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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
  
 FORM 10-K (Mark One)  þ
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2004 OR  o
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934   Commission file
number: 001-11335
 Dominion Resources Black Warrior Trust
  Delaware
(State or other jurisdiction of
incorporation or organization)
    
    75-6461716
(I.R.S. employer
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 onTitle of Each Class
    
    Which RegisteredUnits 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 þ No o Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of the registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. þ Indicate by a check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2
of the Act). Yes þ No o 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 $238,912,314. At March 1, 2005, there were 7,850,000 units of beneficial interest outstanding. DOCUMENTS INCORPORATED BY REFERENCENone.




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TABLE OF CONTENTS PagePART I
    
    
    4Item 1.Business
    
    
    4GLOSSARY
    
    
    4DESCRIPTION OF THE TRUST
    
    
    8Creation and Organization of the Trust
    
    
    8Assets of the Trust
    
    
    8Duties and Limited Powers of the Trustee and the Delaware Trustee
    
    
    8Resignation of Trustees
    
    
    9Transfer of Royalty Interests
    
    
    10Liabilities of the Trust
    
    
    10Liabilities of the Trustee and the Delaware Trustee
    
    
    10Termination and Liquidation of the Trust
    
    
    10Arbitration and Actions by Unitholders
    
    
    12DESCRIPTION OF UNITS
    
    
    13Distributions and Income Computations
    
    
    13Conditional Right of Repurchase
    
    
    14Possible Divestiture of Units
    
    
    15Periodic Reports
    
    
    16Voting Rights of Unitholders
    
    
    16Liability of Unitholders
    
    
    18Transfer Agent
    
    
    18Website/SEC Filings
    
    
    18FEDERAL INCOME TAX CONSIDERATIONS
    
    
    18Summary of Certain Federal Income Tax Consequences
    
    
    19ERISA CONSIDERATIONS
    
    
    21STATE TAX CONSIDERATIONS
    
    
    22Alabama Income Tax
    
    
    22Alabama Business Privilege Tax
    
    
    23Alabama Severance Taxes
    
    
    24Other Alabama Taxes
    
    
    24REGULATION AND PRICES
    
    
    24Regulation of Natural Gas
    
    
    24Environmental Regulation
    
    
    25Competition, Markets and Prices
    
    
    26Item 2.Properties
    
    
    27THE ROYALTY INTERESTS
    
    
    27The Underlying Properties
    
    
    27The Royalty Interests
    
    
    29Reserve Estimate
    
    
    30Natural Gas Sales Prices and Production
    
    
    32Gas Purchase Agreement
    
    
    32Operation of Properties
    
    
    34Sale and Abandonment of Underlying Properties
    
    
    34Dominion Resources Assurances
    
    
    35Title to Properties
    
    
    35Item 3.Legal Proceedings
    
    
    36Item 4.Submission of Matters to a Vote of Security Holders
    
    
    36
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PagePART II
    
    
    37Item 5.Market for Registrants Common Equity Related Stockholder
Matters and Issuer Purchases of Equity Securities
    
    
    37Item 6. Selected Financial Data
    
    
    37Item 7. Trustees Discussion and Analysis of Financial Condition and Results
of Operations
    
    
    38Critical Accounting Policies and Estimates
    
    
    40Liquidity and Capital Resources
    
    
    42Off-Balance Sheet Arrangements
    
    
    42Tabular Disclosure of Contractual Obligations
    
    
    43Forward-Looking Statements
    
    
    43Item 7A. Quantitative and Qualitative Disclosures About Market Risk
    
    
    43Item 8. Financial Statements and Supplementary Data
    
    
    44REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
    
    
    44Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
    
    
    53Item 9A. Controls and Procedures
    
    
    53Disclosure Controls and Procedures
    
    
    53Trustees Report on Internal Control Over Financial Reporting
    
    
    53Item 9B. Other Information
    
    
    55PART III
    
    
    55Item 10. Directors and Executive Officers of the Registrant
    
    
    55Item 11. Executive Compensation
    
    
    56Item 12. Security Ownership of Certain Beneficial Owners and Management
    
    
    57Item 13. Certain Relationships and Related Transactions
    
    
    57Dominion Resources Conditional Right of Repurchase
    
    
    57Potential Conflicts of Interest
    
    
    57Item 14. Principal Accounting Fees and Services
    
    
    58PART IV
    
    
    58Item 15. Exhibits, Financial Statement Schedules
    
    
    58Financial Statements
    
    
    58Financial Statement Schedules
    
    
    59Exhibits
    
    
    59Consent of Ralph E. Davis Associates, Inc.Certification Required by Rule 13a-14(a)/15d-14(a)Certification Required by Rule 13a-14(b)/15d-14(b)Summary of Reserve Report
  3




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PART I. 
 Item 1. Business. 
 GLOSSARY The following is a glossary of certain defined terms used in this Annual Report on Form 10-K. Administrative Services Agreement means the Administrative Services Agreement dated as of
June 28, 1994, between Dominion Resources and the Trust, a copy of which is filed as an exhibit to
this Form 10-K. 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. ConocoPhillips means ConocoPhillips Corporation, successor to The River Gas Corporation. 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 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 was divided into two categories, a
Fixed 4




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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 Price Quantity was $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 was 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. Effective
January 1, 2004, the pricing formula for the Index Price Quantity described in the immediately
preceding sentence applied 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 was the sum of the Index Price and $.02 per MMBtu, multiplied by 0.9826, the wet/dry
conversion factor. Effective January 31, 2004, the Gas Purchase Agreement was terminated. For the
period of February 1, 2004 through October 30, 2004, the gas was sold on a month to month basis to
various purchasers. Contracts were secured from two purchasers, ConocoPhillips and Coral Energy
Resources, L.P., for the base load gas at Index Price plus $0.02125 per MMBtu for the period of
November 1, 2004 through May 31, 2005. Any gas above the base load was sold on the spot market to
various purchasers. The basis for gas sales after March 31, 2005 will be determined subsequent to
the filing of this Annual Report on Form 10-K but will be reported in future filings. 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. Grantor trust means a trust as to which the grantor is treated as the owner of the trust
income and corpus under the Code. 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. 5




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Index Price means the price published by Inside FERC Gas Market Reportin 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. MMcf means million cubic feet of natural gas. As used herein, 1 MMcf is assumed to have a
Btu content of 1008 MMBtu. MMBtu means million Btu. As used herein, 992 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. 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. Prospectus means the prospectus dated June 21, 1994, as supplemented by the final prospectus
supplement dated June 1, 1995, relating to the offer and sale of the Units, and forming a part of
Dominion Resources Registration Statement on Form S-3 (No. 33-53513). Ralph E. Davis & Associates means Ralph E. Davis & Associates, independent petroleum
engineers. Reserve Estimate means the estimated net proved reserves, estimated future net revenues and
the discounted estimated future net revenues attributable to the Royalty Interests as of January 1,
2005, 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 were generated
upon the sale of such production prior to January 1, 2003. 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. 6




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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. 7




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DESCRIPTION OF THE TRUST Dominion Resources Black Warrior Trust is a Delaware business trust formed under the Delaware
Business Trust Act, Title 12, Chapter 38 of the Delaware Code, Section 3801 et seq. (the Delaware
Code). The following information is subject to the detailed provisions of the Trust Agreement and
the Conveyance, copies of which are filed as exhibits to this Form 10-K. The provisions governing
the Trust are complex and extensive, and no attempt has been made below to describe or reference
all of such provisions. The following is a general description of the basic framework of the Trust
and the material provisions of the Trust Agreement. 
 Creation and Organization of the Trust The Trust was initially created by the filing of its Certificate of Trust with the Delaware
Secretary of State on May 31, 1994. In accordance with the Trust Agreement, the Company
contributed $1,000 as the initial corpus of the Trust. On June 28, 1994, the Royalty Interests
were conveyed to the Trust by the Company pursuant to the Conveyance, in consideration for the
issuance to the Company of all 7,850,000 of the authorized Units in the Trust. The Company
transferred all the Units to its parent, Dominion Energy, Inc., a Virginia corporation (Dominion
Energy), which in turn transferred all the Units to its parent, Dominion Resources. Dominion
Resources sold an aggregate of 6,904,000 Units to the public through various underwriters (the
Underwriters) in June and August 1994 in the initial public offering of the Units (the Initial
Public Offering) and sold the remaining 946,000 Units to the public through certain of the
Underwriters in June 1995 pursuant to Post-Effective Amendment No. 1 to the Form S-3 Registration
Statement relating to the Units (the Secondary Public Offering and, collectively with the Initial
Public Offering, the Public Offerings). 
 Assets of the Trust The only assets of the Trust, other than cash and temporary investments being held for the
payment of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests.
The Royalty Interests consist of overriding royalty interests burdening the Companys interest in
the Underlying Properties. The Royalty Interests generally entitle the Trust to receive 65 percent
of the Companys Gross Proceeds. The Royalty Interests are non-operating interests and bear only
expenses related to property, production and related taxes (including severance taxes). See
PropertiesThe Royalty Interests. 
 Duties and Limited Powers of the Trustee and the Delaware Trustee Under the Trust Agreement, the Trustee has all powers to collect the payments attributable to
the Royalty Interests and to pay all expenses, liabilities and obligations of the Trust. The
Trustee has the discretion to establish a cash reserve for the payment of any liability 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 8




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such loan. The terms of such indebtedness and security interest, if funds were loaned by the
Trustee, must be similar to the terms that the Trustee would grant to a similarly-situated
commercial customer with whom it did not have a fiduciary relationship, and the Trustee shall be
entitled to enforce its rights with respect to any such indebtedness and security interest as if it
were not then serving as Trustee. The Delaware Trustee has only such powers as are set forth in the Trust Agreement or are
required by law and is not empowered to take part in the management of the Trust. The Royalty Interests are passive in nature and neither the Trustee nor the Delaware Trustee
has any control over or any responsibility relating to the operation of the Underlying Properties.
The Company does not have any contractual commitment to the Trust to develop further the Underlying
Properties or to maintain its ownership interest in any of the Underlying Properties. The Company
may sell the Company Interests subject to and burdened by the Royalty Interests and, absent certain
conditions having been met, with the continuing benefit of Dominion Resources 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 the treatment of the Trust as an association taxable as a corporation
for federal income tax purposes and such modifications or settlements do not alter the nature of
the Royalty Interests as a right to receive a share of production or the proceeds of production
from the Underlying Properties, which, with respect to the Trust, are free of any operating rights,
expenses or obligations. The Trust Agreement provides that cash being held by the Trustee as a
reserve for liabilities or for distribution at the next distribution date will be placed in demand
deposit accounts, U.S. government obligations, repurchase agreements secured by such obligations or
certificates of deposit, but the Trustee is otherwise prohibited from acquiring any asset other
than the Royalty Interests and cash proceeds therefrom or engaging in any business or investment
activity of any kind whatsoever. The Trustee may deposit funds awaiting distribution in an account
with the Trustee provided the interest rate paid equals the interest rate paid by the Trustee on
similar deposits. 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. 9




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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. 
 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 for federal income tax purposes, then the Trust would incur
substantial federal income tax liabilities. See Federal Income Tax Consequences. 
 Liabilities of the Trustee and the Delaware Trustee Each of the Trustee and the Delaware Trustee may act in its discretion and is personally or
individually liable only for fraud or acts or omissions in bad faith or that constitute gross
negligence (and for taxes, fees and other charges on, based on or measured by any fees, commissions
or compensation received pursuant to the Trust Agreement) and will not be otherwise liable for any
act or omission of any agent or employee unless such Trustee has acted in bad faith or with gross
negligence in the selection and retention of such agent or employee. Each of the Trustee and the
Delaware Trustee (and their respective agents) is indemnified by 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 that does not constitute gross negligence), and will have a first
lien upon the assets of the Trust as security for such indemnification and for reimbursements and
compensation to which it is entitled; provided that the Trustee and the Delaware Trustee are
generally required to first be indemnified from the Trust assets before seeking indemnification
from Dominion Resources. Dominion Resources also has agreed to indemnify the Trustee and the
Delaware Trustee against liabilities under certain securities laws. Neither the Trustee nor the
Delaware Trustee is entitled to indemnification from Unitholders (except in connection with lost or
destroyed Unit certificates). Insofar as indemnification for liabilities arising under the
Securities Act of 1933, as amended (the Securities Act), is permitted to the Trustee pursuant to
the foregoing provisions, the Trustee has been informed that in the opinion of the Securities and
Exchange Commission (the Commission), such indemnification is against public policy as expressed
in the Securities Act and is, therefore, unenforceable. 
 Termination and Liquidation of the Trust The Trust will terminate upon the occurrence of: (i) an affirmative vote of the holders of not
less than 66 percent of the outstanding Units to terminate the Trust; (ii) such time as the ratio
of the cash amounts received by the Trust attributable to the Royalty Interests in any calendar
quarter to administrative costs of the Trust for such calendar quarter is less than 1.2 to 1.0 for 10




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two consecutive calendar quarters; or (iii) March 1 of any year if it is determined, based on
a reserve report as of December 31 of the prior year prepared by a firm of independent petroleum
engineers mutually selected by the Trustee and the Company, that the net present value (discounted
at 10 percent) of estimated future net revenues from proved reserves attributable to the Royalty
Interests is equal to or less than $5 million (as applicable, the Termination Date). Upon such
occurrence causing the Trust to terminate, the remaining assets of the Trust will be sold, the net
proceeds of the sale will be distributed to Unitholders and the Trust will be wound up and a
certificate of cancellation filed. Upon the termination of the Trust, the Trustee will use its best efforts to sell any remaining
Royalty Interests then owned by the Trust for cash pursuant to the procedures described in the
Trust Agreement. The Trustee will retain a nationally recognized investment banking firm (the
Advisor) on behalf of the Trust who will assist the Trustee in selling the remaining Royalty
Interests. The Company has the right, but not the obligation, within 60 days following the
Termination Date, to make a cash offer to purchase all of the remaining Royalty Interests then held
by the Trust. In the event such an offer is made by the Company, the Trustee will decide, based on
the recommendation of the Advisor, to either (i) accept such offer (in which case no sale to the
Company will be made unless a fairness opinion is given by the Advisor that the purchase price is
fair to Unitholders) or (ii) defer action on the offer for approximately 60 days and seek to locate
other buyers for the remaining Royalty Interests. If the Trustee defers action on the Companys
offer, the offer will be deemed withdrawn and the Trustee will then use its best efforts, assisted
by the Advisor, to locate other buyers for the Royalty Interests. At the end of the 120-day period
following the Termination Date, the Trustee is required to notify the Company of the highest of any
other offers acceptable to the Trustee (which must be an all-cash offer) received during such
period (such price, net of any commissions or other fees payable by the Trust, the Highest
Acceptable Offer). The Company then has the right (whether or not it made an initial offer), but
not the obligation, to purchase all remaining Royalty Interests for a cash purchase price computed
as follows: (i) if the Highest Acceptable Offer is more than 105 percent of the Companys original
offer (or if the Company did not make an initial offer), the purchase price will be 105 percent of
the Highest Acceptable Offer, or (ii) if the Highest Acceptable Offer is equal to or less than 105
percent of the Companys original offer, the purchase price will be equal to the Highest Acceptable
Offer. If no other acceptable offers are received for all remaining Royalty Interests, the Trustee
may request the Company to submit another offer for consideration by the Trustee and may accept or
reject such offer. 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. 11




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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 likely to succeed. The procedures for the arbitration of disputes enumerated in the
Trust Agreement neither bar nor restrict the statutory right of any Unitholder under Section 3816
of the Delaware Code to bring a derivative action. Pursuant to Section 3816 of the Delaware Code, a plaintiff in a derivative action must be a
beneficial owner at the time such action is brought and (i) at the time of the transaction subject
to such complaint or (ii) the Unitholders status as a beneficial owner must have devolved upon it
by operation of law or pursuant to the terms of the governing instrument of the Trust from a person
or entity who was a beneficial owner at the time of the transaction giving rise to the complaint.
If a derivative action is successful, in whole or in part, or if anything is received by the Trust
as a result of a judgment, compromise or settlement of any such action, the Delaware Chancery Court
may award the plaintiff reasonable expenses, including reasonable attorneys fees. If any award is
so received by the plaintiff, the Delaware Chancery Court will make such award of the plaintiffs
expenses payable out of those proceeds and direct the plaintiff to remit to the Trust the remainder
thereof. If the proceeds are insufficient to reimburse the plaintiffs reasonable expenses in
bringing the derivative action, the Delaware Chancery Court may direct that any such award of the
plaintiffs expenses or a portion thereof be paid by the Trust. The rights of Unitholders to bring
a derivative action on behalf of the Trust provided pursuant to the 12




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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 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 Assurances. 
 DESCRIPTION OF UNITS Each Unit represents an equal undivided share of beneficial interest in the Trust and is
evidenced by a transferable certificate issued by the Trustee. Each Unit entitles its holder to
the same rights as the holder of any other Unit, and the Trust has no other authorized or
outstanding class of equity security. At March 1, 2005, there were 7,850,000 Units outstanding.
The Trust may not issue additional Units. 
 Distributions and Income Computations The Trustee determines for each calendar quarter the amount of cash available for distribution
to Unitholders. Such amount (the Quarterly Distribution Amount) is equal to the excess, if any,
of the cash received by the Trust attributable to production from the Royalty Interests during such
calendar quarter, provided that such cash is received by the Trust on or before the last business
day prior to the 45th day following the end of such calendar quarter, plus the amount of interest
expected by the Trustee to be earned on such cash proceeds during the period between the date of
receipt by the Trust of such cash proceeds and the date of payment to the Unitholders of such
Quarterly Distribution Amount, plus all other cash receipts of the Trust during such calendar
quarter (to the extent not distributed or held for future distribution as a Special Distribution
Amount (as defined herein) or included in the previous Quarterly Distribution Amount) (which might
include sales proceeds not sufficient in amount to qualify for a special distribution, as described
in the next paragraph, and interest), over the liabilities of the Trust paid during such calendar
quarter and not taken into account in determining a prior Quarterly Distribution Amount, subject to
adjustments for changes made by the Trustee during such calendar quarter in any cash reserves
established for the payment of contingent or future obligations of the Trust. An amount that is
not included in the Quarterly Distribution Amount for a calendar quarter because such amount is
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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. 
 Conditional Right of Repurchase Dominion Resources (and any of its successors and affiliates) has the right to repurchase all
(but not less than all) outstanding Units at any time at which 15 percent or less of the
outstanding Units are owned by persons or entities other than Dominion Resources and its
affiliates. Subject to the following sentence, any such repurchase would be at a price equal to
the greater of (i) the highest price at which Dominion Resources or any of its affiliates acquired
Units during the 90 days immediately preceding the date (the Determination Date) that is three
New York Stock Exchange (NYSE) trading days prior to the date on which notice of such exercise is
delivered to the Unitholders and (ii) the average closing price of Units on the NYSE for the 30
trading days immediately preceding the Determination Date. If Dominion Resources or any of its
affiliates acquires Units (other than an acquisition from Dominion Resources or any affiliate)
during the period that is 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 14




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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 two years from the repurchase date
shall revert to the general funds of Dominion Resources. After such reversion, the holders of such
Units so noticed for repurchase could look only to the general funds of Dominion Resources for the
payment of the purchase price. Any interest accrued on funds so deposited would be paid to
Dominion Resources from time to time as requested by Dominion Resources. If Dominion Resources exercises and consummates its right of repurchase, then, at its option,
it may cause the Trust to be terminated by providing written notice thereof to the Trustee and the
Delaware Trustee. Within 30 days following written notice of Dominion Resources decision to
terminate the Trust, the Trustee must cause any remaining Royalty Interests (and, subject to the
rights of Unitholders with respect to the receipt of distributions for which a record date has been
determined, all proceeds of production attributable to the Royalty Interests) and any other assets
of the Trust to be conveyed to Dominion Resources or its assignee (subject to the right of such
trustees to create reasonable reserves in connection with the liquidation of the Trust). 
 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 15




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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 showing in reasonable detail the assets, liabilities,
receipts and disbursements of the Trust for such calendar quarter. Within 120 days following the
end of each fiscal year, the Trustee mails to Unitholders of record as of a date to be selected by
the Trustee an annual report containing audited financial statements, including reserve information
relating to the Trust and the Royalty Interests. The Trustee files such returns for federal income tax purposes as it is advised are required
to comply with applicable law. The Trustee mails to each person or entity who was a Unitholder of
record (i) on the record date for each such calendar quarter and (ii) on a Special Distribution
Amount record date occurring during such quarter, if any, a report that shows in reasonable detail
information to permit each Unitholder to make all calculations reasonably necessary for tax
purposes. The Trustee treats all income, credits and deductions recognized during each calendar
quarter during the term of the Trust as having been recognized by holders of record on the
quarterly record date established for the distribution unless otherwise advised by counsel.
Available year-end tax information permitting each Unitholder to make all calculations reasonably
necessary for tax purposes is distributed by the Trustee to Unitholders no later than March 15 of
the following year. Each Unitholder and his duly authorized agents and attorneys have the right during reasonable
business hours, and upon reasonable prior notice, to examine and inspect records of the Trust and
the Trustee and the Delaware Trustee. 
 Voting Rights of Unitholders While Unitholders have certain voting rights as provided in the Trust Agreement, such rights
differ from and are more limited than those of stockholders of a corporation for profit. For
example, there is no requirement for annual meetings of Unitholders or for annual or other periodic
reelection of the Trustee. Meetings of Unitholders may be called by the Trustee or by Unitholders owning not less than 10
percent of the outstanding Units. In addition, the Delaware Trustee may call such a meeting but
only for the purpose of appointing a successor to it upon its resignation. All 16




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meetings of Unitholders will be held in Dallas, Texas. Written notice of every such meeting
setting forth the time and place of the meeting and the matters proposed to be acted upon will be
given not more than 60 days nor less than 20 days before such meeting is to be held to all of the
Unitholders of record at the close of business on a record date selected by the Trustee, which
record date will not be more than 60 days before the date of such meeting. The presence in person
or by proxy of Unitholders representing a majority of the outstanding Units is necessary to
constitute a quorum. Each Unitholder is entitled to one vote for each Unit owned by such
Unitholder. The Trustee will call such meetings to consider amendments, waivers, consents and
other changes relating to the Conveyance, if requested in writing by the Company or Dominion
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 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 Unitholders, from
time to time supplement or amend the Trust Agreement in order to cure any ambiguity or to correct
or supplement any defective or inconsistent provisions, provided such supplement or amendment is
not adverse to the interests of Unitholders. In addition, (i) Dominion Resources may direct the
Trustee to change the name of the Trust without approval of Unitholders and (ii) in the event that
a business purpose of the Trust is found or deemed to exist by any taxing or other authority on
which finding any taxation authority might rely, the Trustee is authorized to amend or delete and,
subject to the receipt of an opinion of counsel reasonably satisfactory to the Trustee, the
Trustee, the Delaware Trustee, 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 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. 17




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Liability of Unitholders Consistent with Delaware law, the Trust Agreement provides that Unitholders will have the same
limitation on liability as is accorded under Delaware law to stockholders of a corporation for
profit. No assurance can be given, however, that the courts in jurisdictions outside of Delaware
will give effect to such limitation. 
 Transfer Agent Mellon Investor Services, L.L.C. (as successor to Chemical Shareholder Services Group, Inc.)
serves as transfer agent and registrar for the Units. 
 Website/SEC Filings The Trust maintains an Internet Website at www.dom-dominionblackwarriortrust.com, and will
provide website access to its annual reports on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K and amendments to such reports as soon as reasonably practicable after such
material is filed with or furnished to the SEC. 
 FEDERAL INCOME TAX CONSIDERATIONS THE TAX CONSEQUENCES TO A UNITHOLDER OF THE OWNERSHIP AND SALE OF UNITS WILL DEPEND IN PART ON
THE UNITHOLDERS TAX CIRCUMSTANCES. EACH UNITHOLDER SHOULD THEREFORE CONSULT THE UNITHOLDERS TAX
ADVISOR ABOUT THE FEDERAL, STATE AND LOCAL TAX CONSEQUENCES TO THE UNITHOLDER OF THE OWNERSHIP OF
UNITS. The 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 Internal Revenue Service
(IRS). In addition, such opinions were based on various representations as to factual matters
made by the Company and Dominion Resources in connection with the Public Offerings. In addition,
such opinions were expressly limited in their 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. 18




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Neither the Trustee, the Delaware Trustee, nor counsel to the Trustee, respectively, has
rendered any opinions with respect to any tax matters associated with the Trust or the Units. At the time of the Public Offerings, no ruling was requested by Dominion Resources, as the
sponsor of the Trust, the Trustee or the Delaware Trustee from the IRS with respect to any matter
affecting the Trust or Unitholders. No assurance can be provided that the opinions of Special
Counsel (which do not bind the IRS) will not be challenged by the IRS or will be sustained by a
court if so challenged. 
 Summary of Certain Federal Income Tax Consequences The following summary of certain federal income tax consequences of acquiring, owning and
disposing of Units is based on the opinions of Special Counsel to Dominion Resources on federal
income tax matters, which are set forth in the Prospectus, and is qualified in its entirety by
express reference to the sections of the Prospectus identified in the first paragraph of this
Federal Income Tax Considerations section. Although the Trustee believes that the following
summary contains a description of all of the material matters discussed in the opinions referenced
above, the summary is not exhaustive and many other provisions of the federal tax laws may affect
individual Unitholders. Furthermore, the summary does not purport to be complete or address the
tax issues potentially affecting Unitholders acquiring Units other than by purchase through either
of the Public Offerings. Each Unitholder should consult the Unitholders tax advisor with respect
to the effects of the Unitholders ownership of Units on the Unitholders personal tax situation. Coal seam gas produced and sold after December 31, 2002 no longer generates Section 29 tax
credits under the Code. Therefore, Unitholders are not entitled to claim Section 29 tax credits
for coal seam gas produced and sold after 2002. However, a Unitholder may benefit from unused
Section 29 tax credits for alternative minimum tax purposes as discussed below. All discussion of
Section 29 tax credits are applicable only to credits attributable to coal seam gas produced and
sold on or before December 31, 2002. Classification and Taxation of the
Trust
    
    The Trust is a grantor trust for
federal tax purposes and not an
association taxable as a
corporation. As a grantor
trust, the Trust is not subject
to federal income tax. There
can be no assurance that the IRS
will not challenge this
treatment. The tax treatment of
the Trust and Unitholders would
be materially different if the
IRS were to successfully
challenge this treatment.Taxation of Unitholders
    
    Each Unitholder is taxed
directly on his proportionate
share of income, deductions and
credits of the Trust
attributable to the Royalty
Interests consistent with each
such Unitholders taxable year
and method of accounting and
without regard to the taxable
year or method of accounting
employed by the Trust.
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Income and Deductions
    
    The income of the Trust consists
primarily of a specified share
of the proceeds from the sale of
coal seam gas produced from the
Underlying Properties. During
2004, the Trust earned interest
income on funds held for
distribution and made
adjustments to the cash reserve
maintained for the payment of
contingent and future
obligations of the Trust. The
deductions of the Trust consist
of severance taxes and
administrative expenses. In
addition, each Unitholder is
entitled to depletion
deductions. See Unitholders
Depletion Allowance below.Individuals may deduct
miscellaneous itemized
deductions (including, in
general, investment expenses)
only to the extent that such
expenses exceed 2 percent of the
individuals adjusted gross
income. Although there are
exceptions to the 2 percent
limitation, authority suggests
that no exceptions apply to
expenses passed through from a
grantor trust, like the Trust.Section 29 Tax Credits
    
    Coal seam gas produced and sold
after December 31, 2002, no
longer generates a Section 29
tax credit under the Code.
Therefore, Unitholders are not
entitled to claim Section 29 tax
credits for coal seam gas
produced and sold after 2002.
However, a Unitholder may
benefit from unused Section 29
tax credits for alternative
minimum tax purposes. Before
its expiration, the Section 29
tax credit could be used only to
the extent that a Unitholders
regular tax liability exceeded
the Unitholders tentative
minimum tax liability after the
regular tax liability had been
reduced by the foreign tax
credit and certain nonrefundable
personal credits. Any part of
the Section 29 tax credit not
allowed for the tax year solely
because of this alternative
minimum tax limitation was
subject to certain carryover
provisions relating to the
alternative minimum tax
calculation. Except for the
foregoing, there were no other
Code provisions that allowed for
the carryback or carryforward of
Section 29 tax credits. As the
carryforward of unused Section
29 tax credits is related to the
alternative minimum tax
calculation for succeeding
years, carryforwards should
continue to be allowed, even
though the Section 29 tax credit
is no longer allowed for coal
seam gas produced and sold after
2002.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.
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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.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.Non-Passive Activity Income, Credits
and Loss
    
    The income, credits and expenses
of the Trust are not taken into
account in computing the passive
activity losses and income under
Section 469 of the Code for a
Unitholder who acquires and
holds Units as an investment and
did not acquire them in the
ordinary course of a trade or
business.Tax Shelter Registration
    
    The Trust is registered as a
tax shelter, and its tax
shelter registration number is
94-277000355. Issuance of a tax
shelter registration number does
not indicate that the investment
in Units or the claimed tax
benefits have been reviewed,
examined or approved by the IRS.Unitholder Reporting Information
    
    The Trustee furnishes to
Unitholders tax information
concerning royalty income and
depletion and other relevant tax
matters on an annual basis.
Year-end tax information is
furnished to Unitholders no
later than March 15 of the
following year. See third
paragraph under Description of
UnitsPeriodic Reports.
 
 ERISA CONSIDERATIONS The section entitled ERISA Considerations appearing in the Prospectus sets forth certain
information regarding the applicability of the Employee Retirement Income Security Act of 1974, as
amended (ERISA), and the Code to pension, profit-sharing and other employee 21




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benefit plans and to individual retirement accounts (collectively, Qualified Plans). A copy
of this section of the Prospectus is filed as an exhibit to this Form 10-K and is incorporated
herein by reference. Due to the complexity of the prohibited transaction rules and the penalties imposed upon
persons involved in prohibited transactions, it is important that potential Qualified Plan
investors consult their counsel regarding the consequences under ERISA and the Code of their
acquisition and ownership of Units. 
 STATE TAX CONSIDERATIONS THE FOLLOWING IS INTENDED AS A BRIEF SUMMARY OF CERTAIN INFORMATION REGARDING STATE INCOME
TAXES AND OTHER STATE TAX MATTERS AFFECTING THE TRUST AND UNITHOLDERS. UNITHOLDERS SHOULD
THEREFORE CONSULT THE UNITHOLDERS TAX ADVISOR REGARDING STATE INCOME TAX FILING AND COMPLIANCE
MATTERS. 
 Alabama Income Tax All revenues attributable to the Royalty Interests are derived from sources within the State
of Alabama. Alabama imposes an income tax on individuals, corporations (subject to certain
exceptions for S corporations) and certain other entities that are residents of, conduct business
in, or derive income from sources within Alabama. Under general rules of application, both
resident and nonresident Unitholders would be required to file annual Alabama income tax returns
and pay Alabama income taxes with respect to any income received from the Trust and would be
subject to penalties for failure to comply with those rules. The Alabama Department of Revenue (the DOR) has issued a letter ruling that permits the
Trust to file a composite income tax return on behalf of all Unitholders who are not residents of
Alabama. The filing of the composite income tax return and acceptance of the return by DOR will
relieve those nonresident Unitholders of any obligation to file Alabama state income tax returns.
The Trust filed for each of the years 1995-2003 composite income tax returns with the DOR on behalf
of all Nonresident Unitholders (defined below), and intends to file a composite return for 2004 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
2004. Accordingly, no Alabama state income tax is due under the 2004 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 2004 (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 22




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##### Table of Contents



Alabama state income tax due as well as any penalties and interest due thereon. For purposes
of the filing of the composite income tax return for any taxable year, Nonresident Unitholders
will consist of those Unitholders to whom the Trust has provided an individualized tax information
letter (together with its tax information booklet) for such tax year that shows a mailing address
outside the State of Alabama. All other Unitholders will be treated by the Trust for purposes of
the filing of the composite income tax return as Resident Unitholders. The filing of the composite income tax return by the Trust does not relieve any resident of
the State of Alabama or any Resident Unitholder from the obligation to file an Alabama state income
tax return individually (and pay Alabama state income tax thereon, if any) with respect to the
revenues and expenses attributable to the Royalty Interests. In light of the foregoing, each
Unitholder should consult his tax adviser regarding the requirements for filing state income tax
returns for his state of residence and Alabama. 
 Alabama Business Privilege Tax Alabama previously imposed a franchise tax on domestic corporations and foreign corporations
doing business in Alabama, under a broad definition of corporation in the state constitution,
based on the amount of a corporations capital employed in the state. In reliance upon the
representations and assumptions set forth in the Prospectus and on a private letter ruling issued
June 10, 1994, by the DOR as to the offering of the Units, special Alabama tax counsel to the
Company opined in connection with each of the Public Offerings that the Trust was not subject to
Alabama franchise tax. Although the Alabama Commissioner of Revenue has the authority to revoke
retroactively DOR rulings under certain limited circumstances, special Alabama tax counsel did not
believe, based on the above representations and assumptions, that those circumstances existed with
respect to the Companys private letter ruling. 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 (the BPT), which imposes an annual privilege tax on corporations, limited liability entities,
and disregarded entities (as those terms are statutorily defined in Alabamas tax code) doing
business in Alabama or organized under Alabama law. The DOR issued a revenue ruling in 2002
holding that the BPT applied to a grantor trust. The DOR had previously issued a revenue ruling
holding that the BPT did not apply to a grantor trust, but that revenue ruling was revoked.
Alabama tax counsel recently advised the Trustee that the Trust has been subject to the BPT
beginning in 2000 when the BPT replaced the Alabama franchise tax. Prior to the enactment of the
BPT, the Trust was not subject to any Alabama state taxes. On May 26, 2004, Alabama local counsel submitted a proposal for a Voluntary Compliance
Agreement (the Agreement) with the Alabama Department of Revenue, which has been accepted. As
required by the Agreement, the Trust filed Alabama BPT tax returns for the 2002 and 2003 tax years,
and voluntarily paid the BPT owed for these years with interest. These payments were $15,000 plus
interest for each year. Therefore, the Alabama Department of Revenue should not impose penalties
or seek to collect the BPT or corporate shares taxes or applicable penalties and interest that may
have been due prior to the 2002 report. In accordance with now being subject to the BPT, the Trust
will file BPT returns and pay related taxes, if any, on a going-forward basis. 23




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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 24




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##### Table of Contents



gas wells may be established on a market demand or conservation basis or both. Reductions in
allowable production may extend the timing of recovery of reserves. Although the Trust is not
aware of any pending or contemplated proceedings to change allowable rates of production from the
Underlying Properties, there can be no assurances made that such changes will not be made. The
Unitholders and the Trust will not have any control over such changes. Reductions in the allowable
production from the Underlying Properties could affect the timing or amount of distributions to
Unitholders. 
 Environmental Regulation Operations on the Underlying Properties associated with the production of natural gas are
subject to numerous federal and state laws, rules and regulations governing the discharge of
materials into the environment or otherwise relating to the protection of the environment. Such
laws, rules and regulations require the acquisition of certain permits, impose substantial
liabilities for pollution resulting from exploration and production operations and may also
restrict air or other pollution resulting from operations. It is possible that federal and state
environmental laws and regulations will become more stringent in the future. For instance,
legislation has been proposed in Congress in connection with the pending reauthorization of the
Federal Resource Conservation and Recovery Act (RCRA) that would amend RCRA to reclassify certain
oil and gas production wastes as hazardous waste. If adopted, this amendment would result in
more rigorous and expensive disposal requirements. It is impossible to predict what the precise
effect additional regulation or legislation, or enforcement policies thereunder, could have on the
operation of the Underlying Properties. However, any costs or expenses incurred by the Company in
connection with environmental liabilities arising out of or relating to activities occurring on, in
or in connection with, or conditions existing on or under, the Underlying Properties, will be borne
by the Company and not the Trust, and such costs and expenses will not be deducted in calculating
Gross Proceeds. Such costs and expenses may, however, be taken into account by the Company in
exercising its rights to abandon a well and may accelerate the termination of the Trust. See
PropertiesThe Royalty InterestsSale and Abandonment of Underlying Properties and
PropertiesDescription of the TrustTermination and Liquidation of the Trust. Water from the operations on the Underlying Properties is discharged into the Black Warrior
River pursuant to a National Pollutant Discharge Elimination System permit issued by the Alabama
Department of Environmental Management (ADEM). ADEM initially issued five permits in connection
with the Underlying Properties, which were consolidated into one permit in February 1994. The ADEM
permit was renewed in 1999 and again in July 2004. Renewal of the permit has been applied for and
is under review by the Alabama Department of Environmental Management. 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 $87,000
during 2005 for anticipated expenditures related to compliance with environmental laws. 25




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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
the continuation of/return to low prices for natural gas will directly impact Trust distributions,
estimates of reserves attributable to the Royalty Interests and estimated future net revenue from
reserves attributable to the Royalty Interests. Prices for natural gas are subject to wide fluctuations in response to relatively minor
changes in supply, market uncertainty and a variety of additional factors that are beyond the
control of the Trust and the Company. These factors include political conditions in the Middle
East, the price and quantity of imported oil and gas, the level of consumer product demand, the
severity of weather conditions, government regulations, the price and availability of alternative
fuels and overall economic conditions. Additionally, lower natural gas prices may reduce the
amount of gas that is economic to develop or produce from the Underlying Properties. The Trusts revenues and distributions to Unitholders will be primarily dependent on the sales
prices for Gas produced from the Underlying Properties and the quantities of Gas sold. Natural gas
prices have historically been volatile and are likely to continue to be volatile. Price volatility
and the risk of production curtailment make it difficult to estimate the future levels of cash
distributions to Unitholders or the value of the Units. Since the termination of the Gas Purchase
Agreement, Gas is sold on a month to month basis to various purchasers until such time as a long
term contract can be secured. See PropertiesThe Royalty InterestsGas Purchase Agreement. 26




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Item 2. Properties. 
 THE ROYALTY INTERESTS The Royalty Interests held by the Trust generally entitle the Trust to receive 65 percent of
Gross Proceeds. The Royalty Interests were conveyed to the Trust by means of a single instrument
of conveyance. The Conveyance was recorded in the appropriate real property records in Alabama, so
as to give notice of the Royalty Interests to creditors, and any transferees will take an interest
in the Underlying Properties subject to the Royalty Interests. The Conveyance was intended to
convey the Royalty Interests as real property interests under Alabama law. The following description of the material provisions of the Conveyance and the Trust Agreement
is subject to and qualified by the more detailed provisions of the Conveyance and the Trust
Agreement included as exhibits to this Form 10-K. 
 The Underlying Properties Black Warrior Basin. The Black Warrior Basin covers 6,000 square miles in west central
Alabama and contains 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 Dominion Black Warrior Basin, Inc. in accordance with the
Operating Agreement. See Operation of Properties. The Underlying Properties comprise 34,212
gross acres of land in an area approximately 5 miles wide and 23 miles long located on the
Tuscaloosa to Bankhead Lake portion of the Black Warrior Basin. Initial production began in
December 1988 and consisted of 8 wells. The Company acquired its interest in the Underlying
Properties in December 1992. As of December 31, 2004, 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, 2004, 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. 27




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##### Table of Contents



Number of Wells
    
    
    AcresGross
    
    
    Net
    
    
    Gross
    
    
    NetCompany Interests
    
    
    532
    
    
    
    519
    
    
    
    34,212
    
    
    
    33,363
 Royalty Interests, Company Interests and Retained Interests.On June 1, 1994, the effective
date of the Conveyance, the Company had an average aggregate working interest in the Existing Wells
of approximately 98 percent, and an average aggregate net revenue interest of approximately 80
percent in the Existing Wells. The Company has not sold or otherwise disposed of any of its
interest in the Company Interests since June 1, 1994. The Royalty Interests are entitled to
approximately 52 percent of the net revenue from natural gas produced and sold from the Underlying
Properties, and the interests (the Retained Interests) of the Company in the Underlying
Properties (after giving effect to the Royalty Interests) entitle the Company to receive
approximately 28 percent of the net revenue from the natural gas produced and sold from the
Underlying Properties. As a working interest owner in the Underlying Properties, the Company is
responsible for an average of approximately 98 percent of the operating costs of the Existing
Wells. The Royalty Interests do not burden (i) royalties and other obligations, expressed or implied,
under oil or natural gas leases, (ii) the overriding royalties and other burdens created by the
Companys predecessors in title, or (iii) the working interests owned by other individual working
interest owners. Water Removal and Disposal.Water from the wells located on the Underlying Properties is
pumped from the wellhead to one of five water disposal systems, each with two ponds, where the
water is analyzed and chemically treated to remove impurities, if necessary, prior to discharge
into the Black Warrior River. Water from the operations on the Underlying Properties is discharged
into the Black Warrior River pursuant to a National Pollutant Discharge Elimination System permit
issued by ADEM that expired in July 2004. A new permit was requested and obtained for post-July
2004 and will expire in August 2009. The ADEM permit generally authorizes water disposal based
upon the Black Warrior Rivers minimum flow rate and maximum chloride level. The Company has
advised the Trust that, since 1987, water disposal from the Underlying Properties has not been
disrupted. Although the facilities of the Company have the capacity to store several days of water
production, if water disposal into the Black Warrior River is disrupted, natural gas production
from the wells on the Underlying Properties would be curtailed during the period of such
disruption. See BusinessRegulation and PricesEnvironmental Regulation. Curtailments.The Company has advised the Trust that, during 2004, 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. 28




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The Trust is subject to certain rules of the Bureau of Land Management under which the holding
of interests in leases by persons other than citizens, nationals and legal resident aliens of the
United States (Eligible Citizens) are limited. As a result, non-Eligible Citizens are prohibited
from owning Units. If any Units are acquired by persons or entities not constituting Eligible
Citizens, such Unitholders may be required to sell such Units pursuant to a procedure set forth in
the Trust Agreement. See BusinessDescription of the TrustPossible Divestiture of Units. Additional Wells.Well spacing rules, which are in effect in Alabama, generally govern the
space between wells drilled to the same productive formation and are promulgated in order to
prevent waste and confiscation of property. Pursuant to such rules, the Existing Wells are located
on 40- to 80-acre spacing units. Exceptions or changes to these rules may be granted by the
applicable regulatory agency upon application of an interested party following notice to other
interested parties if, in the agencys opinion, good reasons exist therefor after consideration of
evidence presented by the applicant and any opponents. The Company has informed the Trust that it
is not aware of any plans to change spacing regulations with respect to the Underlying Properties
in Alabama. No assurances can be made, however, that exceptions or changes will not be made in the
future. The Company and its affiliates or unrelated third parties may acquire interests in properties
adjoining the Underlying Properties. It is possible that wells drilled on adjoining properties
would drain reserves attributable to the Underlying Properties. The Company has agreed for the term of the Trust not to consent to, cooperate with, assist in
or conduct infill drilling (except as required by law) on any of the Underlying Properties in which
the Company owned an interest as of June 1, 1994. Although the Company believes that it is
unlikely that any additional wells will be drilled, if the Operating Agreement is terminated, the
Company cannot prevent one of the other owners of an interest in the Underlying Properties from
drilling additional wells on the Underlying Properties. Additional wells, if drilled, could
recover a portion of the reserves otherwise producible from wells burdened by the Company
Interests, thereby reducing the Gross Proceeds attributable to the Royalty Interests. 
 The Royalty Interests Summary of Conveyance.The Conveyance has been filed as an exhibit to this Form 10-K. The
following summary of the material terms of the Conveyance is qualified in its entirety by reference
to the terms thereof as set forth in such exhibit. 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. 29




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Pratt Recompletions.To recover behind pipe reserves, the Company Interests Owner recompleted
certain of the Existing Wells to the Pratt coal seam prior to March 31, 1997. Right to Take In-Kind.The owner of the Royalty Interests has no right to take production
in-kind. Pooling and Unitization.The Company Interests Owner has certain pooling and unitization
rights. Right to Assign Company Interests.The Company Interests Owner has the right to assign all or
any part of the Company Interests, subject to the Royalty Interests and the terms and provisions of
the Conveyance. If any such assignment is made of part, but not all, of such interests, then
effective as of the date of such assignment, the assignee will be required to make a separate
computation of Gross Proceeds attributable to the assigned interests. Sale or Assignment of Royalty Interests.In certain situations, the Trust may sell or dispose
of all or a part of the Royalty Interests, in which case the Trust would receive the proceeds
therefrom and distribute such proceeds to the Unitholders, net of any amounts held as a reserve.
See BusinessDescription of the TrustTransfer of Royalty Interests and BusinessDescription of
the TrustDuties and Limited Powers of the Trustee. Books and Records.The Company Interests Owner is required to maintain books and records
sufficient to determine the amounts payable with respect to the Royalty Interests. Computation and Payment.The Royalty Interests entitle the Trust to receive 65 percent of the
Gross Proceeds. The Royalty Interests bear their proportionate share of property, production and
related taxes (including severance taxes). The definitions, formulas and accounting procedures and
other terms governing the computation of the Royalty Interests are set forth in the Conveyance. The Company Interests Owner is required, pursuant to the Conveyance, to pay to the Trust
amounts received by the Company Interests Owner from the sale of Subject Gas attributable to the
Royalty Interests. Under the Conveyance, the amounts payable by the Company Interests Owner with
respect to the Royalty Interests are computed with respect to each calendar quarter ending prior to
termination of the Trust, and such amounts are paid to the Trust not later than the last business
day before the 45th day following the end of each calendar quarter. The amounts paid to the Trust
do not include interest on any amounts payable with respect to the Royalty Interests that are held
by the Company Interests Owner prior to payment to the Trust. The Company Interests Owner is
entitled to retain all amounts attributable to the Retained Interests. The Company Interests Owner
deducts from the payment to the Trust the Royalty Interests share of property, production and
related taxes (including severance taxes) and pays the same on behalf of the Trust. 
 Reserve Estimate Reserve Estimate.The following table summarizes net proved reserves estimated as of January
1, 2005, 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. 30




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As ofRoyalty Interests
    
    January 1, 2005Net Proved Natural Gas Reserves (MMcf)(a)(b):Developed Producing
    
    
    39,101Estimated Future Net Revenues (in thousands) (a)(c):2005
    
    $
    22,8502006
    
    
    20,2282007
    
    
    17,9292008
    
    
    15,9112009
    
    
    14,136Thereafter
    
    
    113,262Total
    
    $
    204,316Total Discounted at 10 Percent
    
    $
    113,440
   (a)
    
    The estimates of reserves and future net revenues summarized in this table are based upon a
price of $5.56 per Mcf, which represented the market price for gas in their fields as of
December 31, 2004. This price may not be the most representative price for estimating
reserves or related future net revenues data.(b)
    
    As discussed in BusinessFederal Income Tax Considerations, coal seam gas produced and sold
after December 31, 2002, no longer generates a Section 29 tax credit.(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 property may vary from engineer to engineer even though each engineer bases his estimate
on common data and utilizes techniques and principles customary in the industry. For properties with short production histories, reserve estimates in many instances are based
upon volumetric calculations and upon analogy to similar types of production or producing fields.
Relative to many conventional natural gas producing properties, coal seam gas producing properties
in general, and the Underlying Properties in particular, have short production histories. In
addition, there are no significant coal seam reservoirs that have been produced to depletion that
can be used as analogies to the Underlying Properties. 31




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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 4.4
Bcf in 2005 to 2.7 Bcf in 2009. Detailed information concerning the number of wells on royalty properties is not generally
available to the owner of royalty interests. Consequently, the Registrant does not have
information that would be disclosed by a company with oil and gas operations, such as an accurate
count of the number of wells located on the Underlying Properties, the number of exploratory or
development wells drilled on the Underlying Properties during the periods presented by this report,
or the number of wells in process or other present activities on the Underlying Properties, and the
Registrant cannot readily obtain such information. Miscellaneous.Ralph E. Davis & Associates has delivered to the Trust the Reserve Estimate, a
summary of which is included as an exhibit to this Form 10-K. Information concerning historical
changes in net proved developed reserves attributable to the Royalty Interests, and the calculation
of the standardized measure of discounted future net revenues related thereto, is contained in Note
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, 2004, December 31, 2003 and December 31,
2002. Year ended December 31,2004
    
    
    2003
    
    
    2002Production attributable to the Royalty Interests (Bcf)
    
    
    4.7
    
    
    
    5.1
    
    
    
    6.0Weighted average property, production and related taxes (per Mcf)
    
    $
    0.38
    
    
    $
    0.16
    
    
    $
    0.15Average Contract Price (per Mcf)
    
    $
    6.15
    
    
    $
    4.22
    
    
    $
    3.70
 
 Gas Purchase Agreement El Paso Merchant Energy  Gas, L.P. (El Paso), successor to Sonat Marketing Company (Sonat
Marketing), was required under the Gas Purchase Agreement to purchase the Gas produced from the
Underlying Properties until such agreement was terminated, effective January 31, 2004. 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 32




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(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
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,
was 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, (i) a fixed
price quantity, (ii) an index price quantity subject to a floor and ceiling price (the Collared
Index Quantity), and (iii) 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 or 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 was 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
was 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 was
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 was $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 was the sum of (i) the Index Price and (ii) a
premium 33




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##### Table of Contents



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 applied 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 was the sum of the Index Price and $.02 per MMBtu, multiplied by 0.9826,
the wet/dry conversion factor. Effective January 31, 2004, the Gas Purchase Agreement was
terminated. For the period of February 1, 2004 through October 30, 2004, the gas was sold on a
month to month basis to various purchasers. Contracts were secured from two purchasers,
ConocoPhillips and Coral Energy Resources, L.P., for the base load gas at Index Price plus $0.02125
per MMBtu for the period of November 1, 2004 through May 31, 2005. Any gas above the base load was
sold on the spot market to various purchasers. The basis for gas sales after March 31, 2005 will
be determined subsequent to the filing of this Annual Report on Form 10-K but will be reported in
future filings. 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 Trustees nor Unitholders
will be able to influence or control the operation or future development of the Underlying
Properties. Unitholders will therefore be reliant on the Company and the other working interest
owners to make all decisions regarding operations on the Underlying Properties. The Trust will not
be able to appoint or control the appointment of operators. The Conveyance does not prohibit the transfer of the Underlying Properties by the Company,
subject to and burdened by the Royalty Interests. The Company and the other working interest
owners of the Underlying Properties will have the right, subject to certain restrictions, to
abandon any well or lease on the Underlying Properties under certain circumstances. Upon
abandonment of any such well or lease, that portion of the Royalty Interests relating thereto will
be extinguished. See Sale and Abandonment of the Underlying Properties. Operating Agreement.Pursuant to the Operating Agreement, ConocoPhillips operated and
maintained the Underlying Properties for the Company and the other working interest owners until
January 1, 2003. As amended October 30, 1996, the Operating Agreement had a three-year term and
was to be automatically renewed for additional one-year periods unless either party provided
written notice to the other party of its desire to terminate the Operating Agreement before the end
of the current calendar year. On December 27, 2000, Dominion Resources notified ConocoPhillips
that it was terminating the automatic one-year extension of the agreement. As such, the Operating
Agreement was amended effective January 1, 2003 naming Dominion Black Warrior Basin, Inc. as the
operator of the underlying properties. 
 Sale and Abandonment of Underlying Properties The Company has the right to abandon any well or lease included in the Underlying Properties
if, in its opinion, acting as would a reasonably prudent operator, such well or lease is not
capable of producing Gas in commercial quantities (determined before giving effect to the Royalty
Interests). Neither the Trust nor the Unitholders will control the timing of the plugging 34




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##### Table of Contents



and
abandoning of any wells. Through December 31, 2004, none of the wells included in the Underlying
Properties had been plugged and abandoned. The Company may sell its interest in the Underlying Properties, subject to and burdened by the
Royalty Interests, without the consent of the Trust or Unitholders. Under the Trust Agreement, the
Company has certain rights (but not the obligation) to purchase the Royalty Interests upon
termination of the Trust. See BusinessDescription of the Trust AgreementTermination and
Liquidation of the Trust. 
 Dominion Resources 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 performance obligations. All of Dominion Resources 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 direct or
indirect equity ownership interest in the Company; provided that, with respect to clauses (ii) and
(iii) above, Dominion Resources obligations will terminate only if: (a) the transferee has a
specified credit rating or the transferee together with an affiliate that guarantees the
transferees obligations has not less than a specified net worth or (b) the transferee is approved
by the holders of a majority of the outstanding Units; and provided further, that in the case of
clauses (ii) or (iii) above the transferee also unconditionally agrees in writing, in form and
substance reasonably satisfactory to the Trustee, to assume Dominion Resources 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 that, in the opinion of Alabama counsel, are not so material as to detract
substantially from the use or value of the Company Interests or the Royalty Interests. 35




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Although the matter is not entirely free from doubt, Alabama counsel has opined that the
Royalty Interests constitute interests in real property under Alabama law. Consistent therewith,
the Conveyance states that the Royalty Interests constitute real property interests. The Company
has recorded the Conveyance in the appropriate real property records of Alabama in accordance
with local recordation provisions. If, during the term of the Trust, the Company or any
Company Interests Owner becomes involved as a debtor in bankruptcy proceedings under the Federal
Bankruptcy Code, it is not entirely clear that the Royalty Interests would be treated as real
property interests under the laws of Alabama. 
 Item 3. Legal Proceedings.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. 36




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##### Table of Contents



PART II. 
 Item 5. Market for
Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities.The Units in the Trust are listed and traded on the NYSE under the symbol
DOM. The following table sets forth, for the periods indicated, the high and low sales prices
per Unit on the NYSE and the amount of quarterly cash distributions per Unit paid by the Trust. PriceDistributionHigh
    
    
    Low
    
    
    per Unit2004First Quarter
    
    $
    29.50
    
    
    $
    25.76
    
    
    $
    .568977Second Quarter
    
    
    30.58
    
    
    
    26.26
    
    
    
    .806399Third Quarter
    
    
    34.74
    
    
    
    30.00
    
    
    
    .806256Fourth Quarter
    
    
    38.80
    
    
    
    32.33
    
    
    
    .8000672003First Quarter
    
    $
    24.25
    
    
    $
    20.10
    
    
    $
    .644817Second Quarter
    
    
    27.30
    
    
    
    21.95
    
    
    
    .695362Third Quarter
    
    
    29.18
    
    
    
    23.05
    
    
    
    .616863Fourth Quarter
    
    
    29.25
    
    
    
    26.70
    
    
    
    .572678
 At March 1, 2005, there were 7,850,000 Units outstanding and approximately 634 Unitholders of
record. The Trust has no equity compensation plans and has not repurchased any units during the period
covered by this report. 
 Item 6. Selected Financial Data. Year Ended December 31,2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Royalty Income
    
    $
    24,340,315
    
    
    $
    20,746,843
    
    
    $
    19,418,476
    
    
    $
    25,937,254
    
    
    $
    20,874,519Distributable Income
    
    $
    23,449,768
    
    
    $
    19,835,642
    
    
    $
    18,623,941
    
    
    $
    25,215,487
    
    
    $
    20,229,281Distributable Income per
Unit
    
    $
    2.99
    
    
    $
    2.53
    
    
    $
    2.37
    
    
    $
    3.21
    
    
    $
    2.58Distributions per Unit
    
    $
    2.99
    
    
    $
    2.53
    
    
    $
    2.37
    
    
    $
    3.21
    
    
    $
    2.58Total Assets, December 31
    
    $
    39,946,530
    
    
    $
    44,820,393
    
    
    $
    50,566,037
    
    
    $
    57,819,259
    
    
    $
    65,691,406Total Corpus, December 31
    
    $
    39,819,581
    
    
    $
    44,689,580
    
    
    $
    50,441,689
    
    
    $
    57,707,439
    
    
    $
    65,575,056
 37




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##### Table of Contents



Item 7. Trustees Discussion and Analysis of Financial Condition and Results of Operations.The Trust
collects the proceeds attributable to the Royalty Interests and makes quarterly cash distributions
to Unitholders. The only assets of the Trust, other than cash and cash equivalents being held for
the payment of expenses and liabilities and for distribution to Unitholders, are the Royalty
Interests. The Royalty Interests owned by the Trust burden the interest in the Underlying
Properties that is owned by the Company. The Royalty Interests consist of overriding royalty interests burdening the Companys interest
in the Underlying Properties. The Royalty Interests generally entitle the Trust to receive 65
percent of the Gross Proceeds (as defined below) during the preceding calendar quarter. The
Royalty Interests are non-operating interests and bear only expenses related to property,
production and related taxes (including severance taxes). Gross Proceeds consist generally of the
aggregate amounts received by the Company attributable to the interests of the Company in the
Underlying Properties from the sale of coal seam gas at the central delivery points in the
gathering system for the Underlying Properties. Distributable income of the Trust generally consists of the excess of royalty income plus
interest income over the administrative expenses of the Trust. Upon receipt by the Trust, royalty
income is invested in short-term investments in accordance with the Trust Agreement until its
subsequent distribution to Unitholders. The amount of distributable income of the Trust for any calendar year may differ from the
amount of cash available for distribution to the Unitholders in such year due to differences in the
treatment of the expenses of the Trust and the determination of those amounts. The financial
statements of the Trust are prepared on a modified cash basis pursuant to which the expenses of the
Trust are recognized when they are paid or reserves are established whereas royalty income is
recognized when received by the Trust. Consequently, the reported distributable income of the
Trust for any year is determined by deducting from the income received by the Trust the amount of
expenses paid by the Trust during such year. The amount of cash available for distribution to
Unitholders is determined after adjustment for changes in reserves for unpaid liabilities in
accordance with the provisions of the Trust Agreement. See Note 5 to the financial statements of
the Trust appearing elsewhere in this Form 10-K for additional information regarding the
determination of the amount of cash available for distribution to Unitholders. The year 2004 marked the tenth full year of the existence of the Trust. The Trust received
royalty income amounting to $24,340,315 during the year ended December 31, 2004, compared to
$20,746,843 for 2003 and $19,418,476 for 2002. 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, 2004 decreased to $908,507, compared to $923,785 for
2003 and $810,557 for 2002. Distributable income for the year ended December 31, 2004 was
$23,449,768, or $2.99 per Unit, compared to $19,835,642, or $2.53 per Unit, for 2003 and
$18,623,941, or $2.37 per Unit, for 2002. The decrease in administrative expenses in 2004 compared to 2003 was primarily the result of
lower professional fees. Similarly, the increase from 2002 to 2003 was the result of higher
printing costs and 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 38




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##### Table of Contents



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 three
quarters of that year and the fourth quarter of the preceding calendar year due to the timing of
the receipt of these revenues. Accordingly, the royalty income included in distributable income
for the years ended December 31, 2004, 2003 and 2002, was based on production volumes and natural
gas prices for the periods from October 1, 2003 to September 30, 2004, October 1, 2002 to September
30, 2003 and October 1, 2001 to September 30, 2002, 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. For 12 Months EndedSeptember 30,2004
    
    
    2003
    
    
    2002Production (Bcf)(1)
    
    
    4.825
    
    
    
    5.326
    
    
    
    6.129Production (MMBtu)(2)
    
    
    4.865
    
    
    
    5.367
    
    
    
    6.152Average Contract Price Received ($/MMBtu)
    
    $
    5.33
    
    
    $
    4.13
    
    
    $
    3.36Average Index Price ($/MMBtu)
    
    $
    5.45
    
    
    $
    4.27
    
    
    $
    2.78
   (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) was required under the Gas Purchase Agreement to
purchase the Gas produced from the Underlying Properties for as long as reserves on the Underlying
Properties until such agreement was terminated, effective January 31, 2004. 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 39




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##### Table of Contents



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 was 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
was 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 was
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 was $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 was 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 applied 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 was the sum of the Index Price and $.02 per MMBtu, multiplied by 0.9826, the
wet/dry conversion factor. 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, was Southern Natural Gas Companys posted index price for deliveries
of gas in Louisiana. Effective January 31, 2004, the Gas Purchase Agreement was terminated. For
the period of February 1, 2004 through October 30, 2004, the gas was sold on a month to month basis
to various purchasers. Contracts were secured from two purchasers, ConocoPhillips and Coral Energy
Resources, L.P., for the base load gas at Index Price plus $0.02125 per MMBtu for the period of
November 1, 2004 through March 31, 2005. Any gas above the base load was sold on the spot market
to various purchasers. The basis for gas sales after March 31, 2005 will be determined subsequent
to the filing of this Annual Report on Form 10-K but will be reported in future filings. The net proved reserves attributable to the Royalty Interests have been estimated as of
December 31, 2004, 2003 and 2002, by independent petroleum engineers. The reserve quantities of
39.1 Bcf for 2004 compared to 41.6 Bcf for 2003 and compared to 42.6 Bcf for 2002, reflect a
decline in reserves between 2002 and 2003 and between 2003 and 2004 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 judgment areas in the application of accounting policies that currently affect
the Trusts financial condition and results of operations. 40




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##### Table of Contents



1.
    New Accounting Pronouncements Statement of Financial Accounting Standards (SFAS) No. 123R, Accounting for Stock-Based
Compensation was issued in December 2004 and provides new implementation guidance for stock-based
compensation accounting. This Statement is effective for public entities that do not file as small
business issuers  as of the beginning of the first interim or annual reporting period that begins
after June 15, 2005. The Trust has no options or other stock-based instruments and accordingly,
the impact of this new Standard will not be material to the financial statements of the Trust.  2.
    Basis of Accounting The financial statements of the Trust are prepared on a modified cash basis and are not
intended to present financial position and results of operations in conformity with accounting
principles generally accepted in the United States of America. Preparation of the Trusts
financial statements on such basis includes the following:  
    Royalty income and interest income are recorded in the period in which amounts are received by the Trust rather than in
the period of production and accrual, respectively.
    General and administrative expenses are recorded based on liabilities paid and cash reserves established out of cash
received.
    Amortization of the Royalty Interests is calculated on a unit-of-production basis and charged directly to Trust corpus
based upon when revenues are received.
    Distributions to Unitholders are recorded when declared by the Trustee (see Note 5). The financial statements of the Trust differ from financial statements prepared in accordance
with accounting principles generally accepted in the United States of America because royalty
income is not accrued in the period of production, general and administrative expenses recorded are
based on liabilities paid and cash reserves established rather than on an accrual basis, and
amortization of the Royalty Interests is not charged against operating results. The comprehensive
basis of accounting other than accounting principles generally accepted in the United States of
America corresponds to the accounting permitted for royalty trusts by the U.S. Securities and
Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of
Royalty Trusts.  3.
    Impairment The net amount of Royalty Interests in gas properties is limited to the fair value of these
assets, which would likely be measured by discounting projected cash flows. If the net cost of
Royalty Interests in gas properties exceeds the aggregate of these amounts, an impairment provision
is recorded and charged to the Trust Corpus.  4.
    Revenue Recognition Revenues from Royalty Interests are recognized in the period in which amounts are received by
the Trust. Royalty income received by the Trust in a given calendar year will generally reflect
the proceeds, on an entitlements basis, from natural gas produced for the twelve-month period ended
September 30th in that calendar year. 41




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##### Table of Contents



5.
    Reserve Disclosure Independent petroleum engineers estimate the net proved reserves attributable to the Royalty
Interest. In accordance with SFAS No. 69, Disclosures About Oil and Gas Producing Activities,
estimates of future net revenues from proved reserves have been prepared using year-end contractual
gas prices and related costs. Numerous uncertainties are inherent in estimating volumes and the
value of proved reserves and in projecting future production rates and the timing of development of
non-producing reserves. Such reserve estimates are subject to change as additional information
becomes available. The reserves actually recovered and the timing of production may be
substantially different from the reserve estimates. Detailed information concerning the number of wells on royalty properties is not generally
available to the owner of royalty interests. Consequently, the Registrant does not have
information that would be disclosed by a company with oil and gas operations, such as an accurate
count of the number of wells located on the Underlying Properties, the number of exploratory or
development wells drilled on the Underlying Properties during the periods presented by this report,
or the number of wells in process or other present activities on the Underlying Properties, and the
Registrant cannot readily obtain such information.  6.
    Contingencies Contingencies related to the Underlying Properties that are unfavorably resolved would
generally be reflected by the Trust as reductions to future royalty income payments to the Trust
with corresponding reductions to cash distributions to Unitholders. The Trustee is aware of no
such items as of December 31, 2004. 
 Liquidity and Capital Resources As stipulated in the Trust Agreement, the Trust is intended to be passive in nature and
neither the Delaware Trustee nor the Trustee has any control over or any responsibility relating to
the operation of the Underlying Properties. The Trustee has powers to collect and distribute
proceeds received by the Trust and pay Trust liabilities and expenses and its actions have been
limited to those activities. The assets of the Trust are passive in nature, and other than the
Trusts ability to periodically borrow money as necessary to pay expenses, liabilities and
obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited
from engaging in borrowing transactions. As a result, other than such borrowings, if any, the
Trust has no source of liquidity or capital resources other than the Royalty Interests. See the
earlier discussions in Item 7 for the discussion of the operations and cash inflows and outflows of
the Trust. 
 Off-Balance Sheet Arrangements As stipulated in the Trust Agreement, the Trust is intended to be passive in nature and
neither the Delaware Trustee nor the Trustee has any control over or any responsibility relating to
the operation of the Underlying Properties. The Trustee has powers to collect and distribute
proceeds received by the Trust and pay Trust liabilities and expenses and its actions have been
limited to those activities. Therefore, the Trust has not engaged in any off-balance sheet
arrangements. 42




---



Tabular Disclosure of Contractual Obligations. Contractual Obligations
    
    

Total
    


Payments Due by PeriodLess than
    
    
    
    1 - 3
    
    
    
    3-5
    
    
    
    More than1 Year
    
    
    
    Years
    
    
    
    Years
    
    
    
    5 YearsDistribution declared
subsequent to year end
    
    
    $
    7,284,447
    
    
    
    $
    7,284,447
    
    
    
    
    0
    
    
    
    
    0
    
    
    
    
    0Total
    
    


    $
    7,284,447
  
    
  
    $
    7,284,447
  
    
  
  
    0
  
    
  
  
    0
  
    
  
  
    0
 The above payable relates to distributions declared February 18, 2005 and payable March 11,
2005. 
 Forward-Looking Statements This Annual Report includes forward-looking statements within the meaning of Section 27A of
the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934,
which are intended to be covered by the safe harbor created thereby. All statements other than
statements of historical fact included in this Annual Report are forward-looking statements. Such
statements include, without limitation, factors affecting the price of oil and natural gas
contained in Item 1, Business, certain reserve information and other statements contained in Item
2, Properties, and certain statements regarding the Trusts financial position, industry
conditions and other matters contained in this Item 7. Although the Trustee believes that the
expectations reflected in such forward-looking statements are reasonable, such expectations are
subject to numerous risks and uncertainties and the Trustee can give no assurance that they will
prove correct. There are many factors, none of which is within the Trustees control, that may
cause such expectations not to be realized, including, among other things, factors identified in
this Annual Report affecting oil and gas prices and the recoverability of reserves, general
economic conditions, actions and policies of petroleum-producing nations and other changes in the
domestic and international energy markets. 
 Item 7A. Quantitative and Qualitative Disclosures About Market Risk.The Trust invests in no
derivative financial instruments and has no foreign operations or long-term debt instruments. The
assets of the Trust are passive in nature, and other than the Trusts ability to periodically
borrow money as necessary to pay expenses, liabilities and obligations of the Trust that cannot be
paid out of cash held by the Trust, the Trust is prohibited from engaging in borrowing
transactions. The amount of any such borrowings is unlikely to be material to the Trust. The
Trust periodically holds short-term investments acquired with funds held by the Trust pending
distribution to Unitholders and funds held in reserve for the payment of Trust expenses and
liabilities. Because of the short-term nature of these borrowings and investments and certain
limitations upon the types of such investments that may be held by the Trust, the Trustee believes
that the Trust is not subject to any material interest rate risk. The Trust does not engage in
transactions in foreign currencies that could expose the Trust or Unitholders to any foreign
currency related market risk. 43




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##### Table of Contents



Item 8. Financial Statements and Supplementary Data. 
 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Unit Holders of Dominion Resources Black Warrior Trust and Bank of America, N.A., Trustee We have audited the accompanying statements of assets, liabilities and trust corpus of
Dominion Resources Black Warrior Trust (the Trust) as of December 31, 2004 and 2003, and the
related statements of distributable income and changes in trust corpus for each of the three years
in the period ended December 31, 2004. These financial statements are the responsibility of the
Trustee. Our responsibility is to express an opinion on these financial statements based on our
audits. We conducted our audits in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our
opinion. As described in Note 2 to the financial statements, these financial statements have been
prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other
than accounting principles generally accepted in the United States of America. In our opinion, such financial statements present fairly, in all material respects, the
assets, liabilities and trust corpus of the Trust at December 31, 2004 and 2003, and the
distributable income and changes in trust corpus for each of the three years in the period ended
December 31, 2004, on the basis of accounting described in Note 2. /s/ DELOITTE & TOUCHE LLP Dallas, Texas
March 14, 2005 44




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##### Table of Contents



DOMINION RESOURCES BLACK WARRIOR TRUST FINANCIAL STATEMENTS Statements of Assets, Liabilities and Trust Corpus December 31,2004
    
    
    2003ASSETSCash and cash equivalents
    
    $
    126,590
    
    
    $
    87,026Royalty interests in gas properties (less accumulated
amortization of $115,997,561 and
$111,084,133, respectively)
    
    
    39,819,940
    
    
    
    44,733,367Total Assets
    
    $
    39,946,530
    
    
    $
    44,820,393LIABILITIES AND TRUST CORPUSTrust expenses payable
    
    $
    126,949
    
    
    $
    130,813Trust corpus (7,850,000 units of beneficial interest
authorized, issued and outstanding)
    
    
    39,819,581
    
    
    
    44,689,580Total Liabilities and Trust Corpus
    
    $
    39,946,530
    
    
    $
    44,820,393
 Statements of Distributable Income Year Ended December 31,2004
    
    
    2003
    
    
    2002Royalty income
    
    $
    24,340,315
    
    
    $
    20,746,843
    
    
    $
    19,418,476Interest income
    
    
    17,960
    
    
    
    12,584
    
    
    
    16,02224,358,275
    
    
    
    20,759,427
    
    
    

    19,434,498General and administrative expenses
    
    
    (908,507
    )
    
    
    (923,785
    )
    
    
    (810,557
    )Distributable income
    
    $
    23,449,768
    
    
    $
    19,835,642
    
    
    $
    18,623,941Distributable income per unit
(7,850,000 units)
    
    $
    2.99
    
    
    $
    2.53
    
    
    $
    2.37Distributions per unit
    
    $
    2.99
    
    
    $
    2.53
    
    
    $
    2.37
 Statements of Changes in Trust Corpus Year Ended December 31,2004
    
    
    2003
    
    
    2002Trust corpus, beginning of period
    
    $
    44,689,580
    
    
    $
    50,441,689
    
    
    $
    57,707,439Amortization of royalty interests

    
    
    (4,913,428
    )
    
    
    (5,729,450
    )
    
    
    (7,263,029
    )Distributable income
    
    
    23,449,768
    
    
    
    19,835,642
    
    
    
    18,623,941Distributions to Unitholders
    
    
    (23,406,339
    )
    
    
    (19,858,301
    )
    
    
    (18,626,662
    )Trust corpus, end of period
    
    $
    39,819,581
    
    
    $
    44,689,580
    
    
    $
    50,441,689
 The accompanying notes are an integral part of these financial statements. 45




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Notes to Financial StatementsYears Ended December 31, 2004, 2003 and 2002 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 (Dominion
Energy), which in turn transferred all the Units to its parent, Dominion Resources, Inc., a
Virginia corporation (Dominion Resources), which sold an aggregate of 6,904,000 Units to the
public through various underwriters (the Underwriters) in June and August 1994 and the remaining
946,000 Units through certain of the Underwriters in June 1995. The Trustee has all powers to collect and distribute proceeds received by the Trust and to pay
Trust liabilities and expenses. The Delaware Trustee has only such powers as are set forth in the
Trust Agreement or are required by law and is not empowered to otherwise manage or take part in the
management of the Trust. The Royalty Interests are passive in nature and neither the Trustee nor
the Delaware Trustee has any control over, or any responsibility relating to, the operation of the
Underlying Properties or the Companys interest therein. The Trust is subject to termination under certain circumstances described in the Trust
Agreement. Upon the termination of the Trust, all Trust assets will be sold and the net proceeds
therefrom distributed to Unitholders. The only assets of the Trust, other than cash and temporary investments being held for the
payment of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests.
The Royalty Interests consist of overriding royalty interests burdening the Companys interest in
the Underlying Properties. The Royalty Interests generally entitle the Trust to receive 65 percent
of the Companys Gross Proceeds (as defined below). The Royalty Interests are non-operating
interests and bear only expenses related to property, production and related taxes (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 46




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##### Table of Contents



for the Underlying Properties. The definitions, formulas and accounting procedures and
other terms governing the computation of the Royalty Interests are set forth in the Conveyance. Because of the passive nature of the Trust and the restrictions and limitations on the powers
and activities of the Trustee contained in the Trust Agreement, the Trustee does not consider any
of the officers and employees of the Trustee to be officers or executive officers of the Trust
as such terms are defined under applicable rules and regulations adopted under the Securities
Exchange Act of 1934. 2. Basis of Accounting The financial statements of the Trust are prepared on a modified cash basis and are not
intended to present financial position and results of operations in conformity with accounting
principles generally accepted in the United States of America. Preparation of the Trusts
financial statements on such basis includes the following:  
    Royalty income and interest income are recorded in the period in which amounts are received by the Trust rather than in
the period of production and accrual, respectively.
    General and administrative expenses are recorded based on liabilities paid and cash reserves established out of cash
received.
    Amortization of the Royalty Interests is calculated on a unit-of-production basis and charged directly to Trust corpus
based upon when revenues are received.
    Distributions to Unitholders are recorded when declared by the Trustee (see Note 5). The financial statements of the Trust differ from financial statements prepared in accordance
with accounting principles generally accepted in the United States of America because royalty
income is not accrued in the period of production, general and administrative expenses recorded are
based on liabilities paid and cash reserves established rather than on an accrual basis, and
amortization of the Royalty Interests is not charged against operating results. The comprehensive
basis of accounting other than accounting principles generally accepted in the United States of
America corresponds to the accounting permitted for royalty trusts by the U.S. Securities and
Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of
Royalty Trusts. Use of Estimates The preparation of financial statements in conformity with the basis of accounting described
above requires management to make estimates and assumptions that affect reported amounts of certain
assets, liabilities, revenues and expenses as of and for the reporting periods. Actual results may
differ from such estimates. Impairment The net amount of Royalty Interests in Gas properties is limited to the fair value of these
assets, which would likely be measured by discounting projected cash flows. If the net cost of
Royalty Interests in Gas properties exceeds the aggregate of these amounts, an impairment provision
is recorded and charged to the Trust corpus. 47




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##### Table of Contents



Distributable Income Per Unit Basic distributable income per unit is computed by dividing distributable income by the
weighted average units outstanding. Distributable income per unit assuming dilution is computed by
dividing distributable income by the weighted average number of units and equivalent units
outstanding. The Trust had no equivalent units outstanding for any period presented, thus basic
distributable income per unit and diluted distributable income per unit are the same. New Accounting Pronouncements Statement of Financial Accounting Standards (SFAS) No. 123R, Accounting for Stock-Based
Compensation was issued in December 2004 and provides new implementation guidance for stock-based
compensation accounting. This Statement is effective for public entities that do not file as small
business issuers  as of the beginning of the first interim or annual reporting period that begins
after June 15, 2005. The Trust has no options or other stock-based instruments and accordingly,
the impact of this new Standard will not be material to the financial statements of the Trust. 3. Federal Income Taxes The Trust is a grantor trust for Federal income tax purposes. As a grantor trust, the Trust
is not required to pay Federal income taxes. Accordingly, no provision for federal income taxes
has been made in these financial statements. Because the Trust is treated as a grantor trust, and because a Unitholder is treated as
directly owning an interest in the Royalty Interests, each Unitholder is taxed directly on his per
Unit pro rata share of income attributable to the Royalty Interests consistent with the
Unitholders method of accounting and without regard to the taxable year or accounting method
employed by the Trust. Coal seam gas produced and sold after December 31, 2002, no longer generates a Section 29 tax
credit under the Code. Therefore, Unitholders are not entitled to claim Section 29 tax credits for
coal seam gas produced and sold after 2002. However, a Unitholder may benefit from unused Section
29 tax credits for alternative minimum tax purposes. Before its expiration, the Section 29 tax
credit could be used only to the extent that a Unitholders regular tax liability exceeded the
Unitholders tentative minimum tax liability after the regular tax liability had been reduced by
the foreign tax credit and certain nonrefundable personal credits. Any part of the Section 29 tax
credit not allowed for the tax year solely because of this alternative minimum tax limitation was
subject to certain carryover provisions relating to the alternative minimum tax calculation.
Except for the foregoing, there were no other Code provision that allowed for the carryback or
carryforward of Section 29 tax credits. As the carryforward of unused Section 29 tax credits is
related to the alternative minimum tax calculation for succeeding years, carryforwards should
continue to be allowed, even though the Section 29 tax credit is no longer allowed for coal seam
gas produced and sold after 2002. Each Unitholder should consult his tax advisor regarding Trust tax compliance matters. 48




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##### Table of Contents



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 2004
this fee was $400,239 and will increase annually by three percent. Aggregate fees paid by the
Trust to Dominion Resources in 2004, 2003 and 2002 were $400,239, $388,582, and $380,031,
respectively. Aggregate fees and expense reimbursements paid by the Trust to the Trustees in 2004, 2003, and
2002 were $45,024, $43,852 and $43,003, respectively. 5. Distributions to Unitholders The Trustee determines for each calendar quarter the amount of cash available for distribution
to Unitholders. Such amount (the Quarterly Distribution Amount) is an amount equal to the
excess, if any, of the cash received by the Trust attributable to production from the Royalty
Interests during such quarter, provided that such cash is received by the Trust on or before the
last business day prior to the 45th day following the end of such calendar quarter, plus the amount
of interest expected by the Trustee to be earned on such cash proceeds during the period between
the date of receipt by the Trust of such cash proceeds and the date of payment to the Unitholders
of such Quarterly Distribution Amount, plus all other cash receipts of the Trust during such
quarter (to the extent not distributed or held for future distribution as a Special Distribution
Amount (as defined below) or included in the previous Quarterly Distribution Amount) (which might
include sales proceeds not sufficient in amount to qualify for a special distribution as described
in the next paragraph), over the liabilities of the Trust paid during such quarter and not taken
into account in determining a prior Quarterly Distribution Amount, subject to adjustments for
changes made by the Trustee during such quarter in any cash reserves established for the payment of
contingent or future obligations of the Trust. An amount that is 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. 49




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6. Subsequent Events Subsequent to December 31, 2004, the Trust declared and paid the following distribution: Quarterly Record Date
    
    Payment Date
    
    Distribution per UnitMarch 1, 2005
    
    March 11, 2005
    
    $.927955
 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, 2004 and 2003 (in
thousands, except per Unit amounts): DistributableCalendar Quarter
    
    Royalty Income
    
    
    Distributable Income
    
    
    Income per Unit2004First
    
    $
    4,751
    
    
    $
    4,508
    
    
    $
    .57Second
    
    
    6,541
    
    
    
    6,261
    
    
    
    .80Third
    
    
    6,577
    
    
    
    6,361
    
    
    
    .81Fourth
    
    
    6,471
    
    
    
    6,320
    
    
    
    .81$
    24,340
    
    
    $
    23,450
    
    
    $
    2.992003First
    
    $
    5,229
    
    
    $
    4,950
    
    
    $
    .63Second
    
    
    5,707
    
    
    
    5,498
    
    
    
    .70Third
    
    
    5,094
    
    
    
    4,850
    
    
    
    .62Fourth
    
    
    4,717
    
    
    
    4,538
    
    
    
    .58$
    20,747
    
    
    $
    19,836
    
    
    $
    2.53
 Selected 2004 fourth quarter data are as follows (in thousands, except per Unit amounts): Royalty income
    
    $
    6,471Interest income
    
    
    7General and administrative expenses
    
    
    (158
    )Distributable income
    
    $
    6,320Distributable income per Unit
    
    $
    .81Distributions per Unit
    
    $
    .81
 50




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Due to significant revisions in estimate of reserve quantities (see Note 8), estimated
amortization of royalty interests decreased by approximately $0.1 million, decreased by
approximately $0.1 million and increased by approximately $0.1 million during the fourth quarters
of 2004, 2003 and 2002, 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, 2004, 2003, 2002, and January 1, 2002, 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, 2004, 2003, and
January 1, 2003, were $6.0435, $5.89 and $4.10 per Mcf, respectively, including the effect of the Gas
Purchase Agreement through its termination on January 31, 2004 (see Note 9). As of February 15,
2005, published Gas prices were approximately $6.30 per Mcf. The use of such price as compared to
$5.56 per Mcf, which was used to calculate the above information, would result in a larger
standardized measure of discounted future net cash flows for Gas. Numerous uncertainties are inherent in estimating volumes and value of proved reserves and in
projecting future production rates and timing of development expenditures. Such reserve estimates
are subject to change as additional information becomes available. The reserves actually recovered
and the timing of production may be substantially different from the original estimates. Detailed information concerning the number of wells on royalty properties is not generally
available to the owner of royalty interests. Consequently, the Registrant does not have
information that would be disclosed by a company with oil and gas operations, such as an accurate
count of the number of wells located on the Underlying Properties, the number of exploratory or
development wells drilled on the Underlying Properties during the periods presented by this report,
or the number of wells in process or other present activities on the Underlying Properties, and the
Registrant cannot readily obtain such information. The reserve estimates for the Royalty Interests are based on a percentage share of the
Companys Gross Proceeds payable to the Trust of 65 percent. Proved developed reserves at January 1, 2002
    
    
    50,964Revisions of previous estimates
    
    
    (2,422
    )Production (mmcf)
    
    
    (5,957
    )Proved developed reserves at December 31, 2002
    
    
    42,585Revisions of previous estimates
    
    
    4,138Production (mmcf)
    
    
    (5,137
    )Proved developed reserves at December 31, 2003
    
    
    41,586Revisions of previous estimates
    
    
    2,210Production (mmcf)
    
    
    (4,695
    )Proved developed reserves at December 31, 2004
    
    
    39,101
 51




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All proved reserve estimates presented above at December 31, 2004, 2003, 2002, and January 1,
2002, are proved developed. Proved developed reserves, all located in the United States, for the Trusts Interests are
estimated quantities of coal seam gas that geological and engineering data indicate with reasonable
certainty to be recoverable in future years from the coal formation under existing economic and
operating conditions. The Trusts proved developed reserves are proved reserves that can be
expected to be recovered through existing wells with existing equipment and operating methods. The following table sets forth the standardized measure of discounted estimated future net
cash flows from proved reserves at December 31, 2004, 2003 and 2002 relating to the Trusts Royalty
Interests (thousands of dollars): 2004
    
    
    2003
    
    
    2002Future cash inflows
    
    $
    217,358
    
    
    $
    225,561
    
    
    $
    174,543Future severance taxes
    
    
    (13,042
    )
    
    
    (13,534
    )
    
    
    (10,473
    )Future net cash flows
    
    
    204,316
    
    
    
    212,027
    
    
    
    164,07010% annual discount for estimated timing
of cash flow
    
    
    (90,876
    )
    
    
    (94,743
    )
    
    
    (68,507
    )Standardized measure of discounted
future net cash flows
    
    $
    113,440
    
    
    $
    117,284
    
    
    $
    95,563
 Future cash flows do not include Section 29 tax credits, which no longer apply for coal seam
gas produced and sold after December 31, 2002, as discussed in Note 3. 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, 2004, 2003 and 2002 (thousands of
dollars): 2004
    
    
    2003
    
    
    2002Balance at beginning of period
    
    $
    117,284
    
    
    $
    95,563
    
    
    $
    85,244Increase (decrease) due to:Royalty income, net of taxes
    
    
    (24,340
    )
    
    
    (20,269
    )
    
    
    (19,988
    )Changes in prices
    
    
    1,755
    
    
    
    30,434
    
    
    
    48,600Changes in estimated volumes
    
    
    7,013
    
    
    
    2,000
    
    
    
    (26,817
    )Accretion of discount
    
    
    11,728
    
    
    
    9,556
    
    
    
    8,524Balance at December 31
    
    $
    113,440
    
    
    $
    117,284
    
    
    $
    95,563
 9. Gas Purchase Agreement El Paso Merchant EnergyGas, L.P. (El Paso) , as successor to Sonat Marketing Company
(Sonat Marketing) was required under a gas purchase agreement to purchase the gas produced from
the Underlying Properties until such agreement was terminated, effective January 31, 2004. 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 52




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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. 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 was $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 was 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 Prixe Quantity described in the
immediately preceding sentence applied 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 was the sum of the Index Price and $.02 per MMBtu, multiplied by 0.9826, the
wet/dry conversion factor. Effective January 31, 2004, the Gas Purchase Agreement was terminated.
Since February 1, 2004, Gas has been sold on a month to month basis to various purchasers until
such time as a long-term contract can be secured. 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, was Southern Natural Gas Companys posted
index price for deliveries of gas in Louisiana. 
 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None. 
 Item 9A. Controls and Procedures. 
 Disclosure Controls and Procedures As of the end of the period covered by this report, the Trustee carried out an evaluation of
the effectiveness of the design and operation of the Trusts disclosure controls and procedures
pursuant to Exchange Act Rules 13a-15 and 15d-15. Based upon that evaluation, the Trustee
concluded that the Trusts disclosure controls and procedures are effective in timely alerting the
Trustee to material information relating to the Trust required to be included in the Trusts
periodic filings with the Securities and Exchange Commission. In its evaluation of disclosure
controls and procedures, the Trustee has relied, to the extent considered reasonable, on
information provided by the Company. 
 Trustees Report on Internal Control Over Financial Reporting As
permitted by the Order Under Section 36 of the Securities Exchange
Act of 1934 Granting an Exemption from Specified Provisions of
Exchange Act Rules 13a-1 and 15d-1 issued by the SEC on November 30,
2004, the Trustee will file the Trustee's Report on Internal Control
Over Financial Reporting and the related Attestation Report of
Deloitte & Touche LLP, an independent registered public accounting firm, by April 30, 2005 through an amendment to this annual report on Form 10-K. 53




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There has not been any change in the Trusts internal control over financial reporting during
the fourth quarter of 2004 that has materially affected, or is reasonably likely to materially
affect, the Trusts internal control over financial reporting. 
 54




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Item 9B. Other Information.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. Audit Committee and Nominating Committee.Because the Trust has no directors, it does not
have an audit committee, an audit committee financial expert or a nominating committee. Compliance withSection 16(a)of the Exchange Act. The Trust has no directors and officers
and knows of no Unitholder that is a beneficial owner of more than 10 percent of the 55




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outstanding
Units and is therefore unaware of any person that failed to report on a timely basis reports
required by Section 16(a) of the Exchange Act. Code of Ethics.Because the Trust has no employees, it does not have a code of ethics.
Employees of the Trustee, Bank of America, N.A., must comply with the banks code of ethics, a copy
of which will be provided to Unitholders, without charge, upon request made to Bank of America,
N.A., Trustee, 901 Main Street, 17th Floor, Dallas, Texas 75202, Attention: Ron Hooper. 
 Item 11. Executive Compensation.The following is a description of certain fees and expenses
anticipated to be paid or borne by the Trust, including fees expected to be paid to Dominion
Resources, the Trustee, the Delaware Trustee, Mellon Investor Service, L.L.C. (as successor to
Chemical Shareholder Services Group, Inc.) (the Transfer Agent) or their respective affiliates. Ongoing Administrative Expenses.The Trust is responsible for paying all fees, charges,
expenses, disbursements and other costs incurred by the Trustee in connection with the discharge of
its duties pursuant to the Trust Agreement, including, without limitation, trustee fees,
engineering, audit, accounting and legal fees and expenses, printing and mailing costs, amounts
reimbursed or paid to the Company or Dominion Resources pursuant to the Trust Agreement or the
Administrative Services Agreement and the out-of-pocket expenses of the Transfer Agent. Compensation of the Trustee.The Trust Agreement provides that the Trustee is to be
compensated for its administrative services and preparation of quarterly and annual statements, out
of the Trust assets, in an annual amount of $28,858, plus an hourly charge for services in excess
of a combined total of 350 hours annually at its standard rate, which is currently $125 per hour.
These service fees escalate by three percent annually. The Delaware Trustee is compensated for its
administrative services, in an annual amount of $5,000, which will be paid 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 2004, the Trustee and the Delaware Trustee received total
compensation of $38,858 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. 56




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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, 2005, Bank of America, N.A., the Trustee, beneficially owned 9,097 units. Mellon Bank
(DE) National Association, the Delaware Trustee, did not beneficially own any Units. Changes in Control.The Trustee knows of no arrangements the operation of which may at a
subsequent date result in a change in control of the Registrant. 
 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 $400,239 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 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 57




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credits (before the Section 29
tax credit expired for coal seam gas produced and sold after 2002). The terms of the Conveyance
provide, however, that the Company Interests Owner will make decisions with respect to the Company
Interests pursuant to the standard of a reasonably prudent operator. Sale or abandonment of Underlying Properties may terminate assurances.The Company Interests
Owners interests may conflict with those of the Trust and Unitholders in situations involving the
sale or abandonment of Underlying Properties. The Company Interests Owner has the right at any
time to sell any of the Underlying Properties subject to the Royalty Interests and may abandon a
well or lease included in the Underlying Properties if such well or lease is not capable of
producing in commercial quantities, determined before giving effect to the Royalty Interests.
Under certain circumstances, a sale or abandonment will effectively terminate Dominion Resources
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. Principal Accounting Fees and Services. Fees for services performed by Deloitte & Touche LLP for the years ended December 31, 2004 and
2003 are: 2004
    
    
    2003Audit Fees
    
    $
    79,000
    
    
    $
    79,000Audit-related fees
    
    
    
    
    
    
    Tax fees
    
    
    
    
    
    
    All other fees
    
    
    9,300
    
    
    
    7,500$
    87,300
    
    
    $
    86,500
 As referenced in Item 10 above, the Trust has no audit committee, and as a result, has no
audit committee pre-approval policy with respect to fees paid to Deloitte & Touche LLP. 
 PART IV. 
 Item 15. Exhibits, Financial Statement Schedules.(a) The following documents are filed as a part
of this report: 
 Financial Statements (included in Item 8 of this report) Report of Independent Registered Public Accounting Firm Statements of Assets, Liabilities and Trust Corpus as of December 31, 2004 and 2003 Statements of Distributable Income for the years ended December 31, 2004, 2003 and 2002 Statements of Changes in Trust Corpus for the years ended December 31, 2004, 2003 and 2002 58




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Notes to Financial Statements 
 Financial Statement Schedules Financial statement schedules are omitted because of the absence of conditions under which
they are required or because the required information is included in the financial statements and
notes thereto. 
 Exhibits No.
    
    
    
    Exhibit3.1
    
    
    
    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
 59




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No.
    
    
    
    Exhibitthe 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.31.1
    
    
    
    Certification required by Rule 13a-14(a)/15d-14(a).32.1
    
    
    
    Certification required by Rule 13a-14(b)/15d-14(b) and Section 906 of the
Sarbanes Oxley Act of 2002.99.1
    
    
    
    The information under the sections captioned Federal Income Tax
Consequences, 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 10, 2005, on the estimated
reserves, estimated future net revenues and the discounted estimated future
net revenues attributable to the Royalty Interests as of January 1, 2005,
prepared by Ralph E. Davis & Associates Petroleum Engineers, independent
petroleum engineers.
   *
    
    On its own behalf and as sponsor of the Dominion Resources Black Warrior Trust 60




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SIGNATURES Pursuant to the requirements of Section 13 or15(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 TrustBy:
    Bank of America, N.A., Trustee By:

/s/
Ron E. HooperRon E. HooperDate: March 16, 2005
    
    Senior Vice President and Administrator (The Registrant has no directors or executive officers.) 61




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Index to Exhibits No.
    
    
    
    Exhibit3.1
    
    
    
    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
 62




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##### Table of Contents



No.
    
    
    
    ExhibitMerchant 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.31.1
    
    
    
    Certification required by Rule 13a-14(a)/15d-14(a).32.1
    
    
    
    Certification required by Rule 13a-14(b)/15d-14(b) and Section 906 of the
Sarbanes Oxley Act of 2002.99.1
    
    
    
    The information under the sections captioned Federal Income Tax
Consequences, 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 10, 2005, on the estimated
reserves, estimated future net revenues and the discounted estimated future
net revenues attributable to the Royalty Interests as of January 1, 2005,
prepared by Ralph E. Davis & Associates Petroleum Engineers, independent
petroleum engineers.
   *
    
    On its own behalf and as sponsor of the Dominion Resources Black Warrior Trust 63