Annual Report (10-k)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2014

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)

Royalty Trust Management

Southwest Bank

2911 Turtle Creek Boulevard

Suite 850

Dallas, Texas 75219

(Address of principal executive offices; Zip Code)

Registrant’s telephone number, including area code:

(855) 588-7839

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 þ

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

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

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. þ

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


Large accelerated filer ¨		Accelerated filer ¨		Non-accelerated filer þ		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 þ

The aggregate market value of the registrant’s units of beneficial interest outstanding (based on the closing sale price on the New York Stock Exchange) held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $47,414,000.00.

At March 23, 2015, there were 7,850,000 units of beneficial interest outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

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		11
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	47
Item 9A.	Controls and Procedures	47
Item 9B.	Other Information	49
PART III.		49
Item 10.	Directors, Executive Officers and Corporate Governance	49
Item 11.	Executive Compensation	49
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	50
Item 13.	Certain Relationships and Related Transactions, and Director Independence	50
Item 14.	Principal Accounting Fees and Services	51
PART IV.		52
Item 15.	Exhibits, Financial Statement Schedules	52

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 BNY Mellon Trust of Delaware.

“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.

“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, 2014, prepared by Ralph E. Davis & Associates.

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

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

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

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

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

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

“Trustee” means Bank of America, N.A. (as successor to NationsBank of Texas, N.A.) for periods prior to August 29, 2014, and means Southwest Bank (as successor to Bank of America, N.A.) for periods on or after August 29, 2014.

“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 Trust’s 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.

Assets of the Trust

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 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.

On January 9, 2014, Bank of America, N.A. (as successor to NationsBank of Texas, N.A.) gave notice to holders of units of beneficial interest in the Trust and the Delaware Trustee that it would be resigning as trustee subject to certain conditions that included the appointment of Southwest Bank or another successor trustee as trustee of the Trust by a vote of the Unitholders or a court order. Effective as of August 29, 2014, a court appointed Southwest Bank as successor trustee of the Trust and Bank of America, N.A.’s resignation as trustee became effective.

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 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 2/3 percent of the outstanding Units to terminate the Trust; (ii) such time as the ratio of the cash amounts received by the Trust attributable to the Royalty Interests in any calendar quarter to administrative costs of the Trust for such calendar quarter is less than 1.2 to 1.0 for two consecutive calendar quarters; or (iii) March 1 of any year if it is determined, based on a reserve report as of December 31 of the prior year prepared by a firm of independent petroleum engineers mutually selected by the Trustee and the Company, that the net

present value (discounted at 10 percent) of estimated future net revenues from proved reserves attributable to the Royalty Interests plus the amount of all remaining Section 29 tax credits attributable to the Royalty Interests is equal to or less than $5 million (as applicable, the “Termination Date”). Upon such occurrence 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. With respect to (ii) above, the ratio of cash amounts to expenses for the most recent calendar quarter was 6.5 to 1 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, 2014 was approximately $27.5 million. While the results of these computations will not trigger an early termination of the Trust as of December 31, 2014, future computations are subject to the numerous uncertainties. “See Item 1A — Risk Factors.”

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. Within five business days following the Termination Date, the Trustee will provide written notice of termination to the Company, Dominion Resources and the Delaware Trustee. 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.

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 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 23, 2015, 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 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).

Dominion Resources assigned its rights under the Trust Agreement to HighMount Alabama (now 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 25 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.

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 66 2/3 percent of the outstanding Units, no provision of the Trust Agreement may be amended with respect to (a) the sale or disposition of all or any part of the Trust estate, including the Royalty Interests, except as specifically provided in the Trust Agreement; (b) termination of the Trust and the disposition of Trust assets upon liquidation of the Trust; or (c) the Company’s right of first refusal with respect to the purchase of any remaining Royalty Interests upon termination of the Trust. Without the written consent of 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.

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-dominion.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.

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 2014, the Trust earned interest income on funds held for distribution and for the cash reserve maintained for the payment of contingent and future obligations of the Trust. The deductions of the Trust consist of severance taxes and administrative expenses. In addition, each Unitholder is entitled to depletion deductions. See “Unitholder’s Depletion Allowance” below.

Individuals may 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.

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.

Income tax rates

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6%, and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and qualified dividends of individuals is 20%. Such marginal tax rates may be effectively increased by up to 1.2% due to the phaseout of personal exemptions and the limitations on itemized deductions. The highest marginal U.S. federal income tax rate applicable to corporations is 35%, and such rate applies to both ordinary income and capital gains.

Medicare tax on investment income

Section 1411 of the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income generally will

include a Unitholder’s allocable share of the Trust’s interest and royalty income plus the gain recognized from a sale of Trust Units. In the case of an individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all investments, or (ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels depending on such individual’s federal income tax filing status. In the case of an estate or trust, the tax is imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

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.”

Withholding tax on distributions to foreign Unitholders

Pursuant to the Foreign Account Tax Compliance Act (commonly referred to as “FATCA”), distributions from the Trust to “foreign financial institutions” and certain other “non-financial foreign entities” may be subject to U.S. withholding taxes. Specifically, certain “withholdable payments” (including certain royalties, interest and other gains or income from U.S. sources) made to a foreign financial institution or non-financial foreign entity will generally be subject to the withholding tax unless the foreign financial institution or non-financial foreign entity complies with certain information reporting, withholding, identification, certification and related requirements imposed by FATCA. Foreign financial located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules.

The Treasury Department recently issued guidance providing that the FATCA withholding rules described above generally will apply to qualifying payments made after June 30, 2014. Foreign Unitholders are encouraged to consult their own tax advisors regarding the possible implications of these withholding provisions on their investment in Trust Units.

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. Southwest Bank, EIN: 75-1105980, 2911 Turtle Creek Boulevard, Suite 850, Dallas, Texas 75219, telephone number (855) 588-7839, email address trustee@dom-dominion.com, 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-dominion.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.

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 1995-2013 composite income tax returns with the DOR on behalf of all Nonresident Unitholders (defined below), and intends to file a composite return for 2014 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 2014. Accordingly, no Alabama state income tax is due under the 2014 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 2014 (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.”

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 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 to, for example, conduct drilling or underground injection activities, restrict air emissions, water discharges or other potential sources of 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, for example, 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 is 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, including cap and trade programs, have been adopted by many foreign countries and almost half of the 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 set forth reporting requirements for the petroleum and natural gas industry and required 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. On November 30, 2011, the EPA published a final rule that established technical amendments to certain greenhouse gas reporting requirements and that extended the reporting deadline to September 28, 2012 for the petroleum and natural gas industry sources to report their greenhouse gas emissions. These reporting obligations continue in effect.

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 indicated that it will use data collected through the reporting rules to decide whether to promulgate future greenhouse gas emission limits. On August 16, 2012, the EPA published a final rule that established new source performance standards (“NSPS”) for volatile organic compounds (“VOCs”) and sulfur dioxide, an air toxics standard for major sources of oil and natural gas production, and an air toxics standard for major sources of natural gas transmission and storage. Beginning January 1, 2015 all hyraulicly fractured or

refractured natural gas wells had to be completed using so called “green completion” technology, which significantly reduces VOC emissions. Limiting emissions of VOCs will have the co-benefit of also limiting methane, a greenhouse gas. These regulations also apply to storage tanks and other equipment.

In addition, EPA is seeking direct regulation of the greenhouse gas methane from new and modified oil and gas production sources in order to help President Obama meet his new goal of reducing methane emissions 40 to 45 % from 2012 levels by 2025, while avoiding direct regulation of existing drilling operations. On December 19, 2014, EPA published an internet version notice of the final amendments to the NSPS for the oil and natural gas sector; the official version will be published in the Federal Register this summer. EPA plans to build on its 2012 NSPS for the sector to set standards for methane and ozone-forming VOC emissions from new and modified oil and natural gas production sources. A final rule is slated for issuance in 2016. The White House said in its fact sheet that the “focus will be on in-use technologies, current industry practices, emerging innovations, and streamlined and flexible regulatory approaches to ensure that emissions reductions can be achieved as oil and gas production and operations continue to grow.” Despite the benefits of reducing methane emissions, it will affect the oil and gas industry’s operations and increase the cost of its operations.

Hydraulic Fracturing. Congress, the EPA and various states, including Alabama and cities 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. The EPA, however, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act (the “SDWA”). The EPA has developed draft underground injection control regulations for oil and natural gas hydraulic fracturing activities using diesel fuel. A relevant issue is how the EPA will define diesel, which could cover a variety of oils that are not diesel but that have similar carbon-chain molecules. On February 12, 2014, the EPA released an “interpretative memorandum” providing technical recommendations for implementing Underground Injection Control (“UIC”) requirements for hydraulic fracturing activities using diesel fuels. In this guidance document, EPA expansively defined the term “diesel” to include categories of oils, such as kerosene that have not typically been considered to be diesel.

The EPA is also conducting a congressionally mandated study on the effects of hydraulic fracturing on water at all stages in the operational cycle of harvesting natural gas. While the study was expected to be completed in 2014, as of March 2015 the EPA has not released any findings. When eventually completed, this study is anticipated to form the basis for a comprehensive regulatory effort. The EPA study, or other studies, of hydraulic fracturing could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory programs. The re-election of President Obama makes such regulation of the oil and gas industry more likely as evidenced by the Department of the Interior’s March 20, 2015 issuance of the first regulations on fracking associated with wells on federal and tribal lands but not on state and private lands where most of the fracking wells are located. Key regulatory requirements reportedly include (i) disclosure of chemicals used in the fracking operations to the Bureau of Land Management, (ii) use of cement barriers to restrict the flow of fracking fluid into underground water supplies, and (iii) use of covered tanks aboveground to hold fluids injected into wells for fracking operations.

On January 7, 2015, a coalition of nine environmental and open government groups sued the EPA in the U.S. District Court for the District of Columbia over the toxic chemicals released into the air, water and land by the oil and gas industry. The oil and gas industry has not been previously required to disclose the chemicals that it releases or disposes while other industries have been subject to such rules. If the Plaintiffs win the lawsuit or if EPA otherwise agrees to require the oil and gas industry to make such disclosures, the overall cost to comply with the rules may be significant and would also potentially allow outside parties to more effectively lobby EPA to regulate the oil and gas industry’s releases to air, water and land.

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 2015, 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 2015, the Company could incur significant costs to remediate the environmental contamination in accordance with 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. 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. The Company informed the Trustee that it abandoned 11 wells in 2012, 11 wells in 2013, and 8 wells in 2014 as the Company considered them uneconomic, and up to an additional 10 to 20 wells may become subject to abandonment during 2015 if natural gas prices remain low. It is impossible to predict future natural gas price movements, and this reduces the predictability of future cash distributions to Unitholders.

Additionally, declines in natural gas prices could trigger an early termination of the Trust. See “— The Trust will be terminated upon the occurrence of certain events” below.

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. The Company informed the Trustee that it abandoned 11 wells in 2012, 11 wells in 2013, and 8 wells in 2014 as the Company considered them uneconomic and will evaluate an additional 10 to 20 wells in 2015. If the Company decides to suspend production or abandon any additional 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.

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 2/3 percent of the outstanding Units to terminate the Trust; (ii) such time as the ratio of the cash amounts received by the Trust attributable to the Royalty Interests in any calendar quarter to administrative costs of the Trust for such calendar quarter is less than 1.2 to 1.0 for two consecutive calendar quarters; or (iii) March 1 of any year if it is determined, based on a reserve report as of December 31 of the prior year prepared by a firm of independent petroleum engineers mutually selected by the Trustee and the Company, that the net present value (discounted at 10 percent) of 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 6.5 to 1 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, 2014 was approximately $27.5 million. While the results of these computations will not trigger an early termination of the Trust as of December 31, 2014, 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 abandoned 11 wells in 2012, 11 wells in 2013, and 8 wells in 2014 as it considered them uneconomic and that it is continuing to study the economic viability of an additional 10 to 20 wells within the Underlying Properties in 2015, as a result of which the Company could decide to suspend production or abandon such additional 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.

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.

Future royalty income may be subject to risks relating to the creditworthiness of third parties.

The Trust does not lend money and has limited ability to borrow money, which the Trustee believes limits the Trust’s risk from the 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 that are continuing to produce 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, 2014, the Underlying Properties contained 502 wells that were producing gas, all of which were drilled prior to 1993.

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 then-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. The Company notified the Trustee that it abandoned 11 wells in 2012, 11 wells in 2013, and 8 wells in 2014 because it considered them uneconomic, and that it continues to evaluate an additional 10 to 20 wells in 2015. If the Company decides to suspend production or abandon any such additional 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, 2014, the gross and net producing wells and acres for the Company Interests. The Net wells and acres are determined by multiplying the Gross Wells or acres by the Company Interests Owner’s Working Interest in the wells or acres.

Number of
Wells

Acres

Gross

Net

Gross

Net

Company Interests

502

489

34,212

33,363

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

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

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

Curtailments. The Company has advised the Trust that during 2014 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.

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, 2014, and certain related information for the Royalty Interests from the Reserve Estimate prepared by Ralph E. Davis & Associates. The natural gas reserves were estimated by Ralph E. Davis & Associates by applying volumetric and decline curve analyses. All of such reserves constitute proved developed gas reserves located in the United States. The Reserve Estimate was prepared in accordance with criteria established by the Commission.

Summary of Gas Reserves as of December 31, 2014 Based on Average Fiscal-Year Prices


	December 31, 2014
Net Proved (MMcf) (a):
Developed		11,460
Undeveloped		0

Total Proved		11,460

Estimated Future Net Revenues (in thousands) (a)(b):
2015	$	6,286
2016		5,535
2017		4,822
2018		4,176
2019		3,593
Thereafter		19,205

Total	$	43,617

Total Discounted at 10 Percent	$	27,489

(a)

The estimates of reserves and future net revenues summarized in this table are based upon a price of $4.077 per Mcf, which represented the average market price for gas in their fields during the 12-month period prior to December 31, 2014, 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 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.

Pursuant to the Conveyance, the Company has the obligation to conduct and carry on the development, maintenance and operation of the Underlying Properties as if they were not burdened by the Trust’s Royalty Interests. As a result, a well may be considered economic for purposes of calculating proved reserves even if such well is then being operated at a negative cash flow to the Company.

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 decrease from 1.7 Bcf in 2015 to 0.9 Bcf in 2019.

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, 2014, December 31, 2013 and December 31, 2012.


	Year ended December 31,
	2014		2013		2012
Production attributable to the Royalty Interests (Bcf)		1.7		1.9		2.0
Weighted average property, production (per Mcf)	$	0.25	$	0.21	$	0.25
Average Sales Price or Contract Price, as applicable (per Mcf)	$	4.24	$	3.59	$	2.78

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 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, 2012, 11 of the wells included in the Underlying Properties had been plugged and abandoned, through December 31, 2013, an additional 11 wells included in the Underlying Properties had been plugged and abandoned, and through December 31, 2014 an additional 8 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 (10 to 20 of which will continue to be evaluated in 2015), so there can be no assurance that additional 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 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.

PART II.

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

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


	Price				Distribution per Unit
	High		Low		Distribution per Unit
2014
First Quarter	$	7.92	$	5.40	$	0.171950
Second Quarter	$	11.12	$	5.53	$	0.191957
Third Quarter	$	8.70	$	4.80	$	0.194010
Fourth Quarter	$	7.90	$	5.37	$	0.180647

2013
First Quarter	$	5.85	$	3.07	$	0.160567
Second Quarter	$	5.84	$	4.11	$	0.146878
Third Quarter	$	6.18	$	3.96	$	0.201383
Fourth Quarter	$	8.29	$	5.00	$	0.172241

At March 04, 2015, there were 7,850,000 Units outstanding and approximately 244 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,
	2014		2013		2012		2011		2010
Royalty Income	$	7,059,159	$	6,423,288	$	5,341,293	$	8,359,767	$	10,207,523
Distributable Income	$	5,845,857	$	5,374,915	$	4,245,723	$	7,361,311	$	9,185,598
Distributable Income per Unit	$	0.74	$	0.68	$	0.54	$	0.94	$	1.17
Distributions per Unit	$	0.74	$	0.68	$	0.54	$	0.94	$	1.16
Total Assets, December 31	$	7,926,941	$	9,058,770	$	11,123,776	$	14,063,652	$	16,812,650
Total Corpus, December 31	$	7,766,371	$	8,920,146	$	11,003,644	$	13,927,682	$	16,653,530

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 2014 marked the twentieth full year of the existence of the Trust. The Trust received royalty income amounting to $7,059,159 during the year ended December 31, 2014, compared to $6,423,288 for 2013 and $5,341,293 for 2012, increasing due to higher pricing for natural gas but offset by declining production. 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, 2014 increased to $1,213,492, compared to $1,048,678 for 2013 and $1,095,854 for 2012. Distributable income for the year ended December 31, 2014 was $5,845,857, or $0.74 per Unit, compared to $5,374,915, or $0.68 per Unit, for 2013 and $4,245,723, or $0.54 per Unit, for 2012. The increase in general and administrative expenses in 2014 compared to 2013 was primarily the result of additional costs due to legal expenses related to the Trustee change. The decrease in general and administrative expenses in 2013 compared to 2012 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, 2014, 2013 and 2012, was based on production volumes and natural gas prices for the periods from October 1, 2013 to September 30, 2014, October 1, 2012 to September 30, 2013 and October 1, 2011 to September 30, 2012, respectively.

The following table sets forth the production volumes attributable to the Trust’s Royalty Interests and the average sales Price or contract price received, as applicable, 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,
	2014		2013		2012
Production (Bcf)(1)		1.771		1.902		2.034
Production (MMBtu)(2)		1.755		1.884		2.013
Average Sales or Contract Price Received ($/MMBtu)	$	4.28	$	3.62	$	2.81
Average Index Price ($/MMBtu)	$	4.29	$	3.65	$	2.73

(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, 2014, 2013 and 2012, by independent petroleum engineers. The reserve quantities of 11.5 Bcf for 2014 compared to 8.1 Bcf for 2013 and compared to 7.6 Bcf for 2012, reflect an increase in reserves between 2013 and 2014 and between 2012 and 2013 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. The Company informed the Trustee that it abandoned 11 wells in 2012, 11 wells in 2013 and 8 wells in 2014 as it considered them uneconomic and will continue to evaluate an additional 10 to 20 wells in 2015. If the Company decides to suspend production or abandon any such additional 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. Pursuant to the terms of the Trust Agreement, the Trust will terminate upon the occurrence of (i) such time as the ratio of cash amounts received by the Trust attributable to the Royalty Interests in any calendar quarter to administrative costs of the Trust for such calendar quarter is less than 1.2 to 1.0 for two consecutive calendar quarters; or (ii) 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 (i) above, the ratio of cash amounts to expenses for the most recent calendar quarter was 6.5 to 1 ratio and with respect to (ii) above, the net present value of the estimated future net revenues computed as described above by the independent petroleum engineers as of December 31, 2014 was approximately $27.5 million. While the results of these computations will not trigger early termination of the Trust as of December 31, 2014, future computations are subject to the numerous uncertainties in estimating the future net revenues. 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.

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, 2014, 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.

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, 2014, other than as stated below.

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

Tabular Disclosure of Contractual Obligations


			Payments Due by Period
Contractual Obligations	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years
Distribution declared subsequent to year end	$	1,370,200	$	1,370,200		0		0		0
Total	$	1,370,200	$	1,370,200		0		0		0

The above payable relates to distributions declared February 19, 2015 and payable March 11, 2015 to Unitholders of record on March 2, 2015.

Forward-Looking Statements

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

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

The Trust invests in no derivative financial instruments and has no foreign operations or long-term debt instruments. The assets of the Trust are passive in nature, and other than the Trust’s ability to periodically borrow money as necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited from engaging in borrowing transactions. The amount of any such borrowings is unlikely to be material to the Trust. The Trust periodically holds short-term investments acquired with funds held by the Trust pending distribution to Unitholders and funds held in reserve for the payment of Trust expenses and liabilities. Because of the short-term nature of these borrowings and investments and certain limitations upon the types of such investments 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 a fund that holds only U.S. Treasury Securities. 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 — 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.

Item 8. Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Unit Holders of Dominion Resources Black Warrior Trust and

Southwest Bank, Trustee,

Dallas, Texas:

We have audited the accompanying statements of assets, liabilities, and trust corpus of Dominion Resources Black Warrior Trust (the “Trust”) as of December 31, 2014 and 2013, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2014. 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 the Trustee, 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, 2014 and 2013, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2014, on the basis of accounting described in Note 2.

As described in Note 10 to the financial statements, in March 2012, Walter Black Warrior Basin LLC 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 Walter Black Warrior Basin LLC 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.

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, 2014, based on criteria established in Internal Control —Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 23, 2015 expressed an unqualified opinion on the Trust’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Dallas, Texas

March 23, 2015

DOMINION RESOURCES BLACK WARRIOR TRUST

FINANCIAL STATEMENTS

Statements of Assets, Liabilities and Trust Corpus


	December 31,
	2014		2013
ASSETS
Cash and cash equivalents	$	176,847	$	106,772
Royalty interests in gas properties (less accumulated amortization of $148,067,406 and $146,865,502, respectively)		7,750,094		8,951,998

Total Assets	$	7,926,941	$	9,058,770

LIABILITIES AND TRUST CORPUS
Trust expenses payable	$	160,570	$	138,624
Contingencies (Note 10)
Trust corpus (7,850,000 units of beneficial interest authorized, issued and outstanding)		7,766,371		8,920,146

Total Liabilities and Trust Corpus	$	7,926,941	$	9,058,770

Statements of Distributable Income


	Year Ended December 31,
	2014			2013			2012
Royalty income	$	7,059,159		$	6,423,288		$	5,341,293
Interest income		190			305			284

		7,059,349			6,423,593			5,341,577
General and administrative expenses		(1,213,492	)		(1,048,678	)		(1,095,854	)

Distributable income	$	5,845,857		$	5,374,915		$	4,245,723

Distributable income per unit (7,850,000 units)	$	0.74		$	0.68		$	0.54

Statements of Changes in Trust Corpus


	Year Ended December 31,
	2014			2013			2012
Trust corpus, beginning of period	$	8,920,146		$	11,003,644		$	13,927,682
Amortization of Royalty Interests		(1,201,904	)		(2,112,022	)		(2,942,685	)
Distributable income		5,845,857			5,374,915			4,245,723
Distributions to Unitholders		(5,797,728	)		(5,346,391	)		(4,227,076	)

	$	7,766,371		$	8,920,146		$	11,003,644

Distributions per unit	$	0.74		$	0.68		$	0.54

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

Notes to Financial Statements

Years Ended December 31, 2014, 2013 and 2012

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 NationsBank of Texas, N.A., a national banking association, as the initial trustee; and BNY Mellon Trust of Delaware, a national banking association (the “Delaware Trustee”), as trustees. Southwest Bank, a state bank chartered under the laws of the State of Texas (“Southwest Bank”) now serves as the trustee (the “Trustee”). The trustees are independent financial institutions.

The Trust is a grantor trust formed to acquire and hold certain overriding royalty interests (the “Royalty Interests”) burdening proved natural gas properties located in the Pottsville coal formation of the Black Warrior Basin, Tuscaloosa County, Alabama (the “Underlying Properties”) owned by 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

Notes to Financial Statements — (Continued)

“executive officers” of the Trust as such terms are defined under applicable rules and regulations adopted under the Securities Exchange Act of 1934.

2. Accounting Policies

Basis of Accounting

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).

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.

Notes to Financial Statements — (Continued)

Impairment

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

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

Notes to Financial Statements — (Continued)

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. Southwest Bank, EIN: 75-1105980, 2911 Turtle Creek Boulevard, Suite 850, Dallas, Texas 75219, telephone number (855) 588-7839, email address trustee@dom-dominion.com 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-dominion.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.

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 2014 the fee for these services was $537,888 and will increase annually by three percent. Fees paid by the Trust to Walter Exploration & Production in 2013 were $522,221 and in 2012 were $507,011.

Aggregate fees and expense reimbursements paid by the Trust to the Trustees in 2014, 2013 and 2012 were $72,335, $57,222 and $55,701, 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

Notes to Financial Statements — (Continued)

$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, 2014, the Trust declared and paid the following distribution:


Quarterly Record Date	Payment Date	Distribution per Unit
March 2, 2015	March 11, 2015	$ 0.174547

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, 2014 and 2013 (in thousands, except per Unit amounts):


Calendar Quarter	Royalty Income		Distributable Income		Distributable Income per Unit
2014
First	$	1,590	$	1,235	$	0.16
Second		1,958		1,631		0.21
Third		1,848		1,574		0.20
Fourth		1,663		1,406		0.17

	$	7,059	$	5,846	$	0.74


2013
First	$	1,593	$	1,296	$	0.17
Second		1,395		1,075		0.14
Third		1,831		1,619		0.20
Fourth		1,604		1,385		0.17

	$	6,423	$	5,375	$	0.68

Selected 2014 fourth quarter data are as follows (in thousands, except per Unit amounts):


Royalty income	$	1,663
Interest income		—
General and administrative expenses		(257	)

Distributable income	$	1,406

Distributable income per Unit	$	0.17
Distributions per Unit	$	0.17

8. Supplemental Gas Disclosure (Unaudited)

The net proved reserves attributable to the Royalty Interests have been estimated as of December 31, 2014, 2013, 2012 and January 1, 2012, by independent petroleum engineers.

Notes to Financial Statements — (Continued)

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

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

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


Proved developed reserves at January 1, 2012	11,036
Revisions of previous estimates	(1,377	)
Production (MMcf)	(2,010	)

Proved developed reserves at December 31, 2012	7,649
Revisions of previous estimates	2,315
Production (MMcf)	(1,902	)

Proved developed reserves at December 31, 2013	8,062
Revisions of previous estimates	5,169
Production (MMcf)	(1,771	)

Proved developed reserves at December 31, 2014	11,460

All proved reserve estimates presented above at December 31, 2014, 2013, 2012 and January 1, 2012, 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.

Notes to Financial Statements — (Continued)

The following table sets forth the standardized measure of discounted estimated future net cash flows from proved reserves at December 31, 2014, 2013 and 2012 relating to the Trust’s Royalty Interests (thousands of dollars):


	2014			2013			2012
Future cash inflows	$	46,728		$	27,875		$	21,036
Future taxes		(3,111	)		(1,882	)		(1,498	)

Future net cash flows		43,617			25,993			19,538
10% annual discount for estimated timing of cash flow		(16,128	)		(9,150	)		(6,714	)

Standardized measure of discounted future net cash flows	$	27,489		$	16,843		$	12,824

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

The following table sets forth the changes in the present value of estimated future net cash flows from proved reserves during the year ended December 31, 2014, 2013 and 2012 (thousands of dollars):


	2014			2013			2012
Balance at beginning of period	$	16,843		$	12,824		$	26,893
Increase (decrease) due to:
Royalty income, net of taxes		(7,059	)		(6,423	)		(5,341	)
Changes in prices		8,116			5,408			(9,192	)
Changes in estimated volumes		7,905			3,752			(2,225	)
Accretion of discount		1,684			1,282			2,689

Balance at December 31	$	27,489		$	16,843		$	12,824

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 LLC.

10. Contingencies

Notes to Financial Statements — (Continued)

rights related to property in Fayette and Tuscaloosa Counties in Alabama. The plaintiff alleges that defendants are knowingly producing gas in violation of the deeds in question. The plaintiff is also alleging conversion of gas, continuing trespass by defendants on plaintiff’s property, and suppression of material facts by defendants, and plaintiff is requesting an accounting, injunctive relief and compensatory and punitive damages, plus court costs and attorneys fees. The Trustee does not believe this litigation will have a material effect on the Trust’s financial statements.

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

None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

There has not been any change in the Trust’s internal control over financial reporting during the fourth quarter of 2014 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 (2013) 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 (2013), the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2014. 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, 2014, has issued an attestation report on the Trust’s internal control over financial reporting, which is included herein.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Unit Holders of Dominion Resources Black Warrior Trust and

Southwest Bank, Trustee,

Dallas, Texas:

We have audited the internal control over financial reporting of Dominion Resources Black Warrior Trust (the “Trust”) as of December 31, 2014, based on criteria established in Internal Control — Integrated Framework (2013) 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, 2014, based on the criteria established in Internal Control — Integrated Framework (2013) 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, 2014 and the related statement of distributable income and changes in trust corpus for the year ended December 31, 2014, 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 23, 2015 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding a study of the underlying properties on a well-by-well basis to determine the economic viability of continuing to produce each individual well.

/s/ DELOITTE & TOUCHE LLP

Dallas, Texas

March 23, 2015

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.

Standards of Conduct. Because the Trust has no employees, it does not have a code of ethics. Employees of the Trustee, Southwest Bank, must comply with the bank’s standards of conduct, a copy of which will be provided to Unitholders, without charge, upon request made to Royalty Trust Management, Southwest Bank, 2911 Turtle Creek Boulevard, Suite 850, Dallas, Texas 75219, 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 $53,788, plus an hourly charge of $13,567 for services in excess of a combined total of 350 hours annually at its standard rate, which is currently $200 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 2014, the Trustee (and its predecessor) and the Delaware Trustee received total compensation of $67,335 and $5,000, respectively.

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. Southwest Bank, the Trustee, and BNY Mellon Trust of Delaware, the Delaware Trustee, did not beneficially own any Units as of December 31, 2014.

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 $537,888 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.”

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, 2014 and 2013 are:


	2014		2013
Audit Fees	$	146,250	$	109,900
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—

	$	146,250	$	109,900

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

PART IV.

Item 15. Exhibits, Financial Statement Schedules.

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

Financial Statements (included in Item 8 of this report)


Report of Independent Registered Public Accounting Firm			37
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2014 and 2013			38
Statements of Distributable Income for the years ended December 31, 2014, 2013 and 2012			38
Statements of Changes in Trust Corpus for the years ended December 31, 2014, 2013 and 2012			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.		Exhibit

3.1	—	Trust Agreement of Dominion Resources Black Warrior Trust dated as of May 31, 1994, by and among Dominion Black Warrior Basin, Inc., Dominion Resources, Inc., Mellon Bank (DE) National Association and NationsBank, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 3.1 to Dominion Resources, Inc.’s Registration Statement* on Form S-3 (No. 33-53513), and incorporated herein by reference).

3.2	—	First Amendment of Trust Agreement of Dominion Resources Black Warrior Trust dated as of June 27, 1994, by and among Dominion Black Warrior Basin, Inc., Dominion Resources, Inc., Mellon Bank (DE) National Association and NationsBank, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 3.2 to the Registrant’s Form 10-Q for the quarter ended June 30, 1994 and incorporated herein by reference).

10.1	—	Overriding Royalty Conveyance dated as of June 28, 1994, from Dominion Black Warrior Basin, Inc. to Dominion Resources Black Warrior Trust (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 1994 and incorporated herein by reference).

10.2	—	Administrative Services Agreement dated as of June 1, 1994, by and between Dominion Resources, Inc. and Dominion Resources Black Warrior Trust (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarter ended June 30, 1994 and incorporated herein by reference).

10.3	—	Amendment to and Ratification of Overriding Royalty Conveyance dated as of November 20, 1994, among Dominion Black Warrior Basin, Inc., NationsBank, N.A. (as successor to NationsBank of Texas, N.A.), and Mellon Bank (DE) National Association (filed as Exhibit 10.3 to the Registrant’s Form 10-K for the year ended December 31, 1994 and incorporated herein by reference).

10.4	—	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.


No.		Exhibit

99.2	—	Summary of Reserve Report, dated February 27, 2015, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests as of December 31, 2014, 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

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: SOUTHWEST BANK, TRUSTEE

By:		/S/ RON E. HOOPER
		Ron E. Hooper SVP Royalty Trust Management

Date: March 23, 2015

(The Registrant has no directors or executive officers.)

Index to Exhibits


No.		Exhibit

3.1	—	Trust Agreement of Dominion Resources Black Warrior Trust dated as of May 31, 1994, by and among Dominion Black Warrior Basin, Inc., Dominion Resources, Inc., Mellon Bank (DE) National Association and NationsBank, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 3.1 to Dominion Resources, Inc.’s Registration Statement* on Form S-3 (No. 33-53513), and incorporated herein by reference).

3.2	—	First Amendment of Trust Agreement of Dominion Resources Black Warrior Trust dated as of June 27, 1994, by and among Dominion Black Warrior Basin, Inc., Dominion Resources, Inc., Mellon Bank (DE) National Association and NationsBank, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 3.2 to the Registrant’s Form 10-Q for the quarter ended June 30, 1994 and incorporated herein by reference).

10.1	—	Overriding Royalty Conveyance dated as of June 28, 1994, from Dominion Black Warrior Basin, Inc. to Dominion Resources Black Warrior Trust (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended June 30, 1994 and incorporated herein by reference).

10.2	—	Administrative Services Agreement dated as of June 1, 1994, by and between Dominion Resources, Inc. and Dominion Resources Black Warrior Trust (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarter ended June 30, 1994 and incorporated herein by reference).

10.3	—	Amendment to and Ratification of Overriding Royalty Conveyance dated as of November 20, 1994, among Dominion Black Warrior Basin, Inc., NationsBank, N.A. (as successor to NationsBank of Texas, N.A.), and Mellon Bank (DE) National Association (filed as Exhibit 10.3 to the Registrant’s Form 10-K for the year ended December 31, 1994 and incorporated herein by reference).

10.4	—	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 February 27, 2015, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests as of December 31, 2014, 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

Exhibit 23.1

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

Ralph E. Davis Associates, Inc. hereby consents to the reference to our firm and to its having prepared a report of DOMINION RESOURCES BLACK WARRIOR TRUST (the “Company”), and an estimate of the proved gas reserves for the fiscal year ended December 31, 2014. We hereby further consent to the use of the report dated March 23, 2015 appearing in the Company’s Form 10-K for the year ended December 31, 2014 and in all current and future registration statements of the Company that incorporate by reference such Form 10-K.


RALPH E. DAVIS ASSOCIATES, INC.

By:		/s/ Allen C. Barron
		Name: Allen C. Barron
		Title: President

March 23, 2015

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

Exhibit 31.1

Certification Required by Rule 13a-14(a)

or Rule 15d-14(a)

I, Ron Hooper, certify that:

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

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

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

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

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

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

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

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

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

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

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

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

Date: March 23, 2015



By:		/s/ Ron E. Hooper
		Ron E. Hooper
		SVP Royalty Trust Management
		Southwest Bank

Exhibit 32.1

Certification required by Rule 13a-14(b) or

Rule 15d-14(b) and Section 906 of

the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Dominion Resources Black Warrior Trust (the “Trust”) on Form 10-K for the period ended December 31, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, not in its individual capacity but solely as the trustee of the Trust, certifies pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to its knowledge:

(1)

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

(2)

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


	SOUTHWEST BANK, TRUSTEE FOR DOMINION RESOURCES BLACK WARRIOR TRUST

March 23, 2015	By:	/s/ Ron E. Hooper
		Ron E. Hooper,
		SVP Royalty Trust Management
		Southwest Bank

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

Exhibit 99.2

LOGO

February 27, 2015

Dominion Black Warrior Trust 1994-1

c/o Royalty Trust Management, Southwest Bank

2911 Turtle Creek Blvd., Suite 850

Dallas, Texas 75219

Attn: Mr.

Ron E. Hooper

Sr. VP, Royalty Trust Management

Re: Estimated Reserves and Non Escalated Future

Net Revenue Remaining as of December 31, 2014

Dominion Black Warrior Trust 1994-1

Gentlemen:

At your request the firm of Ralph E. Davis Associates, Inc. (“Davis”) of Houston, Texas has prepared an estimate of the natural gas reserves on specific leaseholds in which Dominion Black Warrior Trust 1994-1 (the “Trust”) has certain interests. The interests evaluated are a royalty interest ownership position applicable to specific gas properties in the Black Warrior Basin, Tuscaloosa County, Alabama. The purpose of this report is to present our estimate of the proved reserves that in our opinion meet the criteria for proved reserve volumes in keeping with the directives of the Securities and Exchange Commission as detailed later in this report, and are anticipated to be produced from those leaseholds and remaining as of the effective date of December 31, 2014.

Davis has reviewed 100% of the Trust’s proved developed properties located in the Black Warrior Basin area of Alabama. It is our opinion that these properties represent all of the Trust’s natural gas assets that may be classified as proved as per the Securities Exchange Commission directives as detailed later in this report. This report presents our assessment of those reserves as of the effective date of the report, December 31, 2014, having completed the evaluation of said estimate of reserves based upon the information presented within this report, on February 27, 2015.

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

We have also estimated the future net revenue and discounted present value associated with these reserves as of December 31, 2014, utilizing a scenario of non-escalated product prices as well as non-

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

Worldwide Energy Consultants Since 1924




Estimated Reserves and Non Escalated Future Net Revenue Remaining as of December 31, 2014 Dominion Black Warrior Trust 1994-1			February 27, 2015 Page 2

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

The results of our study may be summarized as follows:

Non Escalated Pricing Scenario

Estimated Reserves and Future Net Income

Net to Dominion Black Warrior Trust 1994-1

As of December 31, 2014


	Total Proved
Net Remaining Sales Gas Reserves:
Gas: Mcf		11,460,345

Future Revenue:
Sales Revenue	$	46,728,406
Tax Credit Revenue	$	0
Total Revenue	$	46,728,406

Total Production and Ad Valorem Taxes	($	3,111,177	)
Other Deductions	$	0

Future Net Income	$	43,617,227
Future Net Income Discounted @ 10%	$	27,488,895

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

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

DISCUSSION

The scope of this study was to review basic information compiled by Walter Black Warrior Basin LLC (“Walter”) the operator of the properties, and prepare estimates of the proved reserves attributable to the interests of the Trust. Reserve estimates were prepared by Davis using acceptable evaluation principals for each source and were based in large part on the basic information supplied by the parties.

The quantities presented herein are estimated reserves of natural gas that geologic and engineering data demonstrate can be recovered from known reservoirs under current terms and conditions attributable to the Trust’s ownership and with reasonable certainty. There are no Proved undeveloped locations scheduled to be drilled on the subject properties.

Texas Registered Engineering Firm F-1529




Estimated Reserves and Non Escalated Future Net Revenue Remaining as of December 31, 2014 Dominion Black Warrior Trust 1994-1			February 27, 2015 Page 3

This evaluation has been prepared in accordance with the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” as proclaimed by the Society of Petroleum Engineers, the SPE Standards.

OWNERSHIP

Ownership interests in the subject properties have been furnished by the Trust and accepted by Davis as accurate without independent verification.

DATA SOURCE

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

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

Operating cost data provided by the operator were utilized to estimate the direct cost of operation for each producing property. The current operating cost were reviewed with previous year’s data and found to be consistent and reasonable. These costs were utilized to determine whether each individual well was currently an economic completion, and if so, when the well would reach its economic life.

RESERVE ESTIMATES

The estimate of reserves included in this report is based primarily upon production history, or analogy with wells in the area producing from the same or similar formations. Individual well production histories were analyzed and an appropriate daily producing rate was utilized for each individual well in the preparation of a forecast of future producing rates.

Recent lifting costs not borne by the Trust but applicable to the operator’s cost of operation have exceeded the sales prices of gas at various times during the past few years. The operator has reported to the Trust and to Davis that they are reviewing all producing properties on a well by well basis to determine the economic viability of continuing to produce each individual well. Several criteria are to be considered, including anticipated future changes in the sales price of natural gas.

Based upon the operator’s review eight wells were abandoned during calendar 2014 from among those wells identified as being non-economic. On-going studies have indicated that as many as ten to twenty additional wells will be subject to abandonment during 2015 should prices for the sale of natural gas remain at a level insufficient to cover cost of operations. An analysis by Davis of the current operating conditions indicates that over eighty percent of the existing producing wells are being operated at a negative cash flow to the working interest owner, Walter, at this time. Pursuant to the Overriding Royalty Conveyance governing the Trust’s interests, Walter has the obligation to conduct and carry on

Texas Registered Engineering Firm F-1529




Estimated Reserves and Non Escalated Future Net Revenue Remaining as of December 31, 2014 Dominion Black Warrior Trust 1994-1			February 27, 2015 Page 4

the development, maintenance and operation of the properties as if they were not burdened by the Trust’s royalty interests. As a result, a well may be considered economic for purposes of calculating proved reserves even if such well is then being operated at a negative cash flow to Walter.

Davis has continued to evaluate the Trust’s assets as a royalty interest position within the context of a royalty owner not being allocated any cost of operations. Consequently, any determination by the operator to temporarily cease production from an individual well or to abandon production entirely could have an immediate and negative impact on the Trust’s valuation. However, within this report the data utilized, assumptions made and methods and procedures used are consistent with previous evaluation methods and are considered appropriate and necessary for the estimates made and purposes for which this report was prepared.

In addition to the normal gas filed operational considerations, active coal mining operations have begun encroaching upon the properties containing the Trust acreage. As a result, producing wells will be abandoned on an ongoing basis as the subsurface mining activities expand throughout the area. A schedule of specific wells to be abandoned and the anticipated timing of the abandonment have been taken into consideration in this evaluation.

The reserves included in this report are estimates only and should not be construed as being exact quantities. Reserve volumes presented in this report are based upon the available data and are calculated using all methods and procedures as we considered necessary under the circumstances to prepare this report and are believed to be reasonable; however, future reservoir performance may justify revision of these estimates. The various methods and procedures used in the evaluation of the subject properties are considered appropriate for an audit of the subject properties.

It should be noted that all reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends primarily on the amount of reliable geological and engineering data available at the time of the estimate and the interpretation of these data. These reserves have been determined using methods and procedures widely accepted within the industry and are believed to be appropriate for the purposes of this report. In our opinion, we used all methods and procedures necessary under the circumstances to prepare this report.

Regulations in the Oil and Gas industry are constantly changing to meet new safety and environmental concerns, in addition to the possibility of some market regulations which have occasionally occurred historically. State, Local or Federal Regulations, such as upon hydraulic fracturing, or drill/production site security and safety, environmental regulations of spills noxious emissions, greenhouse gases, and drill site location, wildlife protections and extensive permitting processes, sometimes with multiple agencies or governments, in the future may all adversely affect the ability of the Registrant to recover the estimated reserves, as well as potentially rendering the reserves uneconomic, in certain, as yet undetermined, circumstances. To the best of the engineers belief, none of the reserves described in this report are negatively impacted as of the date of this report, by any such current regulations.

Texas Registered Engineering Firm F-1529




Estimated Reserves and Non Escalated Future Net Revenue Remaining as of December 31, 2014 Dominion Black Warrior Trust 1994-1			February 27, 2015 Page 5

PRODUCING RATES

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

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

PRICING PROVISIONS

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

Natural Gas - The unit price used throughout this report for natural gas is an initial price of $4.35 per MMBTU, based upon the appropriate price in effect the first trading of each month during calendar 2014, and averaged for the year. This price is representative of the price in effect for sales based upon the Sonat T1 price on that trading day. A basis differential was applied to all sales volumes, and this differential as well as the price for gas was held constant throughout the producing life of the property. Prices for gas reserves scheduled for initial production at some future date were estimated using this same price. The average price realized for natural gas reserves over the producing life of the properties, was $3.457 per MMBTU, and represents the combined effect due to the adjustments for location and quality differentials such as transportation and the BTU (heating value) of the gas.

FUTURE NET INCOME

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

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

Texas Registered Engineering Firm F-1529




Estimated Reserves and Non Escalated Future Net Revenue Remaining as of December 31, 2014 Dominion Black Warrior Trust 1994-1			February 27, 2015 Page 6

GENERAL

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

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

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

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

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

Neither Ralph E. Davis Associates, Inc. nor any of its employees have any interest in Dominion Black Warrior Trust 1994-1 or the properties reported herein. The employment and compensation to make this study are not contingent on our estimate of reserves. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the SPE standards.

This report has been prepared for public disclosure by Dominion Black Warrior Trust 1994-1 in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

We appreciate the opportunity to be of service to you in this matter and will be glad to address any questions or inquiries you may have.

Very truly yours,

RALPH E. DAVIS ASSOCIATES, INC.

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Texas Registered Engineering Firm F-1529

SECURITIES AND EXCHANGE COMMISSION

DEFINITIONS OF RESERVES

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

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

Rules of General Application

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

Reserves

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

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

Proved Oil and Gas Reserves

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

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

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

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

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

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

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

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

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

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

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

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

Probable Reserves

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

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

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

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

Possible Reserves

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

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

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

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

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

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

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

Developed Oil and Gas Reserves

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

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

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

Undeveloped Oil and Gas Reserves

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

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

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

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

Additional Definitions:

Deterministic Estimate

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

Probabilistic Estimate

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

Reasonable Certainty

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

DOMINION BLACK WARRIOR TRUST 1994-1

UNESCALATED ANALYSIS

TOTAL ROYALTY INTERESTS

TOTAL PROVED RESERVES

RESERVES AND ECONOMICS


							AS OF DECEMBER 31, 2014
			GROSS PRODUCTION						NET PRODUCTION				PRICES				OPERATIONS, M$
END MO–YEAR	NO. OF WELLS		OIL MBBL		WELL HEAD GAS, MMCF		SALES GAS, MMCF		OIL MBBL		SALES GAS, MMCF		OIL $/B		GAS $/M		OIL REVENUE		GAS REVENUE		TAX CREDITS		TOTAL REVENUE
12-2015		426.8		0.000		3435.527		3091.973		0.000		1651.597		0.00		4.077		0.000		6734.221		0.000		6734.221
12-2016		406.8		0.000		3021.995		2719.796		0.000		1454.441		0.00		4.077		0.000		5930.339		0.000		5930.339
12-2017		377.9		0.000		2627.824		2365.041		0.000		1266.870		0.00		4.077		0.000		5165.533		0.000		5165.533
12-2018		346.8		0.000		2271.313		2044.182		0.000		1097.247		0.00		4.077		0.000		4473.913		0.000		4473.913
12-2019		314.4		0.000		1950.177		1755.160		0.000		944.018		0.00		4.077		0.000		3849.139		0.000		3849.139
12-2020		280.2		0.000		1658.432		1492.589		0.000		805.276		0.00		4.077		0.000		3283.435		0.000		3283.435
12-2021		248.2		0.000		1407.675		1266.908		0.000		684.470		0.00		4.077		0.000		2790.857		0.000		2790.857
12-2022		206.9		0.000		1154.957		1039.461		0.000		563.465		0.00		4.077		0.000		2297.473		0.000		2297.473
12-2023		168.9		0.000		940.987		846.888		0.000		459.748		0.00		4.077		0.000		1874.578		0.000		1874.578
12-2024		140.0		0.000		775.678		698.110		0.000		379.707		0.00		4.077		0.000		1548.218		0.000		1548.218
12-2025		115.8		0.000		642.063		577.856		0.000		314.547		0.00		4.077		0.000		1282.534		0.000		1282.534
12-2026		92.8		0.000		523.259		470.933		0.000		257.127		0.00		4.077		0.000		1048.410		0.000		1048.410
12-2027		75.0		0.000		430.582		387.524		0.000		211.752		0.00		4.077		0.000		863.398		0.000		863.398
12-2028		62.8		0.000		363.013		326.712		0.000		178.312		0.00		4.077		0.000		727.049		0.000		727.049
12-2029		53.2		0.000		308.901		278.011		0.000		151.885		0.00		4.077		0.000		619.296		0.000		619.296
S TOT		1.4		0.000		21512.383		19361.145		0.000		10420.460		0.00		4.077		0.000		42488.395		0.000		42488.395
AFTER		1.4		0.000		2082.302		1874.072		0.000		1039.882		0.00		4.077		0.000		4240.014		0.000		4240.014
TOTAL		1.4		0.000		23594.684		21235.217		0.000		11460.342		0.00		4.077		0.000		46728.406		0.000		46728.406


	OPERATIONS, M$								CAPITAL COSTS, M$
END MO–YEAR	PRODUCTION TAXES		AD VALOREM EXPENSES		NET OPER EXPENSES		OPERATION CASH FLOW		TANGIBLE INV.		INTANG. INV.		TOTAL BORROW INV		TOTAL EQUITY INV		CASH FLOW BTAX, M$		10.0% DISCOUNTED BTAX, M$
12-2015		404.053		44.311		0.000		6285.855		0.000		0.000		0.000		0.000		6285.855		6001.324
12-2016		355.820		39.022		0.000		5535.497		0.000		0.000		0.000		0.000		5535.497		4804.904
12-2017		309.932		33.989		0.000		4821.613		0.000		0.000		0.000		0.000		4821.613		3805.230
12-2018		268.435		29.438		0.000		4176.040		0.000		0.000		0.000		0.000		4176.040		2996.119
12-2019		230.948		25.327		0.000		3592.863		0.000		0.000		0.000		0.000		3592.863		2343.700
12-2020		197.006		21.605		0.000		3064.824		0.000		0.000		0.000		0.000		3064.824		1817.225
12-2021		167.452		18.364		0.000		2605.043		0.000		0.000		0.000		0.000		2605.043		1404.554
12-2022		137.848		15.117		0.000		2144.508		0.000		0.000		0.000		0.000		2144.508		1051.334
12-2023		112.475		12.335		0.000		1749.768		0.000		0.000		0.000		0.000		1749.768		779.859
12-2024		92.893		10.187		0.000		1445.138		0.000		0.000		0.000		0.000		1445.138		585.466
12-2025		76.952		8.439		0.000		1197.143		0.000		0.000		0.000		0.000		1197.143		440.862
12-2026		62.905		6.899		0.000		978.607		0.000		0.000		0.000		0.000		978.607		327.715
12-2027		51.804		5.681		0.000		805.913		0.000		0.000		0.000		0.000		805.913		245.227
12-2028		43.623		4.784		0.000		678.642		0.000		0.000		0.000		0.000		678.642		187.785
12-2029		37.158		4.075		0.000		578.063		0.000		0.000		0.000		0.000		578.063		145.360
S TOT		2549.303		279.574		0.000		39659.512		0.000		0.000		0.000		0.000		39659.512		26936.666
AFTER		254.401		27.899		0.000		3957.714		0.000		0.000		0.000		0.000		3957.714		552.228
TOTAL		2803.704		307.473		0.000		43617.227		0.000		0.000		0.000		0.000		43617.227		27488.895


	OIL		GAS				P.W. %		P.W., M$
GROSS WELLS		0.0		503.0	LIFE, YRS.	43.00		5.00		33518.859
GROSS ULT., MB & MMF		0.000		339167.000	DISCOUNT %	10.00		10.00		27488.887
GROSS CUM., MB & MMF		0.000		315572.312	UNDISCOUNTED PAYOUT, YRS.	0.00		15.00		23450.666
GROSS RES., MB & MMF		0.000		23594.680	DISCOUNTED PAYOUT, YRS.	0.00		18.00		21604.447
NET RES., MB & MMF		0.000		11460.345	UNDISCOUNTED NET/INVEST.	0.00		20.00		20545.582
NET REVENUE, M$		0.000		46728.406	DISCOUNTED NET/INVEST.	0.00		25.00		18351.576
INITIAL PRICE, $		0.000		4.077	RATE-OF-RETURN, PCT.	100.00		40.00		14120.642
INITIAL N.I., PCT.		0.000		52.969	INITIAL W.I., PCT.	0.000		60.00		11073.763
								80.00		9290.772
								100.00		8116.268

RALPH E. DAVIS ASSOCIATES, INC.

Texas Registered Engineering Firm F-1529

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CERTIFICATE OF QUALIFICATION

I, Allen C. Barron, of 1717 St. James Place, Suite 460, Houston, Texas 77056 hereby certify:

I am an employee of Ralph E. Davis Associates, Inc., that has prepared an estimate of the natural gas reserves on specific leaseholds in which Dominion Black Warrior Trust 1994-1 has certain interests. The effective date of this evaluation is December 31, 2014.

I am Licensed Professional Engineer by the State of Texas, P.E. License number 48284.

I attended the University of Houston in Houston, Texas and graduated with a Bachelor of Science Degree in Chemical Engineering with a Petroleum Engineering option in 1968. I have in excess of forty-six years of experience in the Petroleum Industry of which over thirty-six years of experience are in the conduct of evaluation and engineering studies relating to both domestic U.S. oil and gas fields and international energy assets.

I have prepared reserve evaluation studies and reserve audits for public and private companies for the purpose of reserve certification filings in foreign countries, domestic regulatory filings, financial disclosures and corporate strategic planning. I personally supervised and participated in the evaluation of the Dominion Black Warrior Trust 1994-1 properties that are the subject of this report.

I do not have, nor do I expect to receive, any direct or indirect interest in the securities of Dominion Black Warrior Trust 1994-1or any affiliated organization.

A personal field inspection of the properties was not made, however, such an inspection was not considered necessary in view of the information available from public information, records and the files of the operator of the properties.

SIGNED: February 27, 2015

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