Agreement
will be suspended during the period of its inability to perform, and such party
will as far as possible remedy the event with reasonable dispatch. During the
pendency of any such suspension, the cash available for distribution, and the
depletion deductions and Section 29 tax credits available for allocation (to the
extent the Section 29 credit is available), by the Trust to Unitholders could be
reduced materially or eliminated entirely. As discussed in "Business--Federal
Income Tax Considerations", coal seam


                                       28


<PAGE>
gas produced and sold after December 31, 2002, will no longer generate a Section
29 credit unless applicability of the Section 29 credit is extended by Congress.

       The Gas Purchase Agreement, and the amendments thereto, are filed as
exhibits to this Form 10-K, and the foregoing summary of the material terms of
such agreement is qualified in its entirety by reference to the terms of such
agreement and amendments as set forth in such exhibits.


OPERATION OF PROPERTIES

       No Control by Trust. Under the terms of the Conveyance, neither the
Trustee nor the 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 the Underlying Properties."

       Operating Agreement. Pursuant to the Operating Agreement, Phillips
Petroleum operates and maintains the Underlying Properties for the Company and
the other working interest owners. As amended October 30, 1996, the Operating
Agreement had a 3 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 Phillips
Petroleum that it was terminating the automatic one year extension of the
agreement. As such, the current operating agreement will expire, unless agreed
upon otherwise, on December 31, 2003. Upon not less than 30 days notice either
Phillips Petroleum or the Company may terminate the Operating Agreement earlier
than December 31, 2003 if: (i) the other party has committed a material breach
of the Operating Agreement, unless such breach is cured in the manner specified
in the Operating Agreement; (ii) the other party files a petition for relief
under federal or state bankruptcy laws, the other party's insolvency is
determined by a final court proceeding, the other party's filing of a petition
or application to accomplish such a result or for the appointment of a receiver
or trustee for such party or for a substantial part of its assets or
commencement of any proceedings relating to the other party under any other
reorganization, arrangement, insolvency, adjustment of debt or liquidation law
of any jurisdiction; provided, however, that if such proceeding is not
commenced, the proceeding will not give rise to a right to terminate the
Operating Agreement unless such party consents or such proceeding has not been
finally dismissed within 90 days after its commencement; or (iii) after good
faith negotiations Phillips Petroleum and the Company and the other working
interest owners cannot agree on an annual operating plan or budget for any year.

       While the Operating Agreement is in effect, all of the production
attributable to the Company Interests will be gathered, treated and processed by
Phillips Petroleum pursuant to the Operating Agreement. Such production will be
gathered at the wellhead and transported to the central delivery points in the
gathering system for the Underlying Properties, which is owned by the Company
and the other working interest owners.

       Under the terms of the Operating Agreement, Phillips Petroleum owes a
duty to the Company and the other working interest owners to conduct the
operations on the Underlying Properties in a good and workmanlike manner and
following practices that (i) are engaged in or accepted by a significant portion
of the natural gas production industry at the time the decision was made or (ii)
in the exercise of reasonable judgment in light of the facts known at the time
the decision was made would have been expected to accomplish the desired result
at a reasonable cost consistent with reliability, safety, expeditiousness and
protection of the environment. Phillips Petroleum has no direct contractual or
fiduciary duty to protect the interests of the Trust or the Unitholders.


                                       29

<PAGE>
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, 2002, 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
the 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 Agreement--Termination and
Liquidation of the Trust."


DOMINION RESOURCES'S ASSURANCES

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

       The Trustee may, at any time after the 10th day following receipt by
Dominion Resources of written notice from the Trustee that a Payment Obligation
has not been paid when due, make demand of Dominion Resources for payment
stating the amount due. Dominion Resources 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 Dominion Resources's performance obligations.

       All of Dominion Resources'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 Dominion Resources's direct or indirect
equity ownership interest in the Company; provided that, with respect to clauses
(ii) and (iii) above, Dominion Resources's obligations will terminate only if:
(a) the transferee has a specified credit rating or the transferee together with
an affiliate which 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
Dominion Resources'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 Dominion Resources and 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 which, 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


                                       30

<PAGE>
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.

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


ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

       Not applicable.


                                     PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

       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.

<Table>
<Caption>
                                                           PRICE
                                                      -----------------   DISTRIBUTION
                                                       HIGH       LOW       PER UNIT
                                                      ------     ------   ------------
<S>                                                   <C>        <C>      <C>
2002
----
First Quarter.......................................  $21.30     $19.65    $ .576189
Second Quarter......................................   24.55      17.20      .575137
Third Quarter.......................................   22.27      17.55      .623862
Fourth Quarter......................................   22.00      19.05      .597635

2001
----
First Quarter.......................................  $20.05     $15.50    $ .623899
Second Quarter......................................   25.50      15.70     1.098552
Third Quarter.......................................   21.93      15.95      .860489
Fourth Quarter......................................   20.49      17.35      .626706
</Table>

At March 1, 2003, there were 7,850,000 Units outstanding and approximately 1,493
Unitholders of record.

       The trust has no equity compensation plans.

ITEM 6. SELECTED FINANCIAL DATA.

<Table>
<Caption>
                                                          YEAR ENDED DECEMBER 31,
                                    -------------------------------------------------------------------
                                       2002          2001          2000          1999          1998
                                    -----------   -----------   -----------   -----------   -----------
<S>                                 <C>           <C>           <C>           <C>           <C>
Royalty Income                      $19,418,476   $25,937,254   $20,874,519   $20,031,958   $22,849,760
Distributable Income                $18,623,941   $25,215,487   $20,229,281   $19,385,356   $22,226,804
Distributable Income per Unit       $      2.37   $      3.21   $      2.58   $      2.47   $      2.83
Distributions per Unit              $      2.37   $      3.21   $      2.58   $      2.46   $      2.83
Total Assets, December 31           $50,566,037   $57,819,259   $65,691,406   $75,397,111   $85,645,529
Total corpus, December 31           $50,441,689   $57,707,439   $65,575,056   $75,273,180   $85,533,029
</Table>


                                       31

<PAGE>
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 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. 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 2002 marked the eighth full year of the existence of the Trust.
The Trust received royalty income amounting to $19,418,476 during the year ended
December 31, 2002, compared to $25,937,254 for 2001 and $20,874,519 for 2000.
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, 2002 increased to $810,557, compared
to $776,431 for 2001 and $725,420 for 2000. Distributable income for the year
ended December 31, 2002 was $18,623,941, or $2.37 per Unit, compared to
$25,215,487, or $3.21 per Unit, for 2001 and $20,229,281, or $2.58 per Unit, for
2000.

       The increase in administrative expenses in 2002 compared to 2001 was
primarily the result of higher printing costs and increased professional fees.
Similarly, the increase from 2000 to 2001 was the result of increased
professional fees.

       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 decreases in royalty income and
distributable income noted in the preceding paragraph were due primarily to this
depletion of reserves and to a decrease 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 3 quarters of that year and the fourth quarter of
the


                                       32

<PAGE>
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, 2002, 2001 and 2000, was based on production volumes and
natural gas prices for the periods from October 1, 2001 to September 30, 2002,
October 1, 2000 through September 30, 2001 and October 1, 1999 to September 30,
2000, 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.

<Table>
<Caption>
                                                   FOR 12 MONTHS ENDED
                                                       SEPTEMBER 30,
                                                -------------------------
                                                2002      2001      2000
                                                -----     -----     -----
<S>                                             <C>       <C>       <C>
Production (Bcf)(1)                             6.129     6.963     8.351
Production (MMBtu)(2)                           6.152     6.942     8.267
Average Contract Price Received($/MMBtu)        $3.36     $3.76     $2.52
Average Index Price($/MMBtu)                    $2.78     $4.94     $3.86
</Table>

----------

(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 (as successor to Sonat Marketing) is required under the Gas
Purchase Agreement to purchase the gas produced from the Underlying Properties
for as long as reserves on the Underlying Properties produce natural gas. Under
the agreement, Sonat Marketing was, in past years, obligated to purchase up to a
specified monthly base quantity of gas (the "Index Price Quantity") for a
contract price equal to the Index Price plus a specified premium (between $.05
and $.07 per MMBtu) over the Index Price. Until December 31, 1998, the Contract
Price paid was subject to a minimum price of $1.85 per MMBtu and a maximum price
of $2.63 per MMBtu. Beginning effective January 1, 1999, the Contract Price paid
was subject to a minimum price of $2.16 per MMBtu and a maximum price of $3.07
per MMBtu. Beginning effective January 1, 2000 through December 31, 2000, the
price paid on Index Price Quantities was subject to a minimum price of $2.20 and
a maximum price of $2.82. Beginning effective January 1, 2001 through December
31, 2001, the Contract Price paid was subject to a minimum price of $2.83 per
MMBtu and a maximum price of $6.46 per MMBtu. Beginning effective January 1,
2002 through December 31, 2002, the Contract Price paid was subject to a minimum
price of $3.70 per MMBtu and a maximum price of $5.30 per MMBtu. Commencing
January 1, 2003, the price for quantities up to and including the Monthly Base
Quantity shall be the sum of (i) the Index Price and (ii) a premium per MMBtu,
ranging from $.05 to $.07, multiplied by 0.9826, the wet/dry conversion factor.
Pursuant to the same Gas Purchase Agreement amendment, commencing January 1,
2003, the price for quantities up to and including the Monthly Base Quantity
shall be the sum of (i) the Index Price and (ii) a premium per MMBtu, ranging
from $.05 to $.07, multiplied by 0.9826, the wet/dry conversion factor. Pursuant
to the July 1, 2002 Gas Purchase Agreement amendment, effective January 1, 2003,
the price payable by El Paso for each MMBtu of gas produced up to and including
the applicable monthly specified base quantity during each month shall be
divided into two categories, a Fixed Price quantity and an Index Price Quantity.
Until December 31, 2003, the price payable by El Paso for each MMBtu of gas
produced up to and including the applicable monthly Fixed Price Quantity shall
be $3.68 per MMBtu. The price payable by El Paso for each MMBtu of gas produced
in excess of the applicable monthly Fixed Price Quantity and up to and including
the applicable monthly Index Price Quantity shall be the sum of (i) the Index
Price and (ii) a premium per MMBtu, ranging from $.05 to $.07, multiplied by
0.9826, the wet/dry conversion factor. Commencing January 1, 2004, the pricing
formula for the Index Price Quantity described in the immediately preceding
sentence shall apply to the entire monthly base quantity. Also effective January
1, 2004, the price payable by El Paso for gas production in excess of the
specified monthly base quantity each month shall be the sum of the Index Price
and $.02 per MMBtu, multiplied by 0.9826, the wet/dry conversion factor. Prior
to


                                       33


<PAGE>
April 1, 1996, Sonat Marketing was obligated to purchase gas production in
excess of the specified monthly base quantities at the Index Price. Effective
April 1, 1996 through December 31, 2001, the price paid for such gas production
in excess of the specified monthly basis quantities was the Index Price plus
$.02. The Index Price, which is determined on a monthly basis, is Southern
Natural Gas Company's posted index price for deliveries of gas in Louisiana. The
Company has advised the Trust that at the end of the primary term or any
extensions thereof, El Paso will be obligated to purchase the Subject Gas at the
Index Price until such time as the Company and El Paso negotiate a different
price, and that the Company will have the ability to obtain an offer to purchase
the Subject Gas from another purchaser and terminate the Gas Purchase Agreement
if El Paso does not match such offer.

       The net proved reserves attributable to the Royalty Interests have been
estimated as of December 31, 2002, 2001 and 2000, by independent petroleum
engineers. The reserve quantities of 42.6 Bcf for 2002 compared to 51.0 Bcf for
2001 and compared to 56.8 Bcf for 2000, reflect a decline in reserves between
2002 and 2001 and between 2001 and 2002 as a result of production. 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 judgement areas in the
application of accounting policies that currently affect the Trust's financial
condition and results of operations.

1. BASIS OF ACCOUNTING

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

o      Royalty income and interest income are recorded in the period in which
       amounts are received by the Trust rather than in the month of production
       or when earned.

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

o      Amortization of the Royalty Interests is calculated on a
       unit-of-production basis and charged directly to trust corpus based upon
       when revenue is received.

o      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.

2. IMPAIRMENT

       The net amount of royalty interests in gas properties is limited to the
sum of the future net cash flows attributable to the Trust's gas reserves at
year end using current unescalated product prices plus the estimated Section 29
credits for federal income tax purposes (to the extent the Section 29 credit is
available and not expired). 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.


                                       34

<PAGE>
3. REVENUE RECOGNITION

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


4. RESERVE DISCLOSURE

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


5. CONTINGENCIES

       Contingencies related to the Underlying Properties that are unfavorably
resolved would generally be reflected by the Trust as reductions to future
royalty income payments to the Trust with corresponding reductions to cash
distributions to Unitholders. The Trustee is aware of no such items as of
December 31, 2002.

NEW ACCOUNTING PRONOUNCEMENTS

       SFAS No. 143, "Accounting for Asset Retirement Obligations" was issued in
June 2001, and will be adopted by the Trust on January 1, 2003. This Statement
addresses financial accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset retirement
costs. The effect of adopting SFAS No. 143 will not have a material impact on
the Trust's financial statements.

       SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment
of FASB Statement No. 13, and Technical Corrections" was issued in April 2002
and is effective for fiscal years beginning after May 15, 2002. This Statement
includes the rescission of FASB Statement No. 4, "Reporting Gains and Losses
from Extinguishment of Debt," and an amendment to FASB Statement No. 13,
"Accounting for Leases," to eliminate an inconsistency between the required
accounting for sale-leaseback transactions and the required accounting for
certain lease modifications that have economic effects that are similar to
sale-leaseback transactions. The effect of adopting SFAS No. 145 will not have a
material impact on the Trust's financial statements.

       SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities" was issued in June 2002 and will be effective for exit or disposal
activities subsequent to December 31, 2002. The Trust anticipates no material
impact on its financial statements from the adoption of this accounting
standard.

       SFAS No. 148, "Accounting for Stock-Based Compensation -- Transition and
Disclosure, an amendment of FASB Statement No. 123," was issued in December 2002
and provides new transition methods if an entity adopts the fair value based
method of valuing stock-based compensation suggested in SFAS No. 123 "Accounting
for Stock-Based Compensation," as well as requiring additional disclosures in
interim and annual financial statements. The Trust has no options or other
stock-based instruments and accordingly, the impact of this new Standard is not
expected to be material to the financial statements of the Trust.

       FASB Interpretation ("FIN") No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others," requires disclosures beginning with financial
statements ending after December 15, 2002 and requires liability recognition
beginning January 1, 2003. The Trust had no such guarantees outstanding as of
December 31, 2002.

       FIN No. 46, "Consolidation of Variable Interest Entities" was issued in
January 2003. This interpretation of Accounting Research Bulletin No. 51,
"Consolidated Financial Statements," applies immediately to variable interest
entities created after January 31, 2003 and applies to the first period
beginning after June 15, 2003 to entities acquired before February 1, 2003. This
FIN does not affect the Trust as it has no unconsolidated subsidiaries accounted
for under the equity method of accounting.


                                       35

<PAGE>
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 Trust is a passive entity and other than the Trust's
ability to periodically borrow money as necessary to pay expenses, liabilities
and obligations of the Trust that cannot be paid out of cash held by the Trust,
the Trust is prohibited from engaging in borrowing transactions. As a result,
other than such borrowings, if any, the Trust has no source of liquidity or
capital resources other than the Royalty Interests. See the earlier discussions
in Item 7 for the discussion of the operations and cash inflows and outflows of
the Trust.


OFF-BALANCE SHEET ARRANGEMENTS

       As stipulated in the Trust Agreement, the Trust is intended to be passive
in nature and neither the Delaware Trustee nor the Trustee has any control over
or any responsibility relating to the operation of the Underlying Properties.
The Trustee has powers to collect and distribute proceeds received by the Trust
and pay Trust liabilities and expenses and its actions have been limited to
those activities. Therefore, the Trust has not engaged in any off-balance sheet
arrangements.


TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS.

<Table>
<Caption>
CONTRACTUAL OBLIGATIONS               TOTAL                          PAYMENTS DUE BY PERIOD
-----------------------               -----       -----------------------------------------------------------
                                                  LESS THAN 1                                     MORE THAN 5
                                                     YEAR         1-3 YEARS     3-5 YEARS           YEARS
                                                  -----------     ---------     ---------         -----------
<S>                                   <C>         <C>             <C>           <C>              <C>
Long-Term Debt Obligations              0              0               0              0                0
Capital Lease Obligations               0              0               0              0                0
Operating Lease Obligations             0              0               0              0                0
Purchase Obligations                    0              0               0              0                0
Other Long-Term Liabilities
Reflected on the Trusts Balance
Sheet under GAAP                        0              0               0              0                0
Total                                   0              0               0              0                0
</Table>


FORWARD-LOOKING STATEMENTS

       This Annual Report includes "forward-looking statements" within the
meaning of 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.


                                       36

<PAGE>
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 Trust is a passive entity
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 which 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 which could expose
the Trust or Unitholders to any foreign currency related market risk.



                                       37

<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

INDEPENDENT AUDITORS' REPORT

To Unitholders 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, 2002 and 2001, and the related statements of distributable income
and changes in trust corpus for each of the three years in the period ended
December 31, 2002. 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 auditing standards generally
accepted in the United States of America. 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 statements were
prepared on a modified cash basis of accounting, which is a comprehensive basis
of accounting other than accounting principles generally accepted in the United
States of America.

     In our opinion, such financial statements present fairly, in all material
respects, the assets, liabilities and trust corpus of the Trust at December 31,
2002 and 2001, and the distributable income and changes in trust corpus for each
of the three years in the period ended December 31, 2002, on the basis of
accounting described in Note 2.

DELOITTE & TOUCHE LLP

Dallas, Texas
March 24, 2003


                                       38


<PAGE>
                     DOMINION RESOURCES BLACK WARRIOR TRUST

                              FINANCIAL STATEMENTS


STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

<Table>
<Caption>
                                                                            December 31,
                                                                      -------------------------
                                                                         2002          2001
                                                                      -----------   -----------
<S>                                                                   <C>           <C>
                              ASSETS

Cash and cash equivalents .........................................   $   103,220   $    93,413
Royalty interests in gas properties (less accumulated
    amortization of $105,354,683 and $98,091,654, respectively) ...    50,462,817    57,725,846
                                                                      -----------   -----------
        Total Assets ..............................................   $50,566,037   $57,819,259
                                                                      ===========   ===========
                   LIABILITIES AND TRUST CORPUS

Trust expenses payable ............................................   $   124,348   $   111,820
Trust corpus (7,850,000 units of beneficial interest
    authorized, issued and outstanding) ...........................    50,441,689    57,707,439
                                                                      -----------   -----------
        Total Liabilities and Trust Corpus ........................   $50,566,037   $57,819,259
                                                                      ===========   ===========
</Table>

STATEMENTS OF DISTRIBUTABLE INCOME

<Table>
<Caption>
                                                                 Year Ended December 31,
                                                      --------------------------------------------
                                                          2002            2001            2000
                                                      ------------    ------------    ------------
<S>                                                   <C>             <C>             <C>
Royalty income ....................................   $ 19,418,476    $ 25,937,254    $ 20,874,519
Interest income ...................................         16,022          54,664          80,182
                                                      ------------    ------------    ------------
                                                        19,434,498      25,991,918      20,954,701
General and administrative expenses ...............       (810,557)       (776,431)       (725,420)
                                                      ------------    ------------    ------------
Distributable income ..............................   $ 18,623,941    $ 25,215,487    $ 20,229,281
                                                      ============    ============    ============
Distributable income per unit (7,850,000 units) ...   $       2.37    $       3.21    $       2.58
                                                      ============    ============    ============
Distributions per unit ............................   $       2.37    $       3.21    $       2.58
                                                      ============    ============    ============
</Table>

STATEMENTS OF CHANGES IN TRUST CORPUS

<Table>
<Caption>
                                                    Year Ended December 31,
                                        --------------------------------------------
                                            2002            2001            2000
                                        ------------    ------------    ------------
<S>                                     <C>             <C>             <C>
Trust corpus, beginning of period ...   $ 57,707,439    $ 65,575,056    $ 75,273,180
Amortization of royalty interests ...     (7,263,029)     (7,887,390)     (9,659,716)
Distributable income ................     18,623,941      25,215,487      20,229,281
Distributions to Unitholders ........    (18,626,662)    (25,195,714)    (20,267,689)
                                        ------------    ------------    ------------
Trust corpus, end of period .........   $ 50,441,689    $ 57,707,439    $ 65,575,056
                                        ============    ============    ============
</Table>

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


                                       39

<PAGE>
NOTES TO FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

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 (the "Company"), 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 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, which in turn transferred all the Units to its
parent, Dominion Resources, Inc., 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 were sold to the public through certain of
the Underwriters in June 1995. All of the production attributable to the
Underlying Properties is from the Pottsville coal formation and currently
constitutes coal seam gas that entitles the owners of such production, provided
certain requirements are met, to tax credits pursuant to Section 29 of the
Internal Revenue Code of 1986, as amended (the "Code"), for coal seam gas
produced and sold before 2003 (unless extended by Congress).

       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 (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.


                                       40


<PAGE>
       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.

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:

o      Royalty income and interest income are recorded in the period in which
       amounts are received by the Trust rather than in the month of production
       or when earned.

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

o      Amortization of the Royalty Interests is calculated on a
       unit-of-production basis and charged directly to trust corpus based upon
       when revenue is received.

o      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.

       Dominion Resources sold an aggregate of 6,904,000 Units in the Public
Offering during 1994 at a price of $20.00 per Unit and sold the remaining
946,000 Units to the public during 1995 through certain of the Underwriters at a
price of $18.75 per Unit. Accordingly, the statements of assets, liabilities and
trust corpus reflects 6,940,000 Units at the Public Offering price of $20.00 per
Unit and 946,000 Units at the price of $18.75 per Unit.

       The net amount of royalty interests in gas properties is limited to the
sum of the future net cash flows attributable to the Trust's gas reserves at
year end using current unescalated product prices plus the estimated Section 29
credits for federal income tax purposes (to the extent the Section 29 credit is
available and not expired). 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.

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

       Trust management routinely reviews its royalty interests in oil and gas
properties for impairment whenever events or circumstances indicate that the
carrying amount of an asset may not be recoverable. If an impairment event
occurs and it is determined that the carrying value of the Trust's royalty
interests may not be recoverable, an impairment will be recognized as measured
by the amount by which the carrying amount of the royalty interests exceeds the
fair value of these assets, which would likely be measured by discounting
projected cash flows. Should the aggregate dollar amount of the Trust's reserves
decline, an additional impairment provision, which could be material, will be
required. As discussed in Note 3, coal seam gas produced and sold after December
31, 2002, will no longer generate a Section 29 credit unless applicability of
the Section 29 credit is extended by Congress.


                                       41


<PAGE>
Distributable Income Per Unit

       Basic earnings per share is computed by dividing net income by the
weighted average shares outstanding. Earnings per share assuming dilution is
computed by dividing net income by the weighted average number of shares and
equivalent shares outstanding. The Trust had no equivalent shares outstanding
for any period presented. As a result basic diluted earnings per unit and
distributable income per unit are the same.

New Accounting Pronouncements

       SFAS No. 143, "Accounting for Asset Retirement Obligations" was issued in
June 2001, and will be adopted by the Trust on January 1, 2003. This Statement
addresses financial accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset retirement
costs. The effect of adopting SFAS No. 143 will not have a material impact on
the Trust's financial statements.

       SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment
of FASB Statement No. 13, and Technical Corrections" was issued in April 2002
and is effective for fiscal years beginning after May 15, 2002. This Statement
includes the rescission of FASB Statement No. 4, "Reporting Gains and Losses
from Extinguishment of Debt," and an amendment to FASB Statement No. 13,
"Accounting for Leases," to eliminate an inconsistency between the required
accounting for sale-leaseback transactions and the required accounting for
certain lease modifications that have economic effects that are similar to
sale-leaseback transactions. The effect of adopting SFAS No. 145 will not have a
material impact on the Trust's financial statements.

       SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities" was issued in June 2002 and will be effective for exit or disposal
activities subsequent to December 31, 2002. The Trust anticipates no material
impact on its financial statements from the adoption of this accounting
standard.

       SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure, an amendment of FASB Statement No. 123," was issued in December 2002
and provides new transition methods if an entity adopts the fair value based
method of valuing stock-based compensation suggested in SFAS No. 123 "Accounting
for Stock-Based Compensation," as well as requiring additional disclosures in
interim and annual financial statements. The Trust has no options or other
stock-based instruments and accordingly, the impact of this new Standard is not
expected to be material to the financial statements of the Trust.

       FASB Interpretation ("FIN") No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others," requires disclosures beginning with financial
statements ending after December 15, 2002 and requires liability recognition
beginning January 1, 2003. The Trust had no such guarantees outstanding as of
December 31, 2002.

       FIN No. 46, "Consolidation of Variable Interest Entities" was issued in
January 2003. This interpretation of Accounting Research Bulletin No. 51,
"Consolidated Financial Statements," applies immediately to variable interest
entities created after January 31, 2003 and applies to the first period
beginning after June 15, 2003 to entities acquired before February 1, 2003. This
FIN does not affect the Trust as it has no unconsolidated subsidiaries accounted
for under the equity method of accounting.

3. FEDERAL INCOME TAXES

       The Trust is a grantor trust for Federal income tax purposes. As a
grantor trust, the Trust will not be required to pay Federal or state income
taxes. Accordingly, no provision for income taxes has been made in these
financial statements.

       Because the Trust will be treated as a grantor trust, and because a
Unitholder will be treated as directly owning an interest in the Royalty
Interests, each Unitholder will be 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.


                                       42


<PAGE>
       Production from coal seam gas wells drilled after December 31, 1979 and
prior to January 1, 1993, qualified for the Federal income tax credit for
producing nonconventional fuels under Section 29 of the Code. This tax credit
was calculated annually based on each year's qualified production through the
year 2002. Dominion Resources provides the Trustee with Section 29 tax credit
information related to the Underlying Properties. Coal seam gas produced and
sold after December 31, 2002, will no longer generate a Section 29 credit unless
the applicability of the Section 29 credit is extended by Congress. Legislation
currently is proposed to extend the Section 29 credit retroactively to January
1, 2003. Of course, there can be no assurance that such legislation will be
passed, and if passed, will be effective retroactively to January 1, 2003.

       The Section 29 credit is based on the Unitholder's pro rata share of
qualifying production. It can be used only to the extent that a Unitholder's
regular tax liability exceeds the Unitholder's tentative minimum tax liability
after the regular tax liability has been reduced by the foreign tax credit and
certain nonrefundable personal credits. Any part of the Section 29 credit not
allowed for the tax year solely because of this alternative minimum tax
limitation is subject to certain carryover provisions relating to the
alternative minimum tax calculation. Except for the foregoing, there are no Code
provisions that allow for the carryback or carryforward of Section 29 credits in
any other circumstances. As the carryforward of unused Section 29 credits is
related to the alternative minimum tax calculation for succeeding years,
carryforwards should be allowed even if the Section 29 credit is not extended
after 2002.

       In 1997, the Tax Court upheld the Internal Revenue Service ("IRS")
position that nonconventional fuel such as coal seam gas does not qualify for
the Section 29 credit unless the producer received a formal certification from
the Federal Energy Regulatory Commission ("FERC"). The FERC's certification
authority expired effective January 1, 1993. During March 1999, the U.S. Court
of Appeals for the 10th Circuit affirmed that decision. The appeal (which is not
binding as precedent) suggests that lack of a certification from FERC may render
the Section 29 credit unavailable in respect of production from wells
recompleted in a qualified formation after January 1, 1993, the date that FERC's
certification authority expired (so that obtaining the requisite determination
of any such well was impossible). Many producers believe that wells meeting the
certification requirements are eligible for the Section 29 credits regardless of
FERC certification. However, this position is not in accordance with the IRS
position, the decision of the Tax Court or the decision of the U.S. Court of
Appeals.

       On December 23, 1999, a petition was filed with FERC by a coalition of
energy producers seeking reinstatement of the certification process. FERC issued
a Final Rule on July 14, 2000, amending its regulations to reinstate provisions
for well category determinations under section 503 of the Natural Gas Policy Act
("NGPA") of 1978 for Section 29 tax credits. The Final Rule extended the
provisions to all wells spudded before January 1, 1993, and recompletions both
before and after that date that qualify for the Section 29 tax credit. The Final
Rule also provided for the designation of new tight formations. The Final Rule
became effective on September 25, 2000.

       During 2002, Dominion Resources initiated a review of all recompletion
activity on the Underlying Properties since 1992 and caused applications for
NGPA determinations for 383 wells to be filed with the Alabama Oil and Gas Board
(the "Board") on April 29, 2002. A formal hearing by the Board was held on May
29, 2002. At that hearing, affirmative notices for 75 of the 383 wells were
issued. A second hearing was held on July 10, 2002, which favorably adjudicated
the remaining 308 wells. Applications were timely filed with FERC and barring
timely filed objections, the applications are accepted as final 45 days after
receipt. To the best of Dominion Resource's knowledge, no objections were filed
to these applications. The ability of the Unitholders to utilize Section 29
credits (to the extent the Section 29 credit is available) could be in question
during any time period a well was not certified, although arguments exist for
retroactive application and for allowance of the Section 29 credits without
certification.

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


4. RELATED PARTY TRANSACTIONS

       Dominion Resources provides accounting, bookkeeping and informational
services to the Trust in accordance with an Administrative Services Agreement
dated effective June 1, 1994. During 2002 this fee was $380,031 and will
increase annually by three percent. Aggregate fees paid by the Trust to Dominion
Resources in 2002, 2001 and 2000 were $380,031, $373,552 and $369,813,
respectively.


                                       43


<PAGE>
       Aggregate fees and expense reimbursements paid by the Trust to the
trustees in 2002, 2001, and 2000 were $38,003, $42,355 and $35,821,
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 which is not included in the Quarterly
Distribution Amount for a calendar quarter because such amount is received by
the Trust after the last business day prior to the 45th day following the end of
such calendar quarter will be included in the Quarterly Distribution Amount for
the next calendar quarter. The Quarterly Distribution Amount for each quarter
will be payable to Unitholders of record on the 60th day following the end of
such calendar quarter unless such day is not a business day in which case the
record date is the next business day thereafter. The Trustee will distribute the
Quarterly Distribution Amount for each quarter on or prior to 70 days after the
end of such calendar quarter to each person who was a Unitholder of record on
the record date for such calendar quarter.

       The Royalty Interests may be sold under certain circumstances and will be
sold following termination of the Trust. A special distribution will be made of
undistributed net sales proceeds and other amounts received by the Trust
aggregating in excess of $10 million (a "Special Distribution Amount"). The
record date for a Special Distribution Amount will be the 15th day following the
receipt by the Trust of amounts aggregating a Special Distribution Amount
(unless such day is not a business day, in which case the record date will be
the next business day thereafter) unless such day is within 10 days or less
prior to the record date for a Quarterly Distribution Amount, in which case the
record date for the Special Distribution Amount will be the same as the record
date for the Quarterly Distribution Amount. Distribution to Unitholders of a
Special Distribution Amount will be made no later than 15 days after the Special
Distribution Amount record date.


6. SUBSEQUENT EVENTS

       Subsequent to December 31, 2002, the Trust declared and paid the
following distribution:

<Table>
<Caption>
       QUARTERLY                                               DISTRIBUTION
      RECORD DATE                      PAYMENT DATE              PER UNIT
     -------------                    --------------           ------------
<S>                                   <C>                      <C>
     March 1, 2003                    March 11, 2003            $ .644817
</Table>

       The Trustee has estimated the Section 29 tax credit associated with the
March 11, 2003 quarterly distribution (to the extent the Section 29 credit is
available and not expired) to be $.20 per unit (unaudited).


                                       44

<PAGE>
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, 2002 and 2001 (in thousands, except per Unit amounts):

<Table>
<Caption>
                                  ROYALTY   DISTRIBUTABLE    DISTRIBUTABLE
CALENDAR QUARTER                  INCOME       INCOME       INCOME PER UNIT
----------------                  -------   -------------   ---------------
<S>                               <C>       <C>             <C>
2002
     First ..............         $ 4,659      $ 4,441         $   .58
     Second .............           4,752        4,558             .58
     Third ..............           5,122        4,904             .62
     Fourth .............           4,885        4,721             .59
                                  -------      -------         -------
                                  $19,418      $18,624         $  2.37
                                  =======      =======         =======
2001
     First ..............         $ 5,081      $ 4,850         $   .62
     Second .............           8,805        8,610            1.10
     Third ..............           6,982        6,821             .87
     Fourth .............           5,069        4,934             .62
                                  -------      -------         -------
                                  $25,937      $25,215         $  3.21
                                  =======      =======         =======
</Table>

       Selected 2002 fourth quarter data are as follows (in thousands, except
per Unit amounts):

<Table>
<S>                                                 <C>
Royalty income...............................       $4,885
Interest income..............................            3
General and administrative expenses..........         (167)
                                                    ------
Distributable income.........................       $4,721
                                                    ======
Distributable income per Unit................       $  .59
                                                    ======
Distributions per Unit.......................       $  .59
                                                    ======
</Table>

         Due to significant revisions in estimate of reserve quantities (see
Note 8), estimated amortization of royalty interests was increased by
approximately $0.1 million, decreased by approximately $0.1 million, and
increased by $0.6 million during the fourth quarters of 2002, 2001 and 2000,
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, 2002, 2001, 2000 and January 1, 2000 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, 2002, 2001,
2000 and January 1, 2000 were $4.10, $2.63, $9.80 and $2.16 per Mcf,
respectively, including the effect of the Gas Purchase Agreement (see Note 9).

         Numerous uncertainties are inherent in estimating volumes and value of
proved reserves and in projecting future production rates and timing of
development expenditures. Such reserve estimates are subject to change as
additional information becomes available. The reserves actually recovered and
the timing of production may be substantially different from the original
estimates.


                                       45

<PAGE>
         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.

<Table>
<S>                                                                 <C>
    Proved developed reserves at January 1, 2000..........          69,180
         Revisions of previous estimates..................          (4,371)
         Production.......................................          (8,041)
                                                                    ------
    Proved developed reserves at December 31, 2000........          56,768
         Revisions of previous estimates..................             897
         Production.......................................          (6,701)
                                                                    ------
    Proved developed reserves at December 31, 2001........          50,964
         Revisions of previous estimates..................          (2,422)
         Production.......................................          (5,957)
                                                                    ------
    Proved developed reserves at December 31, 2002........          42,585
                                                                    ======
</Table>

         All proved reserve estimates presented above at December 31, 2002,
2001, 2000 and January 1, 2000 are proved developed.

         Proved developed reserves, all located in the United States, for the
Trust's Interests are estimated quantities of coal seam gas which geological and
engineering data indicate with reasonable certainty to be recoverable in future
years from the coal formation under existing economic and operating conditions.
Proved developed reserves are proved reserves which can be expected to be
recovered through existing wells with existing equipment and operating methods.
Estimated economic quantities were determined considering the Section 29 tax
credits until December 31, 2002. As discussed in Note 3, coal seam gas produced
and sold after December 31, 2002, will no longer generate a Section 29 credit
unless applicability of the Section 29 credit is extended by Congress.

         The following table sets forth the standardized measure of discounted
estimated future net cash flows from proved reserves at December 31, 2002, 2001
and 2000 relating to the Trust's Royalty Interests (thousands of dollars):

<Table>
<Caption>
                                                  2002         2001         2000
                                               ---------    ---------    ---------
<S>                                            <C>          <C>          <C>
Future cash inflows ........................   $ 174,543    $ 141,190    $ 523,243
Future taxes ...............................     (10,473)      (6,712)     (31,395)
                                               ---------    ---------    ---------
Future net cash flows ......................     164,070      134,478      491,848
10% annual discount for estimated timing
      of cash flow .........................     (68,507)     (49,234)    (220,798)
                                               ---------    ---------    ---------
Standardized measure of discounted
      future net cash flows ................   $  95,563    $  85,244    $ 271,050
                                               =========    =========    =========
</Table>

         Future cash flows do not include Section 29 tax credits which expired
December 31, 2002. As discussed in Note 3, coal seam gas produced and sold after
December 31, 2002, will no longer generate a Section 29 credit unless
applicability of the Section 29 credit is extended by Congress.

         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, 2002, 2001 and 2000 (thousands of dollars):

<Table>
<Caption>
                                           2002         2001         2000
                                        ---------    ---------    ---------
<S>                                     <C>          <C>          <C>
Balance at beginning of period ......   $  85,244    $ 271,050    $  82,539
Increase (decrease) due to:
     Royalty income, net of taxes ...     (19,988)     (25,515)     (21,470)
     Changes in prices ..............      48,600     (260,906)     207,402
     Changes in estimated volumes ...     (26,817)      73,510       (5,675)
     Accretion of discount ..........       8,524       27,105        8,254
                                        ---------    ---------    ---------
Balance at December 31 ..............   $  95,563    $  85,244    $ 271,050
                                        =========    =========    =========
</Table>


                                       46

<PAGE>
9. GAS PURCHASE AGREEMENT

       El Paso Merchant Energy-Gas, L.P. ("El Paso") , as successor to Sonat
Marketing Company ("Sonat Marketing") is required under a gas purchase agreement
to purchase the gas produced from the Underlying Properties for as long as
reserves on the Underlying Properties produce natural gas. Under the agreement,
Sonat Marketing was, in past years, obligated to purchase up to a specified
monthly base quantity (the "Index Price Quantity") of gas for a contract price
equal to the Index Price plus a specified premium (between $.05 and $.07 per
MMBtu) over the Index Price. Until December 31, 1998, the Contract Price paid
was subject to a minimum price of $1.85 per MMBtu and a maximum price of $2.63
per MMBtu. Beginning effective January 1, 1999, the Contract Price paid was
subject to a minimum price of $2.16 per MMBtu and a maximum price of $3.07 per
MMBtu. Beginning effective January 1, 2000 through December 31, 2000 the price
paid on Index Price Quantities was subject to a minimum price of $2.20 and a
maximum price of $2.82. Beginning effective January 1, 2001 through December 31,
2001, the Contract Price paid was subject to a minimum price of $3.00 per MMBtu
and a maximum price of $5.30 per MMBtu. Beginning effective January 1, 2002
through December 31, 2002, the Contract Price paid was subject to a minimum
price of $3.80 per MMBtu and a maximum price of $5.30 per MMBtu. Prior to April
1, 1996, Sonat Marketing was obligated to purchase gas production in excess of
the specified monthly base quantities at the Index Price. Effective April 1,
1996 through December 31, 2001, the price paid for such gas production in excess
of the specified monthly basis quantities was the Index Price plus $.02. The
"Index Price," which is determined on a monthly basis, is Southern Natural Gas
Company's posted index price for deliveries of gas in Louisiana. The Company has
advised the Trust that at the end of the primary term or any extensions thereof,
El Paso will be obligated to purchase the Subject Gas at the Index Price until
such time as the Company and El Paso negotiate a different price, and that the
Company will have the ability to obtain an offer to purchase the Subject Gas
from another purchaser and terminate the Gas Purchase Agreement if El Paso does
not match such offer.


                                       47


<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE.

       None.


                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

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

       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 ten 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.


ITEM 11. EXECUTIVE COMPENSATION.

       The following is a description of certain fees and expenses anticipated
to be paid or borne by the Trust, including fees expected to be paid to Dominion
Resources, the Trustee, the Delaware Trustee, 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
$38,003, plus an hourly charge for services in excess of a combined total of 350
hours annually at its standard rate which is currently $120 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 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
2002, the Trustee and the Delaware Trustee received total compensation of
$38,003 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 Dominion Resources. Dominion Resources 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 Item 13 under "Administrative Services
Agreement."


                                       48

<PAGE>
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, 2003, neither Bank of America, N.A., the Trustee, nor
Mellon Bank (DE) National Association, the Delaware Trustee, beneficially owned
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.


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. The annual fee, payable in equal quarterly installments, is
currently $380,030 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 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.

DOMINION RESOURCES'S CONDITIONAL RIGHT OF REPURCHASE

       Dominion Resources retains in the Trust Agreement 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 is owned by persons or entities other than
Dominion Resources and its affiliates. Any such repurchase would generally 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 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 the Trust--Conditional
Right of Repurchase."

POTENTIAL CONFLICTS OF INTEREST

       The interests of Dominion Resources 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. 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 (to the
extent the Section 29 credit is available and not expired).


                                       49


<PAGE>
       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 Dominion Resources'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.

       Dominion Resources may profit from contracts with the Trust. The amount
that Dominion Resources 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 actual cost of rendering such services
by Dominion Resources. Accordingly, Dominion Resources may profit or suffer
losses in connection with the performance of such contract.


ITEM 14. CONTROLS AND PROCEDURES.

       Within the 90 days prior to the date of 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 Rule 13a-14.
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. No significant
changes in the Trust's internal controls or other factors that could affect
these controls have occurred subsequent to the date of such evaluation.


                                    PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.

       (a) The following documents are filed as a part of this report:

       1. Financial Statements (included in Item 8 of this report)

          Independent Auditors' Report

          Statements of Assets, Liabilities and Trust Corpus as of December 31,
          2002 and 2001

          Statements of Distributable Income for the years ended December 31,
          2002, 2001 and 2000

          Statements of Changes in Trust Corpus for the years ended December 31,
          2002, 2001 and 2000

          Notes to Financial Statements

       2. Financial Statement Schedules

       Financial statement schedules are omitted because of the absence of
       conditions under which they are required or because the required
       information is included in the financial statements and notes thereto.

       3. Exhibits

<Table>
<Caption>
EXHIBIT
NUMBER                                 EXHIBIT
-------                                -------
<S>      <C>   <C>
  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).
</Table>


                                       50

<PAGE>
<Table>
<S>      <C>   <C>
  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).

 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).

 23.1    --    Consent of Ralph E. Davis Associates, Inc., independent petroleum
               engineers.

 99.1    --    The information under the sections captioned "Federal Income
               Tax Consequences," "Risk Factors - Tax Considerations," 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.
</Table>


                                       51


<PAGE>
<Table>
<S>      <C>   <C>
 99.2    --    Summary of Reserve Report, dated February 14, 2003, on the
               estimated reserves, estimated future net revenues and the
               discounted estimated future net revenues attributable to the
               Royalty Interests as of January 1, 2003, prepared by Ralph E.
               Davis & Associates Petroleum Engineers, independent petroleum
               engineers.

 99.3    --    Certification by Bank of America, N.A., Trustee of the
               Registrant, furnished pursuant to Section 906 of the
               Sarbanes-Oxley Act of 2002.
</Table>

----------

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

       (b) Reports on Form 8-K. No report on Form 8-K was filed by the
Registrant during the last quarter of the period covered by this report.


                                       52


<PAGE>
                                   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 25, 2003


            (THE REGISTRANT HAS NO DIRECTORS OR EXECUTIVE OFFICERS.)


                                       53

<PAGE>
                                 CERTIFICATIONS


         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-14 and 15d-14), or for causing such procedures to be
                  established and maintained, for the registrant and I have:

                  a)       designed such disclosure controls and procedures, or
                           caused such controls and procedures to be designed,
                           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)       evaluated the effectiveness of the registrant's
                           disclosure controls and procedures as of a date
                           within 90 days prior to the filing date of this
                           annual report (the "Evaluation Date"); and

                  c)       presented in this annual report my conclusions about
                           the effectiveness of the disclosure controls and
                           procedures based on my evaluation as of the
                           Evaluation Date;

         5.       I have disclosed, based on my most recent evaluation, to the
                  registrant's auditors:

                  a)       all significant deficiencies in the design or
                           operation of internal controls which could adversely
                           affect the registrant's ability to record, process,
                           summarize and report financial data and have
                           identified for the registrant's auditors any material
                           weaknesses in internal controls; and

                  b)       any fraud, whether or not material, that involves
                           persons who have a significant role in the
                           registrant's internal controls; and

         6.       I have indicated in this annual report whether or not there
                  were significant changes in internal controls or in other
                  factors that could significantly affect internal controls
                  subsequent to the date of my most recent evaluation, including
                  any corrective actions with regard to significant deficiencies
                  and material weaknesses.

                  In giving the certifications in paragraphs 4, 5 and 6 above, I
                  have relied to the extent I consider reasonable on information
                  provided to me by Dominion Black Warrior Basin, Inc.



Date: March 25, 2003                 By: /s/ RON E. HOOPER
                                         ---------------------------------------
                                         Ron E. Hooper
                                         Senior Vice President and Administrator
                                         Bank of America, N.A.


<PAGE>
                                Index to Exhibits


<Table>
<Caption>
EXHIBIT
NUMBER                                     EXHIBIT
-------                                    -------
<S>    <C>     <C>
  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).

 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).
</Table>


<PAGE>
<Table>
<S>    <C>     <C>
 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).

 23.1  --      Consent of Ralph E. Davis Associates, Inc., independent petroleum
               engineers.

 99.1  --      The information under the sections captioned "Federal Income
               Tax Consequences," "Risk Factors - Tax Considerations," 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 14, 2003, on the
               estimated reserves, estimated future net revenues and the
               discounted estimated future net revenues attributable to the
               Royalty Interests as of January 1, 2003, prepared by Ralph E.
               Davis & Associates Petroleum Engineers, independent petroleum
               engineers.

 99.3  --      Certification by Bank of America, N.A., Trustee of the
               Registrant, furnished pursuant to Section 906 of the
               Sarbanes-Oxley Act of 2002.
</Table>

----------

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