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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
(MARK ONE)
[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
OR
[_]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
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COMMISSION FILE NUMBER: 001-11335
DOMINION RESOURCES BLACK WARRIOR TRUST
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 75-6461716
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NUMBER)
NATIONSBANK OF TEXAS, N.A.
NATIONSBANK CENTER
901 MAIN STREET
17TH FLOOR
DALLAS, TEXAS 75202
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(214) 508-2400
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
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NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
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Units of Beneficial Interest New York Stock Exchange, Inc.
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SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
At March 18, 1997, there were 7,850,000 units of beneficial interest
outstanding and the aggregate market value of such units (based on the closing
sale price on the New York Stock Exchange) held by non-affiliates of the
registrant was approximately $169,756,250.
DOCUMENTS INCORPORATED BY REFERENCE
Listed below are documents parts of which are incorporated herein by
reference and the part of this report into which the document is incorporated:
(1) 1996 Annual Report to Unitholders--Part II.
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TABLE OF CONTENTS
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PART I..................................................................... 1
Item 1. Business......................................................... 1
GLOSSARY............................................................... 1
DESCRIPTION OF THE TRUST............................................... 4
Creation and Organization of the Trust............................... 4
Assets of the Trust.................................................. 4
Duties and Limited Powers of the Trustee and the Delaware Trustee.... 4
Resignation of Trustees.............................................. 5
Transfer of Royalty Interests........................................ 6
Liabilities of the Trust............................................. 6
Liabilities of the Trustee and the Delaware Trustee.................. 6
Termination and Liquidation of the Trust............................. 7
Arbitration and Actions by Unitholders............................... 8
DESCRIPTION OF UNITS................................................... 9
Distributions and Income Computations................................ 9
Conditional Right of Repurchase...................................... 10
Possible Divestiture of Units........................................ 12
Periodic Reports..................................................... 12
Voting Rights of Unitholders......................................... 13
Liability of Unitholders............................................. 14
Transfer Agent....................................................... 14
FEDERAL INCOME TAX CONSIDERATIONS...................................... 14
Summary of Certain Federal Income Tax Consequences................... 15
ERISA CONSIDERATIONS................................................... 19
STATE TAX CONSIDERATIONS............................................... 20
Alabama Income Tax................................................... 20
Alabama Franchise Tax................................................ 21
Other Alabama Taxes.................................................. 21
REGULATION AND PRICES.................................................. 21
Regulation of Natural Gas............................................ 21
Environmental Regulation............................................. 22
Competition, Markets and Prices...................................... 23
Item 2. Properties....................................................... 24
THE ROYALTY INTERESTS.................................................. 24
The Underlying Properties............................................ 24
The Royalty Interests................................................ 26
Reserve Estimate..................................................... 28
Natural Gas Sales Prices and Production.............................. 29
Gas Purchase Agreement............................................... 30
Operation of Properties.............................................. 31
Sale and Abandonment of Underlying Properties........................ 32
Dominion Resources' Assurances....................................... 32
Title to Properties.................................................. 33
Item 3. Legal Proceedings................................................ 33
Item 4. Submission of Matters to a Vote of Security Holders.............. 33
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PART II................................................................... 34
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters......................................................... 34
Item 6. Selected Financial Data......................................... 34
Item 7. Trustee's Discussion and Analysis of Financial Condition and
Results of Operations........................................... 34
Item 8. Financial Statements and Supplementary Data..................... 34
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure............................................ 34
PART III.................................................................. 34
Item 10. Directors and Executive Officers of the Registrant............. 34
Item 11. Executive Compensation......................................... 34
Item 12. Security Ownership of Certain Beneficial Owners and
Management..................................................... 35
Item 13. Certain Relationships and Related Transactions................. 35
Administrative Services Agreement..................................... 35
Dominion Resources' Conditional Right of Repurchase................... 36
Potential Conflicts of Interest....................................... 36
PART IV................................................................... 37
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-
K.............................................................. 37
Financial Statements.................................................. 37
Financial Statement Schedules......................................... 37
Exhibits.............................................................. 37
Reports on Form 8-K................................................... 38
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PART I
ITEM 1. BUSINESS.
GLOSSARY
The following is a glossary of certain defined terms used in this Annual
Report on Form 10-K.
"Administrative Services Agreement" means the Administrative Services
Agreement dated as of June 28, 1994, between Dominion Resources and the Trust,
a copy of which is filed as an exhibit to this Form 10-K.
"Bcf" means billion cubic feet of natural gas.
"Btu" means British Thermal Unit, the common unit of gross heating value
measurement for natural gas.
"Code" means the Internal Revenue Code of 1986, as amended.
"Company" means Dominion Black Warrior Basin, Inc., an Alabama corporation
and a wholly-owned indirect subsidiary of Dominion Resources.
"Company Interests" means the Company's interest in the Underlying
Properties, as of June 1, 1994, not burdened by the Royalty Interests.
"Company Interests Owner" means the Company while it owns all or part of the
Company Interests and any other person or persons who acquire all or any part
of the Company Interests or any operating rights therein other than a royalty,
overriding royalty, production payment or net profits interest.
"Contract Price" means the price at which, pursuant to the Gas Purchase
Agreement, Sonat Marketing is obligated to purchase the Subject Gas at the
central delivery points in the gathering system for the Underlying Properties.
Prior to April 1, 1996, the Gas Purchase Agreement specified that the Contract
Price for each month equaled (i) from June 1, 1994 through December 31, 1998
(a) for quantities of natural gas equal to or less than the Monthly Base
Quantity, the sum of the Index Price and the Premium, which price would not
have been below the Minimum Price or above the Maximum Price, and (b) for
quantities of natural gas in excess of the Monthly Base Quantity, the Index
Price and (ii) after December 31, 1998, a price to be negotiated by the
Company and Sonat Marketing, which price would not have been less than the
Index Price. Effective April 1, 1996, the Contract Price for each month will
equal (i) for quantities of natural gas in excess of the Monthly Base
Quantity, the sum of the Index Price and $.02 per MMBtu and (ii) for
quantities of natural gas equal to or less than the Monthly Base Quantity, (a)
from April 1, 1996 through December 31, 1998, the sum of the Index Price and
the Premium, which price shall not be below the Minimum Price or above the
Maximum Price, (b) from January 1, 1999 through December 31, 2001, the sum of
the Index Price and the Premium, which price shall not be limited by either
the Minimum Price or the Maximum Price, and (c) after December 31, 2001, a
price to be negotiated by the Company and Sonat Marketing, which price shall
not be less than the Index Price.
"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.
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"Delaware Trustee" means Mellon Bank (DE) National Association.
"Dominion Resources" means Dominion Resources, Inc., a Virginia corporation.
"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 Sonat Marketing, as amended by instrument
effective as of April 1, 1996.
"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.
"Index Price" means the price published by Inside Ferc's Gas Market Report in
its first issue of the month which posts prices for the beginning of such month
for "Prices of Spot Gas Delivered to Pipelines" "Southern Natural Gas Co."
"Louisiana" "Index," for such month.
"Mcf" means thousand cubic feet of natural gas. Natural gas volumes are
stated herein at the legal pressure base of 14.65 or 14.73 pounds per square
inch absolute, as the case may be, at 60 degrees Fahrenheit.
"Maximum Price" means $2.63 per MMBtu, the maximum price payable for the
Monthly Base Quantities pursuant to the Gas Purchase Agreement from June 1,
1994 through December 31, 1998.
"Minimum Price" means $1.85 per MMBtu, the minimum price payable for the
Monthly Base Quantities pursuant to the Gas Purchase Agreement from June 1,
1994 through December 31, 1998.
"MMcf" means million cubic feet of natural gas. As used herein, 1 MMcf is
assumed to have a Btu content of 990 MMBtu.
"MMBtu" means million Btu. As used herein, 990 MMBtu is deemed to be the Btu
content of 1 MMcf.
"Monthly Base Quantity" means the volumes of natural gas designated as such
in the Gas Purchase Agreement.
"Net revenue interest" means working interest or mineral interest less any
applicable royalties, overriding royalties or similar burdens on production
prior to the Royalty Interests.
"Net wells" and "net acres" are calculated by multiplying gross wells or
gross acres by the working interest in such wells or acres.
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"Premium" means the premium per MMbtu on a wet basis pursuant to the Gas
Purchase Agreement from June 1, 1994 through December 31, 2001 as follows:
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INDEX PRICE PREMIUM
($/MMBTU) ($ /MMBTU)
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Below $2.00................................................... $0.050
$2.01-2.25.................................................... $0.060
$2.26-2.50.................................................... $0.065
Above $2.50................................................... $0.070
</TABLE>
"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).
"Reserve Estimate" means the estimated net proved reserves, estimated future
net revenues and the discounted estimated future net revenues attributable to
the Royalty Interests as of January 1, 1997, prepared by Ryder Scott.
"River Gas" means The River Gas Corporation, an Alabama corporation.
"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.
"Ryder Scott" means Ryder Scott Company Petroleum Engineers, independent
petroleum engineers.
"Section 29 tax credit" means the tax credits for federal income tax purposes
pursuant to Section 29 of the Code to an owner of coal seam gas production,
which tax credits are generated upon the sale of such production.
"Sonat" means Sonat, Inc., a Delaware corporation.
"Sonat Marketing" means Sonat Marketing Company, a Delaware Corporation.
"Subject Gas" means Gas attributable to the Company Interests.
"Trust" means Dominion Resources Black Warrior Trust, a Delaware business
trust formed pursuant to the Trust Agreement.
"Trust Agreement" means the Trust Agreement dated as of May 31, 1994, among
the Company, as grantor, Dominion Resources, the Delaware Trustee and the
Trustee, as amended by instrument dated as of June 27, 1994, copies of which
are filed as exhibits to this Form 10-K.
"Trustee" means NationsBank of Texas, N.A.
"Working interest" generally refers to the lessee's interest in an oil, gas
or mineral lease which entitles the owner to receive a specified percentage of
oil and gas production, but requires the owner of such working interest to bear
such specified percentage of the costs to explore for, develop, produce and
market such oil and gas.
"Underlying Properties" means the natural gas properties in which the Company
has an interest located in the Black Warrior Basin, Tuscaloosa County, Alabama
insofar as such properties include the Pottsville Formation.
"Units" means the 7,850,000 units of beneficial interest issued by, and
evidencing the entire beneficial interest in, the Trust.
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DESCRIPTION OF THE TRUST
Dominion Resources Black Warrior Trust is a Delaware business trust formed
under the Delaware Business Trust Act, Title 12, Chapter 38 of the Delaware
Code, Section 3801 et seq. (the "Delaware Code"). The following information is
subject to the detailed provisions of the Trust Agreement and the Conveyance,
copies of which are filed as exhibits to this Form 10-K. The provisions
governing the Trust are complex and extensive and no attempt has been made
below to describe or reference all of such provisions. The following is a
general description of the basic framework of the Trust and the material
provisions of the Trust Agreement.
CREATION AND ORGANIZATION OF THE TRUST
The Trust was initially created by the filing of its Certificate of Trust
with the Delaware Secretary of State on May 31, 1994. In accordance with the
Trust Agreement, the Company contributed $1,000 as the initial corpus of the
Trust. On June 28, 1994, the Royalty Interests were conveyed to the Trust by
the Company pursuant to the Conveyance, in consideration for the issuance to
the Company of all 7,850,000 of the authorized Units in the Trust. The Company
transferred all the Units to its parent, Dominion Energy, Inc., which in turn
transferred all the Units to its parent, Dominion Resources. Dominion Resources
sold an aggregate of 6,904,000 Units to the public through various underwriters
(the "Underwriters") in June and August 1994 in the initial public offering of
the Units (the "Initial Public Offering") and sold the remaining 946,000 Units
to the public through certain of the Underwriters in June 1995 pursuant to
Post-Effective Amendment No. 1 to the Form S-3 Registration Statement relating
to the Units (the "Secondary Public Offering and, collectively with the Initial
Public Offering, the "Public Offerings").
ASSETS OF THE TRUST
The only assets of the Trust, other than cash and temporary investments being
held for the payment of expenses and liabilities and for distribution to
Unitholders, are the Royalty Interests. The Royalty Interests consist of
overriding royalty interests burdening the Company's interest in the Underlying
Properties. The Royalty Interests generally entitle the Trust to receive 65
percent of the Company's Gross Proceeds (as defined below). The Royalty
Interests are non-operating interests and bear only expenses related to
property, production and related taxes (including severance taxes). See
"Properties--The Royalty Interests."
The Company has advised the Trustee that all the production attributable to
the Underlying Properties is from the Pottsville coal formation and currently
constitutes coal seam gas that entitles the owners of such production, provided
certain requirements are met, to tax credits pursuant to Section 29 of the
Code, upon the production and sale of such gas. See "--Federal Income
Taxation."
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
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(including any indebtedness to the Trustee), the Trustee is authorized to (i)
mortgage and otherwise encumber the entire Trust estate or any portion thereof;
(ii) carve out and convey production payments; (iii) include all terms, powers,
remedies, covenants and provisions it deems necessary or advisable, including
confession of judgment and the power of sale with or without judicial
proceedings; and (iv) provide for the exercise of those and other remedies
available to a secured lender in the event of a default on such loan. The terms
of such indebtedness and security interest, if funds were loaned by the
Trustee, must be similar to the terms which the Trustee would grant to a
similarly 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 have any control over or any responsibility relating to the
operation of the Underlying Properties. The Company does not have any
contractual commitment to the Trust to develop further the Underlying
Properties or to maintain its ownership interest in any of the Underlying
Properties. The Company may sell the Company Interests subject to and burdened
by the Royalty Interests and, absent certain conditions having been met, with
the continuing benefit of Dominion Resources' assurances and the Gas Purchase
Agreement. For a description of the Underlying Properties, the Royalty
Interests and other information relating to such properties, see "Properties--
The Royalty Interests."
The Trust Agreement authorizes the Trustee to take such action as in its
judgment is necessary, desirable or advisable to best achieve the purposes of
the Trust. The Trustee is empowered by the Trust Agreement to employ
consultants and agents (including the Company, Dominion Energy and Dominion
Resources) and to make payments of all fees for services or expenses out of the
assets of the Trust. The Trustee is authorized to agree to modifications of the
terms of the Conveyance and to settle disputes with respect thereto, so long as
such modifications or settlements do not result in 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
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the outstanding Units, provided in each case that a successor trustee has been
appointed and has accepted its appointment. Any successor must be a bank or
trust company meeting certain requirements, including having capital, surplus
and undivided profits of at least $100,000,000, in the case of the Trustee, and
$20,000,000, in the case of the Delaware Trustee.
TRANSFER OF ROYALTY INTERESTS
Prior to the termination of the Trust, the Trustee is not authorized to sell
or otherwise dispose of all or any part of the Royalty Interests. The Trustee
is authorized and directed to sell and convey the Royalty Interests without
Unitholder approval upon termination of the Trust. No Unitholder approval for
such sales or dispositions is required even though they may constitute a
disposition of all or substantially all the assets of the Trust. Any sales upon
termination may be made to Dominion Resources or its affiliates. See "--
Termination and Liquidation of the Trust."
LIABILITIES OF THE TRUST
Because of the passive nature of the Trust assets and the restrictions on the
activities of the Trustee, the only liabilities the Trust have incurred are
those for routine administrative expenses, such as trusteeship fees and
accounting, engineering, legal and other professional fees and the
administrative services fee paid to Dominion Resources. If a court were to hold
that the Trust is taxable as a corporation, then the Trust would incur
substantial federal income tax liabilities. See also "--State Tax
Considerations--Alabama Franchise Tax."
LIABILITIES OF THE TRUSTEE AND THE DELAWARE TRUSTEE
Each of the Trustee and the Delaware Trustee may act in its discretion and is
personally or individually liable only for fraud or acts or omissions in bad
faith or which constitute gross negligence (and for taxes, fees and other
charges on, based on or measured by any fees, commissions or compensation
received pursuant to the Trust Agreement) and will not be otherwise liable for
any act or omission of any agent or employee unless such trustee has acted in
bad faith or with gross negligence in the selection and retention of such agent
or employee. Each of the Trustee and the Delaware Trustee (and their respective
agents) is indemnified by Dominion Resources and from the Trust assets for
certain environmental liabilities, and for any other liability, expense, claim,
damage or other loss incurred in performing its duties, unless resulting from
gross negligence, fraud or bad faith (each of the Trustee and the Delaware
Trustee is indemnified from the Trust assets against its own negligence which
does not constitute gross negligence), and will have a first lien upon the
assets of the Trust as security for such indemnification and for reimbursements
and compensation to which it is entitled; provided that the Trustee and the
Delaware Trustee are generally required to first be indemnified from Trust
assets before seeking indemnification from Dominion Resources. Dominion
Resources also has agreed to indemnify the Trustee and the Delaware Trustee
against certain securities laws' liabilities. Neither the Trustee nor the
Delaware Trustee is entitled to indemnification from Unitholders (except in
connection with lost or destroyed Unit certificates). Insofar as
indemnification for liabilities arising under the Securities Act of 1933, as
amended (the "Securities Act"), is permitted to the Trustee pursuant to the
foregoing provisions, the Trustee has been informed that in the opinion of the
Securities and Exchange Commission (the "Commission") such indemnification is
against public policy as expressed in the Securities Act and is, therefore,
unenforceable.
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TERMINATION AND LIQUIDATION OF THE TRUST
The Trust will terminate upon the occurrence of: (i) an affirmative vote of
the holders of not less than 66 2/3 percent of the outstanding Units to
terminate the Trust; (ii) such time as the ratio of the cash amounts received
by the Trust attributable to the Royalty Interests in any calendar quarter to
administrative costs of the Trust for such calendar quarter is less than 1.2 to
1.0 for two consecutive calendar quarters; or (iii) March 1 of any year if it
is determined, based on a reserve report as of December 31 of the prior year
prepared by a firm of independent petroleum engineers mutually selected by the
Trustee and the Company, that the net present value (discounted at 10 percent)
of (a) estimated future net revenues from proved reserves attributable to the
Royalty Interests plus (b) the amount of all remaining Section 29 tax credits
attributable to the Royalty Interests, is equal to or less than $5 million (as
applicable, the "Termination Date"). Upon such occurrence, the remaining assets
of the Trust will be sold, the net proceeds of the sale will be distributed to
the Unitholders and the Trust will be wound up and a certificate of
cancellation filed.
Upon the termination of the Trust, the Trustee will use its best efforts to
sell any remaining Royalty Interests then owned by the Trust for cash pursuant
to the procedures described in the Trust Agreement. The Trustee will retain a
nationally recognized investment banking firm (the "Advisor") on behalf of the
Trust who will assist the Trustee in selling the remaining Royalty Interests.
The Company has the right, but not the obligation, within 60 days following the
Termination Date, to make a cash offer to purchase all of the remaining Royalty
Interests then held by the Trust. In the event such an offer is made by the
Company, the Trustee will decide, based on the recommendation of the Advisor,
to either (i) accept such offer (in which case no sale to the Company will be
made unless a fairness opinion is given by the Advisor that the purchase price
is fair to the Unitholders) or (ii) defer action on the offer for approximately
60 days and seek to locate other buyers for the remaining Royalty Interests. If
the Trustee defers action on the Company's offer, the offer will be deemed
withdrawn and the Trustee will then use its best efforts, assisted by the
Advisor, to locate other 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 (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
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calendar year, the Trustee is required to sell the remaining Royalty Interests
at a public auction, which sale may be to the Company or any of its affiliates.
The Company's purchase rights, as described above, may be exercised by the
Company and each of its successors in interest and assigns. The Company's
purchase rights are fully assignable by the Company to any person or entity.
The costs of liquidation, including the fees and expenses of the Advisor and
the Trustee's liquidation fee will be paid by the Trust.
The Trust may terminate without Unitholder approval. Unitholders are not
entitled to any rights of appraisal or similar rights in connection with the
termination of the Trust.
ARBITRATION AND ACTIONS BY UNITHOLDERS
Pursuant to the Trust Agreement, any dispute, controversy or claim that may
arise between or among Dominion Resources or the Company, on the one hand, and
the Trustee, the Delaware Trustee or the Trust, on the other hand, in
connection with or otherwise relating to the Trust Agreement or the Conveyance
or the application, implementation, validity or breach thereof or any provision
thereof, shall be settled by final and binding arbitration in Dallas, Texas in
accordance with the Rules of Practice and Procedure for the arbitration of
commercial disputes of Judicial Arbitration & Mediation Services, Inc. (or any
successor thereto) then in effect. The Administrative Services Agreement also
includes a provision that will require Dominion Resources and the Trustee and
the Trust to submit any dispute regarding such contract to alternative dispute
resolution before litigating such matter.
The Trust Agreement requires under certain circumstances that the Trustee and
the Trust pursue any claims against Dominion Resources and the Company with
respect to any breach by Dominion Resources and the Company of the terms of the
Conveyance or the Trust Agreement (and requires that any such claims be brought
in arbitration), without the joinder of any Unitholder. The Trust Agreement
does not provide for any procedure allowing Unitholders to bring an action on
their own behalf to enforce the rights of the Trust under the Conveyance and,
except in the case of the failure of the Trustee to enforce certain performance
obligations of Dominion Resources to the Trust, does not provide for any
procedure allowing Unitholders to direct the Trustee to bring an action on
behalf of the Trust to enforce the Trust's rights under the Conveyance. Each
Unitholder has a statutory right, however, under Section 3816 of the Delaware
Code to bring a derivative action in the Delaware Court of Chancery on behalf
of the Trust to enforce the rights of the Trust if the Trustee has refused to
bring the action or if an effort to cause the Trustee to bring the action is
not 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
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are insufficient to reimburse the plaintiff's reasonable expenses in bringing
the derivative action, the Delaware Chancery Court may direct that any such
award of the plaintiff's expenses or a portion thereof be paid by the Trust.
The rights of the Unitholders to bring a derivative action on behalf of the
Trust provided pursuant to the Trust Agreement and Section 3816 of the Delaware
Code are substantially similar to the derivative rights afforded stockholders
under Section 327 of Chapter 8 of the Delaware General Corporation Law and
applicable Delaware case law.
In the event that any Unitholder was successful in bringing a derivative
action on behalf of the Trust to enforce rights on behalf of the Trust against
Dominion Resources or the Company, then such Unitholder could, on behalf of the
Trust, pursue such rights against Dominion Resources or the Company, as the
case may be, in the Delaware Chancery Court. The Trust Agreement does not
require, and expressly provides that it shall not be construed to require,
arbitration of a claim or dispute solely between the Trustee and the Delaware
Trustee or of any claim or dispute brought by any person or entity, including,
without limitation, any Unitholder (whether in its own right or through a
derivative action in the right of the Trust), who is not a party to the Trust
Agreement.
The right of a Unitholder to bring a derivative action on behalf of the Trust
with respect to Dominion Resources' obligation to cure certain deficiencies
under the Trust Agreement is subject to the restriction that such right may
only be exercised by Unitholders owning of record not less than 25 percent of
the Units then outstanding (treated as a single class) and then only absent
action by the Trustee to enforce any such obligation within 10 days following
receipt by the Trustee of a written request served upon the Trustee by such
Unitholders to take such action. In such an event, Unitholders owning of record
not less than 25 percent of the Units then outstanding may, acting as a single
class and on behalf of the Trust, seek to enforce such obligations. See
"Properties--The Royalty Interests--Dominion Resources' Assurances."
DESCRIPTION OF UNITS
Each Unit represents an equal undivided share of beneficial interest in the
Trust and is evidenced by a transferable certificate issued by the Trustee.
Each Unit entitles its holder to the same rights as the holder of any other
Unit, and the Trust has no other authorized or outstanding class of equity
security. At March 18, 1997, 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 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
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taken into account in determining a prior Quarterly Distribution Amount,
subject to adjustments for changes made by the Trustee during such calendar
quarter in any cash reserves established for the payment of contingent or
future obligations of the Trust. An amount which is not included in the
Quarterly Distribution Amount for a calendar quarter because such amount is
received by the Trust after the last business day prior to the 45th day
following the end of such calendar quarter shall be included in the Quarterly
Distribution Amount for the next calendar quarter. The Quarterly Distribution
Amount for each calendar quarter will be payable to Unitholders of record on
the 60th day following the end of such calendar quarter unless such day is not
a business day in which case the record date will be the next business day
thereafter. The Trustee will distribute the Quarterly Distribution Amount for
each calendar quarter on or prior to 70 days after the end of such calendar
quarter to each person who was a Unitholder of record on the record date for
such calendar quarter.
The Royalty Interests will be sold in whole or in part upon termination of
the Trust. Any proceeds from sales of the Royalty Interests, plus any interest
expected by the Trustee to be earned thereon, less liabilities and expenses of
the Trust and amounts used for cash reserves, will be distributed to
Unitholders of record on the record date established for such distribution. A
special distribution will be made of undistributed cash proceeds and other
amounts received by the Trust aggregating in excess of $10,000,000, plus the
amount of interest expected by the Trustee to be earned on such cash proceeds
during the period between the date of receipt by the Trust of such cash
proceeds and the date of payment to the Unitholders of such special
distribution (a "Special Distribution Amount"). The record date for
distribution of a Special Distribution Amount will be the 15th day following
receipt of amounts aggregating a Special Distribution Amount by the Trust
(unless such day is not a business day in which case the record date will be
the next business day thereafter) unless such day is within 10 days prior to
the record date for a Quarterly Distribution Amount in which case the record
date will be the date as is established for the next Quarterly Distribution
Amount. Distributions to Unitholders will be no later than 15 days after the
Special Distribution Amount record date.
Gross income attributable to cash being distributed in most cases will be
reported by the Unitholder who receives such distributions assuming that such
Unitholder is the owner of record on the applicable record date. In certain
circumstances, however, a Unitholder will not receive the cash giving rise to
such income. For example, the Trustee maintains a cash reserve, and is
authorized to borrow money under certain conditions, in order to pay or provide
for the payment of Trust liabilities. Income associated with the cash used to
increase that reserve or to repay that loan must be reported by the Unitholder,
even though that cash is not distributed to him. Likewise, if a portion of a
cash distribution is attributable to a reduction in the cash reserve maintained
by the Trustee, such cash is treated as a reduction to the Unitholders' basis
in his Units and is not treated as taxable income to such Unitholder (assuming
such Unitholder's basis exceeds the amount of the distribution of cash
reserve).
CONDITIONAL RIGHT OF REPURCHASE
Dominion Resources (and any of its successor and affiliates) has the right to
repurchase all (but not less than all) outstanding Units at any time at which
15 percent or less of the outstanding Units are owned by persons or entities
other than Dominion Resources and its affiliates. Subject to the following
sentence, any such repurchase would be at a price equal to the greater of (i)
the highest price at which Dominion Resources or any of its affiliates acquired
Units during the 90 days immediately preceding the date (the "Determination
Date") which is three New York Stock Exchange ("NYSE") trading days prior to
the date on
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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 which reversion the holders of such Units so noticed for
repurchase could look only to the general funds of Dominion Resources for the
payment of the purchase price. Any interest accrued on funds so deposited would
be paid to Dominion Resources from time to time as requested by Dominion
Resources.
In the event that Dominion Resources exercises and consummates its right of
repurchase, then at its option it may cause the Trust to be terminated by
providing written notice thereof to the Trustee and the Delaware Trustee.
Within 30 days following written notice of Dominion Resources' decision to
terminate the Trust, the Trustee must cause any remaining Royalty Interests
(and, subject to the rights of Unitholders with respect to the receipt of
distributions for which a record date has been determined, all proceeds of
production attributable to the Royalty Interests) and any other assets of the
Trust to be conveyed to Dominion Resources or its assignee (subject to the
right of such trustees to create reasonable reserves in connection with the
liquidation of the Trust).
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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 year-end Contract Price as of December 31) from proved reserves
attributable to the Royalty Interests and the amount of the estimated net
present value (discounted at 10 percent) of the remaining Section 29 tax
credits attributable to the Royalty Interests. The costs of the reserve reports
are paid by the Trust and constitute an administrative expense. The Trustee
also provides to Dominion Resources and the Company, within 15 days after the
end of each calendar quarter, a written itemized report showing all
administrative costs of the Trust paid during such quarter.
Within 75 days following the end of each of the first three calendar quarters
of each calendar year, the Trustee mails to each person or entity who was a
Unitholder of record (i) on the record date for each such calendar quarter and
(ii) on a Special Distribution Amount record date occurring during such
quarter, if any, a report which shows in reasonable detail the assets and
liabilities and receipts and disbursements of the Trust for such calendar
quarter. Within 120 days following the end of each fiscal year, the Trustee
mails to Unitholders of record as of a date to be selected by the Trustee an
annual report containing audited financial statements which includes reserve
information relating to the Trust and the Royalty Interests.
The Trustee files such returns for federal income tax purposes as it is
advised are required to comply with applicable law. The Trustee mails to each
person or entity who was a Unitholder of record (i) on the record date for each
such calendar quarter and (ii) on a Special Distribution Amount record date
occurring during such quarter, if any, a report which shows in reasonable
detail information to permit each Unitholder to make all calculations
reasonably necessary for tax purposes. The Trustee treats all income, credits
and deductions recognized during each calendar quarter during the term of the
Trust as
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having been recognized by holders of record on the quarterly record date
established for the distribution unless otherwise advised by counsel. Available
year-end tax information permitting each Unitholder to make all calculations
reasonably necessary for tax purposes is distributed by the Trustee to
Unitholders no later than March 15 of the following year.
Each Unitholder and his duly authorized agents and attorneys have the right
during reasonable business hours upon reasonable prior notice to examine and
inspect records of the Trust and the Trustee and the Delaware Trustee.
VOTING RIGHTS OF UNITHOLDERS
While Unitholders have certain voting rights as provided in the Trust
Agreement, such rights differ from and are more limited than those of
stockholders of a corporation for profit. For example, there is no requirement
for annual meetings of Unitholders or for annual or other periodic reelection
of the Trustee.
Meetings of Unitholders may be called by the Trustee or by Unitholders owning
not less than 10 percent of the outstanding Units. In addition, the Delaware
Trustee may call such a meeting but only for the purpose of appointing a
successor to it upon its resignation. All meetings of Unitholders will be held
in Dallas, Texas. Written notice of every such meeting setting forth the time
and place of the meeting and the matters proposed to be acted upon will be
given not more than 60 nor less than 20 days before such meeting is to be held
to all of the Unitholders of record at the close of business on a record date
selected by the Trustee, which record date will not be more than 60 days before
the date of such meeting. The presence in person or by proxy of Unitholders
representing a majority of the outstanding Units is necessary to constitute a
quorum. Each Unitholder is entitled to one vote for each Unit owned by such
Unitholder. The Trustee will call such meetings to consider amendments,
waivers, consents and other changes relating to the Conveyance, if requested in
writing by the Company or Dominion Resources. No matter other than that stated
in the notice of the Unitholder meeting will be voted on and no action by the
Unitholders may be taken without a meeting.
Generally, amendments to the Trust Agreement require approval of a majority
of the outstanding Units (except that amendments of required voting percentages
requires approval of at least 80 percent of the outstanding Units), but no
provision of the Trust Agreement may be amended that would (i) increase the
power of the Trustee or the Delaware Trustee to engage in business or
investment activities or (ii) alter the rights of the Unitholders as among
themselves. Without the written consent of Dominion Resources and the approval
of not less than 66 2/3 percent of the outstanding Units, no provision of the
Trust Agreement may be amended with respect to (a) the sale or disposition of
all or any part of the Trust estate, including the Royalty Interests, except as
specifically provided in the Trust Agreement, (b) termination of the Trust and
the disposition of Trust assets upon liquidation of the Trust or (c) the
Company's right of first refusal with respect to the purchase of any remaining
Royalty Interests upon termination of the Trust. Without the written consent of
Dominion Resources and the approval of a majority of the outstanding Units, no
amendment may be made to the Trust Agreement that would alter Dominion
Resources' conditional right to repurchase all outstanding Units at any time at
which 15 percent or less of the outstanding Units is owned by persons or
entities other than Dominion Resources or its affiliates. Additionally, any
amendment that increases the obligations, duties or liabilities of or affects
the rights of the Trustee or the Delaware Trustee must be consented to by such
entity. The Trustee, the Delaware Trustee, Dominion Resources and the Company
may, without approval of the Unitholders, from time to time supplement or amend
the Trust Agreement in order to cure any ambiguity or to correct or supplement
any defective or inconsistent provisions, provided
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such supplement or amendment is not adverse to the interests of the
Unitholders. In addition, (i) Dominion Resources may direct the Trustee to
change the name of the Trust without approval of the Unitholders and (ii) in
the event that a business purpose of the Trust is found or deemed to exist by
any taxing or other authority on which finding any taxation authority might
rely, the Trustee is authorized to amend or delete and, subject to the receipt
of an opinion of counsel reasonably satisfactory to the Trustee, the Trustee,
the Delaware Trustee, Dominion Resources and the Company will amend or delete
any provision of the Trust Agreement or take such other action as may be
necessary to eliminate such business purpose, without approval of the
Unitholders. Removal of the Trustee and the Delaware Trustee, approval of
amendments, waivers, consents and other changes relating to the Conveyance and
the approval of the merger or consolidation of the Trust into one or more
entities require approval of a majority of the outstanding Units. Except as set
forth under "Description of the Trust--Termination and Liquidation of the
Trust," all other actions may be approved by a majority vote of the Units
represented at a meeting at which a quorum is present or represented.
LIABILITY OF UNITHOLDERS
Consistent with Delaware law, the Trust Agreement provides that the
Unitholders will have the same limitation on liability as is accorded under
Delaware law to stockholders of a corporation for profit. No assurance can be
given, however, that the courts in jurisdictions outside of Delaware will give
effect to such limitation.
TRANSFER AGENT
Mellon Securities Trust Company serves as transfer agent and registrar for
the Units.
FEDERAL INCOME TAX CONSIDERATIONS
THE TAX CONSEQUENCES TO A UNITHOLDER OF THE OWNERSHIP AND SALE OF UNITS WILL
DEPEND IN PART ON THE UNITHOLDER'S TAX CIRCUMSTANCES. EACH UNITHOLDER SHOULD
THEREFORE CONSULT THE UNITHOLDER'S TAX ADVISOR ABOUT THE FEDERAL, STATE AND
LOCAL TAX CONSEQUENCES TO THE UNITHOLDER OF THE OWNERSHIP OF UNITS.
The sections entitled "Federal Income Tax Consequences" and "Risk Factors--
Tax Considerations" appearing in the Prospectus set forth, respectively, a
discussion of the material federal income tax matters of general application of
the acquisition, ownership and sale of the Units acquired in the Public
Offerings and a discussion of certain risk factors associated with matters of
federal income taxation as applied to the Trust and such Unitholders.
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 resect 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
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or may not be retroactively applied. Some of the applicable provisions of the
Code have not been interpreted by the courts or the IRS. In addition, such
opinions were based on various representations as to factual matters made by
the Company and Dominion Resources in connection with the Public Offerings. In
addition, such opinions were expressly limited in their application to
investors purchasing Units in each of such Public Offerings and, as a result,
provide no assurance to investors not purchasing Units in one of the Public
Offerings.
Neither the Trustee, the Delaware Trustee, nor counsel to the Trustee,
respectively, has rendered any opinions with respect to any tax matters
associated with the Trust or the Units.
No ruling was requested by Dominion Resources, as the sponsor of the Trust,
the Trustee or the Delaware Trustee from the IRS with respect to any matter
affecting the Trust or Unitholders. No assurance can be provided that the
opinions of Special Counsel (which do not bind the IRS) will not be challenged
by the IRS or will be sustained by a court if so challenged.
SUMMARY OF CERTAIN FEDERAL INCOME TAX CONSEQUENCES
The following summary of certain federal income tax consequences of
acquiring, owning and disposing of Units is based on the opinions of Special
Counsel to Dominion Resources on oil and gas and federal income tax matters,
which are set forth in the Prospectus. The summary is not exhaustive and many
other provisions of the federal tax laws may affect individual Unitholders, and
the summary is not intended to 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 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.
Economic Substance of
Ownership of Units .......
Generally, a taxpayer is entitled to claim
deductions and tax credits generated by an
investment only if the investment has economic
substance. The application of this principle in
the context of the production and sale of
nonconventional fuels (like coal seam gas) which
generate the Section 29 tax credit is uncertain
because such application has not been addressed
either by a court or the IRS. An investment has
economic substance if the investor can
demonstrate that there is a reasonable
possibility of deriving an economic profit from
the investment in excess of a de minimis amount,
apart from tax benefits. In many cases, economic
profit has been computed by comparing the
taxpayer's total cash investment to the total
cash reasonably expected to be
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received by the taxpayer as a result of the
investment (a "Pre-Tax Profit Objective"). At the
time of the Public Offerings, Special Counsel to
Dominion Resources expressed the opinion (only in
connection with the Public Offerings) that the
ownership of Units purchased in either of the
Public Offerings, whose ownership of Units is not
subject to puts, calls or other risk allocation
devices, has economic substance even if the owner
has no Pre-Tax Profit Objective. No assurance is
given either by the Trustee or counsel to the
Trustee to a purchaser of Units in or following
the Public Offerings as to whether (and to what
extent) such purchaser is or will be entitled to
claim deductions and the Section 29 tax credit
generated with respect to such Units.
Taxation of Unitholders ... Each Unitholder is taxed directly on his
proportionate share of income, deductions and
credits of the Trust attributable to the Royalty
Interests consistent with each such Unitholder's
taxable year and method of accounting and without
regard to the taxable year or method of
accounting employed by the Trust.
Income and Deductions ..... The income of the Trust consists primarily of a
specified share of the proceeds from the sale of
coal seam gas produced from the Underlying
Properties. During 1996, the Trust earned
interest income on funds held for distribution
and made adjustments to the cash reserve
maintained for the payment of contingent and
future obligations of the Trust. The deductions
of the Trust consist of property, production and
related taxes and administrative expenses. In
addition, each Unitholder is entitled to
depletion deductions. See "Unitholder's Depletion
Allowance" below.
Section 29 Tax Credits .... Unitholders are entitled, provided certain
requirements are met, to claim tax credits
pursuant to Section 29 of the Code with respect
to sales of coal seam gas production attributable
to the Royalty Interests that is produced from
the Existing Wells, the gross income from which
is included in their taxable income. The Section
29 tax credit provides to a taxpayer a dollar-
for-dollar reduction in his regular federal
income tax liability and, therefore, generally
provides to him a greater benefit than a
deduction, which merely reduces the amount of his
taxable income. Such credits may be earned each
year until the year beginning January 1, 2003.
For a Unitholder who owned the same Units of
record on all four quarterly record dates during
1996, the available Section 29 tax credit is
approximately $1.529912 per Unit, based on the
first estimate of the GNP implicit price deflator
published by the Bureau of Economic Analysis.
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The availability of Section 29 tax credits is
dependent upon meeting a number of requirements,
many of which are factual in nature. The Company
and Dominion Resources represented in connection
with the Public Offerings only that those factual
requirements were met. At the time of each of the
Public Offerings, Special Counsel opined as to
those requirements which are statutory or legal
in nature. If any of the factual requirements are
not met, or the opinion not followed, some or all
of the expected Section 29 tax credits may not be
available.
Limits on Unitholder's Use
of Credits ...............
In any year, a Unitholder is permitted to reduce
his regular federal income tax liability by the
Section 29 tax credits allocated to such
Unitholder for such year on a dollar-for-dollar
basis, but only to the extent such Unitholder's
regular tax liability exceeds his alternative
minimum tax liability (with certain adjustments).
Any amount of Section 29 tax credit in excess of
a Unitholder's total regular federal income tax
liability for a year is permanently lost. Section
29 tax credits cannot be used to reduce a
Unitholder's liability for any alternative
minimum tax for any taxable year but can be
carried forward to reduce his regular tax
liability in a subsequent year (subject to the
applicable rules governing such carryforward(s)).
Quarterly Allocations ..... Under the Code, a Unitholder is entitled to
Section 29 tax credits only to the extent that he
is an owner of the economic interest at the time
the coal seam gas is produced. The Trustee
allocates the income received by the Trust during
a quarter, and the Section 29 tax credit
allocable to such income, to Unitholders of
record on the quarterly record date for such
quarter. Such an allocation may be challenged by
the IRS, but any challenge is likely to have a
material adverse impact only if successful and
only for Unitholders who do not own Units for a
full quarter for each record date, particularly
Unitholders who acquire Units shortly before a
record date and sell shortly after a record date.
At the time of each of the Public Offerings,
Special Counsel declined to express an opinion as
to whether the IRS would accept quarterly
allocations or would require income, credits and
deductions of the Trust to be determined and
allocated daily based on ownership at the time of
production or on some other basis.
Treatment of the Royalty
Interests ................
Each Royalty Interest is a nonoperating economic
interest in an Underlying Property because it is
a right to a fixed percentage of the gross
proceeds from the sale of gas as, if and when
produced from such properties, the right
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endures for the economic life of the burdened
reserves and the right is not required to bear
any cost in developing or producing such gas.
Unitholder's Depletion
Allowance ................
Each Unitholder is entitled to amortize the cost
of the Units through cost depletion over the life
of the Royalty Interests (or, if greater, through
percentage depletion equal to 15 percent of gross
income). If any portion of the Royalty Interests
is treated as a production payment or is not
treated as an economic interest, however, a
Unitholder will not be entitled to depletion in
respect of such portion. No depletion allowances
were available to Unitholders in respect of
production from the Royalty Interests prior to
June 28, 1994.
Non-Passive Activity
Income, Credits and Loss
.......................... The income, credits and expenses of the Trust are
not taken into account in computing the passive
activity losses and income under Section 469 of
the Code for a Unitholder who acquires and holds
Units as an investment and did not acquire them
in the ordinary course of a trade or business.
Section 29 tax credits generated by an investment
in Units, therefore, can be utilized to offset
regular tax liability on income from any source
whether active or passive, subject to other
limitations discussed herein or arising from the
individual tax circumstances of each Unitholder.
See "Limits on Unitholder's Use of Credits"
above.
Tax Shelter Registration The Trust is registered as a "tax shelter" and
.......................... its tax shelter registration number is 94-
277000355. Issuance of a tax shelter registration
number does not indicate that the investment in
Units or the claimed tax benefits have been
reviewed, examined or approved by the IRS.
Substantial Understatement
Penalty ..................
Section 6662 of the Code imposes a penalty in
certain circumstances for a substantial
understatement of taxes if a taxpayer's tax
liability is understated by more than the greater
of (i) 10 percent of the taxes required to be
shown on the return and (ii) $5,000 ($10,000 for
most corporations). The penalty (which is not
deductible) is 20 percent of the understatement.
Except in the case of understatements
attributable to "tax shelter" items, which are
subject to special rules discussed below, an item
of understatement will not give rise to the
penalty if: (i) there is or was "substantial
authority" for the taxpayer's treatment of the
item or (ii) all the facts relevant to the tax
treatment of the item are adequately disclosed on
the return or on a statement attached to the
return and there is a reasonable basis for the
tax treatment of such item. In the case of Units,
an individual Unitholder may
18
<PAGE>
make adequate disclosure with respect to
particular tax items if certain conditions are
met. Special rules enacted in December 1994 could
affect the application of these provisions with
regard to a corporation acquiring Units after
December 8, 1994, to the extent such provisions
were found to apply to the ownership of Units.
In the case of understatements attributable to
"tax shelter" items, the substantial
understatement penalty may be avoided only if the
taxpayer establishes that, in addition to having
substantial authority for his position, he
reasonably believed that the treatment claimed
was more likely than not the proper treatment of
the item. A "tax shelter" item is one that arises
from a form of investment if its principal
purpose was the avoidance or evasion of Federal
income tax. Regulations promulgated by the IRS
indicate that an entity or person has a principal
purpose of avoidance or evasion of Federal income
tax if that purpose "exceeds any other purpose."
No assurance is given either by the Trustee or
counsel to the Trustee as to the possible
application of this penalty, in part because such
application depends largely upon the individual
circumstances under which the Units were
acquired. As a result, purchasers of Units in and
after the Public Offerings should consult with
their personal tax advisors.
Unitholder Reporting
Information ..............
The Trustee furnishes to Unitholders tax
information concerning royalty income, depletion
and the Section 29 tax credits on an annual
basis. Year-end tax information is furnished to
Unitholders no later than March 15 of the
following year. Unless the final information
issued by the U.S. Treasury Department at the end
of March regarding the amount of the section 29
credit for 1996 differs materially from the
Trustee's estimate, the final information will be
contained in the next quarterly report. However,
to the extent the final information issued by the
U.S. Treasury Department causes the tax credit
amounts for 1996 to materially differ from the
Trustee's estimates contained in the 1996 Tax
Information booklet, the Trustee will promptly
mail final tax credit information to each
affected Unitholder.
ERISA CONSIDERATIONS
The section entitled "ERISA Considerations" appearing in the Prospectus sets
forth certain information regarding the applicability of the Employee
Retirement Income Security Act of 1974, as amended, and the Code to pension,
profit-sharing and other employee benefit plans and to individual retirement
accounts (collectively, "Qualified Plans").
Due to the complexity of the prohibited transaction rules and the penalties
imposed upon persons involved in prohibited transactions, it is important that
potential Qualified Plan investors consult with their counsel regarding the
consequences under ERISA and the Code of their acquisition and ownership of
Units.
19
<PAGE>
STATE TAX CONSIDERATIONS
The following is intended as a brief discussion of certain state tax matters
affecting individuals who are Unitholders. Unitholders are urged to consult
their own legal and tax advisors with respect to these 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 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.
Alabama tax counsel has advised the Trust that the Alabama Department of
Revenue (the "DOR") will permit the Trust to file a "composite income tax
return" on behalf of all Unitholders who are not residents of Alabama, and that
the filing of the composite income tax return and acceptance of the return by
DOR will relieve those nonresident Unitholders of any obligation to file
Alabama state income tax returns. The Trust filed for 1995 a composite income
tax return with the DOR on behalf of all Nonresident Unitholders (defined
below), and intends to file a composite return for 1996 and each year
thereafter for so long as the composite return will 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 1996. Accordingly, no Alabama
state income tax is due under the 1996 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 1996 (or any
other tax year) as initially filed by the Trust is not accepted as filed by the
DOR, the Trust may decide not to refile a composite income tax return either
(i) because the Trust would have net Alabama taxable income for that year as a
result of the assumptions required by the DOR or (ii) because the refiling of
the composite income tax return imposes an unreasonable burden on the Trust in
the judgment of the Trustee (based on its sole discretion). In that event, each
Nonresident Unitholder would be required to file a separate Alabama state
income tax return and pay any Alabama state income tax due as well as any
penalties and interest due thereon. For purposes of the filing of the composite
income tax return for any taxable year, "Nonresident Unitholders" will consist
of those Unitholders to whom the Trust has provided an individualized tax
information letter (together with its tax information booklet) for such tax
year which shows a mailing address outside the State of Alabama. All other
Unitholders will be treated by the Trust for purposes of the filing of the
composite income tax return as "Resident Unitholders."
The filing of the composite income tax return by the Trust does not relieve
any resident of the State of Alabama or any Resident Unitholder from the
obligation to file an Alabama state income tax return individually (and pay
Alabama state income tax thereon, if any) with respect to the revenues and
expenses attributable to the Royalty Interests. In light of the foregoing, each
Unitholder should consult his tax adviser regarding the requirements for filing
state income tax returns for his state of residence and Alabama.
20
<PAGE>
ALABAMA FRANCHISE TAX
Alabama imposes a franchise tax on domestic corporations and foreign
corporations doing business in Alabama, under a broad definition of
"corporation" in the state constitution, based on the amount of a corporation's
"capital employed" in the state. In reliance upon the representations and
assumptions set forth in the Prospectus and on a private letter ruling issued
June 10, 1994 by the DOR as to the offering of the Units, special Alabama tax
counsel to the Company opined in connection with each of the Public Offerings
that the Trust is not subject to Alabama franchise tax. Although the Alabama
Commissioner of Revenue has the authority to revoke retroactively DOR rulings
under certain limited circumstances, special Alabama tax counsel did not
believe, based on the above representations and assumptions, that those
circumstances exist with respect to the Company's private letter ruling.
Dominion Resources has agreed to indemnify the Trust against any resulting
Alabama franchise tax imposed on the Trust.
ALABAMA SEVERANCE TAXES
The DOR has proposed a set of regulations that indicate the DOR is
considering changing the way it computes the amount of severance taxes due by
disallowing certain deductions previously allowed on audit. Such a change could
result in an increase in the amount of severance taxes due for natural gas
production. Since the Trust, as owner of the Royalty Interests, bears its
proportionate share of severance taxes, any increase in the amount of severance
taxes will decrease the amount of cash distributions payable to Unitholders.
The Company has informed the Trust that it has been advised by Alabama counsel
that it is impossible to predict whether this change will be implemented (by
regulations or otherwise) and, if so, whether and in what amount severance
taxes may be increased.
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 franchise 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 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.
As a result of the Natural Gas Policy Act of 1978 ("NGPA") and the Natural
Gas Wellhead Decontrol Act of 1989 ("NGWDA"), as of January 1, 1993, the
wellhead price for natural gas is no longer subject to federal regulation. All
sales of natural gas produced from the Underlying Properties are considered
under NGPA and NGWDA 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.
21
<PAGE>
The transportation of natural gas in interstate commerce is subject to
federal regulation by the Federal Energy Regulatory Commission ("FERC") under
the Natural Gas Act ("NGA") and the NGPA. FERC has initiated a number of
regulatory policy initiatives that may affect the transportation of natural gas
from the wellhead to the market and thus may affect the marketing of natural
gas. Such initiatives include regulations intended to further open access to
interstate pipelines by requiring such pipelines to unbundle their
transportation services from sales services and allow customers to choose and
pay for only the services they require, regardless of whether the customer
purchases natural gas from such pipelines or from other suppliers. Although
these regulations should generally facilitate the transportation of natural gas
produced from the Underlying Properties to natural gas markets, the impact of
these regulations on marketing production from the Underlying Properties cannot
be predicted at this time and could be significant.
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
Operations on the Underlying Properties associated with the production of
natural gas are subject to numerous federal and state laws, rules and
regulations governing the discharge of materials into the environment or
otherwise relating to the protection of the environment. Such laws, rules and
regulations require the acquisition of certain permits, impose substantial
liabilities for pollution resulting from exploration and production operations
and may also restrict air or other pollution resulting from operations. It is
possible that federal and state environmental laws and regulations will become
more stringent in the future. For instance, legislation has been proposed in
Congress in connection with the pending reauthorization of the Federal Resource
Conservation and Recovery Act ("RCRA") that would amend RCRA to reclassify
certain oil and gas production wastes as "hazardous waste." If adopted, this
amendment would result in more rigorous and expensive disposal requirements. It
is impossible to predict what the precise effect additional regulation or
legislation, or enforcement policies thereunder, could have on the operation of
the Underlying Properties. However, any costs or expenses incurred by the
Company in connection with environmental liabilities arising out of or relating
to activities occurring on, in or in connection with, or conditions existing on
or under, the Underlying Properties, will be borne by the Company and not the
Trust and such costs and expenses will not be deducted in calculating Gross
Proceeds. Such costs and expenses may, however, be taken into account by the
Company in exercising its rights to abandon a well and may accelerate the
termination of the Trust. See "Properties--The Royalty Interests--Sale and
Abandonment
22
<PAGE>
of Underlying Properties" and "Properties--Description of the Trust--
Termination and Liquidation of the Trust."
Water from the operations on the Underlying Properties is discharged into the
Black Warrior River pursuant to a National Pollutant Discharge Elimination
System permit issued by the Alabama Department of Environmental Management
("ADEM"). ADEM initially issued five permits in connection with the Underlying
Properties which were consolidated into one permit in February 1994. The ADEM
permit, which expires in July 1999, generally authorizes water disposal based
upon the Black Warrior River's minimum flow rate and maximum chloride level.
The Company has advised the Trust that since 1987 water disposal from the
Underlying Properties has not been disrupted.
While the Company has informed the Trust that it believes the Underlying
Properties are in material compliance with all environmental laws and
regulations, such regulations have generally become more stringent and costly
over time. As a royalty holder the Trust may not be directly subject to
increased costs; however, such costs may be taken into account by the Company
in exercising its rights to abandon a well, which may accelerate the
termination of the Trust. The Company has informed the Trust that it estimates
that it plans to expend approximately $117,000 during 1997 for anticipated
expenditures related to compliance with environmental laws.
COMPETITION, MARKETS AND PRICES
The revenues of the Trust and the amount of cash distributions to Unitholders
depend upon, among other things, the effect of competition and other factors in
the market for natural gas. The natural gas industry is highly competitive in
all of its phases. The Company encounters competition from major oil and gas
companies, independent oil and gas concerns and individual oil and gas
producers and operators. Many of these competitors have greater financial and
other resources than the Company. Competition may also be presented by
alternative fuel sources, including heating oil and other fossil fuels.
Demand for natural gas production has historically been seasonal in nature
and prices for natural gas fluctuate accordingly. Unseasonably warm weather and
the ability of markets to access storage can cause the demand for natural gas
to decrease, resulting in lower prices received by producers than when demand
is higher due to seasonal weather factors. Such price fluctuations and any
continuation of a depressed market for natural gas will directly impact Trust
distributions, estimates of reserves attributable to the Royalty Interests and
estimated future net revenue from reserves attributable to the Royalty
Interests.
Prices for natural gas are subject to wide fluctuations in response to
relatively minor changes in supply, market uncertainty and a variety of
additional factors that are beyond the control of the Trust and the Company.
These factors include political conditions in the Middle East, the price and
quantity of imported oil and gas, the level of consumer product demand, the
severity of weather conditions, government regulations, the price and
availability of alternative fuels and overall economic conditions.
Additionally, lower natural gas prices may reduce the amount of gas that is
economic to produce from the Underlying Properties.
The Trust's revenues and distributions to Unitholders will be primarily
dependent on the sales prices for Gas produced from the Underlying Properties
and the quantities of Gas sold. Natural gas prices have historically been
volatile and are likely to continue to be volatile. Price volatility and the
risk of production curtailment make it difficult to estimate the future levels
of cash distributions to Unitholders or the value of the Units. While the
Minimum
23
<PAGE>
Price will mitigate to some extent the negative effects of such volatility, the
Maximum Price may limit the benefits Unitholders realize from future price
increases. See "Properties--The Royalty Interests--Gas Purchase Agreement."
ITEM 2. PROPERTIES.
THE ROYALTY INTERESTS
The Royalty Interests held by the Trust generally entitle the Trust to
receive 65 percent of Gross Proceeds. The Royalty Interests were conveyed to
the Trust by means of a single instrument of conveyance. The Conveyance was
recorded in the appropriate real property records in Alabama, so as to give
notice of the Royalty Interests to creditors, and any transferees will take an
interest in the Underlying Properties subject to the Royalty Interests. The
Conveyance was intended to convey the Royalty Interests as real property
interests under Alabama law.
The following description of the material provisions of the Conveyance and
the Trust Agreement is subject to and qualified by the more detailed provisions
of the Conveyance and the Trust Agreement included as exhibits to this Form 10-
K.
THE UNDERLYING PROPERTIES
Black Warrior Basin. The Black Warrior Basin covers 6,000 square miles in
west central Alabama and contains seven Pennsylvania age multi-seam coal groups
in the Pottsville formation: the Black Creek, Mary Lee, Pratt, Cobb, Gwin,
Utley and Brookwood coal groups. The Pottsville coal formation ranges from the
surface to a depth of 4,100 feet.
Wells in the Black Warrior Basin produce natural gas from coal seam
formations that have production characteristics materially different from
conventional natural gas wells. The primary factor affecting recovery of gas
reserves from coal seams in the Black Warrior Basin is the lowering of
reservoir pressure through "dewatering" operations. In a typical coal seam gas
well on the Underlying Properties, average daily natural gas production
generally will increase as wells are "dewatered" until natural gas production
reaches a "peak" at which time natural gas production will decline. The amount
of time necessary to "dewater" a well and cause it to reach its peak
production, and the ultimate level of a well's peak production, are difficult
to estimate. Since all of the 532 wells included in the Underlying Properties
were producing by mid-1991, the Company believes that production from such
wells is currently at or near its peak and will decline over the term of the
Trust.
The Royalty Interests were conveyed by the Company to the Trust out of the
Company Interests. The Existing Wells are operated by River Gas in accordance
with the Operating Agreement. See "--Operation of Properties." The Underlying
Properties comprise 34,212 gross acres of land in an area approximately five
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, 1996, the Underlying Properties
contained 532 wells that were producing Gas, all of which were drilled prior to
1993.
Well Count and Acreage Summary. The following table shows as of December 31,
1996, the gross and net producing wells and acreage for the Company Interests.
The net wells and
24
<PAGE>
acreage are determined by multiplying the gross wells or acres by the Company
Interests Owner's working interest in the wells or acreage.
<TABLE>
<CAPTION>
NUMBER OF
WELLS ACRES
--------- -------------
GROSS NET GROSS NET
----- --- ------ ------
<S> <C> <C> <C> <C>
Company Interests.................................... 532 519 34,212 33,391
</TABLE>
Royalty Interests, Company Interests and Retained Interests. On June 1, 1994,
the effective date of the Conveyance, the Company had an average aggregate
working interest in the Existing Wells of approximately 98 percent, and an
average aggregate net revenue interest of approximately 80 percent in the
Existing Wells. The Company has not sold or otherwise disposed of any of its
interest in the Company Interests since June 1, 1994. The Royalty Interests are
entitled to approximately 52 percent of the net revenue from natural gas
produced and sold from the Underlying Properties and the interests (the
"Retained Interests") of the Company in the Underlying Properties (after giving
effect to the Royalty Interests) entitle the Company to receive approximately
28 percent of the net revenue from the natural gas produced and sold from the
Underlying Properties. As a working interest owner in the Underlying
Properties, the Company is responsible for an average of approximately 98
percent of the operating costs of the Existing Wells.
The Royalty Interests do not burden (i) royalties and other obligations,
expressed or implied, under oil or natural gas leases, (ii) the overriding
royalties and other burdens created by the Company's predecessors in title or
(iii) the working interests owned by other individual working interest owners.
Water Removal and Disposal. Water from the wells located on the Underlying
Properties is pumped from the wellhead to one of five water disposal systems,
each with two ponds, where the water is analyzed and chemically treated to
remove impurities, if necessary, prior to discharge into the Black Warrior
River. Water from the operations on the Underlying Properties is discharged
into the Black Warrior River pursuant to a National Pollutant Discharge
Elimination System permit issued by ADEM that expires in July 1999. 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 1996, 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.
25
<PAGE>
The Trust is subject to certain rules of the Bureau of Land Management under
which the holding of interests in leases by persons other than citizens,
nationals and legal resident aliens of the United States ("Eligible Citizens")
are limited. As a result, non-Eligible Citizens are prohibited from owning
Units. If any Units are acquired by persons or entities not constituting
Eligible Citizens, such Unitholders may be required to sell such Units pursuant
to a procedure set forth in the Trust Agreement. See "Business--Description of
the Trust--Possible Divestiture of Units."
Additional Wells. Well spacing rules, which are in effect in Alabama,
generally govern the space between wells drilled to the same productive
formation and are promulgated in order to prevent waste and confiscation of
property. Pursuant to such rules, the Existing Wells are located on 40 to 80
acre spacing units. Exceptions or changes to these rules may be granted by the
applicable regulatory agency upon application of an interested party following
notice to other interested parties if, in the agency's opinion, good reasons
exist therefor after consideration of evidence presented by the applicant and
any opponents. The Company has informed the Trust that it is not aware of any
plans to change spacing regulations with respect to the Underlying Properties
in Alabama. No assurances can be made, however, that exceptions or changes will
not be made in the future.
The Company and its affiliates or unrelated third parties may acquire
interests in properties adjoining the Underlying Properties. It is possible
that wells drilled on adjoining properties would drain reserves attributable to
the Underlying Properties.
The Company has agreed for the term of the Trust not to consent to, cooperate
with, assist in or conduct infill drilling (except as required by law) on any
of the Underlying Properties in which the Company owned an interest as of June
1, 1994. Although the Company believes that it is unlikely that any additional
wells will be drilled, if the Operating Agreement is terminated, the Company
cannot prevent one of the other owners of an interest in the Underlying
Properties from drilling additional wells on the Underlying Properties.
Additional wells, if drilled, could recover a portion of the reserves otherwise
producible from wells burdened by the Company Interests, thereby reducing the
Gross Proceeds attributable to the Royalty Interests. The Company has advised
the Trust that it is not aware of any wells that have been drilled by others on
spacing units adjacent to the Company Interests since the date of the
Conveyance.
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.
26
<PAGE>
Pratt Recompletions. To recover behind pipe reserves, the Company
Interests Owner was obligated to recomplete certain of the Existing Wells
to the Pratt coal seam by March 31, 1997. As of August 1, 1996, all
scheduled recompletions were performed.
Right to Take in Kind. The owner of the Royalty Interests has no right to
take production in-kind.
Pooling and Unitization. The Company Interests Owner has certain pooling
and unitization rights.
Right to Assign Company Interests. The Company Interests Owner has the
right to assign all or any part of the Company Interests, subject to the
Royalty Interests and the terms and provisions of the Conveyance. If any
such assignment is made of part, but not all, of such interests, then
effective as of the date of such assignment the assignee will be required
to make a separate computation of Gross Proceeds attributable to the
assigned interests.
Sale or Assignment of Royalty Interests. In certain situations, the Trust
may sell or dispose of all or a part of the Royalty Interests, in which
case the Trust would receive the proceeds therefrom and distribute such
proceeds to the Unitholders, net of any amounts held as a reserve. See
"Business--Description of the Trust--Transfer of Royalty Interests" and
"Business--Description of the Trust--Duties and Limited Powers of the
Trustee."
Books and Records. The Company Interests Owner is required to maintain
books and records sufficient to determine the amounts payable with respect
to the Royalty Interests.
Computation and Payment. The Royalty Interests entitle the Trust to receive
65 percent of the Gross Proceeds. The Royalty Interests bear their
proportionate share of property, production and related taxes (including
severance taxes). The definitions, formulas and accounting procedures and other
terms governing the computation of the Royalty Interests are set forth in the
Conveyance.
The Company Interests Owner is required, pursuant to the Conveyance, to pay
to the Trust amounts received by the Company Interests Owner from the sale of
Subject Gas attributable to the Royalty Interests. Under the Conveyance, the
amounts payable by the Company Interests Owner with respect to the Royalty
Interests are computed with respect to each calendar quarter ending prior to
termination of the Trust, and such amounts are paid to the Trust not later than
the last business day before the 45th day following the end of each calendar
quarter. The amounts paid to the Trust do not include interest on any amounts
payable with respect to the Royalty Interests which are held by the Company
Interests Owner prior to payment to the Trust. The Company Interests Owner is
entitled to retain all amounts attributable to the Retained Interests. The
Company Interests Owner deducts from the payment to the Trust the Royalty
Interests' share of property, production and related taxes (including severance
taxes) and pays the same on behalf of the Trust.
27
<PAGE>
RESERVE ESTIMATE
Reserve Estimate. The following table summarizes net proved reserves
estimated as of January 1, 1997, and certain related information for the
Royalty Interests from the Reserve Estimate prepared by Ryder Scott. The
natural gas reserves were estimated by Ryder Scott by applying volumetric and
decline curve analyses. All of such reserves constitute proved developed gas
reserves. The Reserve Estimate was prepared in accordance with criteria
established by the Commission.
<TABLE>
<CAPTION>
AS OF
ROYALTY INTERESTS JANUARY 1, 1997
----------------- ---------------
<S> <C>
Net Proved Natural Gas Reserves (Bcf)(a)(b):
Developed Producing........................................ 82.388
========
Estimated Future Net Revenues (in thousands) (a)(c):
1997....................................................... $ 29,080
1998....................................................... 24,525
1999....................................................... 20,740
2000....................................................... 17,810
2001....................................................... 15,487
Thereafter................................................. 110,188
--------
Total.................................................... $217,830
========
Total Discounted at 10 Percent........................... $134,675
========
</TABLE>
- --------
(a) The estimates of reserves and future net revenues summarized in this table
are based upon an unescalated price of $2.81 per MMBtu through 2004, which
was the price being received by the Company under the Gas Purchase
Agreement as of December 31, 1996. This price may not be the most
representative price for estimating reserves or related future net revenues
data. See "--Gas Purchase Agreement."
(b) The estimated economic life of the wells comprising the Royalty Interests
has been determined taking into account the Section 29 tax credits.
(c) Estimated future net revenues are defined as the total revenues
attributable to the Royalty Interests for gas production less the relevant
share of production, property and related taxes (including severance
taxes). Overhead costs have not been included, nor have the effects of
depreciation, depletion and federal income tax. Estimated future net
revenues do not include any Section 29 tax credits, although, as discussed
in footnote (b) above, Section 29 tax credits have been taken into account
in determining the estimated economic life of the wells comprising the
Royalty Interests. 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 Ryder Scott in a
manner customary in the industry, is an estimate only, and actual quantities,
rates of production
28
<PAGE>
and sales prices for natural gas are likely to differ from the estimated
amounts set forth herein, and such differences could be significant.
There are many uncertainties inherent in estimating quantities and values of
proved reserves and in projecting future rates of production. Reserve
engineering is a subjective process of estimating underground accumulations of
natural gas that cannot be measured in an exact manner. The accuracy of any
reserve estimate is a function of the quality of available data and of the
geological and engineering evaluation of that data. Results of testing and
production subsequent to the date of an estimate may justify revision of such
estimate. Further, reserve estimates for any given property may vary from
engineer to engineer even though each engineer bases his estimate on common
data and utilizes techniques and principles customary in the industry.
For properties with short production histories, reserve estimates in many
instances are based upon volumetric calculations and upon analogy to similar
types of production or producing fields. Relative to many conventional natural
gas producing properties, coal seam gas producing properties in general, and
the Underlying Properties in particular, have short production histories. In
addition, there are no significant coal seam reservoirs which have been
produced to depletion that can be used as analogies to the Underlying
Properties.
The discounted estimated future net revenues shown herein were prepared using
guidelines established by the Commission and may not be representative of the
market value for the estimated reserves.
The reserves attributable to the Royalty Interests are expected to decline
substantially during the term of the Trust and a portion of each cash
distribution made by the Trust will, therefore, be analogous to a return of
capital. As a result, cash distributions will decrease materially over time.
For example, based upon the production estimates set forth in the Reserve
Estimate, annual production attributable to the Royalty Interests is estimated
to decline from 10.9 Bcf in 1997 to 5.1 Bcf in 2002.
Tax Credits Based on Reserves. Based upon the production estimates used in
the Reserve Estimate for the January 1, 1997 through December 31, 2002 period,
and assuming constant future Section 29 tax credits at the estimated 1997 rate
of $1.0555 per MMBtu, the estimated total future tax credits available from the
production and sale of the net proved reserves from the Royalty Interests would
be approximately $47.9 million, having a discounted present value (assuming a
10 percent discount rate) of approximately $29.6 million.
Miscellaneous. Ryder Scott has delivered to the Trust the Reserve Estimate, a
summary of which is included as an exhibit to this Form 10-K. Information
concerning historical changes in net proved developed reserves attributable to
the Royalty Interests, and the calculation of the standardized measure of
discounted future net revenues related thereto, is contained in Note 8 of the
Notes to the Financial Statements incorporated by reference in Item 8 hereof.
Dominion Resources has not filed reserve estimates covering the Royalty
Interests with any other federal authority or agency.
NATURAL GAS SALES PRICES AND PRODUCTION
The following table sets forth the actual net production volumes attributable
to the Royalty Interests, weighted average property, production and related
taxes and information regarding natural gas sales prices for the period from
June 1, 1994 (effective date of the Conveyance) through December 31, 1994 and
for the years ended December 31, 1995 and December 31, 1996:
29
<PAGE>
<TABLE>
<CAPTION>
JUNE 1, 1994
(EFFECTIVE DATE OF
YEAR ENDED YEAR ENDED THE CONVEYANCE) THROUGH
DECEMBER 31, 1996 DECEMBER 31, 1995 DECEMBER 31, 1994
----------------- ----------------- -----------------------
<S> <C> <C> <C>
Production attributable
to the Royalty
Interests (Bcf)........ 11.9 12.4 7.6
Weighted average
property, production
and related taxes (per
Mcf)................... $ .13 $ .10 $ .10
Average Contract Price
(per Mcf).............. $2.40 $1.84 $1.83
</TABLE>
GAS PURCHASE AGREEMENT
Sonat Marketing is required to purchase the Subject Gas pursuant to the Gas
Purchase Agreement. The Company has advised the Trust that the Gas Purchase
Agreement extends until December 31, 2001 and will be automatically renewed
each year unless terminated by either party. Pursuant to the Gas Purchase
Agreement, Sonat Marketing is obligated to purchase monthly up to the Monthly
Base Quantity designated in the Gas Purchase Agreement of the Subject Gas at
the Contract Price, which includes a Premium over the Index Price and is
subject to a Minimum Price of $1.85 per MMBtu and a Maximum Price of $2.63 per
MMBtu until December 31, 1998. While the Minimum Price assures the Unitholder a
minimum price at which the Monthly Base Quantities of the Subject Gas must be
purchased, until January 1, 1999, Unitholders will not benefit from natural gas
prices in excess of $2.63 per MMBtu. The Minimum Price and the Maximum Price
will cease to apply after December 31, 1998. Prior to April 1, 1996, Sonat
Marketing was obligated to purchase the Subject Gas in excess of the Monthly
Base Quantity at the Index Price. Effective April 1, 1996, the price payable
for Subject Gas in excess of the Monthly Base Quantity will equal the Index
Price plus $.02. The Company has advised the Trust that at the end of the
primary term or any extensions thereof Sonat Marketing will be obligated to
purchase the Subject Gas at the Index Price until such time as the Company and
Sonat Marketing negotiate a different price, and that the Company will have the
ability to obtain an offer to purchase the Subject Gas from another purchaser
and terminate the Gas Purchase Agreement if Sonat Marketing does not match such
offer.
Sonat Marketing's obligation to purchase natural gas pursuant to the Gas
Purchase Agreement (as well as the Company's obligation to sell such natural
gas) may be suspended to the extent affected by the occurrence of any event not
within the control of the affected party that renders the affected party unable
to perform its obligations under the Gas Purchase Agreement if the event could
not have been prevented by the exercise of reasonable diligence including: acts
of God, strikes, lockouts or other industrial disturbances, acts of the public
enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning,
earthquakes, fires, storms, floods, washouts, arrests and restraints of
governments and people, civil disturbances, explosions, breakage or accident to
machinery or lines of pipe, the necessity for maintenance of or making repairs
or alterations to machinery or lines of pipe, freezing of wells or lines of
pipe, partial or entire failure of wells, curtailment, interruption or other
unavailability of transportation, inability to acquire or delay in acquiring at
reasonable cost and by the exercise of reasonable diligence, servitudes, rights
of way, grants, permits, permissions, licenses, materials or supplies that are
required to enable the affected party to perform its obligations. Following any
such event, the affected party's obligations under the Gas Purchase Agreement
will be suspended during the period of its inability to perform, and such party
will as far as possible remedy the event with reasonable dispatch. During the
pendency of any such suspension, the cash available for distribution, and the
depletion
30
<PAGE>
deductions and Section 29 tax credits available for allocation, by the Trust to
Unitholders could be reduced materially or eliminated entirely.
Sonat Marketing has entered into a put and call agreement with a nationally
recognized commodities brokerage firm intended to limit its losses in the event
that the Index Price falls below the Minimum Price. Pursuant to the Gas
Purchase Agreement Amendment, Sonat Marketing's obligation to enter into such a
put and call agreement terminates on January 1, 1999. In addition, up to
$10,000,000 of the payment obligations of Sonat Marketing under the Gas
Purchase Agreement are guaranteed by Sonat Marketing.
The Gas Purchase Agreement is filed as an exhibit to this Form 10-K, and the
foregoing summary of the material terms of such agreement is qualified in its
entirety by reference to the terms of such agreement as set forth in such
exhibit.
OPERATION OF PROPERTIES
No Control by Trust. Under the terms of the Conveyance, neither the Trustee
nor the Unitholders will be able to influence or control the operation or
future development of the Underlying Properties. Unitholders will therefore be
reliant on the Company and the other working interest owners to make all
decisions regarding operations on the Underlying Properties. The Trust will not
be able to appoint or control the appointment of operators.
The Conveyance does not prohibit the transfer of the Underlying Properties by
the Company, subject to and burdened by the Royalty Interests. The Company and
the other working interest owners of the Underlying Properties will have the
right, subject to certain restrictions, to abandon any well or lease on the
Underlying Properties under certain circumstances. Upon abandonment of any such
well or lease, that portion of the Royalty Interests relating thereto will be
extinguished. See "--Sale and Abandonment of the Underlying Properties."
Operating Agreement. Pursuant to the Operating Agreement, River Gas operates
and maintains the Underlying Properties for the Company and the other working
interest owners. The Operating Agreement has a one-year term and will be
automatically renewed for additional one year periods unless either party
provides written notice to the other party of its desire to terminate the
Operating Agreement at least six months prior to the date on which the
agreement is to terminate. Upon not less than 30 days' notice either River Gas
or the Company may terminate the Operating Agreement if: (i) the other party
has committed a material breach of the Operating Agreement, unless such breach
is cured in the manner specified in the Operating Agreement; (ii) the other
party files a petition for relief under federal or state bankruptcy laws, the
other party's insolvency is determined by a final court proceeding, the other
party's filing of a petition or application to accomplish such a result or for
the appointment of a receiver or trustee for such party or for a substantial
part of its assets or commencement of any proceedings relating to the other
party under any other reorganization, arrangement, insolvency, adjustment of
debt or liquidation law of any jurisdiction; provided, however, that if such
proceeding is not commenced, the proceeding will not give rise to a right to
terminate the Operating Agreement unless such party consents or such proceeding
has not been finally dismissed within 90 days after its commencement; or (iii)
after good faith negotiations River Gas and the Company and the other working
interest owners cannot agree on an annual operating plan or budget for any
year.
While the Operating Agreement is in effect, all of the production
attributable to the Company Interests will be gathered, treated and processed
by River Gas pursuant to the Operating Agreement. Such production will be
gathered at the wellhead and transported to
31
<PAGE>
the central delivery points in the gathering system for the Underlying
Properties, which is owned by the Company and the other working interest
owners.
Under the terms of the Operating Agreement, River Gas owes a duty to the
Company and the other working interest owners to conduct the operations on the
Underlying Properties in a good and workmanlike manner and following practices
that (i) are engaged in or accepted by a significant portion of the natural gas
production industry at the time the decision was made or (ii) in the exercise
of reasonable judgment in light of the facts known at the time the decision was
made would have been expected to accomplish the desired result at a reasonable
cost consistent with reliability, safety, expeditiousness and protection of the
environment. River Gas has no direct contractual or fiduciary duty to protect
the interests of the Trust or the Unitholders.
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, 1996, none of the wells included
in the Underlying Properties had been plugged and abandoned.
The Company may sell its interest in the Underlying Properties, subject to
and burdened by the Royalty Interests, without the consent of the Trust or the
Unitholders. Under the Trust Agreement, the Company has certain rights (but not
the obligation) to purchase the Royalty Interests upon termination of the
Trust. See "Business--Description of the Trust Agreement--Termination and
Liquidation of the Trust."
DOMINION RESOURCES' ASSURANCES
Pursuant to the Trust Agreement, Dominion Resources has agreed to cause each
of the following obligations to be paid in full when due: (i) all liabilities
and operating and capital expenses that any Company Interests Owner becomes
obligated to pay as a result of such Company Interests Owner's obligations
under the Conveyance and (ii) the obligations of the Company to indemnify the
Trust, the Trustee and the Delaware Trustee for certain environmental
liabilities under the Trust Agreement (collectively, the "Payment
Obligations").
The Trustee may, at any time after the 10th day following receipt by Dominion
Resources of written notice from the Trustee that a Payment Obligation has not
been paid when due, make demand of Dominion Resources for payment stating the
amount due. Dominion Resources is obligated to cure any failure to pay the
obligation within 10 days following receipt of the foregoing demand. After
written request of the Unitholders owning of record not less than 25 percent of
the Units then outstanding served upon the Trustee, and absent action by the
Trustee within 10 days following receipt by the Trustee of such written request
to enforce such obligations for the benefit of the Trust, such Unitholders may,
acting as a single class and on behalf of the Trust, seek to enforce Dominion
Resources' performance obligations.
32
<PAGE>
All of Dominion Resources' obligations will terminate upon: (i) the
termination and cancellation of the Trust, (ii) the sale or other transfer by
the Company of all or substantially all of the Company's interest in the
Underlying Properties subject to the terms of the Trust Agreement and (iii) the
sale or other transfer of a majority of Dominion Resources' direct or indirect
equity ownership interest in the Company; provided that, with respect to
clauses (ii) and (iii) above, Dominion Resources' obligations will terminate
only if: (a) the transferee has a specified credit rating or the transferee
together with an affiliate which guarantees the transferee's obligations has
not less than a specified net worth or (b) the transferee is approved by the
holders of a majority of the outstanding Units; and provided further, that in
the case of clauses (ii) or (iii) above the transferee also unconditionally
agrees in writing, in form and substance reasonably satisfactory to the
Trustee, to assume Dominion Resources' remaining obligations under the Trust
Agreement with respect to the assets transferred and under the Administrative
Services Agreement.
TITLE TO PROPERTIES
Alabama counsel to Dominion Resources and the Company has opined that the
Company's title to its interest in the Underlying Properties, and the Trust's
title to the Royalty Interests, are good and defensible in accordance with
standards generally accepted in the natural gas industry, subject to such
exceptions which, in the opinion of Alabama counsel, are not so material as to
detract substantially from the use or value of the Company Interests or the
Royalty Interests.
Although the matter is not entirely free from doubt, Alabama counsel has
opined that the Royalty Interests constitute interests in real property under
Alabama law. Consistent therewith, the Conveyance states that the Royalty
Interests constitute real property interests. The Company has recorded the
Conveyance in the appropriate real property records of Alabama in accordance
with local recordation provisions. If, during the term of the Trust, the
Company or any Company Interests Owner becomes involved as a debtor in
bankruptcy proceedings under the Federal Bankruptcy Code, it is not entirely
clear that the Royalty Interests would be treated as real property interests
under the laws of Alabama.
ITEM 3. LEGAL PROCEEDINGS.
There are no material pending legal proceedings to which the Trust is a party
or of which any of its property is the subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
33
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Certain information with respect to the Units of the Trust and the market
therefor is set forth on the inside front cover of the Trust's Annual Report to
Unitholders for the year ended December 31, 1996 under the section entitled
"Units of Beneficial Interest" and is incorporated herein by reference.
ITEM 6. SELECTED FINANCIAL DATA.
Selected financial data of the Trust is set forth on the inside front cover
of the Trust's Annual Report to Unitholders for the year ended December 31,
1996 under the section entitled "Selected Financial Data" and is incorporated
herein by reference.
ITEM 7. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.
The "Trustee's Discussion and Analysis of Financial Condition and Results of
Operations" appearing on pages two and three of the Trust's Annual Report to
Unitholders for the year ended December 31, 1996 are incorporated herein by
reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The financial statements of the Trust and notes thereto, together with the
report thereon of Deloitte & Touche LLP, independent auditors, dated March 21,
1997, appearing on pages (four through 11) of the Trust's Annual Report to
Unitholders for the year ended December 31, 1996, are incorporated herein by
reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
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.
ITEM 11. EXECUTIVE COMPENSATION.
The following is a description of certain fees and expenses anticipated to be
paid or borne by the Trust, including fees expected to be paid to Dominion
Resources, the Trustee, the Delaware Trustee, the Transfer Agent, or their
respective affiliates.
34
<PAGE>
Ongoing Administrative Expenses. The Trust is responsible for paying all
fees, charges, expenses, disbursements and other costs incurred by the Trustee
in connection with the discharge of its duties pursuant to the Trust Agreement,
including, without limitation, trustee fees, engineering, audit, accounting and
legal fees and expenses, printing and mailing costs, amounts reimbursed or paid
to the Company or Dominion Resources pursuant to the Trust Agreement or the
Administrative Services Agreement and the out-of-pocket expenses of the
Transfer Agent.
Compensation of the Trustee. The Trust Agreement provides that the Trustee is
to be compensated for its administrative services and preparation of quarterly
and annual statements, out of the Trust assets, in an annual amount of $30,900,
plus an hourly charge for services in excess of a combined total of 350 hours
annually at its standard rate which is currently $120 per hour. These service
fees escalate by three percent annually. The Delaware Trustee is compensated
for its administrative services, in an annual amount of $5,000 which will be
paid by the Trustee. Each of the Trustee and the Delaware Trustee is entitled
to reimbursement for out-of-pocket expenses. Upon termination of the Trust, the
Trustee will receive, in addition to its out-of-pocket expenses, a termination
fee in the amount of $10,000. If the Trustee resigns and a successor has not
been appointed in accordance with the terms of the Trust Agreement within 210
days after the notice of resignation is received, the fee payable to the
Trustee will increase significantly until a new trustee is appointed. During
1996, the Trustee and the Delaware Trustee received total compensation of
$31,853 and $5,000, respectively.
Compensation of the Transfer Agent. The Transfer Agent receives a transfer
agency fee of $3.25 annually per account, plus $1.50 for each certificate
issued and $.40 for each check issued (subject to an annual minimum of $7,200).
Fees to Dominion Resources. Dominion Resources will receive throughout the
term of the Trust an administrative services fee for accounting, bookkeeping
and other administrative services relating to the Royalty Interests and the
Underlying Properties as described below under "Administrative Services
Agreement."
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Security Ownership of Certain Beneficial Owners. The Trustee knows of no
Unitholder that is a beneficial owner of more than five percent of the
outstanding Units.
Security Ownership of Management. The Trust has no directors or executive
officers. As of March 15, 1996, neither NationsBank of Texas, N.A., the
Trustee, nor Mellon Bank (DE) National Association, the Delaware Trustee,
beneficially owned any Units.
Changes in Control. The Trustee knows of no arrangements the operation of
which may at a subsequent date result in a change in control of the Registrant.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
ADMINISTRATIVE SERVICES AGREEMENT
Pursuant to the Trust Agreement, Dominion Resources and the Trust entered
into the Administrative Services Agreement, pursuant to which the Trust is
obligated, throughout the term of the Trust, to pay to Dominion Resources each
quarter an administrative services fee for accounting, bookkeeping and other
administrative services relating to the Royalty Interests and the Underlying
Properties. The annual fee, payable in equal quarterly installments, is
currently $318,270 and will increase annually by three percent.
35
<PAGE>
A copy of the Administrative Services Agreement is filed as an exhibit to
this Form 10-K. The foregoing summary of the material provisions of the
Administrative Services Agreement does not purport to be complete and is
subject to, and is qualified in its entirety by reference to, all the
provisions of the Administrative Services Agreement.
DOMINION RESOURCES' CONDITIONAL RIGHT OF REPURCHASE
Dominion Resources retains in the Trust Agreement the right to repurchase all
(but not less than all) outstanding Units at any time at which 15 percent or
less of the outstanding Units is owned by persons or entities other than
Dominion Resources and its affiliates. Any such repurchase would generally be
at a price equal to the greater of (i) the highest price at which Dominion
Resources or any of its affiliates acquired Units during the 90 days
immediately preceding the Determination Date and (ii) the average closing price
of Units on the NYSE for the 30 trading days immediately preceding the
Determination Date. Any such repurchase would be conducted in accordance with
applicable Federal and state securities laws. See "Business--Description of the
Trust--Conditional Right of Repurchase."
POTENTIAL CONFLICTS OF INTEREST
The interests of Dominion Resources and its affiliates and the interests of
the Trust and the Unitholders with respect to the Underlying Properties could
at times be different. The following is a summary of certain conflicts of
interest:
Obligations of Company Interests Owner may exceed its share of distributions
and tax credits. As a working interest owner in the Underlying Properties, the
Company Interests Owner is responsible for an average of approximately 98
percent of the operating costs of the Existing Wells but only entitled to
approximately 28 percent of the revenues therefrom, after giving effect to the
Royalty Interests. Based on the Reserve Estimate, beginning in the year 2000,
the projected operating costs to be borne by the Company Interests Owner will
exceed its projected share of Gross Proceeds and Section 29 tax credits. The
terms of the Conveyance provide, however, that the Company Interests Owner will
make decisions with respect to the Company Interests pursuant to the standard
of a reasonably prudent operator.
Sale or abandonment of Underlying Properties may terminate assurances. The
Company Interests Owner's interests may conflict with those of the Trust and
Unitholders in situations involving the sale or abandonment of Underlying
Properties. The Company Interests Owner has the right at any time to sell any
of the Underlying Properties subject to the Royalty Interests and may abandon a
well or lease included in the Underlying Properties if such well or lease is
not capable of producing in commercial quantities, determined before giving
effect to the Royalty Interests. Under certain circumstances, a sale or
abandonment will effectively terminate Dominion Resources' assurances of the
Company Interests Owner's obligation to the Trust with respect to the
Underlying Properties sold or abandoned. Such sales or abandonment may not be
in the best interest of the Trust or the Unitholders.
Dominion Resources may profit from contracts with the Trust. The amount that
Dominion Resources may charge for services it renders under the Administrative
Services Agreement is established in such contract at rates that do not
necessarily take into account the actual cost of rendering such services by
Dominion Resources. Accordingly, Dominion Resources may profit or suffer losses
in connection with the performance of such contract.
36
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this report:
1. Financial Statements (incorporated by reference in Item 8. of this report)
Independent Auditors' Report
Statements of Assets, Liabilities and Trust Corpus as of December 31,
1996 and 1995
Statements of Distributable Income for the years ended December 31, 1996
and 1995 and the period from May 31, 1994 (date of inception) to December
31, 1994
Statements of Changes in Trust Corpus for the years ended December 31,
1996 and 1995 and the period from May 31, 1994 (date of inception) to
December 31, 1994
Notes to Financial Statements
2. Financial Statement Schedules
Financial statement schedules are omitted because of the absence of
conditions under which they are required or because the required information is
included in the financial statements and notes thereto.
3. Exhibits
<TABLE>
<CAPTION>
EXHIBIT
NUMBER EXHIBIT
------- -------
<C> <S>
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 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 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 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, 1996 and incorporated herein by reference).
10.4 --Gas Purchase Agreement, dated as of May 3, 1994, between Sonat
Marketing and the Company (filed as Exhibit 10.2 to Dominion
Resources, Inc.'s Registration Statement* on Form S-3 (No. 33-53513),
and incorporated herein by reference).
</TABLE>
37
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NUMBER EXHIBIT
------- -------
<C> <S>
10.5 --Amendment to Gas Purchase Agreement dated May 16, 1996, between Sonat
Marketing and the Company (filed as Exhibit 10.1 to the Registrant's
Form 10-Q for the quarter ended June 30,1996 and incorporated herein
by reference).
13.1 --The following information appearing on the following pages of the
Registrant's 1996 Annual Report to Unitholders: (i) Trustee's
discussion and analysis of financial condition and results of
operations, pages two and three; (ii) selected financial data, inside
front cover; (iii) the section entitled "Units of Beneficial
Interest," inside front cover; and (iv) the financial statements of
the Trust, pages four through 11.
23.1 --Consent of Ryder Scott Company Petroleum Engineers, independent
petroleum engineers.
27.1 --Financial Data Schedule.
99.1 --Summary of Reserve Report, dated March 14, 1997, on the estimated
reserves, estimated future net revenues and the discounted estimated
future net revenues attributable to the Royalty Interests as of
January 1, 1997, prepared by Ryder Scott Company Petroleum Engineers,
independent petroleum engineers.
</TABLE>
- --------
* On its own behalf and as sponsor of the Dominion Resources Black Warrior
Trust.
(b) Reports on Form 8-K. No report on Form 8-K was filed by the Registrant
during the last quarter of the period covered by this report.
38
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
Dominion Resources Black Warrior
Trust
By: NationsBank of Texas, N.A.,
Trustee
/s/ Ron E. Hooper
By: _________________________________
RON E. HOOPER
VICE PRESIDENT
Date: March 31, 1997
(THE REGISTRANT HAS NO DIRECTORS OR EXECUTIVE OFFICERS.)
39
<PAGE>
EXHIBIT 13.1
DOMINION RESOURCES BLACK WARRIOR TRUST
1996 ANNUAL REPORT AND FORM 10-K
THE TRUST
Dominion Resources Black Warrior Trust (the "Trust") was formed as a Delaware
business trust pursuant to the Trust Agreement of Dominion Resources Black
Warrior Trust (the"Trust Agreement") entered into effective as of May 1, 1994 by
and among Dominion Black Warrior Basin, Inc. (the "Company"), as trustor,
Dominion Resources, Inc., as sponsor, and NationsBank of Texas, N.A., (the
"Trustee") and Mellon Bank (DE) National Association (the "Delaware Trustee"),
as trustees. The Trust owns certain overriding royalty interests (the "Royalty
Interests") burdening proved natural gas properties in the Pottsville coal
formation of the Black Warrior basin in Alabama (the "Underlying Properties").
The Royalty Interests are 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 the Unitholders.
The Trust makes quarterly cash distributions to the Unitholders. The record date
for the quarterly cash distribution of the Trust is the 60th day following the
end of the calendar quarter unless such day is not a business day in which case
the record date will be the next business day. The quarterly cash distribution
is payable on or before 70 days after the end of the calendar quarter. Set forth
below are the scheduled record dates and approximate distribution dates for each
quarter of 1997 production attributable to the Trust.
<TABLE>
<CAPTION>
===============================================================
1997 1998
- ---------------------------------------------------------------
<S> <C> <C> <C> <C>
Record Dates May 30 August 29 December 1 March 2
- ---------------------------------------------------------------
Distribution Dates June 9 September 8 December 9 March 11
(approximate)
===============================================================
</TABLE>
UNITS OF BENEFICIAL INTEREST
The units of beneficial interest ("Units") in the Trust are listed and traded on
the New York Stock Exchange under the symbol "DOM". The following table sets
forth, for the periods indicated, the high and low sales prices per Unit on the
New York Stock Exchange and the amount of quarterly cash distributions per Unit
paid by the Trust.
<TABLE>
<CAPTION>
======================================================================
Price Price Distribution
High Low per Unit
- ----------------------------------------------------------------------
1996
<S> <C> <C> <C>
- ----------------------------------------------------------------------
First Quarter $19-1/2 $17-5/8 $0.706488
- ----------------------------------------------------------------------
Second Quarter 19-1/4 18-1/2 0.898614
- ----------------------------------------------------------------------
Third Quarter 20-5/8 19-5/8 0.832243
- ----------------------------------------------------------------------
Fourth Quarter 24 19-3/8 0.798549
- ----------------------------------------------------------------------
1995
- ----------------------------------------------------------------------
First Quarter $19-5/8 $17-1/4 $0.692117
- ----------------------------------------------------------------------
Second Quarter 20-1/8 17-5/8 0.639559
- ----------------------------------------------------------------------
Third Quarter 18-7/8 17-5/8 0.664555
- ----------------------------------------------------------------------
Fourth Quarter 9-7/8 17-1/2 0.659884
======================================================================
</TABLE>
<PAGE>
At March 18, 1997, there were 7,850,000 Units outstanding and approximately 834
Unitholders of record.
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
========================================================================================
YEARS ENDED YEARS ENDED FOR THE PERIOD
DECEMBER 31, DECEMBER 31, FROM MAY 31, 1994
1996 1995 (DATE OF
INCEPTION)TO
DECEMBER 31, 1994
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
ROYALTY INCOME $ 26,013,428 $ 21,603,550 $ 7,596,511
- ----------------------------------------------------------------------------------------
DISTRIBUTABLE INCOME $ 25,423,282 $ 20,947,426 $ 7,278,931
- ----------------------------------------------------------------------------------------
DISTRIBUTABLE INCOME PER UNIT $3.24 $2.67 $ .93
- ----------------------------------------------------------------------------------------
DISTRIBUTIONS PER UNIT $3.24 $2.66 $ .91
- ----------------------------------------------------------------------------------------
TOTAL ASSETS, DECEMBER 31 $109,761,403 $125,641,485 $139,641,366
- ----------------------------------------------------------------------------------------
TOTAL CORPUS, DECEMBER 31 $109,562,077 $125,545,839 $139,471,673
- ----------------------------------------------------------------------------------------
========================================================================================
</TABLE>
TO UNITHOLDERS:
We are pleased to present the 1996 Annual Report to Unitholders of Dominion
Resources Black Warrior Trust. The report includes a copy of the Trust's annual
report on Form 10-K for the period ended December 31, 1996. The Form 10-K
contains important information concerning the creation and administration of the
Trust, and the assets of the Trust, including coal seam gas reserves
attributable to the overriding royalty interests owned by the Trust estimated as
of December 31, 1996.
The Trust was formed as a Delaware business trust under the Delaware Business
Trust Act pursuant to the Trust Agreement. The Trust was formed to acquire and
hold the Royalty Interests, which burden the Company's interest in proved
natural gas properties located in the Pottsville coal formation of the Black
Warrior Basin, Tuscaloosa County, Alabama. The Company has advised the Trustee
that all the production attributable to the Royalty Interests currently
constitutes coal seam gas that entitles the owners of such production, provided
certain requirements are met, to tax credits pursuant to Section 29 of the
Internal Revenue Code of 1986, as amended, upon the production and sale of such
gas. The Royalty Interests are the only assets of the Trust, other than cash and
temporary investments being held for the payment of expenses and liabilities and
for distributions to Unitholders.
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.
On June 28, 1994, the Royalty Interests were conveyed by the Company to the
Trust in consideration for all 7,850,000 authorized Units. The Company
transferred all the Units to its parent, Dominion Energy, Inc., which in turn
transferred all the Units to its parent, Dominion Resources, Inc., which sold an
aggregate of 6,904,000 Units to the public through various underwriters in June,
1994 and August, 1994, and the remaining 946,000 Units were sold in an
underwritten public offering in June 1995.
<PAGE>
Under the Trust Agreement, the Trustee has the function of collecting proceeds
attributable to the Royalty Interests and making quarterly cash distributions to
Unitholders after deducting administrative expenses and any amounts necessary
for cash reserves. The quarterly record date is the close of business on the
60th day following the end of the calendar quarter, unless such day is not a
business day. The quarterly distribution date is on or prior to 70 days after
the end of the calendar quarter.
On or before March 15 of each year, the Trustee distributes to Unitholders of
record on any of the quarterly record dates during the prior year, information
relating to distributions, estimated Section 29 tax credits and cost depletion
deductions for such prior year. Individualized tax information prepared
specifically for the Unitholder was included with the 1996 tax information
booklet if (i) the Unitholder held its Units of record in its own name or (ii)
the Unitholder's brokerage firm or other nominee record holder had made the
beneficial owner's name and address available to the Trustee as the actual
beneficial owner of the Units in a timely manner. Assuming the amount of the
Section 29 tax credit for 1996 (which will not be announced by the U.S. Treasury
department before the end of March) is not materially different from the
Trustee's estimate, the Trustee will provide any other information to
Unitholders for filing their annual income tax returns.
DOMINION RESOURCES BLACK WARRIOR TRUST
BY: NATIONSBANK OF TEXAS, N.A., TRUSTEE
BY:/SIG/RON E. HOOPER
Vice President
March 31, 1997
TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATION
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 consists of overriding royalty interests burdening the
Company's interest in the Underlying Properties. The Royalty Interests generally
entitle the Trust to receive 65 percent of the Gross Proceeds (as defined below)
during the preceding calendar quarter. The Royalty Interests are non-operating
interests and bear only expenses related to property, production and related
taxes (including severance taxes). "Gross Proceeds" consist generally of the
aggregate amounts received by the Company attributable to the interests of the
Company in the Underlying Properties from the sale of coal seam gas at the
central delivery points in the gathering system for the Underlying Properties.
Distributable income of the Trust consists of the excess of royalty income plus
interest income over the organizational and 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 for them.
Consequently, the reported distributable income of the Trust for any year is
determined by deducting form the income received by the Trust the amount of
expenses paid by the Trust during such year. The amount of cash available for
<PAGE>
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 Annual Report to Unitholders for additional information
regarding the determination of the amount of cash available for distribution to
Unitholders.)
The year 1996 marked the second full year of operations for the Trust. Because
the Trust was effective as of May 31, 1994, royalty income for 1994 reflect only
four months of production, whereas 1996 and 1995 reflect a full year of
production. The Trust received royalty income amounting to $26,013,428 during
the year ended December 31, 1996 compared to $21,603,550 for 1995 and $7,596,511
during the period from May 31, 1994 (date of inception) to December 31, 1994.
The royalty income received by the Trust was net of the Royalty Interest's
allocable share of property, production and related taxes. Administrative
expenses during the year ended December 31, 1996 were $656,019 compared to
$713,898 for 1995 and $335,134 for the period from May 31, 1994 to December 31,
1994. Distributable income for the year ended December 31, 1996 was $25,423,282
or $3.24 per Unit compared to $20,947,426 or $2.67 for 1995 and $7,278,931, or
$.93 per Unit for the period from May 31, 1994 to December 31, 1994. .
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.
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. The conveyance of the Royalty Interests to the Trust was effective
June 1, 1994. Accordingly, the royalty income included in distributable income
for the years ended December 31, 1996 and 1995, was based on production volumes
and natural gas prices for the periods from October 1, 1995 through September
30, 1996, and October 1, 1994 to September 30, 1995, respectively, and royalty
income included in distributable income for the period ended December 31, 1994,
was based on production volumes and natural gas prices for the period from June
1, 1994 to September 30, 1994.
The following table sets forth the production volumes attributable to the
Trust's Royalty Interests and the average sales Price and Index Price for such
production for the periods indicated.
<TABLE>
<CAPTION>
===========================================================================
FOR 12 For 12 For 4
MONTHS Months Months
ENDED Ended Ended
9/30/1996 9/30/1995 9/30/1994
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Production (Bcf)(1) 12.031 12.622 4.382
- ---------------------------------------------------------------------------
Production (MMBtu)(2) 11.907 12.488 4.332
- ---------------------------------------------------------------------------
Average
- ---------------------------------------------------------------------------
Contract Price
- ---------------------------------------------------------------------------
Received ($/MMBtu). $ 2.31 $ 1.83 $ 1.86
- ---------------------------------------------------------------------------
Average Index Price ($/MMBtu) $ 2.18 $ 1.52 $ 1.69
===========================================================================
</TABLE>
<PAGE>
(1)Billion cubic feet of natural gas.
(2)Trillion British Thermal Units.
The information in this Annual Report to Unitholders 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.
Sonat Marketing Company ("Sonat Marketing") is required under a gas purchase
agreement to purchase the gas produced from the Underlying Properties for as
long as reserves on the Underlying Properties produce natural gas. Under the
agreement, Sonat Marketing is obligated to purchase up to a specified monthly
base quantity of gas for a contract price which provides for a specified premium
(between $.05 and $.07 per MMBtu) over the Index Price (as defined below),
subject to a minimum price of $1.85 per MMBtu and a maximum price of $2.63 per
MMBtu, until December 31, 1998. Although the primary term of the Gas Purchase
Agreement extends through December 31, 2001, the Minimum Price and the Maximum
Price will cease to apply after December 31, 1998. Prior to April 1, 1996, Sonat
Marketing was obligated to purchase gas production in excess of the specified
monthly base quantities at the Index Price. Effective April 1, 1996, the price
payable for such excess gas production will equal the Index Price plus $.02.
After December 31, 2001, assuming the Gas Purchase Contract is extended Sonat
Marketing is obligated to purchase gas production at the Index Price until such
time as the Company and Sonat Marketing negotiate a different price. However,
the Company will have the ability to obtain an offer from another purchaser and
terminate the gas purchase agreement if Sonat Marketing does not match such
offer. The "Index Price", which is determined on a monthly basis, is Southern
Natural Gas Company's posted index price for deliveries of gas in Louisiana.
The net proved reserves attributable to the Royalty Interests have been
estimated as of December 31, 1996, 1995 and 1994, by independent petroleum
engineers. The reserve quantities of 82.388 Bcf for 1996 compared to 74.841 Bcf
for 1995 and 63.148 Bcf for 1994 reflect an upward revision of reserves of
24.130 Bcf as a result of stronger production and advanced Pratt recompletions
(see Note 8).
This Annual Report and the accompanying Form 10-K include "forward-looking
statements" within the meaning of Section 21E of the Securities Exchange Act of
1934, which are intended to be covered by the safe harbor created thereby. All
statements other than statements of historical fact included in this Annual
Report and the accompanying Form 10-K are forward-looking statements. Such
statements include, without limitation, the reserve information and other
statements contained in Item 2, "Properties" of the accompanying Form 10-K.
Although the Trust believes that the expectations reflected in such
forward-looking statements are reasonable, such expectations are subject to
numerous risks and uncertainties and the Trust can give no assurance that they
will prove correct. There are many factors, none of which is within the Trust's
control, that may cause such expectations not to be realized, including, among
other things, factors identified in this Annual Report and the accompanying Form
10-K affecting oil and gas prices and the recoverability of reserves, and future
economic, competitive and market conditions.
FINANCIAL STATEMENTS
An audited Statement of Assets, Liabilities and Trust Corpus of the Trust as of
December 31, 1996 and 1995, and the related Statements of Distributable Income
and Changes in Trust Corpus for the years ended December 31, 1996 and 1995 and
the period from May 31, 1994 (date of inception) to December 31, 1994, are
included in this Annual Report to Unitholders immediately following the
Independent Auditors' Report below.
<PAGE>
INDEPENDENT AUDITORS' REPORT
NATIONSBANK OF TEXAS, N.A., AS TRUSTEE OF
DOMINION RESOURCES BLACK WARRIOR TRUST
We have audited the accompanying statements of assets, liabilities and trust
corpus of Dominion Resources Black Warrior Trust (the "Trust") as of December
31, 1996 and 1995, and the related statements of distributable income and
changes in trust corpus for the years ended December 31, 1996 and 1995 and for
the period from May 31, 1994 (date of inception) to December 31, 1994. 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 generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
As described in Note 2 to the financial statements, these statements were
prepared on a modified cash basis of accounting, which is a comprehensive basis
of accounting other than generally accepted accounting principles.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the assets, liabilities and trust corpus of Dominion
Resources Black Warrior Trust at December 31, 1996 and 1995, and its
distributable income and changes in trust corpus for the years ended December
31, 1996 and 1995 and for the period from May 31, 1994 (date of inception) to
December 31, 1994, on the basis of accounting described in Note 2.
DELOITTE & TOUCHE LLP
Dallas, Texas
March 21, 1997
DOMINION RESOURCES BLACK WARRIOR TRUST
FINANCIAL STATEMENTS
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
==============================================================================
December 31 1996 1995
- ------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
- ------------------------------------------------------------------------------
Cash and cash equivalents $149,707 24,521
- ------------------------------------------------------------------------------
Royalty interests in gas properties 109,611,696 125,616,964
(less accumulated amortization of
$46,205,805 and $30,200,537)
- ------------------------------------------------------------------------------
TOTAL ASSETS $109,761,403 $125,641,485
- ------------------------------------------------------------------------------
LIABILITIES AND TRUST CORPUS
- ------------------------------------------------------------------------------
Trust administration expenses payable $199,326 $95,646
- ------------------------------------------------------------------------------
Trust corpus (7,850,000 units of 109,562,077 125,545,839
beneficial interest authorized, issued
and outstanding
- ------------------------------------------------------------------------------
TOTAL LIABILITIES AND TRUST CORPUS $109,761,403 $125,641,485
==============================================================================
</TABLE>
STATEMENTS OF DISTRIBUTABLE INCOME
<PAGE>
<TABLE>
<CAPTION>
===============================================================================================
FOR YEAR FOR YEAR FOR THE PERIOD
ENDED ENDED FROM MAY 31, 1994
DECEMBER 31, DECEMBER 31, (DATE OF
1996 1995 INCEPTION) TO
DECEMBER 31, 1994
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
ROYALTY INCOME $26,013,428 $21,603,550 $7,596,511
- -----------------------------------------------------------------------------------------------
INTEREST INCOME 65,873 57,774 17,554
- -----------------------------------------------------------------------------------------------
26,079,301 21,661,324 7,614,065
- -----------------------------------------------------------------------------------------------
GENERAL AND ADMINISTRATIVE EXPENSES 656,019 713,898 335,134
- -----------------------------------------------------------------------------------------------
DISTRIBUTABLE INCOME $25,423,282 $20,947,426 $7,278,931
- -----------------------------------------------------------------------------------------------
DISTRIBUTABLE INCOME PER UNIT $3.24 $2.67 $.93
(7,850,000 UNITS)
- -----------------------------------------------------------------------------------------------
Distributions per unit $3.24 $2.66 $.91
===============================================================================================
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
===============================================================================================
FOR YEAR FOR YEAR FOR THE PERIOD
ENDED ENDED FROM MAY 31, 1994
DECEMBER 31, DECEMBER 31, (DATE OF
1996 1995 INCEPTION) TO
DECEMBER 31, 1994
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
TRUST CORPUS, BEGINNING OF PERIOD $125,545,839 $139,471,673 $1,000
- -----------------------------------------------------------------------------------------------
CONVEYANCE OF ROYALTY INTERESTS BY ------ ------ 148,824,287
DOMINION RESOURCES BLACK WARRIOR
BASIN, INC
- -----------------------------------------------------------------------------------------------
SALE OF 946,000 UNITS BY DOMINION ------ 6,993,213 ------
RESOURCES, INC
- -----------------------------------------------------------------------------------------------
AMORTIZATION OF ROYALTY INTERESTS (16,005,268) (21,015,965) (9,184,572)
- -----------------------------------------------------------------------------------------------
DISTRIBUTABLE INCOME 25,423,282 20,947,426 7,278,931
- -----------------------------------------------------------------------------------------------
Trust formation costs ------ ------ (331,656)
- -----------------------------------------------------------------------------------------------
DISTRIBUTIONS TO UNITHOLDERS............ (25,401,776) (20,850,508) (7,116,317)
- -----------------------------------------------------------------------------------------------
TRUST CORPUS, END OF PERIOD $109,562,077 $125,545,839 $139,471,673
===============================================================================================
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
NOTES TO FINANCIAL STATEMENTS
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
<PAGE>
into effective as of May 31, 1994, among Dominion Black Warrior Basin, Inc., an
Alabama corporation (the "Company"), as trustor, Dominion Resources, Inc., a
Virginia corporation ("Dominion Resources"), and NationsBank of Texas, N.A., a
national banking association (the "Trustee"),and Mellon Bank (DE) National
Association, a national banking association (the "Delaware Trustee"), as
trustees. The trustees are independent financial institutions.
The Trust is a grantor trust formed to acquire and hold certain overriding
royalty interests (the "Royalty Interests") burdening proved natural gas
properties located in Pottsville coal formation of the Black Warrior Basin,
Tuscaloosa County, Alabama (the "Underlying Properties") owned by the Company.
The Trust was initially created by the filing of its Certificate of Trust with
the Delaware Secretary of State on May 31, 1994. In accordance with the Trust
Agreement, the Company contributed $1,000 as the initial corpus of the Trust. On
June 28, 1994, the Royalty Interests were conveyed to the Trust by the Company
pursuant to the Overriding Royalty Conveyance (the "Conveyance") effective as of
June 1, 1994, from the Company to the Trust, in consideration for all the
7,850,000 authorized units of beneficial interest ("Units") in the Trust. The
Company transferred all the Units to its parent, Dominion Energy, Inc., a
Virginia corporation, which in turn transferred all the Units to its parent,
Dominion Resources, Inc., which sold an aggregate of 6,904,000 Units to the
public through various underwriters (the "Underwriters") in June and August 1994
and the remaining 946,000 Units were sold to the public through certain of the
Underwriters in June 1995. All of the production attributable to the Underlying
Properties is from the Pottsville coal formation and currently constitutes coal
seam gas that entitles the owners of such production, provided certain
requirements are met, tax credits pursuant to Section 29 of the Internal Revenue
Code of 1986, as amended, upon the production and sale of such gas.
The Trustee has all powers to collect and distribute proceeds received by the
Trust and to pay Trust liabilities and expenses. The Delaware Trustee has only
such powers as are set forth in the Trust Agreement or are required by law and
is not empowered to otherwise manage or take part in the management of the
Trust. The Royalty Interests are passive in nature and neither the Trustee nor
the Delaware Trustee has any control over, or any responsibility relating to,
the operation of the Underlying Properties or the Company's interest therein.
The Trust is subject to termination under certain circumstances described in the
Trust Agreement. Upon the termination of the Trust, all Trust assets will be
sold and the net proceeds therefrom distributed to Unitholders.
The only assets of the Trust, other than cash and temporary investments being
held for the payment of expenses and liabilities and for distribution to
Unitholders, are the Royalty Interests. The Royalty Interests consist of
overriding royalty interests burdening the Company's interest in the Underlying
Properties. The Royalty Interests generally entitle the Trust to receive 65
percent of the Company's Gross Proceeds (as defined below). The Royalty
Interests are non-operating interests and bear only expenses related to
property, production and related taxes (including severance taxes). "Gross
Proceeds" consist generally of the aggregate amounts received by the Company
attributable to the interests of the Company in the Underlying Properties from
the sale of coal seam gas at the central delivery points in the gathering system
for the Underlying Properties. The definitions, formulas and accounting
procedures and other terms governing the computation of the Royalty Interests
are set forth in the Conveyance.
Because of the passive nature of the Trust and the restrictions and limitations
on the powers and activities of the Trustee contained in the Trust Agreement,
the Trustee does not consider any of the officers and employees of the Trustee
to be "officers" or "executive officers" of the Trust as such terms are defined
under applicable rules and regulations adopted under the Securities Exchange Act
of 1934.
<PAGE>
2. BASIS OF ACCOUNTING
The financial statements of the Trust are prepared on a modified cash basis and
are not intended to present financial position and results of operations in
conformity with generally accepted accounting principles ("GAAP"). 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 month of production.
. 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 revenue are received.
. Distributions to Unitholders are recorded when declared by the Trustee (see
Note 5).
The financial statements of the Trust differ from financial statements prepared
in accordance with GAAP because royalty income is not accrued in the period of
production, general and administrative expenses recorded are based on
liabilities paid and cash reserves established rather than on an accrual basis,
and amortization of the Royalty Interests is not charged against operating
results.
Dominion Resources sold an aggregate of 6,904,000 Units in the Public Offering
during 1994 at a price of $20.00 per Unit and sold the remaining 946,000 Units
to the public during 1995 through certain of the Underwriters at a price of
$18.75 per Unit. Accordingly, the statements of assets, liabilities and trust
corpus reflects 6,940,000 Units at the Public Offering price of $20.00 per Unit
and 946,000 Units at the price of $18.75 per Unit.
The net amount of royalty interest in gas properties is limited to the sum of
the future net cash flows attributable to the Trust's gas reserves at the year
end using current unescalated product prices plus the estimated Section 29
credits for federal income tax purposes. If the net cost of royalty interests in
gas properties exceeds this amount, an impairment provision will be recorded and
charged to the Trust Corpus.
USE OF ESTIMATES
The preparation of financial statements in conformity with the basis of
accounting described above requires management to make estimates and assumptions
that affect reported amounts of certain assets, liabilities, revenues and
expenses as of and for the reporting periods. Actual results may differ from
such estimates.
NEW ACCOUNTING STANDARDS
Statement of Financial Accounting Standards ("SFAS") No. 121 "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
establishes accounting standards for the impairment of long-lived assets,
certain identifiable intangibles and goodwill related to those assets to be held
and used and for long-lived assets and certain identifiable intangibles to be
disposed of. SFAS No. 121 requires the review of long-lived assets and certain
identifiable intangibles for impairment. If an impairment event occurs and it is
determined that the carrying value of the asset may not be recoverable, an
impairment loss will be recognized as measured by the amount by which the
carrying amount of the assets exceeds the fair value of the asset. The Trust
adopted SFAS No. 121 effective January 1, 1996 and such adoption did not have a
material impact on the distributable income or financial position.
3. FEDERAL INCOME TAXES
The Trust is a grantor trust for Federal income tax purposes. As a grantor
trust, the Trust will not be required to pay Federal or state income taxes.
Accordingly, no provision for income taxes has been made in these financial
statements.
<PAGE>
Because the Trust will be treated as a grantor trust, and because a Unitholder
will be treated as directly owning an interest in the Royalty Interests, each
Unitholder will be taxed directly on his per Unit share of income attributable
to the Royalty Interests consistent with the Unitholder's method of accounting
and without regard to the taxable year or accounting method employed by the
Trust.
Production from coal seam gas wells drilled after December 31, 1979, and prior
to January 1, 1993, qualifies upon the sale of such production for the Federal
income tax credit for producing nonconventional fuels under Section 29 of the
Internal Revenue Code. This tax credit is calculated annually based on sales of
qualified production for each year through the year 2002. Such credit, based on
the Unitholder's pro rata share of qualifying production, may not be used to
reduce his regular tax liability (after the foreign tax credit and certain other
non-refundable credits) below his alternative minimum tax. Any part of the
Section 29 credit not allowed for any tax year solely because of this limitation
is subject to certain carryover provisions. Each Unitholder should consult their
tax advisor regarding tax consequences.
4. RELATED PARTY TRANSACTIONS
Dominion Resources provides accounting, bookkeeping and informational services
to the Trust in accordance with an Administrative Services Agreement effective
June 1, 1994. During 1996 this fee was $318,270 and will increase annually by
three percent. Aggregate fees paid by the Trust to Dominion Resources in 1996,
1995 and 1994 were $318,270, $331,844 and $175,000, respectively. Additionally,
during 1994, the Trust reimbursed Dominion Resources $331,656 for formation
costs.
Aggregate fees and expense reimbursements paid by the Trust to the trustees in
1996, 1995 and 1994 were $36,853, $30,900 and $5,000, respectively.
5. DISTRIBUTIONS TO UNITHOLDERS
The Trustee determines for each calendar quarter the amount of cash available
for distribution to Unitholders. Such amount (the "Quarterly Distribution
Amount") is an amount equal to the excess, if any, of the cash received by the
Trust attributable to production from the Royalty Interests during such quarter,
provided that such cash is received by the Trust on or before the last business
day prior to the 45th day following the end of such calendar quarter, plus the
amount of interest expected by the Trustee to be earned on such cash proceeds
during the period between the date of receipt by the Trust of such cash proceeds
and the date of payment to the Unitholders of such Quarterly Distribution
Amount, plus all other cash receipts of the Trust during such quarter (to the
extent not distributed or held for future distribution as a Special Distribution
Amount (as defined below) or included in the previous Quarterly Distribution
Amount)(which might include sales proceeds not sufficient in amount to qualify
for a special distribution as described in the next paragraph), over the
liabilities of the Trust paid during such quarter and not taken into account in
determining a prior Quarterly Distribution Amount, subject to adjustments for
changes made by the Trustee during such quarter in any cash reserves established
for the payment of contingent or future obligations of the Trust. An amount
which is not included in the Quarterly Distribution Amount for a calendar
quarter because such amount is received by the Trust after the last business day
prior to the 45th day following the end of such calendar quarter will be
included in the Quarterly Distribution Amount for the next calendar quarter. The
Quarterly Distribution Amount for each quarter will be payable to Unitholders of
record on the 60th day following the end of such calendar quarter unless such
day is not a business day in which case the record date is the next business day
thereafter. The Trustee will distribute the Quarterly Distribution Amount for
each quarter on or prior to 70 days after the end of such calendar quarter to
each person who was a Unitholder of record on the record date for such calendar
quarter.
<PAGE>
The Royalty Interests may be sold under certain circumstance and will be sold
following termination of the Trust. A special distribution will be made of
undistributed net sales proceeds and other amounts received by the Trust
aggregating in excess of $10 million (a "Special Distribution Amount"). The
record date for a Special Distribution Amount will be the 15th day following the
receipt by the Trust of amounts aggregating a Special Distribution Amount
(unless such day is not a business day, in which case the record date will be
the next business day thereafter) unless such day is within 10 days or less
prior to the record date for a Quarterly Distribution Amount, in which case the
record date for the 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, 1996, the Trust declared and paid the following
distribution:
<TABLE>
<CAPTION>
==============================================================
Quarterly Record Date Payment Date Distribution per Unit
- --------------------------------------------------------------
<S> <C> <C>
March 3, 1997 March 11, 1997 $.844175
==============================================================
</TABLE>
The trustee has estimated the Section 29 tax credit associated with the March
11, 1997 quarterly distribution to be $.38 per unit (unaudited).
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, 1996 and 1995 (in thousands, except per Unit amounts):
<TABLE>
<CAPTION>
=======================================================================================
Calendar Quarter Royalty Income Distributable Income Distributable Income per Unit
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C>
1996
- ---------------------------------------------------------------------------------------
First $5,719 $5,534 $.70
- ---------------------------------------------------------------------------------------
Second 7,253 7,063 .90
- ---------------------------------------------------------------------------------------
Third 6,700 6,591 .84
- ---------------------------------------------------------------------------------------
Fourth 6,341 6,235 .80
- ---------------------------------------------------------------------------------------
$26,013 $25,423 $3.24
- ---------------------------------------------------------------------------------------
1995
- ---------------------------------------------------------------------------------------
First $ 5,609 $5,518 $.70
- ---------------------------------------------------------------------------------------
Second 5,336 5,018 .63
- ---------------------------------------------------------------------------------------
Third 5,364 5,225 .67
- ---------------------------------------------------------------------------------------
Fourth 5,295 5,186 .67
- ---------------------------------------------------------------------------------------
$21,604 $20,947 $2.67
=======================================================================================
</TABLE>
Selected 1996 fourth quarter data are as follows (in thousands, except per Unit
amounts):
<PAGE>
<TABLE>
===========================================================
<S> <C>
Royalty income $6,341
- -----------------------------------------------------------
Interest income 16
- -----------------------------------------------------------
General and administrative expenses (123)
- -----------------------------------------------------------
Distributable income $6,235
- -----------------------------------------------------------
Distributable income per Unit $.80
- -----------------------------------------------------------
Distributions per Unit $.80
===========================================================
</TABLE>
Due to significant upward revision in estimate of reserve quantities (see Note
8) estimated amortization of royalty interests was adjusted downward by
approximately $4 million during the fourth quarter of 1996. This adjustment did
not have an impact on the Trust's distributable income.
8. SUPPLEMENTAL GAS DISCLOSURE (UNAUDITED)
The net proved reserves attributable to the Royalty Interests have been
estimated as of December 31, 1996, 1995 and 1994 by independent petroleum
engineers. A reserve estimate as of June 1, 1994 was prepared for the Trust even
though the conveyance of the Royalty Interests to the Trust did not occur until
June 28, 1994.
In accordance with Statement of Financial Accounting Standards No. 69, estimates
of proved reserves and future net cash flows from proved reserves have been
prepared using contractually guaranteed prices and end-of-period natural gas
prices, and related costs. The standardized measure of future net cash flows
from the gas reserves is calculated based on discounting such future net cash
flows at an annual rate of 10 percent. The price for December 31, 1996, 1995 and
1994 were $2.81, $2.26 per Mcf and $1.83 per Mcf, respectively, including the
effect of the Gas Purchase Agreement.
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.
The reserve estimates for the Royalty Interests are based on a percentage share
of the Company's Gross Proceeds payable to the Trust of 65 percent.
<TABLE>
<CAPTION>
============================================================
MMcf
- ------------------------------------------------------------
<S> <C>
Proved developed reserves at June 1, 1994 63,311
- ------------------------------------------------------------
Increase (decreases) due to:
- ------------------------------------------------------------
Revisions of previous estimates 7,480
- ------------------------------------------------------------
Production (7,643)
- ------------------------------------------------------------
Proved developed reserves at December 31, 1994 63,148
- ------------------------------------------------------------
Increase (decreases) due to:
- ------------------------------------------------------------
Revisions of previous estimates 24,130
- ------------------------------------------------------------
Production (12,437)
- ------------------------------------------------------------
Proved developed reserves at December 31,1995 74,841
- ------------------------------------------------------------
Increase (decrease) due to:
- ------------------------------------------------------------
Revisions of previous estimates 19,484
- ------------------------------------------------------------
Production (11,937)
- ------------------------------------------------------------
Proved developed reserves at December 31, 1996 82,388
============================================================
</TABLE>
All proved reserve estimates presented above at December 31, 1996, 1995 and 1994
are proved developed.
<PAGE>
Proved developed reserves, all located in the United States, for the Company
Interests are estimated quantities of coal seam gas which geological and
engineering data indicate with reasonable certainty to be recoverable in future
years from the coal formation under existing economic and operating conditions.
Proved developed reserves are proved reserves which can be expected to be
recovered through existing wells with existing equipment and operating methods.
Estimated economic quantities have been determined considering the Section 29
tax credit.
The following table sets forth the standardized measure of discounted estimated
future net cash flows from proved reserves at December 31, 1996, 1995 and 1994
relating to the Trust's Royalty Interests (thousands of dollars):
<TABLE>
<CAPTION>
===========================================================================
1996 1995 1994
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Future cash inflows $231,734 $169,501 $112,375
- ---------------------------------------------------------------------------
Future taxes (13,904) (10,170) (6,515)
- ---------------------------------------------------------------------------
Future net cash flows. 217,830 159,331 05,860
- ---------------------------------------------------------------------------
10% annual discount for estimated (83,155) (58,945) (27,553)
timing of cash flow
- ---------------------------------------------------------------------------
Standardized measure of discounted $134,675 $100,386 $78,307
future net cash flows
===========================================================================
</TABLE>
Future cash flows do not include Section 29 tax credits which in the aggregate
are estimated to be approximately $47,929,000 having a discounted present value
(assuming a 10% discount rate) of approximately $29,633,000 at December 31,
1996.
The following table sets forth the changes in the present value of estimated
future net cash flows from proved reserves during the period ended December 31,
1996, 1995 and 1994 (thousands of dollars):
<TABLE>
<CAPTION>
=================================================================
1996 1995 1994
- -----------------------------------------------------------------
<S> <C> <C> <C>
Balance at beginning of period $100,386 $ 78,307 $ 95,400
- -----------------------------------------------------------------
Increase (decrease) due to:
- -----------------------------------------------------------------
Royalty income, net of taxes (27,091) (21,714) (13,202)
- -----------------------------------------------------------------
Changes in prices 17,516 18,974 (13,796)
- -----------------------------------------------------------------
Changes in estimated volumes 33,826 16,988 4,340
- -----------------------------------------------------------------
Accretion of discount 10,038 7,831 5,565
- -----------------------------------------------------------------
Balance at December 31 $134,675 $100,386 $78,307
=================================================================
</TABLE>
Subsequent to year end, the price of gas decreased significantly. As of March
21, 1997, published natural gas prices were approximately $1.53 per MMBtu as
compared to the year end price of $2.84 per MMBtu utilized in the Trust's
calculation of its year end standardized measure of discounted future net cash
flow. The use of prices currently being received would result in a lower
standardized measure of discounted future net cash flows.
9. GAS PURCHASE AGREEMENT
Sonat Marketing Company ("Sonat Marketing") is required under a gas purchase
agreement (the "Gas Purchase Agreement") to purchase the natural gas produced
and sold from the Underlying Properties ("Gas") for as long as reserves on the
<PAGE>
Underlying Properties produce natural gas. Under the Gas Purchase Agreement,
Sonat Marketing is obligated to purchase up to a specified monthly base quantity
at the central delivery points for gas in the gathering system for the
Underlying Properties for a contract price which provides for a specified
premium (between $.05 and $.07 per MMBtu) over the Index Price (as defined
below), subject to a minimum price of $1.85 per MMbtu and a maximum price of
$2.63 per MMBtu, until December 31, 1998. Although the primary term of the Gas
Purchase Agreement extends through December 31, 2001, the minimum price and the
maximum price will cease to apply December 31, 1998. Prior to April 1, 1996,
Sonat Marketing was obligated to purchase gas production in excess of the
monthly base quantities at the Index Price. Effective April 1, 1996, the price
payable for such excess gas production will equal the Index Price plus $.02.
After December 31, 2001, Sonat Marketing, assuming the gas Purchases Agreement
is extended, will be obligated to purchase gas production at the Index Price
until such time as the Company and Sonat Marketing negotiate a different price,
although the Company will have the ability to obtain an offer from another
purchaser and terminate the Gas Purchase Agreement if Sonat Marketing does not
match such offer. The "Index Price", which is determined on a monthly basis, is
Southern Natural Gas Company's posted index price for deliveries of gas in
Louisiana. During 1996, 1995 and 1994, Sonat Marketing purchased all the gas
production attributable to the Royalty Interests.
TRUSTEE
NationsBank of Texas, N.A.
Dallas, Texas
DELAWARE TRUSTEE
Mellon Bank (DE) National Association
Wilmington, Delaware
TRANSFER AGENT AND REGISTRAR
Chase Mellon Shareholder Service
Ridgefield Park, New Jersey
TRUST AUDITORS
Deloitte & Touche llp
Dallas, Texas
TRUST ENGINEERING CONSULTANTS
Ryder Scott Company Petroleum Engineers
TRUSTEE COUNSEL
Thompson & Knight,
A Professional Corporation
Dallas, Texas
FORM 10-K
A copy of the Form 10-K of the Trust for the period ended December 31, 1996 as
filed with the Securities and Exchange Commission has been provided with this
Annual Report to Unitholders. Additional copies of the Form 10-K will be
provided, without charge, upon written request to:
Dominion Resources Black Warrior Trust
NationsBank Of Texas, N.A., Trustee
901 Main Street, 17th Floor
Dallas, Texas 75202
DOMINION RESOURCES BLACK WARRIOR TRUST
NATIONSBANK OF TEXAS, N.A., TRUSTEE
901 MAIN STREET, 17TH FLOOR
DALLAS, TEXAS 75202
1-800-365-6548
<PAGE>
EXHIBIT 23.1
March 28, 1997
Dominion Resources Black Warrior Trust
NationsBank Center
901 Main Street, 12th Floor
Dallas, Texas 75202
Gentlemen:
In connection with the filing of the Annual Report on Form 10K for the
year ended December 31, 1996 for Dominion Resources Black Warrior Trust (the
"Trust"), we delivered a report dated March 14, 1997 with respect to an estimate
of the net proved reserves, future production, and income attributable to
certain royalty interests of the Trust as of January 1, 1997.
We understand that you intend that our report be included in the Annual
Report and any amendments thereto, and we hereby consent to such use. We also
consent to the references in the Annual Report to our firm and to the
information provided therein.
Very truly yours,
/s/ Ryder Scott Company
Petroleum Engineers
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
LPC/sw
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<CASH> 149,707
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 149,707
<PP&E> 155,817,501
<DEPRECIATION> 46,205,805
<TOTAL-ASSETS> 109,761,403
<CURRENT-LIABILITIES> 199,326
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 109,562,077
<TOTAL-LIABILITY-AND-EQUITY> 109,761,403
<SALES> 26,013,428
<TOTAL-REVENUES> 26,079,301
<CGS> 0
<TOTAL-COSTS> 656,019
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 25,423,282
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 25,423,282
<EPS-PRIMARY> 3.24
<EPS-DILUTED> 0
</TABLE>
<PAGE>
EXHIBIT 99.1
[LOGO FOR:
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS] FAX (713) 651-0849
1100 LOUISIANA SUITE 3800 HOUSTON, TEXAS 77002-5218 TELEPHONE (713) 651-9191
March 14, 1997
Dominion Resources Black Warrior Trust
NationsBank Center
901 Main Street, 12th Floor
Dallas, Texas 75202
Gentlemen:
At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain royalty interests of Dominion
Resources Black Warrior Trust (the Trust) as of January 1, 1997. The subject
properties are located in Black Warrior Basin, Tuscaloosa County, Alabama. The
income data were estimated using the Securities and Exchange Commission (SEC)
guidelines for future cost and price parameters.
The estimated reserves and future income amounts presented in this
report are related to hydrocarbon prices. December 1996 hydrocarbon prices
provided by Dominion Black Warrior Basin, Inc. (Dominion) were used in the
preparation of this report as required by SEC guidelines. However, future prices
may vary significantly from December 1996 prices. Therefore, volumes of reserves
actually recovered and amounts of income actually received may differ
significantly from the estimated quantities presented in this report. A summary
of the result of this study is shown below.
DENVER OFFICE: 600 SEVENTEENTH SUITE 900N DENVER, COLORADO 80202-5401
TELEPHONE (303) 623-9147 FAX (303) 623-4258
<PAGE>
Dominion Resources Black Warrior Trust
March 29, 1996
Page 2
UNESCALATED PARAMETERS - YEAR END PRICING
Estimated Net Reserve and Income Data
Certain Royalty Interests of
Dominion Resources Black Warrior Trust
65% Overriding Royalty Interest
As of January 1, 1997
--------------------------------------------------------
<TABLE>
<CAPTION>
Total
Proved
------------
<S> <C>
Net Remaining Reserves
- ----------------------
Gas - MMCF 82,388
Income Data
- -----------
Future Gross Revenue $217,830,414
Tax Credits 47,929,114
------------
Future Net Income (FNI) $265,759,528
Discounted FNI @ 10% $164,308,370
</TABLE>
All gas volumes are sales gas expressed in millions of cubic feet
(MMCF) at the official temperature and pressure bases of the areas in which the
gas reserves are located.
Al of the reserves included herein are comprised of the proved
producing category. The various producing status categories are defined in the
attached "Reserve Definitions and Pricing Assumptions" in this report.
A Staff Accounting Bulletin (S.A.B.) issued September 18, 1989 allows
for oil and gas producing companies to include coalbed methane gas in their
estimate of proved reserves under SEC guidelines. In accordance with the S.A.B.
dated November 30, 1989 these reserves should be included provided they comply
in all other respects with the definition of proved oil and gas reserves.
Included is the requirement that methane production be economical at current
prices, costs (net of the tax credit) and existing operating conditions. At the
request of Dominion, the coalbed methane gas reserves presented herein are
based on economic parameters which include Dominion's estimates of the future
Section 29 Tax Credit. Dominion's estimates of the future tax credits are
presented in detail in the attached "Reserve Definitions and Pricing
Assumptions" in this report.
The future gross revenue is after the deduction of production taxes
and before the addition of Dominion's estimate of Section 29 Tax Credit
(presented as "other income"). The future net income is before the deduction of
state and federal income taxes and general overhead, and has not been adjusted
for outstanding loans that may exist nor does it include any adjustment for cash
on hand or undistributed income. No attempt has been made to quantify or
otherwise account for any accumulated gas production imbalances that may exist.
Gas reserves account for 100 percent of total future gross revenue from proved
reserves.
The discounted future net income shown above was calculated using a
discount rate of 10 percent per annum compounded monthly. Future net income was
discounted at four other discount rates which were also compounded monthly.
These results are shown on each estimated projection of future production and
income presented in a later section of this report and in summary form below.
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
<PAGE>
Dominion Resources Black Warrior Trust
March 29, 1996
Page 3
<TABLE>
<CAPTION>
Year End Pricing
Dominion Resources Black Warrior Trust
65% Overriding Royalty Interest
Discounted Future Net Income
As of January 1, 1997
Total Proved
---------------------------------------
Discount Rate Total
Percent Proved
------------- ----------------
<S> <C>
5 $202,809,862
15 $138,431,720
20 $119,810,044
25 $105,725,076
</TABLE>
Reserves Included in This Report
- --------------------------------
The proved reserves included herein conform to the definition
---------------
as set forth in the Securities and Exchange Commission's Regulation S-X
Part 210.4-10 (a) as clarified by subsequent Commission Staff Accounting
Bulletins.
Our definition of proved reserves is included in the attached "Reserve
Definitions and Pricing Assumptions" in this report.
Estimates of Reserves
- ---------------------
In general, the reserves included herein were estimated by
performance methods or the volumetric method; however, other methods were used
in certain cases where characteristics of the data indicated such other methods
were more appropriate in our opinion. The reserves estimated by the performance
method utilized extrapolations of various historical data in those cases where
such data were definitive. Reserves were estimated by the volumetric method in
those cases where there were inadequate historical performance data to establish
a definitive trend or where the use of production performance data as a basis
for the reserve estimates was considered to be inappropriate.
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
<PAGE>
Dominion Resources Black Warrior Trust
March 29, 1996
Page 4
The reserves included in this report are estimates only and should
not be construed as being exact quantities. They may or may not be actually
recovered, and if recovered, the revenues therefrom and the actual costs
related thereto could be more or less than the estimated amounts. Moreover,
estimates of reserves may increase or decrease as a result of future
operations.
Future Production Rates
- -----------------------
Initial production rates are based on the current producing rates for
those wells now on production. Test data and other related information were
used to estimate the anticipated peak production rates for those wells or
locations which are not currently producing at peak rates. If no production
decline trend has been established, future production rates were held constant,
or adjusted for the effects of dewatering where appropriate, until a decline in
ability to produce was anticipated. An estimated rate of decline was then
applied to depletion of the reserves. If a decline trend has been established,
this trend was used as the basis for estimating future production rates. For
reserves not yet on production, sales were estimated to commence at an
anticipated date furnished by Dominion.
In general, we estimate that future gas production rates will
continue to be the same as the average rate for the latest available 12 months
of actual production until such time that the well or wells are incapable of
producing at this rate. The well or wells where then projected to decline at
their decreasing delivery capacity rate. Our general policy on estimates of
future gas production rates is adjusted when necessary to reflect actual gas
market conditions in specific cases.
The future production rates from wells now on production may be more
or less than estimated because of changes in market demand or allowables set by
regulatory bodies. Wells or locations which are not currently producing may
start producing earlier or later than anticipated in our estimates of their
future production rates.
Hydrocarbon Prices
- ------------------
Dominion furnished us with contract gas prices in effect at December
31, 1996 and these prices were held constant to depletion of the reserves. In
accordance with Securities and Exchange Commission guidelines, changes in gas
prices subsequent to December 31, 1996 were not taken into account in this
report. Future prices used in this report are discussed in detail in the
attached "Reserve Definitions and Pricing Assumptions" in this report.
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
<PAGE>
Dominion Resources Black Warrior Trust
March 29, 1996
Page 5
Costs
- -----
The income attributable to Dominion Resources Black Warrior Trust is
based on a 65 percent overriding royalty interest, and has no associated
deductions or costs. The costs utilized in the evaluation of the leasehold
interest are presented below.
Operating costs for the leases and wells in the unescalated case are
based on the operating expense reports of Dominion and include only those costs
directly applicable to the leases or wells. When applicable, the operating costs
include a portion of general and administrative costs allocated directly to the
leases and wells under terms of operating agreements. The current operating
and development costs were held constant throughout the life of the properties.
At the request of Dominion, their estimate of zero net abandonment costs after
salvage value for the properties was used in this report. Ryder Scott has not
performed a detailed study of the abandonment costs nor the salvage value and
makes no warranty for Dominion's estimate. No deduction was made for indirect
costs such as general administration and overhead expenses, loan repayments,
interest expenses, and exploration and development prepayments that are not
charged directly to the leases or wells.
General
- -------
The attached tables 1 through 3 present the grand summaries of our
estimated projection of production and income by years beginning January 1, 1997
by category.
The estimates of reserves presented herein are based upon a detailed
study of the properties in which the Trust owns an interest; however, we have
not made any field examination of the properties. 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. Dominion has informed us that they have
furnished us all of the accounts, records, geological and engineering data, and
reports and other data required for this investigation. The ownership interests,
prices, and other factual data furnished by Dominion were accepted without
independent verification. The estimates presented in this report are based on
data available through December 1996.
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
<PAGE>
Dominion Resources Black Warrior Trust
March 22, 1996
Page 6
Neither we nor any of our employees have any interest in the subject
properties and neither the employment to make this study nor the compensation is
contingent on our estimates of reserves and future income for the subject
properties.
This report was prepared for the exclusive use of the Trust. The
data, work papers, and maps used in the preparation of this report are
available for examination by authorized parties in our offices. Please contact
us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
/s/ LARRY P. CONNOR
Larry P. Connor, P.E.
Petroleum Engineer
LPC/sw
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
<PAGE>
DEFINITIONS OF RESERVES
SEC DEFINITIONS
- ---------------
Proved reserves of crude oil, condensate, natural gas, and natural
---------------
gas liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing operating conditions using the cost and price
parameters discussed in other sections of this report. Reservoirs are
considered proved if economic producibility is supported by actual production or
formation tests. In certain instances, proved reserves are assigned on the
basis of a combination of core analysis and electrical and other type logs
which indicate the reservoirs are analogous to reservoirs in the same field
which are producing or have demonstrated the ability to produce on a formation
test. The area of a reservoir considered proved includes (1) that portion
delineated by drilling and defined by fluid contacts, if any, and (2) the
adjoining portions not yet drilled that can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of data on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir. Proved reserves
are estimates of hydrocarbons to be recovered from a given date forward. They
may be revised as hydrocarbons are produced and additional data become
available. Proved natural gas reserves are comprised of non-associated,
associated and dissolved gas. An appropriate reduction in gas reserves has been
made for the expected removal of natural gas liquids, for lease and plant fuel,
and for the exclusion of non-hydrocarbon gases if they occur in significant
quantities and are removed prior to sale.
Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot project or the
operation of an installed program in the reservoir provides support for the
engineering analysis on which the project or program was based, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.
Estimates of proved reserves do not include crude oil, natural gas,
or natural gas liquids being held in underground or surface storage.
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
<PAGE>
DEFINITIONS OF PRODUCING STATUS CATEGORIES
Developed Producing
- -------------------
Producing reserves are recoverable from completion intervals
---------
currently open and producing to market. Improved recovery reserves are
considered to be producing only after an improved recovery project has been
installed and is in operation.
Developed Non-Producing
- -----------------------
Shut-in reserves are recoverable from completion intervals now open,
-------
but which had not started producing as of the date of our estimate.
Behind pipe reserves are recoverable from zones behind casing in
-----------
existing wells, which will require additional completion work or a future
recompletion prior to the start of production.
Undeveloped
- -----------
Undeveloped reserves are recoverable by new wells on undrilled
-----------
acreage, from existing wells where a relatively large expenditure is required
for recompletion and from acreage where the application of an improved recovery
project is planned and the costs required to place the project in operation are
relatively large. Reserves on undrilled acreage are limited to those drilling
units offsetting productive units that are reasonably certain of production
when drilled. Proved reserves for other undrilled units are included only where
it can be demonstrated with certainty that there is continuity of production
from the existing productive formation.
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
<PAGE>
HYDROCARBON PRICING AND COST PARAMETERS
Dominion Resources Black Warrior Trust
Dominion Black Warrior Basin, Inc.'s Pricing and Cost Policy
Unescalated Parameters
Effective January 1, 1997
Gas
- ---
Dominion has furnished the pricing scenario to use at January 1, 1997.
<TABLE>
<CAPTION>
Year $/MMBTU
---------- -----------
<S> <C>
1997 2.84
1998 2.84
1999 2.84
2000 2.84
2001 2.84
2002 2.84
2003 2.84
2004 2.84
</TABLE>
<TABLE>
<CAPTION>
Lease Operating 1,2 Compression 1
Expense Costs
Year $/Well/Month $/MCF
---------- --------------- -----------
<S> <C> <C>
1997 1,266 .179
1998 1,214 .176
1999 1,136 .175
2000 1,020 .172
2001 903 .172
2002 808 .168
2003 791 .161
2004 623 .153
</TABLE>
<TABLE>
<CAPTION>
Estimated Section 29 Tax Credit
-------------------------------------
Year $/MMBTU
---------- -----------
<S> <C>
1997 1.056
1998 1.056
1999 1.056
2000 1.056
2001 1.056
2002 1.025
</TABLE>
- ---------------
1 All prices and costs are held constant after the year 2004.
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
