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UNITED STATES SECURITIES AND EXCHANGE
COMMISSION

Washington, D.C. 20549





FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2011

OR



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





Commission file number: 001-11335

Dominion Resources Black Warrior Trust

(Exact name of registrant as specified in its charter)



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

U.S. Trust, Bank of America

Private Wealth Management

901 Main Street

17th Floor

Dallas, Texas
75202

(Address of principal executive offices; Zip Code)

Registrants telephone number, including area code:

(214) 209-2400

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



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

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

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes   ̈        No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x        No  
 ̈

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of
Regulations S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes   ̈        No   ̈

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form
10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of large accelerated filer,
accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.



|                           |  |                       |  |                           |  |                              
|-------------------------- |  | --------------------- |  | ------------------------- |  | -----------------------------
|Large accelerated filer   ̈ |  | Accelerated filer  
x |  | Non-accelerated filer  
 ̈ |  | Smaller reporting company    ̈

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act).    Yes   ̈        
No  x

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 $80,933,500.

At March 12, 2012,
there were 7,850,000 units of beneficial interest outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None









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TABLE OF CONTENTS



|                                                        |  |                                                                                                              |    |  |    | 
|------------------------------------------------------- |  | ------------------------------------------------------------------------------------------------------------ | -- |  | -- | 
|PART I                                                  |  |                                                                                                              | 1  | 
|Item 1.                                                 |  | Business                                                                                                     |    |  | 1  | 
|GLOSSARY                                                |  |                                                                                                              | 1  | 
|DESCRIPTION OF THE TRUST                                |  |                                                                                                              | 3  | 
|DESCRIPTION OF UNITS                                    |  |                                                                                                              | 8  | 
|FEDERAL INCOME TAX CONSIDERATIONS                       |  |                                                                                                              | 12 | 
|ERISA CONSIDERATIONS                                    |  |                                                                                                              | 15 | 
|STATE TAX CONSIDERATIONS                                |  |                                                                                                              | 15 | 
|REGULATION AND PRICES                                   |  |                                                                                                              | 16 | 
|Item 1A.                                                |  | Risk Factors                                                                                                 |    |  | 19 | 
|Item 1B.                                                |  | Unresolved Staff Comments                                                                                    |    |  | 23 | 
|Item 2.                                                 |  | Properties                                                                                                   |    |  | 23 | 
|THE ROYALTY INTERESTS                                   |  |                                                                                                              | 23 | 
|Item 3.                                                 |  | Legal Proceedings                                                                                            |    |  | 30 | 
|Item 4.                                                 |  | Mine Safety Disclosures                                                                                      |    |  | 30 | 
|PART II                                                 |  |                                                                                                              | 31 | 
|Item 5.                                                 |  | Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities |    |  | 31 | 
|Item 6.                                                 |  | Selected Financial Data                                                                                      |    |  | 31 | 
|Item 7.                                                 |  | Trustees Discussion and Analysis of Financial Condition and Results of Operations                           |    |  | 32 | 
|Item 7A.                                                |  | Quantitative and Qualitative Disclosures About Market Risk                                                   |    |  | 36 | 
|Item 8.                                                 |  | Financial Statements and Supplementary Data                                                                  |    |  | 37 | 
|REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM |  |                                                                                                              | 37 | 
|Item 9.                                                 |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure                         |    |  | 46 | 
|Item 9A.                                                |  | Controls and Procedures                                                                                      |    |  | 46 | 
|Item 9B.                                                |  | Other Information                                                                                            |    |  | 48 | 
|PART III                                                |  |                                                                                                              | 48 | 
|Item 10.                                                |  | Directors, Executive Officers and Corporate Governance                                                       |    |  | 48 | 
|Item 11.                                                |  | Executive Compensation                                                                                       |    |  | 48 | 
|Item 12.                                                |  | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters               |    |  | 49 | 
|Item 13.                                                |  | Certain Relationships and Related Transactions, and Director Independence                                    |    |  | 49 | 
|Item 14.                                                |  | Principal Accounting Fees and Services                                                                       |    |  | 50 | 
|PART IV                                                 |  |                                                                                                              |    |  | 51 | 
|Item 15.                                                |  | Exhibits, Financial Statement Schedules                                                                      |    |  | 51 | 



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PART I.



|Item 1. | Business.
|------- | ---------

GLOSSARY

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

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

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

Bcf means billion cubic feet of natural gas.

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

Code means the Internal Revenue Code of 1986, as amended.

Company means
Walter Black Warrior Basin LLC, formerly known as HighMount Black Warrior Basin LLC, a Delaware limited liability company, as successor to Dominion Black Warrior Basin, Inc., an Alabama corporation.

Company Interests means the Companys interest in the Underlying Properties, as of June 1, 1994, not burdened by the Royalty
Interests.

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

ConocoPhillips means ConocoPhillips Corporation, successor to The River Gas Corporation.

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

Delaware Trustee
means Mellon Bank (DE) National Association.

Dominion Resources means Dominion Resources, Inc., a Virginia corporation.

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

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

Gas means natural gas produced and sold from the Underlying Properties.

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

Grantor Trust means a trust as to which the grantor is treated as the owner of the trust income and corpus under the applicable
provisions of the Code and the Treasury Regulations thereunder.



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

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

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

HighMount Alabama means HighMount Exploration & Production Alabama LLC, a Delaware limited liability company, now known as
Walter Exploration & Production LLC.

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

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

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

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

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

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

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

Ralph E. Davis & Associates means Ralph E. Davis & Associates, independent petroleum engineers.

Reserve Estimate means the estimated net proved reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests as of December 31,
2011, prepared by Ralph E. Davis & Associates.

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

Sonat Marketing means Sonat Marketing Company, a Delaware Corporation.

Subject
Gas means Gas attributable to the Company Interests.

Treasury Regulations means the United States treasury
regulations promulgated under the Code.

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



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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. References in this Form 10-K to U.S. Trust, Bank of
America Private Wealth Management also describe the legal entity Bank of America, N.A.

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

Unitholder means a holder of Units evidencing beneficial interest in the Trust.

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

Walter Exploration & Production means Walter Exploration & Production LLC, a Delaware limited liability
company, previously known as HighMount Exploration & Production Alabama LLC.

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.

DESCRIPTION OF THE TRUST

Dominion Resources Black Warrior Trust is a Delaware business trust formed under the Delaware Business Trust Act, Title 12, Chapter 38 of the
Delaware Code, Section 3801 et seq. (the Delaware Code). The following information is subject to the detailed provisions of the Trust Agreement and the Conveyance, copies of which are filed as exhibits to this Form 10-K. The
provisions governing the Trust are complex and extensive, and no attempt has been made below to describe or reference all of such provisions. The following is a general description of the basic framework of the Trust and the material provisions of
the Trust Agreement.

Creation and Organization of the Trust

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

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

On May 28, 2010, Walter Natural Gas,
LLC, a wholly owned subsidiary of Walter Energy, LLC, acquired the Alabama natural gas interests of HighMount, effective March 1, 2010. The acquisition included the Companys Alabama coal bed



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methane operations, including the 532 existing conventional gas wells in which the Trust has a net profits interest. The transaction was structured as an acquisition of the membership interests
in HighMount Alabama, following which, HighMount Alabamas name was changed to Walter Exploration & Production LLC. Walter Exploration & Production will continue to be party to the Administrative Services Agreement and Trust
Agreement. Walter Exploration & Production will continue to own all the interests in the Company, and the Company, which has changed its name to Walter Black Warrior Basin LLC, will continue to own the Underlying Properties. References
herein to Walter Exploration & Production for periods prior to the May 28, 2010 acquisition refer to HighMount Alabama. The Trust continues to have ownership in the Royalty Interests burdening the Underlying
Properties and such sale did not affect that ownership.

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 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 Walter Exploration & Productions
assurances. For a description of the Underlying Properties, the Royalty Interests and other information relating to such properties, see Properties  The Royalty Interests.

The Trust Agreement authorizes the Trustee to take such action as in its judgment is necessary, desirable or advisable to best achieve the purposes
of the Trust. The Trustee is empowered by the Trust Agreement to employ consultants and agents (including the Company) and to make payments of all fees for services or expenses out of the assets of the Trust. The Trustee is authorized to agree to
modifications of the terms of the Conveyance and to settle disputes with respect thereto, so long as such modifications or settlements do not result in the treatment of the Trust as an association taxable as a corporation for federal income tax
purposes and such modifications or settlements do not alter the nature of the Royalty



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Interests as a right to receive a share of production or the proceeds of production from the Underlying Properties, which, with respect to the Trust, are free of any operating rights, expenses or
obligations. The Trust Agreement provides that cash being held by the Trustee as a reserve for liabilities or for distribution at the next distribution date will be placed in demand deposit accounts, U.S. government obligations, repurchase
agreements secured by such obligations or certificates of deposit, but the Trustee is otherwise prohibited from acquiring any asset other than the Royalty Interests and cash proceeds therefrom or engaging in any business or investment activity of
any kind whatsoever. The Trustee may deposit funds awaiting distribution in an account with the Trustee provided the interest rate paid equals the interest rate paid by the Trustee on similar deposits.

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

Resignation of Trustees

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

Transfer of Royalty Interests

Prior to the
termination of the Trust, the Trustee is not authorized to sell or otherwise dispose of all or any part of the Royalty Interests. The Trustee is authorized and directed to sell and convey the Royalty Interests without Unitholder approval upon
termination of the Trust. No Unitholder approval for sales or dispositions upon termination is required even though they may constitute a disposition of all or substantially all the assets of the Trust. Any sales upon termination may be made to
Walter Exploration & Production 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 Walter Exploration & Production. If a
court were to hold that the Trust is taxable as a corporation for federal income tax purposes, then the Trust would incur substantial federal income tax liabilities. See Federal Income Tax Considerations.

Liabilities of the Trustee and the Delaware Trustee

Each of the Trustee and the Delaware Trustee may act in its discretion and is personally or individually liable only for fraud or acts or omissions in bad faith or that constitute gross negligence (and for taxes,
fees and other charges on, based on or measured by any fees, commissions or compensation received pursuant to the Trust Agreement) and will not be otherwise liable for any act or omission of any agent or employee unless such Trustee has acted in bad
faith or with gross negligence in the selection and retention of such agent or employee. Each of the Trustee and the Delaware Trustee (and their respective agents) is indemnified by Walter Exploration & Production 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 Walter Exploration & Production. Walter Exploration &
Production 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



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the Trustee pursuant to the foregoing provisions, the Trustee has been informed that in the opinion of the Securities and Exchange Commission (the SEC), such indemnification is
against public policy as expressed in the Securities Act and is, therefore, unenforceable.

Termination and Liquidation of the Trust

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

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

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

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

The
Companys purchase rights, as described above, may be exercised by the Company and each of its successors in interest and assigns. The Companys purchase rights are fully assignable by the Company to any person or entity. The costs of
liquidation, including the fees and expenses of the Advisor and the Trustees liquidation fee, will be paid by the Trust.



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The Trust may terminate without Unitholder approval. Unitholders are not entitled to any rights of
appraisal or similar rights in connection with the termination of the Trust. The sale of the remaining Royalty Interests and the termination of the Trust will be taxable events to the Unitholders. Generally, a Unitholder will realize gain or loss
equal to the difference between the amount realized on the sale and termination of the Trust and his adjusted basis in such Units. The amount realized by the Trust upon termination will be allocated to Unitholders in the same manner as the Trustee
allocates the income received by the Trust. Gain or loss realized by a Unitholder who is not a dealer with respect to such Units and who has a holding period for the Units of more than one year will be treated as long-term capital gain or loss
except to the extent of any depletion recapture amount, which must be treated as ordinary income. Other federal and state tax issues concerning the Trust are discussed herein under Business  Federal Income Tax Considerations and
Business  State Tax Considerations. Each Unitholder should consult his own tax advisor regarding Trust tax compliance matters, including federal and state tax implications concerning the sale of the Royalty Interests and the
termination of the Trust.

Arbitration and Actions by Unitholders

Pursuant to the Trust Agreement and the Assignment and Assumption Agreement, any dispute, controversy or claim that may arise between or among Walter Exploration & Production 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 Walter Exploration & Production 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 Walter Exploration & Production and the Company with respect to any breach by Walter Exploration & Production 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 Walter Exploration & Production to the Trust, does not provide for any procedure allowing Unitholders to direct the Trustee to bring an
action on behalf of the Trust to enforce the Trusts rights under the Conveyance. Each Unitholder has a statutory right, however, under Section 3816 of the Delaware Code to bring a derivative action in the Delaware Court of Chancery on
behalf of the Trust to enforce the rights of the Trust if the Trustee has refused to bring the action or if an effort to cause the Trustee to bring the action is not likely to succeed. The procedures for the arbitration of disputes enumerated in the
Trust Agreement neither bar nor restrict the statutory right of any Unitholder under Section 3816 of the Delaware Code to bring a derivative action.

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

In the event that any Unitholder was successful in bringing a derivative action on behalf of the Trust to enforce rights on behalf of the Trust
against Walter Exploration & Production or the Company, then such Unitholder could, on behalf of the



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Trust, pursue such rights against Walter Exploration & Production 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 Walter Exploration & Productions obligation to cure certain deficiencies under the Trust Agreement is subject to the restriction that such right
may only be exercised by Unitholders owning of record not less than 25 percent of the Units then outstanding (treated as a single class) and then only absent action by the Trustee to enforce any such obligation within 10 days following receipt by
the Trustee of a written request served upon the Trustee by such Unitholders to take such action. In such an event, Unitholders owning of record not less than 25 percent of the Units then outstanding may, acting as a single class and on behalf of
the Trust, seek to enforce such obligations. See Properties  The Royalty Interests  Walter Exploration & Productions Assurances.

DESCRIPTION OF UNITS

Each Unit represents an equal undivided share
of beneficial interest in the Trust and is evidenced by a transferable certificate issued by the Trustee. Each Unit entitles its holder to the same rights as the holder of any other Unit, and the Trust has no other authorized or outstanding class of
equity security. At March 12, 2012, there were 7,850,000 Units outstanding. The Trust may not issue additional Units.

Distributions and Income
Computations

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

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



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Distribution Amount will be the 15th day following receipt of amounts aggregating a Special Distribution Amount by the Trust (unless such day is not a business day in which case the record date
will be the next business day thereafter) unless such day is within 10 days prior to the record date for a Quarterly Distribution Amount in which case the record date will be the date as is established for the next Quarterly Distribution Amount.
Distributions to Unitholders will be no later than 15 days after the Special Distribution Amount record date.

Conditional Right of Repurchase

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

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

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



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Dominion Resources assigned its rights under the Trust Agreement to Walter Exploration &
Production pursuant to the Assignment and Assumption Agreement.

Possible Divestiture of Units

The Trust Agreement imposes no restrictions based on nationality or other status of Unitholders. The Trust Agreement provides, however, that in the
event of certain judicial or administrative proceedings seeking the cancellation or forfeiture of any property in which the Trust has an interest, or asserting the invalidity of, or otherwise challenging any portion of the Royalty Interests because
of the nationality, citizenship or any other status of any one or more Unitholders, the Trustee will give written notice thereof to each Unitholder whose nationality, citizenship or other status is an issue in the proceeding, which notice will
constitute a demand that such Unitholder dispose of his Units within 30 days. If any Unitholder fails to dispose of his Units in accordance with such notice, the Trustee will cancel all outstanding certificates issued in the name of such Unitholder,
transfer all Units held by such Unitholder to the Trustee and sell such Units (including by private sale). The proceeds of such sale (net of sales expenses), pending delivery of certificates representing the Units, will be held by the Trustee in a
non-interest bearing account for the benefit of the Unitholder and paid to the Unitholder upon surrender of such certificates. Cash distributions payable to such Unitholder will also be held in a non-interest bearing account pending disposition by
the Unitholder of the Units or cancellation of certificates representing the Units by the Trustee, subject to a maximum retention period of two years or such shorter period as shall be permitted by applicable laws.

Periodic Reports

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

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

The Trustee files such returns for
federal income tax purposes as it is advised are required to comply with applicable law. The Trustee mails to each person or entity who was a Unitholder of record (i) on the record date for each such calendar quarter and (ii) on a Special
Distribution Amount record date occurring during such quarter, if any, a report that shows in reasonable detail information to permit each Unitholder to make all calculations reasonably necessary for tax purposes. The Trustee treats all income,
credits and deductions recognized during each calendar quarter during the term of the Trust as having been recognized by holders of record on the quarterly record date established for the distribution unless otherwise advised by counsel. Available
year-end tax information permitting each Unitholder to make all calculations reasonably necessary for tax purposes is distributed by the Trustee to Unitholders no later than March 15 of the following year. See also page 23 regarding certain
reporting requirements imposed upon middlemen under Treasury Regulations because the Trust is considered a non-mortgage WHFIT for federal income tax purposes.

Each Unitholder and his duly authorized agents and attorneys have the right during reasonable business hours, and upon reasonable prior notice, to examine and inspect records of the Trust and the Trustee and the
Delaware Trustee.



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Voting Rights of Unitholders

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

Meetings of Unitholders may
be called by the Trustee or by Unitholders owning not less than 10 percent of the outstanding Units. In addition, the Delaware Trustee may call such a meeting but only for the purpose of appointing a successor to it upon its resignation. All
meetings of Unitholders will be held in Dallas, Texas. Written notice of every such meeting setting forth the time and place of the meeting and the matters proposed to be acted upon will be given not more than 60 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 Walter Exploration & Production. 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 Walter Exploration & Production and the
approval of not less than 662/3percent 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 Walter Exploration & Production and the approval of a majority of the outstanding Units, no amendment may be made to the Trust Agreement that would alter Walter Exploration & Productions
conditional right to repurchase all outstanding Units at any time at which 15 percent or less of the outstanding Units is owned by persons or entities other than Walter Exploration & Production 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, Walter Exploration & Production 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) Walter Exploration & Production 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, Walter Exploration & Production 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.

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.



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Transfer Agent

American Stock Transfer & Trust Company serves as the transfer agent and registrar for the Units.

Website/SEC Filings

The Trust maintains an
Internet Website at www.dom-dominionblackwarriortrust.com, and will provide website access to its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports as soon as reasonably
practicable after such material is filed with or furnished to the SEC.

FEDERAL INCOME TAX CONSIDERATIONS

THE TAX CONSEQUENCES TO A UNITHOLDER OF THE OWNERSHIP AND SALE OF UNITS WILL DEPEND IN PART ON THE UNITHOLDERS TAX
CIRCUMSTANCES. EACH UNITHOLDER SHOULD THEREFORE CONSULT THE UNITHOLDERS TAX ADVISOR ABOUT THE FEDERAL, STATE AND LOCAL TAX CONSEQUENCES TO THE UNITHOLDER OF THE OWNERSHIP OF UNITS.

The section entitled Federal Income Tax Consequences appearing in the Prospectus sets forth a discussion of the material federal income
tax matters of general application of the acquisition, ownership and sale of the Units acquired in the Public Offerings and a discussion of certain risk factors associated with matters of federal income taxation as applied to the Trust and such
Unitholders. A copy of such section of the Prospectus is filed as an exhibit to this Form 10-K and is incorporated herein by reference.

In connection with the registration of the Units for offer and sale in the Public Offerings, Dominion Resources and the Underwriters received
certain opinions of special counsel (Special Counsel) to Dominion Resources (upon which the Trustee and the Delaware Trustee were entitled to rely), including, without limitation, opinions as to the material federal income tax
consequences of the ownership and sale of the Units acquired in either of the Public Offerings. Each of these opinions was based on provisions of the Code existing as of June 28, 1994, with respect to the opinions given in connection with the
Initial Public Offering, and as of June 8, 1995, with respect to the opinions given in connection with the Secondary Public Offering, and existing and proposed regulations thereunder, administrative rulings and court decisions as of such dates,
all of which are subject to changes that may or may not be retroactively applied. Some of the applicable provisions of the Code have not been interpreted by the courts or the Internal Revenue Service (IRS). In addition, such opinions
were based on various representations as to factual matters made by the Company and Dominion Resources in connection with the Public Offerings. In addition, such opinions were expressly limited in their application to investors purchasing Units in
each of such Public Offerings and, as a result, provide no assurance to investors not purchasing Units in one of the Public Offerings.

Neither the Trustee, the Delaware Trustee, nor counsel to the Trustee, respectively, has rendered any opinions with respect to any tax matters
associated with the Trust or the Units.

At the time of the Public Offerings, no ruling was requested by Dominion Resources, as the
sponsor of the Trust, the Trustee or the Delaware Trustee from the IRS with respect to any matter affecting the Trust or Unitholders. No assurance can be provided that the opinions of Special Counsel (which do not bind the IRS) will not be
challenged by the IRS or will be sustained by a court if so challenged.



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Summary of Certain Federal Income Tax Consequences

The following summary of certain federal income tax consequences of acquiring, owning and disposing of Units is based on the opinions of Special
Counsel to Dominion Resources on federal income tax matters, which are set forth in the Prospectus, and is qualified in its entirety by express reference to the sections of the Prospectus identified in the first paragraph of this Federal
Income Tax Considerations section. Although the Trustee believes that the following summary contains a description of all of the material matters discussed in the opinions referenced above, the summary is not exhaustive and many other
provisions of the federal tax laws may affect individual Unitholders. Furthermore, the summary does not purport to be complete or address the tax issues potentially affecting Unitholders acquiring Units other than by purchase through either of the
Public Offerings. Each Unitholder should consult the Unitholders tax advisor with respect to the effects of the Unitholders ownership of Units on the Unitholders personal tax situation.



|Classification and Taxation of the Trust | The Trust is a Grantor Trust for federal tax purposes and not an association taxable as a corporation. As a Grantor Trust, the Trust is not subject to federal income tax. There can be no assurance that
the IRS will not challenge this treatment. The tax treatment of the Trust and Unitholders would be materially different if the IRS were to successfully challenge this treatment.
|---------------------------------------- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|Taxation of Unitholders | Each Unitholder is taxed directly on his proportionate share of income, deductions and credits of the Trust attributable to the Royalty Interests consistent with each such Unitholders taxable year
and method of accounting and without regard to the taxable year or method of accounting employed by the Trust.
|----------------------- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|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 2011, the Trust earned interest income on
funds held for distribution. The deductions of the Trust consist of severance taxes and administrative expenses. In addition, each Unitholder is entitled to depletion deductions. See Unitholders Depletion Allowance below.
|--------------------- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | Individuals may incur expenses in connection with the acquisition or maintenance of Trust Units. These expenses may be deductible as miscellaneous itemized deductions
only to the extent that such expenses exceed 2 percent of the individuals adjusted gross income.
| | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|Treatment of the Royalty Interests | Each Royalty Interest is a nonoperating economic interest in an Underlying Property because it is a right to a fixed percentage of the gross proceeds from the sale of gas as, if and when produced from
such properties, the right endures for the economic life of the burdened reserves and the right is not required to bear any cost of developing or producing such gas.
|---------------------------------- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|Unitholders Depletion Allowance | Each Unitholder is entitled to amortize the cost of the Units through cost depletion over the life of the Royalty Interests or, if greater, through percentage depletion equal to 15 percent of gross
income. Unlike cost depletion, percentage depletion is not limited to a Unitholders depletable tax basis in the Units. Rather, a Unitholder is entitled to a percentage depletion deduction as long as the applicable Underlying Properties
generate gross income. If any portion of the Royalty Interests is treated as a production payment or is not treated as an economic interest, however, a Unitholder will not be entitled to depletion in respect of such portion.
|-------------------------------- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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|Depletion Recapture | If a taxpayer disposes of any section 1254 property (certain oil, gas, geothermal or other mineral property), and if the adjusted basis of such property includes adjustments for deductions for
depletion under Section 611 of the Code, the taxpayer generally must recapture the amount deducted for depletion as ordinary income (to the extent of gain realized on the disposition of the property). This depletion recapture rule applies to any
disposition of property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the Treasury Regulations govern dispositions of property after March 13, 1995. The IRS
likely will take the position that a Unitholder who purchases a Unit subsequent to December 31, 1986, must recapture depletion upon the disposition of that Unit.
|------------------- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|Non-Passive Activity Income, Credits and Loss | The income, credits and expenses of the Trust are not taken into account in computing the passive activity losses and income under Section 469 of the Code for a Unitholder who acquires and holds Units as
an investment and not in the ordinary course of a trade or business.
|--------------------------------------------- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|Unitholder Reporting Information | The Trustee furnishes to Unitholders tax information concerning royalty income and depletion and other relevant tax matters on an annual basis. Year-end tax information is furnished to Unitholders no
later than March 15 of the following year. See third paragraph under Description of Units  Periodic Reports.
|-------------------------------- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|WHFIT Reporting Requirements | Some Trust Units are held by middlemen, as such term is broadly defined in Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a customer in
street name, referred to herein collectively as middlemen). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (WHFIT) for U.S. federal income tax purposes. U.S. Trust, Bank of
America Private Wealth Management, EIN: 56-0906609, 901 Main Street, 17th Floor, Dallas, Texas 75202, telephone number (214) 209-2400, is the representative of the Trust that will provide tax information in accordance with applicable Treasury
Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.dom-dominionblackwarriortrust.com. Notwithstanding the foregoing, the middlemen holding Trust Units on
behalf of Unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury Regulations with respect to such Trust Units, including the issuance of IRS Forms 1099 and
certain written tax statements. Unitholders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units.
|---------------------------- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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ERISA CONSIDERATIONS

The section entitled ERISA Considerations appearing in the Prospectus sets forth certain information regarding the applicability of the
Employee Retirement Income Security Act of 1974, as amended (ERISA), and the Code to pension, profit-sharing and other employee benefit plans and to individual retirement accounts (collectively, Qualified Plans). A copy of
this section of the Prospectus is filed as an exhibit to this Form 10-K and is incorporated herein by reference.

Due to the complexity
of the prohibited transaction rules and the penalties imposed upon persons involved in prohibited transactions, it is important that potential Qualified Plan investors consult their counsel regarding the consequences under ERISA and the Code of
their acquisition and ownership of Units.

STATE TAX CONSIDERATIONS

THE FOLLOWING IS INTENDED AS A BRIEF SUMMARY OF CERTAIN INFORMATION REGARDING STATE INCOME TAXES AND OTHER STATE TAX MATTERS AFFECTING THE TRUST
AND UNITHOLDERS. UNITHOLDERS SHOULD THEREFORE CONSULT THE UNITHOLDERS TAX ADVISOR REGARDING STATE INCOME TAX FILING AND COMPLIANCE MATTERS.

Alabama Income Tax

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

The Alabama
Department of Revenue (the DOR) has issued a letter ruling that permits the Trust to file a composite income tax return on behalf of all Unitholders who are not residents of Alabama. The filing of the composite income tax
return and acceptance of the return by the DOR will relieve those nonresident Unitholders of any obligation to file Alabama state income tax returns. The Trust filed for each of the years 1995-2010 composite income tax returns with the DOR on behalf
of all Nonresident Unitholders (defined below), and intends to file a composite return for 2011 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 2011. Accordingly, no Alabama state income tax is due under the 2011 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 2011 (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 would impose an unreasonable burden on the Trust in the judgment of the Trustee (based on its sole discretion). In that event, each Nonresident Unitholder would be required to file a separate Alabama state income tax return and pay any
Alabama state income tax due as well as any penalties and interest due thereon. For purposes of the filing of the composite income tax return for any taxable year, Nonresident Unitholders will consist of those Unitholders to whom the
Trust has provided an individualized tax information letter (together with its tax information booklet) for such tax year that shows a mailing address outside the State of Alabama. All other Unitholders will be treated by the Trust for purposes of
the filing of the composite income tax return as Resident Unitholders.



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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 also imposes a business privilege tax (the
BPT) 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. BPT liability is calculated by
multiplying the taxpayers net worth in Alabama (as such term is statutorily defined in Alabamas tax code) by the applicable tax rate. In 2002, the DOR issued a revenue ruling holding that the BPT applied to a grantor trust. Therefore,
the Trust files BPT returns and pays the applicable tax.

Alabama Severance Taxes

Alabama levies severance taxes on the removal of certain natural resources. Statewide severance taxes are collected from oil, gas, coal, forest
products and iron ore. Additional severance taxes are collected by certain counties on oil, gas, coal, stone, rock, clay, sand and gravel. Therefore, the Trust, as owner of the Royalty Interests, bears its proportionate share of Alabama state and
county severance taxes. To the extent there is an increase in the amount of severance taxes, the cash distribution amount payable to Unitholders will decrease.

Other Alabama Taxes

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

REGULATION AND PRICES

Regulation of Natural Gas

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

Sales of natural gas produced from the Underlying Properties are considered to be sold at the wellhead (as opposed to downstream sales or resales)
for purposes of pricing and, therefore, are not subject to federal regulation.

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

On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct FERC to
facilitate market transparency



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

The State Oil and Gas Board of Alabama regulates the production of natural gas, including requirements for obtaining drilling permits, the method
of developing new fields, provisions for the unitization or pooling of natural gas properties, the spacing, operation, plugging and abandonment of wells and the prevention of waste of natural gas resources. The rate of production may be regulated,
and the maximum daily production allowable from natural gas wells may be established on a market demand or conservation basis or both. Reductions in allowable production may extend the timing of recovery of reserves. Although the Trust is not aware
of any pending or contemplated proceedings to change allowable rates of production from the Underlying Properties, there can be no assurances made that such changes will not be made. The Unitholders and the Trust will not have any control over such
changes. Reductions in the allowable production from the Underlying Properties could affect the timing or amount of distributions to Unitholders.

Environmental Regulation

General.    Operations on the Underlying Properties associated with the production of natural gas are subject to numerous
complex and stringent federal, state and local laws, rules and regulations governing health, safety, environmental quality, disposal of waste, pollution control and discharge of materials into the environment, and otherwise relating to protection of
the environment. Such laws, rules and regulations may require the acquisition of permits and may also restrict air, water or other pollution resulting from operations. Failure by the Company to comply with these laws, rules or regulations may result
in significant liabilities, including administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the operations. The Company could also
be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination, in either case, at a drill site or a waste disposal facility, and regardless of whether the Company was
responsible for the release or contamination or had conducted the operations in compliance with all applicable laws at the time that the release or contamination occurred.

National Pollutant Discharge Elimination System (NPDES) Permit.    Water from the operations on the Underlying Properties is discharged into the Black Warrior River pursuant to a NPDES
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 2004, and a timely renewal application was submitted in 2009. The 2004 permit was administratively extended until such time as ADEM reviews and issues a renewal permit. It generally authorizes water disposal based upon
the Black Warrior Rivers minimum flow rate and maximum chloride level. The Company has advised the Trustee that since 1987 water disposal from the Underlying Properties has not been disrupted.

Climate Change.    Federal, state and local environmental laws, rules and regulations may become more
stringent in the future. For example, climate change has become the subject of an important public policy debate and the basis for new legislation proposed by the United States Congress and certain states. Climate change legislation and regulations
have been adopted by many foreign countries and some states in the United States. The United States Environmental Protection Agency (the EPA) issued greenhouse gas monitoring and reporting regulations that went into effect
January 1, 2010, and that required reporting by regulated facilities by September 30, 2011 and annually thereafter. On November 30, 2010, the EPA published a final rule that sets forth reporting requirements for the petroleum and
natural gas industry and requires companies that hold state drilling permits and that emit 25,000 metric tons or more of carbon dioxide equivalent per year to report annually carbon dioxide, methane and nitrous oxide emissions from certain sources
beginning on March 31, 2012. But on August 4, 2011, the EPA published a proposed rule containing technical amendments to certain greenhouse gas reporting requirements that included a six-month extension for the petroleum and natural gas
industry to report its greenhouse gas emissions.



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Beyond measuring and reporting, the EPA issued an Endangerment Finding under
Section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of future generations. The EPA has issued final regulations requiring operators of petroleum and natural gas operations that meet a
certain emission threshold to report the greenhouse gas emissions to the EPA. The EPA has indicated that it will use data collected through the reporting rules to decide whether to promulgate future greenhouse gas emission limits. On July 28,
2011, the EPA proposed four new regulations that, if finalized, would establish new source performance standards for volatile organic compounds (VOCs) and sulfur dioxide and establish an air toxic standard for oil and natural gas
production, transmission, and storage. Limiting emissions of VOCs will have the co-benefit of also limiting methane, a greenhouse gas. The proposed regulations would apply to wells that are hydraulically fractured, or refractured, and to storage
tanks and other equipment, and limit methane emissions from those sources. The EPA is expected to take final action by April 2012.

Hydraulic Fracturing.    Congress, the EPA and various states have proposed or adopted legislation
regulating hydraulic fracturing (or fracking), including requiring disclosure of the chemicals in the hydraulic fracturing fluid that is used in drilling operations. Hydraulic fracturing has historically been regulated by state oil and
natural gas commissions. Recently, however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act (the SDWA). The EPA has begun the process of
drafting guidance documents related to this newly asserted regulatory authority, which could include a broad definition of diesel that would cover a variety of oils that are not diesel but that have similar carbon-chain molecules. The EPA also plans
to investigate the treatment of wastewater from hydraulic fracturing for the purpose of setting new standards for discharges from natural gas drilling to publicly owned treatment works. In addition, certain other governmental reviews are either
underway or being proposed that focus onenvironmental aspects of hydraulic fracturing practices, including a four-year study by the EPA expected to be completed in 2014. These on-going or proposed reviews, depending on their scope and
results, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory programs.

Potential Effect of Environmental Laws and Regulations.    The Trustee cannot predict the precise effect that the
current legislation and regulations, any future legislation or regulations, or enforcement policies thereunder, could have on the operation of the Underlying Properties. While the Company has informed the Trustee that it believes the Underlying
Properties are in material compliance with all environmental laws and regulations, such laws and regulations have generally become more stringent and costly over time. The Company has also informed the Trustee that it has not budgeted any money for
expenditures related to environmental remediation in 2012, indicating that the Company does not anticipate significant environmental contamination in connection with, or as a result of, its operations. If, however, significant environmental
contamination occurs in 2012, the Company could incur significant costs to remediate the environmental contamination in accordance will all applicable laws and regulations. As a royalty holder, the Trust may not be directly subject to increased
costs to comply with environmental laws and regulations; however, such costs, including any costs associated with remediating environmental contamination, may be taken into account by the Company in exercising its rights to abandon a well, which may
accelerate the termination of the Trust. See Item 2  Properties  The Royalty Interests  Sale and Abandonment of Underlying Properties and Item 1  Business  Description of the Trust  Termination
and Liquidation of the Trust.

Competition, Markets and Prices

The revenues of the Trust and the amount of cash distributions to Unitholders depend upon, among other things, the effect of competition and other factors in the market for natural gas. The natural gas industry is
highly competitive in all of its phases. The Company encounters competition from major oil and gas companies, independent oil and gas concerns and individual oil and gas producers and operators. Many of these competitors have greater financial and
other resources than the Company. Competition may also be presented by alternative fuel sources, including heating oil, other fossil fuels and wind energy.

Demand for natural gas production has historically been seasonal in nature and prices for natural gas fluctuate accordingly. Unseasonably warm weather and the ability of markets to access storage can cause the
demand for natural gas to decrease, resulting in lower prices received by producers than when demand is higher due to seasonal weather factors.



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Such price fluctuations and the continuation of/return to low prices for natural gas will directly impact Trust distributions, estimates of reserves attributable to the Royalty Interests and
estimated future net revenue from reserves attributable to the Royalty Interests.

Prices for natural gas are subject to wide
fluctuations in response to relatively minor changes in supply, market uncertainty and a variety of additional factors that are beyond the control of the Trust and the Company. These factors include political conditions in the Middle East, the price
and quantity of imported oil and gas, the level of consumer product demand, the severity of weather conditions, government regulations, the price and availability of alternative fuels and overall economic conditions. Additionally, lower natural gas
prices may reduce the amount of gas that is economic to develop or produce from the Underlying Properties. In view of the many uncertainties affecting the supply and demand for natural gas and natural gas prices, the Trustee is unable to make
reliable predictions of future gas prices, production or demand or the overall effect they will have on the Trust.

The Trusts
revenues and distributions to Unitholders will be primarily dependent on the sales prices for Gas produced from the Underlying Properties and the quantities of Gas sold. Natural gas prices have historically been volatile and are likely to continue
to be volatile. Price volatility and the risk of production curtailment make it difficult to estimate the future levels of cash distributions to Unitholders or the value of the Units. Since the termination of the Gas Purchase Agreement, various gas
sales contracts were entered into for base load gas from November 1, 2004 through August 31, 2010. During the terms of the above-mentioned contracts, any gas above the base load was sold on the spot market to various purchasers. A ten-year
gas sales contract was entered into effective September 1, 2010 with Alabama Gas Corporation for all gas produced during such period. The foregoing information regarding the gas purchase contracts has been provided to the Trustee by Dominion
Resources and Walter Exploration & Production.



|Item 1A. | Risk Factors.
|-------- | -------------

Risks Related to the Oil and Gas Industry

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

The Trusts quarterly distributions are highly
dependent upon the prices realized from the sale of natural gas and a material decrease in such prices could reduce the amount of cash distributions paid to Unitholders. Natural gas prices can fluctuate widely on a quarter-to-quarter basis in
response to a variety of factors that are beyond the control of the Trust. Factors that contribute to price fluctuation include, among others:



| |  |  | worldwide economic conditions;
| | - |  | ------------------------------



| |  |  | weather conditions;
| | - |  | -------------------



| |  |  | the supply and price of domestic and foreign natural gas;
| | - |  | ---------------------------------------------------------



| |  |  | the level of consumer demand;
| | - |  | -----------------------------



| |  |  | political conditions in major oil and natural gas producing regions, especially the Middle East;
| | - |  | ------------------------------------------------------------------------------------------------



| |  |  | the price and availability of alternative fuels;
| | - |  | ------------------------------------------------



| |  |  | the proximity to, and capacity of, transportation facilities;
| | - |  | -------------------------------------------------------------



| |  |  | the effect of worldwide energy conservation measures; and
| | - |  | ---------------------------------------------------------



| |  |  | the nature and extent of governmental regulation and taxation.
| | - |  | --------------------------------------------------------------

When natural gas prices decline, the Trust is affected in two ways. First, net royalties are reduced. Second, exploration and development activity on the Underlying Properties may decline as some projects may
become uneconomic and are either delayed or eliminated. Recent lifting costs have been close to or in some cases more than recent gas prices for certain projects in the Underlying Properties. It is impossible to predict future natural gas price
movements, and this reduces the predictability of future cash distributions to Unitholders.



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

The
value of the Units will depend upon, among other things, the reserves attributable to the Royalty Interests in the Underlying Properties. The calculations of proved reserves included in this Annual Report on Form 10-K are only estimates, and
estimating reserves is inherently uncertain. In addition, the estimates of future net revenues are based upon various assumptions regarding future production levels, prices and costs that may prove to be incorrect over time.

The accuracy of any reserve estimate is a function of the quality of available data, engineering interpretation and judgment, and the assumptions
used regarding the quantities of recoverable natural gas and the future prices of natural gas. Petroleum engineers consider many factors and make many assumptions in estimating reserves. Those factors and assumptions include:



| |  |  | historical production from the area compared with production rates from similar producing areas;
| | - |  | ------------------------------------------------------------------------------------------------



| |  |  | the effects of governmental regulation;
| | - |  | ---------------------------------------



| |  |  | assumptions about future commodity prices, production and development costs, taxes, and capital expenditures;
| | - |  | -------------------------------------------------------------------------------------------------------------



| |  |  | the availability of enhanced recovery techniques; and
| | - |  | -----------------------------------------------------



| |  |  | relationships with landowners, working interest partners, pipeline companies and others.
| | - |  | ----------------------------------------------------------------------------------------

Changes in any of these factors and assumptions can materially change reserve and future net revenue estimates. The Trusts estimate of
reserves and future net revenues is further complicated because the Trust holds overriding royalty interests and does not own a specific percentage of the natural gas reserves. Ultimately, actual production, revenues and expenditures for the
Underlying Properties, and therefore actual net proceeds payable to the Trust, will vary from estimates, and those variations could be material. Results of drilling, testing and production after the date of those estimates may require substantial
downward revisions or write-downs of reserves.

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

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

Risks Related to the Trust and
Ownership of the Units

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

The net proceeds payable to the Trust
are derived from the sale of depleting assets. The reduction in proved reserve quantities is a common measure of depletion. Future maintenance and development projects on the Underlying Properties will affect the quantity of proved reserves and can
offset the reduction in proved reserves. The timing and size of these projects will depend on the market prices of natural gas. Recent gas prices have been close to or in some cases less than the lifting costs for certain projects in the Underlying
Properties. Additionally, the Company notified the Trustee that it is undertaking a study of the Underlying Properties on a well-by-well basis to determine the economic viability of continuing to produce each individual well. If the Company decides
to suspend production or abandon any such wells, the future rate of production decline of proved reserves may be higher than the rate currently calculated by the Trust and proceeds payable to the Trust (and therefore Trust distributions) would be
reduced.



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Because the net proceeds payable to the Trust are derived from the sale of depleting assets, the
portion of distributions to Unitholders attributable to depletion may be considered a return of capital as opposed to a return on investment. Distributions that are a return of capital will ultimately diminish the depletion tax benefits available to
the Unitholders, which could reduce the market value of the Units over time. Eventually, the Royalty Interests will cease to produce in commercial quantities and the Trust will, therefore, cease to receive any distributions of net proceeds
therefrom.

The Trust will be terminated upon the occurrence of certain events.

Pursuant to the terms of the Trust Agreement, the Trust will terminate upon the occurrence of: (i) an affirmative vote of the holders of not
less than 66 percent of the outstanding Units to terminate the Trust; (ii) such time as the ratio of the cash amounts received by the Trust attributable to the Royalty Interests in any calendar quarter to administrative costs of the Trust
for such calendar quarter is less than 1.2 to 1.0 for two consecutive calendar quarters; or (iii) March 1 of any year if it is determined, based on a reserve report as of December 31 of the prior year prepared by a firm of independent
petroleum engineers mutually selected by the Trustee and the Company, that the net present value (discounted at 10 percent) of estimated future net revenues from proved reserves attributable to the Royalty Interests is equal to or less than
$5 million. With respect to (ii) above, the ratio of cash amounts to expenses for the most recent calendar quarter was 8.2 to 1.0 ratio and with (iii) above, the net present value of the estimated future net revenues computed as
described above by the independent petroleum engineers as of December 31, 2011 was approximately $27 million. While the results of these computations will not trigger an early termination of the Trust as of December 31, 2011, future
computations are subject to the numerous uncertainties in estimating the future net revenues as described in Item 1A  Risk Factors  Reserve estimates depend on many assumptions that may prove to be inaccurate, which could
cause both estimated reserves and estimated future net revenues to be too high, leading to write-downs of estimated reserves, including changes in pricing, costs and production volumes. Additionally, the Company notified the Trustee that it is
undertaking a study of the economic viability of wells within the Underlying Properties, as a result of which the Company could decide to suspend production or abandon certain wells. As a result, the ability of the Trusts ratio of cash
receipts to expenses or the ability of the reserves to exceed the threshold in the future is uncertain. Following termination, the Trustee will use best efforts to sell any remaining Royalty Interests then owned by the Trust and the net proceeds of
any sale would be distributed to Unitholders. There is no assurance that any such sale will be on terms acceptable to all Unitholders. Item 1  Business  Description of the Trust  Termination and Liquidation of the
Trust discusses consequences including tax consequences that may result to Unitholders, in the event Trust assets are sold and the Trust is terminated.

Unitholders and the Trustee have no influence over the operations on, or future development of, the Underlying Properties.

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

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

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



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

The Company, as the operator developing the Underlying Properties, may at any time transfer all or
part of its interest in any Underlying Property to another party. Neither the Trust nor the Unitholders are entitled to vote on any transfer of the properties underlying the Royalty Interests, and the Trust will not receive any proceeds of any such
transfer. Following any transfer, the transferred property will continue to be subject to the Royalty Interests of the Trust, but the net proceeds from the transferred property will be calculated separately and paid by the transferee. The transferee
will be responsible for all of the transferors obligations relating to calculating, reporting and paying to the Trust the net overriding royalties from the transferred property, and the transferor will have no continuing obligation to the
Trust for that property.

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

Walter Exploration & Production has agreed to assume Dominion Resources obligations in the Trust Agreement to pay (i) all
liabilities and operating and capital expenses that any Company Interests Owner becomes obligated to pay as a result of the Company Interests Owners obligations under the Conveyance and (ii) the obligations of the Company to indemnify the
Trust and the Trustees for certain environmental liabilities. Walter Exploration & Productions obligations will terminate, among other times, upon (i) the sale or other transfer by the Company of all or substantially all of its
interest in the Underlying Properties or (ii) the sale or other transfer of a majority of Walter Exploration & Productions direct or indirect equity ownership interests in the Company. However, in these circumstances, Walter
Exploration & Productions obligations will terminate only if (a) the transferee has a specified credit rating or the transferee, together with any affiliate that guarantees its obligations, does not have a rating assigned to its
unsecured long-term debt from a nationally recognized statistical rating organization but has a specified net worth or (b) the transferee is approved by a majority of the Unitholders; and provided that the transferee also unconditionally agrees
in writing, in form and substance reasonably satisfactory to the Trustee, to assume Walter Exploration & Productions remaining obligations under the Trust Agreement with respect to the assets transferred and under the Administrative
Services Agreement.

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

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

Unitholders have limited voting rights.

The voting rights of a Unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for
annual meetings of Unitholders or for an annual or other periodic re-election of the Trustee.

Financial information of the Trust
is not prepared in accordance with GAAP.

The financial statements of the Trust are prepared on a modified cash basis of
accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States, or GAAP. Although this basis of accounting is permitted for royalty trusts by the SEC, the financial statements of the
Trust differ from GAAP financial statements because revenues are not accrued in the month of production and cash reserves may be established for specified contingencies and deducted, which could not be accrued in GAAP financial statements.

Unitholders May Lack Limited Liability.

Consistent with Delaware law, the Trust Agreement provides that the Unitholders will have the same limitation on liability as is accorded under the laws of such state to stockholders of a corporation for profit. No
assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.



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

Currently, cash held by the Trustee as
a reserve for liabilities and for the payment of expenses and distributions to Unitholders is invested in Bank of America money market accounts which are backed by the good faith of Bank of America, N.A., but are not insured by the Federal Deposit
Insurance Corporation. Each Unitholder should independently assess the creditworthiness of Bank of American, N.A. For more information about the credit rating of Bank of America, N.A., please refer to its periodic filings with the SEC. The Trust
does not lend money and has limited ability to borrow money, which the Trustee believes limits the Trusts risk from the current tightening of credit markets. The Trusts future royalty income, however, may be subject to risks relating to
the creditworthiness of the operators of the Underlying Properties and other purchasers of the natural gas produced from the Underlying Properties, as well as risks associated with fluctuations in the price of natural gas.



|Item 1B. | Unresolved Staff Comments.
|-------- | --------------------------

None.



|Item 2. | Properties.
|------- | -----------

THE
ROYALTY INTERESTS

The Royalty Interests held by the Trust generally entitle the Trust to receive 65 percent of Gross Proceeds. The
Royalty Interests were conveyed to the Trust by means of a single instrument of conveyance. The Conveyance was recorded in the appropriate real property records in Alabama, so as to give notice of the Royalty Interests to creditors, and any
transferees will take an interest in the Underlying Properties subject to the Royalty Interests. The Conveyance was intended to convey the Royalty Interests as real property interests under Alabama law.

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

The Underlying Properties

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

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

The Royalty Interests were conveyed by the Company to the Trust out of the Company Interests. The Existing Wells are operated by Dominion Black
Warrior Basin, Inc. in accordance with the Operating Agreement. See  Operation of Properties. The Underlying Properties comprise 34,212 gross acres of land in an area approximately 5 miles wide and 23 miles long located on the
Tuscaloosa to Bankhead Lake portion of the Black Warrior Basin. Initial production began in December 1988 and consisted of eight wells. The Company acquired its interest in the Underlying Properties in December 1992. As of December 31, 2011,
the Underlying Properties contained 532 wells that were producing gas, all of which were drilled prior to 1993.



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

On May 28, 2010, Walter Natural Gas, LLC, a wholly owned
subsidiary of Walter Energy, LLC, acquired the Alabama natural gas interests of HighMount, effective March 1, 2010. The acquisition included the Companys Alabama coal bed methane operations, including the 532 existing conventional gas
wells in which the Trust has a net profits interest. The transaction was structured as an acquisition of the membership interests in HighMount Alabama, following which, HighMount Alabamas name was changed to Walter Exploration &
Production LLC. Walter Exploration & Production will continue to be party to the Administrative Services Agreement and Trust Agreement. Walter Exploration & Production will continue to own all the interests in the Company, and the
Company, which has changed its name to Walter Black Warrior Basin LLC, will continue to own the Underlying Properties. The Trust continues to have ownership in the Royalty Interests burdening the Underlying Properties and such sale did not affect
that ownership. In March 2012, the Company notified the Trustee that it is undertaking a study of the Underlying Properties on a well-by-well basis to determine the economic viability of continuing to produce each individual well. If the Company
decides to suspend production or abandon any such wells, such decision could adversely affect the Trusts future revenue stream, and if a significant number of wells are abandoned, it could cause a termination of the Trust. See Item 1
 Business  Description of the Trust  Termination and Liquidation of the Trust and Item 1A  Risk Factors for additional information.

Present Activities  Well Count and Acreage Summary.    The following table shows as of December 31, 2011, the gross and net producing wells and acres for the Company Interests.
The Net wells and acres are determined by multiplying the Gross Wells or acres by the Company Interests Owners Working Interest in the wells or acres.



|                  |  |                |     |  |       |  |     |       |  |  |        |  |  |  |        | 
|----------------- |  | -------------- | --- |  | ----- |  | --- | ----- |  |  | ------ |  |  |  | ------ | 
|                  |  | Number ofWells |     |  | Acres | 
|                  |  | Gross          |     |  | Net   |  |     | Gross |  |  | Net    | 
|Company Interests |  |                | 532 |  |       |  | 519 |       |  |  | 34,212 |  |  |  | 33,363 | 

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

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

Water Removal and Disposal.    Water from the wells located on the Underlying Properties is pumped from the wellhead to
one of five water disposal systems, each with two ponds, where the water is analyzed and chemically treated to remove impurities prior to discharge into the Black Warrior River. Water from the operations on the Underlying Properties is discharged
into the Black Warrior River pursuant to a National Pollutant Discharge Elimination System permit issued by ADEM. The ADEM permit was renewed in 2004 and a timely renewal application was submitted in 2009. The 2004 permit is administratively
extended until such time as ADEM reviews and issues a renewal permit. The ADEM permit generally authorizes water disposal based upon the Black Warrior Rivers minimum flow rate and maximum chloride level. The



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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 2011 production from the Underlying Properties was not curtailed for any reason other than for routine maintenance.

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

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

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

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

The Company has agreed for
the term of the Trust not to consent to, cooperate with, assist in or conduct infill drilling (except as required by law) on any of the Underlying Properties in which the Company owned an interest as of June 1, 1994. Although the Company has
informed the Trustee that it 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.



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

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

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

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

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

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

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

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

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

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

Reserve Estimate

Reserve
Estimate.    The following table summarizes net proved reserves estimated as of December 31, 2011, and certain related information for the Royalty Interests from the Reserve Estimate prepared by Ralph E. Davis &
Associates. The natural gas reserves were estimated by Ralph E. Davis & Associates by applying volumetric and decline curve analyses. All of such reserves constitute proved developed gas reserves located in the United States. The Reserve
Estimate was prepared in accordance with criteria established by the Commission.



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Summary of Gas Reserves as of December 31, 2011 Based on Average Fiscal-Year Prices



|                                                     |  |                   |        | 
|---------------------------------------------------- |  | ----------------- | ------ | 
|                                                     |  | December 31, 2011 |       
|Net Proved (MMcf) (a):                               |  |                   |        | 
|Developed                                            |  |                   | 11,036 | 
|Undeveloped                                          |  |                   | 0      | 
|                                                     |  |                   |        | 
|Total Proved                                         |  |                   | 11,036 | 
|                                                     |  |                   |        | 
|Estimated Future Net Revenues (in thousands) (a)(b): |  |                   |        | 
|2012                                                 |  | $                 | 6,562  | 
|2013                                                 |  |                   | 5,605  | 
|2014                                                 |  |                   | 4,812  | 
|2015                                                 |  |                   | 4,069  | 
|2016                                                 |  |                   | 3,363  | 
|Thereafter                                           |  |                   | 17,776 | 
|                                                     |  |                   |        | 
|Total                                                |  | $                 | 42,187 | 
|                                                     |  |                   |        | 
|Total Discounted at 10 Percent                       |  | $                 | 26,893 | 
|                                                     |  |                   |        | 



|(a) | The estimates of reserves and future net revenues summarized in this table are based upon a price of $4.12 per Mcf, which represented the average market price for gas in their
fields during the 12-month period prior to December 31, 2011, determined as an unweighted arithmetic average of the first day of the month price for each month within such period. This price may not be the most representative price for
estimating reserves or related future net revenues data.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(b) | Estimated future net revenues are defined as the total revenues attributable to the Royalty Interests for gas production less the relevant share of production, property and
related taxes (including severance taxes). Overhead costs have not been included, nor have the effects of depreciation, depletion and federal income tax. Estimated future net revenues and discounted estimated future net revenues are not intended and
should not be interpreted as representing the fair market value for the estimated reserves.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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

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

Because the process of estimating oil and gas reserves is complex and requires significant judgment, the Trustee has developed internal policies
and controls for estimating reserves. The Trust does not have information that would be available to a company with oil and gas operations because detailed information is not generally available to owners of royalty interests. The Trustee gathers
production information from the Company and provides such information to Ralph E. Davis & Associates, who extrapolates from such information estimates of the reserves attributable to the Underlying Properties based



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on its expertise in the oil and gas fields where the Underlying Properties are situated, as well as publicly available information. The Trusts policies regarding reserve estimates require
proved reserves to be in compliance with the SEC definitions and guidance.

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

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

The reserves attributable to the Royalty Interests are expected to
decline substantially during the term of the Trust, and a portion of each cash distribution made by the Trust will, therefore, be analogous to a return of capital. As a result, cash distributions will decrease 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 1.7 Bcf in 2012 to 0.9 Bcf in 2016.

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

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

Natural Gas Sales Prices and Production

The
following table sets forth the actual net production volumes attributable to the Royalty Interests, weighted average property, production and information regarding natural gas sales prices for the years ended December 31,
2011, December 31, 2010 and December 31, 2009.



|                                                               |  |                         |      |  |      |   |      |      |  |   |      | 
|-------------------------------------------------------------- |  | ----------------------- | ---- |  | ---- | - | ---- | ---- |  | - | ---- | 
|                                                               |  | Year ended December 31, |     
|                                                               |  | 2011                    |      |  | 2010 |   |      | 2009 | 
|Production attributable to the Royalty Interests (Bcf)         |  |                         | 2.1  |  |      |   | 2.4  |      |  |   | 2.7  | 
|Weighted average property, production (per Mcf)                |  | $                       | 0.24 |  |      | $ | 0.26 |      |  | $ | 0.24 | 
|Average Sales Price or Contract Price, as applicable (per Mcf) |  | $                       | 4.03 |  |      | $ | 4.41 |      |  | $ | 4.03 | 

Gas Purchase Agreement

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

Contracts were secured from various purchasers for the base load gas from November 1, 2004 through August 31, 2010. During
the terms of the above-mentioned contracts, any gas above the base load was sold on the spot market to



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various purchasers. A ten-year gas sales contract was entered into effective September 1, 2010 with Alabama Gas Corporation for all gas produced during such period. The foregoing information
regarding the gas purchase contracts has been provided to the Trustee by Dominion Resources and Walter Exploration & Production.

Operation
of Properties

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

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

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

Sale and Abandonment of Underlying Properties

The Company has the right to abandon any well or lease included in the Underlying Properties if, in its opinion, acting as would a reasonably prudent operator, such well or lease is not capable of producing Gas in
commercial quantities (determined before giving effect to the Royalty Interests). Neither the Trust nor the Unitholders will control the timing of the plugging and abandoning of any wells. Through December 31, 2011, none of the wells included
in the Underlying Properties had been plugged and abandoned. The Company has informed the Trustee that it is undertaking a study of the economic viability of producing each well included in the Underlying Properties, so there can be no assurance
that wells will not be plugged and abandoned in the future.

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

Walter Exploration &
Productions Assurances

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

The Trustee may, at any time after the tenth day
following receipt by Walter Exploration & Production of written notice from the Trustee that a Payment Obligation has not been paid when due, make demand of Walter Exploration & Production for payment stating the amount due. Walter
Exploration & Production is obligated to cure any failure to pay the obligation



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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 Walter Exploration & Productions performance obligations.

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

Title to Properties

Alabama counsel to the Company has opined that the Companys title to its interest in the Underlying Properties, and the Trusts title to
the Royalty Interests, are good and defensible in accordance with standards generally accepted in the natural gas industry, subject to such exceptions that, in the opinion of Alabama counsel, are not so material as to detract substantially from the
use or value of the Company Interests or the Royalty Interests.

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



|Item 3. | Legal Proceedings.
|------- | ------------------

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



|Item 4. | Mine Safety Disclosures.
|------- | ------------------------

Not applicable.



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PART II.



|Item 5. | Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
|------- | -------------------------------------------------------------------------------------------------------------

The Units in the Trust are listed and traded on the NYSE under the symbol DOM. The following table sets forth, for the periods
indicated, the high and low sales prices per Unit on the NYSE and the amount of quarterly cash distributions per Unit paid by the Trust.



|               |  |       |       |  |                      |   |       |  |  |   |          | 
|-------------- |  | ----- | ----- |  | -------------------- | - | ----- |  |  | - | -------- | 
|               |  | Price |       |  | Distributionper Unit |  
|               |  | High  |       |  | Low                  |   |      
|2011           |  |       |       |  |                      |   |       |  |  |   |          | 
|First Quarter  |  | $     | 18.00 |  |                      | $ | 13.21 |  |  | $ | 0.228656 | 
|Second Quarter |  | $     | 14.50 |  |                      | $ | 10.15 |  |  | $ | 0.228779 | 
|Third Quarter  |  | $     | 10.85 |  |                      | $ | 7.00  |  |  | $ | 0.251488 | 
|Fourth Quarter |  | $     | 10.00 |  |                      | $ | 7.90  |  |  | $ | 0.226309 | 
|               |  |       |      
|2010           |  |       |       |  |                      |   |       |  |  |   |          | 
|First Quarter  |  | $     | 15.63 |  |                      | $ | 12.94 |  |  | $ | 0.272321 | 
|Second Quarter |  | $     | 14.50 |  |                      | $ | 11.01 |  |  | $ | 0.321086 | 
|Third Quarter  |  | $     | 14.98 |  |                      | $ | 11.02 |  |  | $ | 0.277926 | 
|Fourth Quarter |  | $     | 16.35 |  |                      | $ | 13.13 |  |  | $ | 0.291694 | 

At March 12, 2012, there were 7,850,000 Units outstanding and approximately 337 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, |           
|                              |  | 2011                    |            |  | 2010 |   |            | 2009 |  |   | 2008       |  |  | 2007 |           
|Royalty Income                |  | $                       | 8,359,767  |  |      | $ | 10,207,523 |      |  | $ | 12,425,827 |  |  | $    | 26,537,428 |  |  | $ | 21,962,082 | 
|Distributable Income          |  | $                       | 7,361,311  |  |      | $ | 9,185,598  |      |  | $ | 11,197,573 |  |  | $    | 25,644,510 |  |  | $ | 20,912,169 | 
|Distributable Income per Unit |  | $                       | 0.94       |  |      | $ | 1.17       |      |  | $ | 1.43       |  |  | $    | 3.27       |  |  | $ | 2.66       | 
|Distributions per Unit        |  | $                       | 0.94       |  |      | $ | 1.16       |      |  | $ | 1.45       |  |  | $    | 3.24       |  |  | $ | 2.68       | 
|Total Assets, December 31     |  | $                       | 14,063,652 |  |      | $ | 16,812,650 |      |  | $ | 19,513,673 |  |  | $    | 23,055,462 |  |  | $ | 26,676,808 | 
|Total Corpus, December 31     |  | $                       | 13,927,682 |  |      | $ | 16,653,530 |      |  | $ | 19,345,951 |  |  | $    | 22,941,064 |  |  | $ | 26,353,024 | 



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|Item 7. | Trustees Discussion and Analysis of Financial Condition and Results of Operations.
|------- | -----------------------------------------------------------------------------------

The Trust collects the proceeds attributable to the Royalty Interests and makes quarterly cash distributions to Unitholders. The only assets of the
Trust, other than cash and cash equivalents being held for the payment of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests. The Royalty Interests owned by the Trust burden the interest in the Underlying
Properties that is owned by the Company.

The Royalty Interests consist of overriding royalty interests burdening the Companys
interest in the Underlying Properties. The Royalty Interests generally entitle the Trust to receive 65 percent of the Gross Proceeds (as defined below). 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 2011 marked the seventeenth full year of the existence of the Trust. The Trust received royalty
income amounting to $8,359,767 during the year ended December 31, 2011, compared to $10,207,523 for 2010 and $12,425,827 for 2009, declining primarily due to lower production and lower prices for natural gas. The royalty income received by the
Trust was net of the Royalty Interests allocable share of property, production and related taxes. General and administrative expenses during the year ended December 31, 2011 decreased to $999,090, compared to $1,022,830 for 2010 and
$1,232,893 for 2009. Distributable income for the year ended December 31, 2011 was $7,361,311 or $0.94 per Unit, compared to $9,185,598, or $1.17 per Unit, for 2010 and $11,197,573, or $1.43 per Unit, for 2009. The decrease in general and
administrative expenses in 2011 compared to 2010 was primarily the result of timing of expenses. The decrease in general and administrative expenses in 2010 compared to 2009 was primarily the result of timing of expenses.

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

Royalty Income received by the Trust in a given calendar year will generally reflect the proceeds from the sale of gas produced from the Underlying Properties during the first three quarters of that year and the
fourth quarter of the preceding calendar year due to the timing of the receipt of these revenues. Accordingly, the royalty income included in distributable income for the years ended December 31, 2011, 2010 and 2009, was based on production
volumes and natural gas prices for the periods from October 1, 2010 to September 30, 2011, October 1, 2009 to September 30, 2010 and October 1, 2008 to September 30, 2009, respectively.



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



|                                                   |  |                                   |       |  |      |   |       |      |  |   |       | 
|-------------------------------------------------- |  | --------------------------------- | ----- |  | ---- | - | ----- | ---- |  | - | ----- | 
|                                                   |  | For 12 Months Ended September 30, |      
|                                                   |  | 2011                              |       |  | 2010 |   |       | 2009 | 
|Production (Bcf)(1)                                |  |                                   | 2.166 |  |      |   | 2.410 |      |  |   | 2.758 | 
|Production (MMBtu)(2)                              |  |                                   | 2.156 |  |      |   | 2.406 |      |  |   | 2.761 | 
|Average Sales or Contract Price Received ($/MMBtu) |  | $                                 | 4.12  |  |      | $ | 4.50  |      |  | $ | 4.79  | 
|Average Index Price ($/MMBtu)                      |  | $                                 | 4.11  |  |      | $ | 4.50  |      |  | $ | 4.46  | 



|(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.

Contracts were secured from various purchasers following termination of the Gas Purchase
Agreement for base load gas from November 1, 2004 through August 31, 2010. During the terms of the above-mentioned contracts, any gas above the base load was sold on the spot market to various purchasers. A ten-year gas sales contract at
spot market prices was entered into effective September 1, 2010 with Alabama Gas Corporation for all gas produced during such period. The foregoing information regarding the gas purchase contracts has been provided to the Trustee by Dominion
Resources and Walter Exploration & Production.

The net proved reserves attributable to the Royalty Interests have been
estimated as of December 31, 2011, 2010 and 2009, by independent petroleum engineers. The reserve quantities of 11.0 Bcf for 2011 compared to 14.7 Bcf for 2010 and compared to 15.7 Bcf for 2009, reflect a decline in reserves between 2009 and
2010 and between 2010 and 2011 as a result of production and a significant change in prices which affects the change in quantities. See Financial Statements and Supplementary Data  Notes to Financial Statements  Note 8.

In March 2012, the Company notified the Trustee that it is undertaking a study of the Underlying Properties on a well-by-well basis to
determine the economic viability of continuing to produce each individual well. If the Company decides to suspend production or abandon any such wells, such decision could adversely affect the Trusts future revenue stream, and if a significant
number of wells are abandoned, it could cause a termination of the Trust. See Item 1  Business  Description of the Trust  Termination and Liquidation of the Trust and Item 1A  Risk Factors for
additional information.

Critical Accounting Policies and Estimates

The Trusts financial statements reflect the selection and application of accounting policies that require the Trust to make significant estimates and assumptions. The following are some of the more critical
judgment areas in the application of accounting policies that currently affect the Trusts financial condition and results of operations.



|1. | 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.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



| |  |  | Distributions to Unitholders are recorded when declared by the Trustee (see Financial Statements and Supplementary Data  Notes to Financial
Statements  Note 5).
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------

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



|2. | Impairment
|-- | ----------

The Trustee routinely reviews the
Trusts royalty interests in gas properties for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If an impairment event occurs and it is determined that the carrying value of the
Trusts royalty interests may not be recoverable, an impairment will be recognized and measured by the amount by which the carrying amount of the royalty interests exceeds the fair value of these assets, which would likely be measured by
discounting projected cash flows. As of December 31, 2011, no impairment is required.



|3. | Revenue Recognition
|-- | -------------------

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



|4. | Reserve Disclosure
|-- | ------------------

Independent petroleum
engineers estimate the net proved reserves attributable to the Royalty Interests. Estimates of future net revenues from proved reserves have been prepared using average 12-month gas prices, determined as an unweighted arithmetic average of the
first-day-of-the-month benchmark price for each month within the 12-month period preceding the end of the most recent fiscal year, unless prices are defined by contractual arrangements. The standardized measure of discounted future net cash flows is
achieved by using a discount rate of 10% a year to reflect the timing of future cash flows relating to proved oil and gas reserves. The reserves actually recovered and the timing of production may be substantially different from the reserve
estimates 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 market conditions change.

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.



|5. | Contingencies
|-- | -------------

Contingencies related to the
Underlying Properties that are unfavorably resolved would generally be reflected by the Trust as reductions to future royalty income payments to the Trust with corresponding reductions to cash distributions to Unitholders. The Trustee is aware of no
such items as of December 31, 2011, other than as stated below.



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

New Accounting Pronouncements

There are no new accounting pronouncements that are expected to have a significant impact on the Trusts financial statements.

Liquidity and Capital Resources

As stipulated in the Trust Agreement, the Trust is intended to
be passive in nature and neither the Delaware Trustee nor the Trustee has any control over or any responsibility relating to the operation of the Underlying Properties. The Trustee has powers to collect and distribute proceeds received by the Trust
and pay Trust liabilities and expenses and its actions have been limited to those activities. The assets of the Trust are passive in nature, and other than the Trusts ability to periodically borrow money as necessary to pay expenses,
liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited from engaging in borrowing transactions. As a result, other than such borrowings, if any, the Trust has no source of liquidity or
capital resources other than the Royalty Interests. See the earlier discussions in Item 7 for the discussion of the operations and cash inflows and outflows of the Trust.

Off-Balance Sheet Arrangements

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

Tabular Disclosure of Contractual Obligations



|                                             |  |       |           |  |                        |   |           |            |  |  |            |  |  |                  |   |  |  |  |   | 
|-------------------------------------------- |  | ----- | --------- |  | ---------------------- | - | --------- | ---------- |  |  | ---------- |  |  | ---------------- | - |  |  |  | - | 
|                                             |  |       |           |  | Payments Due by Period |  
|Contractual Obligations                      |  | Total |           |  | Less than 1Year        |   |           | 1 - 3Years |  |  | 3 - 5Years |  |  | More than5 Years |  
|Distribution declared subsequent to year end |  | $     | 1,390,289 |  |                        | $ | 1,390,289 |            |  |  | 0          |  |  |                  | 0 |  |  |  | 0 | 
|Total                                        |  | $     | 1,390,289 |  |                        | $ | 1,390,289 |            |  |  | 0          |  |  |                  | 0 |  |  |  | 0 | 

The above payable relates to distributions declared February 17, 2012 and payable March 9, 2012 to
Unitholders of record on February 29, 2012.

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 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



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many factors, none of which is within the Trustees control, that may cause such expectations not to be realized, including, among other things, factors identified in this Annual Report
affecting oil and gas prices and the recoverability of reserves, general economic conditions, actions and policies of petroleum-producing nations and other changes in the domestic and international energy markets and the factors identified in
Item 1A, Risk Factors.



|Item 7A. | Quantitative and Qualitative Disclosures About Market Risk.
|-------- | -----------------------------------------------------------

The Trust invests in no derivative financial instruments and has no foreign operations or long-term debt instruments. The assets of the Trust are passive in nature, and other than the Trusts ability to
periodically borrow money as necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited from engaging in borrowing transactions. The amount of any such borrowings is
unlikely to be material to the Trust. The Trust periodically holds short-term investments acquired with funds held by the Trust pending distribution to Unitholders and funds held in reserve for the payment of Trust expenses and liabilities. Because
of the short-term nature of these borrowings and investments and certain limitations upon the types of such investments which may be held by the Trust, the Trustee believes that the Trust is not subject to any material interest rate risk. Funds held
by the Trust pending distribution to Unitholders and in reserve for the payment of Trust expenses and liabilities are invested in Bank of America, N.A. money market accounts, which are backed by the good faith and credit of Bank of America, N.A.,
but are not insured by the Federal Deposit Insurance Corporation. Each Unitholder should independently assess the creditworthiness of Bank of America, N.A. For more information about the credit rating of Bank of America, N.A., please refer to its
periodic filings with the SEC. Additionally, the Trusts future royalty income may be subject to risks relating to the creditworthiness of the operators of the Underlying Properties and other purchasers of natural gas produced from the
Underlying Properties, as well as risks associated with fluctuations in the price of natural gas. See Item 1A  Risk Factors  Cash held by the Trustee is not insured by the Federal Deposit Insurance Corporation, and future royalty
income may be subject to risks relating to the creditworthiness of third parties. The Trust does not engage in transactions in foreign currencies which could expose the Trust or Unitholders to any foreign currency related market risk.
Information contained in Bank of America, N.As periodic filings with the SEC is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that the
Trust makes with the SEC.



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##### 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, 2011 and 2010, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2011. These financial statements are the
responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audits.

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

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

In our opinion, such financial statements present fairly, in all material respects,
the assets, liabilities, and trust corpus of the Dominion Resources Black Warrior Trust at December 31, 2011 and 2010, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31,
2011, on the basis of accounting described in Note 2.

We also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the Trusts internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control  Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission and our report dated March 15, 2012 expressed an unqualified opinion on the Trusts internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Austin, TX

March 15, 2012



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##### Table of Contents

DOMINION RESOURCES BLACK WARRIOR TRUST

FINANCIAL STATEMENTS

Statements of Assets, Liabilities and Trust Corpus



|                                                                                                                   |  |              |            |  |      |   |            | 
|------------------------------------------------------------------------------------------------------------------ |  | ------------ | ---------- |  | ---- | - | ---------- | 
|                                                                                                                   |  | December 31, |           
|                                                                                                                   |  | 2011         |            |  | 2010 |  
|ASSETS                                                                                                             |  |              |            |  |      |   |            | 
|Cash and cash equivalents                                                                                          |  | $            | 56,947     |  |      | $ | 60,357     | 
|Royalty interests in gas properties (less accumulated amortization of $141,810,795 and $139,065,207, respectively) |  |              | 14,006,705 |  |      |   | 16,752,293 | 
|                                                                                                                   |  |              |            |  |      |   |            | 
|Total Assets                                                                                                       |  | $            | 14,063,652 |  |      | $ | 16,812,650 | 
|                                                                                                                   |  |              |            |  |      |   |            | 
|LIABILITIES AND TRUST CORPUS                                                                                       |  |              |            |  |      |   |            | 
|Trust expenses payable                                                                                             |  | $            | 135,970    |  |      | $ | 159,120    | 
|Trust corpus (7,850,000 units of beneficial interest authorized, issued and outstanding)                           |  |              | 13,927,682 |  |      |   | 16,653,530 | 
|                                                                                                                   |  |              |            |  |      |   |            | 
|Total Liabilities and Trust Corpus                                                                                 |  | $            | 14,063,652 |  |      | $ | 16,812,650 | 
|                                                                                                                   |  |              |            |  |      |   |            | 

Statements of Distributable Income



|                                                |  |                         |           |   |      |   |            |      |  |   |            |  
|----------------------------------------------- |  | ----------------------- | --------- | - | ---- | - | ---------- | ---- |  | - | ---------- | -
|                                                |  | Year Ended December 31, |          
|                                                |  | 2011                    |           |   | 2010 |   |            | 2009 | 
|Royalty income                                  |  | $                       | 8,359,767 |   |      | $ | 10,207,523 |      |  | $ | 12,425,827 |  
|Interest income                                 |  |                         | 634       |   |      |   | 905        |      |  |   | 4,639      |  
|                                                |  |                         |           |   |      |   |            |      |  |   |            |  
|                                                |  |                         | 8,360,401 |   |      |   | 10,208,428 |      |  |   | 12,430,466 |  
|General and administrative expenses             |  |                         | (999,090  | ) |      |   | (1,022,830 | )    |  |   | (1,232,893 | )
|                                                |  |                         |           |   |      |   |            |      |  |   |            |  
|Distributable income                            |  | $                       | 7,361,311 |   |      | $ | 9,185,598  |      |  | $ | 11,197,573 |  
|                                                |  |                         |           |   |      |   |            |      |  |   |            |  
|Distributable income per unit (7,850,000 units) |  | $                       | 0.94      |   |      | $ | 1.17       |      |  | $ | 1.43       |  
|                                                |  |                         |           |   |      |   |            |      |  |   |            |  
|Distributions per unit                          |  | $                       | 0.94      |   |      | $ | 1.16       |      |  | $ | 1.45       |  
|                                                |  |                         |           |   |      |   |            |      |  |   |            |  

Statements of Changes in Trust Corpus



|                                  |  |                         |            |   |      |   |            |      |  |   |             |  
|--------------------------------- |  | ----------------------- | ---------- | - | ---- | - | ---------- | ---- |  | - | ----------- | -
|                                  |  | Year Ended December 31, |           
|                                  |  | 2011                    |            |   | 2010 |   |            | 2009 | 
|Trust corpus, beginning of period |  | $                       | 16,653,530 |   |      | $ | 19,345,951 |      |  | $ | 22,941,064  |  
|Amortization of Royalty Interests |  |                         | (2,745,588 | ) |      |   | (2,748,257 | )    |  |   | (3,415,148  | )
|Distributable income              |  |                         | 7,361,311  |   |      |   | 9,185,598  |      |  |   | 11,197,573  |  
|Distributions to Unitholders      |  |                         | (7,341,571 | ) |      |   | (9,129,762 | )    |  |   | (11,377,538 | )
|                                  |  |                         |            |   |      |   |            |      |  |   |             |  
|                                  |  | $                       | 13,927,682 |   |      | $ | 16,653,530 |      |  | $ | 19,345,951  |  
|                                  |  |                         |            |   |      |   |            |      |  |   |             |  

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



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Notes to Financial Statements

Years Ended December 31, 2011, 2010 and 2009



|1. | Trust Organization and Provisions
|-- | ---------------------------------

Dominion Resources Black Warrior Trust (the Trust) was formed as a Delaware business trust pursuant to the terms of
the Trust Agreement of Dominion Resources Black Warrior Trust (as amended, the Trust Agreement), entered into effective as of May 31, 1994, among Dominion Black Warrior Basin, Inc., an Alabama corporation, as trustor; Dominion
Resources, Inc., a Virginia corporation (Dominion Resources); and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.), a national banking association (the Trustee); and Mellon Bank (DE) National Association, a
national banking association (the Delaware Trustee), as trustees. The Trustees are independent financial institutions. In 2007 the Bank of America private wealth management group officially became known as U.S. Trust, Bank of
America Private Wealth Management. The legal entity that serves as Trustee of the Trust did not change, and references in this Form 10-K to U.S. Trust, Bank of America Private Wealth Management shall describe the legal entity Bank of America,
N.A.

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

The Trustee has all powers to collect and distribute proceeds received by the Trust and to pay Trust liabilities and expenses. The Delaware Trustee has only such powers as are set forth in the Trust Agreement or
are required by law and is not empowered to otherwise manage or take part in the management of the Trust. The Royalty Interests are passive in nature and neither the Trustee nor the Delaware Trustee has any control over, or any responsibility
relating to, the operation of the Underlying Properties or the Companys interest therein.

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

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

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



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Notes to Financial Statements  (Continued)



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

On May 28, 2010, Walter Natural Gas, LLC, a wholly owned
subsidiary of Walter Energy, LLC, acquired the Alabama natural gas interests of HighMount, effective March 1, 2010. The acquisition included the Companys Alabama coal bed methane operations, including the 532 existing conventional gas
wells in which the Trust has a net profits interest. The transaction was structured as an acquisition of the membership interests in HighMount Alabama, following which, HighMount Alabamas name was changed to Walter Exploration &
Production LLC. Walter Exploration & Production will continue to be party to the Administrative Services Agreement and Trust Agreement. Walter Exploration & Production will continue to own all the interests in the Company, and the
Company, which has changed its name to Walter Black Warrior Basin, will continue to own the Underlying Properties. The Trust continues to have ownership in the Royalty Interests burdening the Underlying Properties and such sale did not affect that
ownership.



|2. | Accounting Policies
|-- | -------------------

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.



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##### Table of Contents

Notes to Financial Statements  (Continued)



Impairment

The Trustee routinely reviews the Trusts royalty interests in gas properties for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If an
impairment event occurs and it is determined that the carrying value of the Trusts royalty interests may not be recoverable, an impairment will be recognized and measured by the amount by which the carrying amount of the royalty interests
exceeds the fair value of these assets, which would likely be measured by discounting projected cash flows. As of December 31, 2011, no impairment is required.

Distributable Income Per Unit

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

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, 2011.

New Accounting Pronouncements

There are no new accounting pronouncements that are expected to have a significant impact on the Trusts financial statements.



|3. | Federal Income Taxes
|-- | --------------------

The Trust is a Grantor Trust for federal income tax purposes. As a Grantor Trust, the Trust is not required to pay federal income
taxes. Accordingly, no provision for federal income taxes has been made in these financial statements.

Because the Trust is treated as
a Grantor Trust, and because a Unitholder is treated as directly owning an interest in the Royalty Interests, each Unitholder is taxed directly on his per Unit pro rata share of income attributable to the Royalty Interests consistent with the
Unitholders method of accounting and without regard to the taxable year or accounting method employed by the Trust.

Some Trust
Units are held by middlemen, as such term is broadly defined in the Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a customer in street name, referred to herein collectively as
middlemen). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (WHFIT) for U.S. federal income tax purposes. U.S. Trust, Bank of America, Private Wealth Management,
EIN: 56-0906609, 901 Main Street, 17th Floor, Dallas, Texas 75202, telephone number (214) 209-2400, is the representative of the Trust that will provide tax information in accordance with applicable Treasury Regulations governing the
information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.dom-dominionblackwarriortrust.com. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of Unitholders, and
not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury Regulations with respect to such Trust Units, including the issuance of IRS Forms 1099 and certain written tax
statements. Unitholders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units.

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



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Notes to Financial Statements  (Continued)



|4. | Related Party Transactions
|-- | --------------------------

Until July 2007, Dominion Resources provided accounting, bookkeeping and informational services to the Trust in accordance with
an Administrative Services Agreement dated effective June 1, 1994, after which HighMount Alabama (now Walter Exploration & Production) assumed this function. During 2011 the fee for these services was $492,245 and will increase
annually by three percent. Fees paid by the Trust to Walter Exploration & Production in 2010 were $477,907 and in 2009 were $463,987.

Aggregate fees and expense reimbursements paid by the Trust to the Trustees in 2011, 2010 and 2009 were $54,224, $52,791 and $51,399, 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.



|6. | Subsequent Events
|-- | -----------------

Subsequent to December 31, 2011, the Trust declared and paid the following distribution:



|                      |  |               |  |                      
|--------------------- |  | ------------- |  | ---------------------
|Quarterly Record Date |  | Payment Date  |  | Distribution per Unit
|February 29, 2012     |  | March 9, 2012 |  | $ 0.177106           



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Notes to Financial Statements  (Continued)



|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, 2011 and 2010 (in thousands, except per Unit amounts):



|                 |  |                |        |  |                      |   |       |                              |  |   |      | 
|---------------- |  | -------------- | ------ |  | -------------------- | - | ----- | ---------------------------- |  | - | ---- | 
|Calendar Quarter |  | Royalty Income |        |  | Distributable Income |   |       | DistributableIncome per Unit | 
|2011             |  |                |        |  |                      |   |       |                              |  |   |      | 
|First            |  | $              | 2,088  |  |                      | $ | 1,805 |                              |  | $ | .23  | 
|Second           |  |                | 2,077  |  |                      |   | 1,801 |                              |  |   | .23  | 
|Third            |  |                | 2,120  |  |                      |   | 1,917 |                              |  |   | .25  | 
|Fourth           |  |                | 2,075  |  |                      |   | 1,838 |                              |  |   | .23  | 
|                 |  |                |        |  |                      |   |       |                              |  |   |      | 
|                 |  | $              | 8,360  |  |                      | $ | 7,361 |                              |  | $ | .94  | 
|                 |  |                |        |  |                      |   |       |                              |  |   |      | 
|                 |  |                |       
|2010             |  |                |        |  |                      |   |       |                              |  |   |      | 
|First            |  | $              | 2,513  |  |                      | $ | 2,236 |                              |  | $ | .28  | 
|Second           |  |                | 2,830  |  |                      |   | 2,531 |                              |  |   | .32  | 
|Third            |  |                | 2,393  |  |                      |   | 2,204 |                              |  |   | .28  | 
|Fourth           |  |                | 2,472  |  |                      |   | 2,215 |                              |  |   | .29  | 
|                 |  |                |        |  |                      |   |       |                              |  |   |      | 
|                 |  | $              | 10,208 |  |                      | $ | 9,186 |                              |  | $ | 1.17 | 
|                 |  |                |        |  |                      |   |       |                              |  |   |      | 

Selected 2011 fourth quarter data are as follows (in thousands, except per Unit amounts):



|                                    |  |   |       |  
|----------------------------------- |  | - | ----- | -
|Royalty income                      |  | $ | 2,075 |  
|Interest income                     |  |   |      |  
|General and administrative expenses |  |   | (237  | )
|                                    |  |   |       |  
|Distributable income                |  | $ | 1,838 |  
|                                    |  |   |       |  
|Distributable income per Unit       |  |   | .23   |  
|Distributions per Unit              |  |   | .23   |  



|8. | Supplemental Gas Disclosure (Unaudited)
|-- | ---------------------------------------

The net proved reserves attributable to the Royalty Interests have been estimated as of December 31, 2011, 2010, 2009 and
January 1, 2009, by independent petroleum engineers.

Independent petroleum engineers estimate the net proved reserves attributable
to the Royalty Interests. Estimates of future net revenues from proved reserves have been prepared using average 12-month gas prices, determined as an unweighted arithmetic average of the first-day-of-the-month benchmark price for each month within
the 12-month period preceding the end of the most recent fiscal year, unless prices are defined by contractual arrangements. The standardized measure of discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect
the timing of future cash flows relating to proved oil and gas reserves. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates 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 market conditions change. The average prices for
December 31, 2011, December 31, 2010 and December 31, 2009, were $4.12, $4.37, and $3.70 per Mcf, respectively. As of February 28, 2012, published Gas prices were approximately $2.45 per Mcf. The use of such price as
compared to $4.12 per Mcf, which was used to calculate the below information, would result in a lower 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



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Notes to Financial Statements  (Continued)



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, 2009   |  |  | 19,800 |  
|Revisions of previous estimates                |  |  | (1,292 | )
|Production (MMcf)                              |  |  | (2,758 | )
|                                               |  |  |        |  
|Proved developed reserves at December 31, 2009 |  |  | 15,750 |  
|Revisions of previous estimates                |  |  | 1,350  |  
|Production (MMcf)                              |  |  | (2,410 | )
|                                               |  |  |        |  
|Proved developed reserves at December 31, 2010 |  |  | 14,690 |  
|Revisions of previous estimates                |  |  | (1,487 | )
|Production (MMcf)                              |  |  | (2,167 | )
|                                               |  |  |        |  
|Proved developed reserves at December 31, 2011 |  |  | 11,036 |  
|                                               |  |  |        |  

All proved reserve estimates presented above at December 31, 2011, 2010, 2009 and January 1, 2009, are
proved developed.

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

The following table sets forth the standardized measure of discounted estimated future net cash flows from proved reserves at December 31,
2011, 2010 and 2009 relating to the Trusts Royalty Interests (thousands of dollars):



|                                                         |  |      |         |   |      |   |         |      |  |   |         |  
|-------------------------------------------------------- |  | ---- | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                                                         |  | 2011 |         |   | 2010 |   |         | 2009 | 
|Future cash inflows                                      |  | $    | 45,469  |   |      | $ | 64,160  |      |  | $ | 55,145  |  
|Future taxes                                             |  |      | (3,282  | ) |      |   | (3,850  | )    |  |   | (3,309  | )
|                                                         |  |      |         |   |      |   |         |      |  |   |         |  
|Future net cash flows                                    |  |      | 42,187  |   |      |   | 60,310  |      |  |   | 51,836  |  
|10% annual discount for estimated timing of cash flow    |  |      | (15,294 | ) |      |   | (23,813 | )    |  |   | (19,311 | )
|                                                         |  |      |         |   |      |   |         |      |  |   |         |  
|Standardized measure of discounted future net cash flows |  | $    | 26,893  |   |      | $ | 36,497  |      |  | $ | 32,525  |  
|                                                         |  |      |         |   |      |   |         |      |  |   |         |  

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.



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Notes to Financial Statements  (Continued)



The following table sets forth the changes in the present value of estimated future net cash flows
from proved reserves during the year ended December 31, 2011, 2010 and 2009 (thousands of dollars):



|                               |  |      |        |   |      |   |         |      |  |   |         |  
|------------------------------ |  | ---- | ------ | - | ---- | - | ------- | ---- |  | - | ------- | -
|                               |  | 2011 |        |   | 2010 |   |         | 2009 | 
|Balance at beginning of period |  | $    | 36,497 |   |      | $ | 32,525  |      |  | $ | 57,370  |  
|Increase (decrease) due to:    |  |      |        |   |      |   |         |      |  |   |         |  
|Royalty income, net of taxes   |  |      | (8,360 | ) |      |   | (10,208 | )    |  |   | (12,426 | )
|Changes in prices              |  |      | (1,972 | ) |      |   | 5,012   |      |  |   | (19,589 | )
|Changes in estimated volumes   |  |      | (2,921 | ) |      |   | 5,915   |      |  |   | 1,433   |  
|Accretion of discount          |  |      | 3,649  |   |      |   | 3,253   |      |  |   | 5,737   |  
|                               |  |      |        |   |      |   |         |      |  |   |         |  
|Balance at December 31         |  | $    | 26,893 |   |      | $ | 36,497  |      |  | $ | 32,525  |  
|                               |  |      |        |   |      |   |         |      |  |   |         |  

In March 2012, the Company notified the Trustee that it is undertaking a study of the Underlying Properties on a
well-by-well basis to determine the economic viability of continuing to produce each individual well. If the Company decides to suspend production or abandon any such wells, such decision could adversely affect the Trusts future revenue
stream, and if a significant number of wells are abandoned, it could cause a termination of the Trust.



|9. | Gas Purchase Agreement
|-- | ----------------------

Contracts were secured from various purchasers following termination of the Gas Purchase Agreement for base load gas from
November 1, 2004 through August 31, 2010. During the terms of the above-mentioned contracts, any gas above the base load was sold on the spot market to various purchasers. A ten-year gas sales contract was entered into effective
September 1, 2010 with Alabama Gas Corporation for all gas produced during such period at spot market prices. The foregoing information regarding the gas purchase contracts has been provided to the Trustee by Dominion Resources and Walter
Exploration & Production.



|10. | 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, 2011, other than as stated below.

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



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|Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
|------- | -------------------------------------------------------------------------------------

None.



|Item 9A. | Controls and Procedures.
|-------- | ------------------------

Disclosure Controls and
Procedures

As of the end of the period covered by this report, the Trustee carried out an evaluation of the effectiveness of the
design and operation of the Trusts disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15. Based upon that evaluation, the Trustee concluded that the Trusts disclosure controls and procedures are effective in
timely recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934 and are effective in ensuring that
information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to the Trustee to allow timely decisions regarding required disclosure. In its
evaluation of disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on information provided by the Company.

Changes in Internal Control Over Financial Reporting

There has not been any change in the Trusts internal control over financial reporting during the fourth quarter of 2011 that has materially affected, or is reasonably likely to materially affect, the
Trusts internal control over financial reporting.

Trustees Report on Internal Control Over Financial Reporting

The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule
13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance
with the modified cash basis of accounting. The Trustee conducted an evaluation of the effectiveness of the Trusts internal control over financial reporting based on the criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustees evaluation under the framework in Internal Control-Integrated Framework, the Trustee concluded that the Trusts internal control
over financial reporting was effective as of December 31, 2011. The independent registered public accounting firm of Deloitte & Touche LLP, as auditors of the statements of assets, liabilities, and trust corpus, and the related
statements of distributable income and changes in trust corpus for the year ended December 31, 2011, has issued an attestation report on the Trusts internal control over financial reporting, which is included herein.



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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the internal control over financial reporting of Dominion Resources Black Warrior Trust (the Trust) as of December 31, 2011, based on criteria established in Internal Control
 Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Trustee is responsible for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting, included in the accompanying Trustees Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Trusts internal control over
financial reporting based on our audit.

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

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

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

In our opinion, the Dominion Resources Black Warrior Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established
in Internal Control  Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statements of assets,
liabilities, and trust corpus of the Trust as of December 31, 2011 and the related statement of distributable income and changes in trust corpus for the year ended December 31, 2011, which financial statements have been prepared on the
modified cash basis of accounting as described in Note 2 to such financial statements, and our report dated March 15, 2012 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Austin, TX

March 15, 2012



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|Item 9B. | Other Information.
|-------- | ------------------

None.

PART III.



|Item 10. | Directors, Executive Officers and Corporate Governance.
|-------- | -------------------------------------------------------

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

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

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

Code of Ethics.    Because the Trust has no employees, it does not have a code of ethics. Employees of the Trustee, Bank of America, N.A., must comply with the banks code of ethics,
a copy of which will be provided to Unitholders, without charge, upon request made to U.S. Trust, Bank of America Private Wealth Management, Trustee, 901 Main Street, 17th Floor, Dallas, Texas 75202, Attention: Ron E. Hooper.



|Item 11. | Executive Compensation.
|-------- | -----------------------

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

The following is a
description of certain fees and expenses anticipated to be paid or borne by the Trust, including fees expected to be paid to Walter Exploration & Production, the Trustee, the Delaware Trustee, American Stock Transfer & Trust
Company (the Transfer Agent) or their respective affiliates.

Ongoing Administrative
Expenses.    The Trust is responsible for paying all fees, charges, expenses, disbursements and other costs incurred by the Trustee in connection with the discharge of its duties pursuant to the Trust Agreement, including,
without limitation, trustee fees, engineering, audit, accounting and legal fees and expenses, printing and mailing costs, amounts reimbursed or paid to the Company or Walter Exploration & Production 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 $49,224, plus
an hourly charge for services in excess of a combined total of 350 hours annually at its standard rate, which is currently $150 per 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 2011, the Trustee and the Delaware Trustee received total compensation of $49,224 and $5,000, respectively.



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

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



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

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

Security Ownership of Management.    The Trust has no directors
or executive officers. As of March 1, 2012, Bank of America, N.A., the Trustee, beneficially owned 7,997 units. Mellon Bank (DE) National Association, the Delaware Trustee, did not beneficially own any Units.

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

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



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

Administrative Services Agreement

Pursuant to the Trust Agreement, Dominion Resources and the
Trust entered into the Administrative Services Agreement, pursuant to which the Trust is obligated, throughout the term of the Trust, to pay to Dominion Resources each quarter an administrative services fee for accounting, bookkeeping and other
administrative services relating to the Royalty Interests and the Underlying Properties. In July 2007, Walter Exploration & Production assumed Dominion Resources obligations under the Administrative Services Agreement and is entitled
to the administrative services fee. The annual fee, payable in equal quarterly installments, is currently $49,224 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.

Walter
Exploration & Productions Conditional Right of Repurchase

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



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Potential Conflicts of Interest

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

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

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

Walter Exploration & Production may profit from contracts with the Trust.    The amount that Walter
Exploration & Production 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 Walter
Exploration & Production. Accordingly, Walter Exploration & Production 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, 2011 and 2010 are:



|                   |  |      |         |  |      |   |         | 
|------------------ |  | ---- | ------- |  | ---- | - | ------- | 
|                   |  | 2011 |         |  | 2010 |  
|Audit Fees         |  | $    | 104,500 |  |      | $ | 114,500 | 
|Audit-related fees |  |      |        |  |      |   |        | 
|Tax fees           |  |      |        |  |      |   |        | 
|All other fees     |  |      |        |  |      |   |        | 
|                   |  |      |         |  |      |   |         | 
|                   |  | $    | 104,500 |  |      | $ | 114,500 | 
|                   |  |      |         |  |      |   |         | 

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.



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##### Table of Contents

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                                    |  |  | 37 | 
|Statements of Assets, Liabilities and Trust Corpus as of December 31, 2011 and 2010        |  |  | 38 | 
|Statements of Distributable Income for the years ended December 31, 2011, 2010 and 2009    |  |  | 38 | 
|Statements of Changes in Trust Corpus for the years ended December 31, 2011, 2010 and 2009 |  |  | 38 | 
|Notes to Financial Statements                                                              |  |  | 39 | 

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 Company L.P. and Dominion Black Warrior Basin, Inc. (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 Company L.P. and Dominion Black Warrior Basin, Inc. (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 Company L.P. and Dominion Black Warrior Basin, Inc. (filed as Exhibit 10.7 to the Registrants Form
10-K for the year ended December 31, 1999 and incorporated herein by reference).




51



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##### Table of Contents

No.



Exhibit10.8



Amendment to Gas Purchase Agreement dated July 1, 2000, between El Paso Merchant Energy Gas, L.P., as successor to Sonat Marketing Company L.P., and Dominion Black Warrior Basin, Inc. (filed
as Exhibit 4 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 L.P., and Dominion Black Warrior Basin, Inc. (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, L.P., as successor to Sonat Marketing Company L.P., and Dominion Black Warrior Basin, Inc. (filed as
Exhibit 10.1 to the Registrants Form 10-Q for the quarter ended September 30, 2002 and incorporated herein by reference).10.11



Assignment and Assumption Agreement, dated as of July 31, 2007, between Dominion Resources and HighMount Exploration & Production Alabama (filed as Exhibit 10.1 to the Registrants
Form 10-Q for the quarter ended June 30, 2007 and incorporated herein by reference).23.1



Consent of Ralph E. Davis Associates, Inc., independent petroleum engineers.31.1



Certification required by Rule 13a-14(a)/15d-14(a).32.1



Certification required by Rule 13a-14(b)/15d-14(b) and Section 906 of the Sarbanes Oxley Act of 2002.99.1



The information under the sections captioned Federal Income Tax Consequences and ERISA Considerations of the Prospectus dated June 21, 1994, which
constitutes a part of the Registration Statement on Form S-3 of Dominion Resources, Inc.* (Registration No. 33-53513) and is incorporated herein by reference.99.2



Summary of Reserve Report, dated March 9, 2012, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests
as of December 31, 2011, 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
|- | ------------------------------------------------------------------------------



52



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##### Table of Contents

SIGNATURES

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



DOMINION RESOURCES BLACK WARRIOR TRUST
 BY: BANK OF AMERICA, N.A.,
TRUSTEEBy:

/S/    RON E.
HOOPERRon E. Hooper Senior Vice President and Administrator


Date: March 15, 2012

(The Registrant has no directors or executive officers.)



53



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##### Table of Contents

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 Company L.P. and Dominion Black Warrior Basin, Inc. (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 Company L.P. and Dominion Black Warrior Basin, Inc. (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 Company L.P. and Dominion Black Warrior Basin, Inc. (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 L.P., and Dominion Black Warrior Basin, Inc. (filed
as Exhibit 4 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 L.P., and Dominion Black Warrior Basin, Inc. (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, L.P., as successor to Sonat Marketing Company L.P., and Dominion Black Warrior Basin, Inc. (filed as
Exhibit 10.1 to the Registrants Form 10-Q for the quarter ended September 30, 2002 and incorporated herein by reference).10.11



Assignment and Assumption Agreement, dated as of July 31, 2007, between Dominion Resources and HighMount Exploration & Production Alabama (filed as Exhibit 10.1 to the Registrants
Form 10-Q for the quarter ended June 30, 2007 and incorporated herein by reference).23.1



Consent of Ralph E. Davis Associates, Inc., independent petroleum engineers.31.1



Certification required by Rule 13a-14(a)/15d-14(a).32.1



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




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##### Table of Contents

No.



Exhibit99.1



The information under the sections captioned Federal Income Tax Consequences and ERISA Considerations of the Prospectus dated June 21, 1994, which
constitutes a part of the Registration Statement on Form S-3 of Dominion Resources, Inc.* (Registration No. 33-53513) and is incorporated herein by reference.99.2



Summary of Reserve Report, dated March 9, 2012, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests
as of December 31, 2011, 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
|- | ------------------------------------------------------------------------------