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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, 1997
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)
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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)
</TABLE>
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.
</TABLE>
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
At March 13, 1998, 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 $158,963,000.
DOCUMENTS INCORPORATED BY REFERENCE
None.
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TABLE OF CONTENTS
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PAGE
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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........................ 5
Liabilities of the Trust............................. 5
Liabilities of the Trustee and the Delaware
Trustee............................................. 6
Termination and Liquidation of the Trust............. 6
Arbitration and Actions by Unitholders............... 7
DESCRIPTION OF UNITS................................... 8
Distributions and Income Computations................ 8
Conditional Right of Repurchase...................... 9
Possible Divestiture of Units........................ 10
Periodic Reports..................................... 10
Voting Rights of Unitholders......................... 11
Liability of Unitholders............................. 12
Transfer Agent....................................... 12
FEDERAL INCOME TAX CONSIDERATIONS...................... 12
Summary of Certain Federal Income Tax Consequences... 13
ERISA CONSIDERATIONS................................... 17
STATE TAX CONSIDERATIONS............................... 17
Alabama Income Tax................................... 17
Alabama Franchise Tax................................ 18
Alabama Severance Taxes.............................. 18
Other Alabama Taxes.................................. 18
REGULATION AND PRICES.................................. 18
Regulation of Natural Gas............................ 18
Environmental Regulation............................. 19
Competition, Markets and Prices...................... 20
Item 2. Properties....................................... 20
THE ROYALTY INTERESTS.................................. 20
The Underlying Properties............................ 20
The Royalty Interests................................ 22
Reserve Estimate..................................... 24
Natural Gas Sales Prices and Production.............. 25
Gas Purchase Agreement............................... 25
Operation of Properties.............................. 26
Sale and Abandonment of Underlying Properties........ 27
Dominion Resources' Assurances....................... 27
Title to Properties.................................. 28
Item 3. Legal Proceedings................................ 28
Item 4. Submission of Matters to a Vote of Security
Holders.............................................. 28
PART II..................................................... 29
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.................................. 29
Item 6. Selected Financial Data.......................... 29
Item 7. Trustee's Discussion and Analysis of Financial
Condition and Results of Operations.............. 29
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Item 8. Financial Statements and Supplementary Data...... 32
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.............. 41
PART III.................................................... 41
Item 10. Directors and Executive Officers of the
Registrant........................................... 41
Item 11. Executive Compensation........................... 41
Item 12. Security Ownership of Certain Beneficial Owners
and Management....................................... 41
Item 13. Certain Relationships and Related Transactions... 42
Administrative Services Agreement.............. 42
Dominion Resources' Conditional Right of
Repurchase...................................... 42
Potential Conflicts of Interest................ 42
PART IV..................................................... 43
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K.................................. 43
Financial Statements........................... 43
Financial Statement Schedules.................. 43
Exhibits....................................... 43
Reports on Form 8-K............................ 44
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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.
"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.
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"Gross Proceeds" means the aggregate amounts received by the Company
Interests Owner attributable to the Company Interests from the sale of Subject
Gas at the central delivery points in the gathering system for the Underlying
Properties.
"Gross Wells" means the total whole number of gas wells.
"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 $1.85 per MMBtu, the minimum price payable for the
Monthly Base Quantities pursuant to the Gas Purchase Agreement from June 1, 1994
through December 31, 1998.
"MMcf" means million cubic feet of natural gas. As used herein, 1 MMcf is
assumed to have a Btu content of 990 MMBtu.
"MMBtu" means million Btu. As used herein, 990 MMBtu is deemed to be the
Btu content of 1 MMcf.
"Monthly Base Quantity" means the volumes of natural gas designated as such
in the Gas Purchase Agreement.
"Net revenue interest" means working interest or mineral interest less any
applicable royalties, overriding royalties or similar burdens on production
prior to the Royalty Interests.
"Net wells" and "net acres" are calculated by multiplying gross wells or
gross acres by the working interest in such wells or acres.
"Premium" means the premium per MMbtu on a wet basis pursuant to the Gas
Purchase Agreement from June 1, 1994 through December 31, 2001 as follows:
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INDEX PRICE PREMIUM
($/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, 1998, 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.
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"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 (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.
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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 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 has incurred are
those for routine administrative expenses, such as trusteeship fees and
accounting, engineering, legal and other professional fees and the
administrative services fee paid to Dominion Resources. If a court were to hold
that the Trust is taxable as a corporation, then the Trust would incur
substantial federal income tax liabilities. See also "-- State Tax
Considerations -- Alabama Franchise Tax."
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LIABILITIES OF THE TRUSTEE AND THE DELAWARE TRUSTEE
Each of the Trustee and the Delaware Trustee may act in its discretion and
is personally or individually liable only for fraud or acts or omissions in bad
faith or which constitute gross negligence (and for taxes, fees and other
charges on, based on or measured by any fees, commissions or compensation
received pursuant to the Trust Agreement) and will not be otherwise liable for
any act or omission of any agent or employee unless such trustee has acted in
bad faith or with gross negligence in the selection and retention of such agent
or employee. Each of the Trustee and the Delaware Trustee (and their respective
agents) is indemnified by Dominion Resources and from the Trust assets for
certain environmental liabilities, and for any other liability, expense, claim,
damage or other loss incurred in performing its duties, unless resulting from
gross negligence, fraud or bad faith (each of the Trustee and the Delaware
Trustee is indemnified from the Trust assets against its own negligence which
does not constitute gross negligence), and will have a first lien upon the
assets of the Trust as security for such indemnification and for reimbursements
and compensation to which it is entitled; provided that the Trustee and the
Delaware Trustee are generally required to first be indemnified from Trust
assets before seeking indemnification from Dominion Resources. Dominion
Resources also has agreed to indemnify the Trustee and the Delaware Trustee
against certain securities laws' liabilities. Neither the Trustee nor the
Delaware Trustee is entitled to indemnification from Unitholders (except in
connection with lost or destroyed Unit certificates). Insofar as indemnification
for liabilities arising under the Securities Act of 1933, as amended (the
"Securities Act"), is permitted to the Trustee pursuant to the foregoing
provisions, the Trustee has been informed that in the opinion of the Securities
and Exchange Commission (the "Commission") such indemnification is against
public policy as expressed in the Securities Act and is, therefore,
unenforceable.
TERMINATION AND LIQUIDATION OF THE TRUST
The Trust will terminate upon the occurrence of: (i) an affirmative vote of
the holders of not less than 66 2/3 percent of the outstanding Units to
terminate the Trust; (ii) such time as the ratio of the cash amounts received by
the Trust attributable to the Royalty Interests in any calendar quarter to
administrative costs of the Trust for such calendar quarter is less than $1.2 to
$1.0 for two consecutive calendar quarters; or (iii) March 1 of any year if it
is determined, based on a reserve report as of December 31 of the prior year
prepared by a firm of independent petroleum engineers mutually selected by the
Trustee and the Company, that the net present value (discounted at 10 percent)
of (a) estimated future net revenues from proved reserves attributable to the
Royalty Interests plus (b) the amount of all remaining Section 29 tax credits
attributable to the Royalty Interests, is equal to or less than $5 million (as
applicable, the "Termination Date"). Upon such occurrence, the remaining assets
of the Trust will be sold, the net proceeds of the sale will be distributed to
the Unitholders and the Trust will be wound up and a certificate of cancellation
filed.
Upon the termination of the Trust, the Trustee will use its best efforts to
sell any remaining Royalty Interests then owned by the Trust for cash pursuant
to the procedures described in the Trust Agreement. The Trustee will retain a
nationally recognized investment banking firm (the "Advisor") on behalf of the
Trust who will assist the Trustee in selling the remaining Royalty Interests.
The Company has the right, but not the obligation, within 60 days following the
Termination Date, to make a cash offer to purchase all of the remaining Royalty
Interests then held by the Trust. In the event such an offer is made by the
Company, the Trustee will decide, based on the recommendation of the Advisor, to
either (i) accept such offer (in which case no sale to the Company will be made
unless a fairness opinion is given by the Advisor that the purchase price is
fair to the Unitholders) or (ii) defer action on the offer for approximately 60
days and seek to locate other buyers for the remaining Royalty Interests. If the
Trustee defers action on the Company's offer, the offer will be deemed withdrawn
and the Trustee will then use its best efforts, assisted by the Advisor, to
locate other 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
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price will be 105 percent of the Highest Acceptable Offer, or (ii) if the
Highest Acceptable Offer is equal to or less than 105 percent of the Company's
original offer, the purchase price will be equal to the Highest Acceptable
Offer. If no other acceptable offers are received for all remaining Royalty
Interests, the Trustee may request the Company to submit another offer for
consideration by the Trustee and may accept or reject such offer.
If a sale of the Royalty Interests is made or a definitive contract for
sale of the Royalty Interests is entered into within a 150-day period following
the Termination Date, the buyer of the Royalty Interests, and not the Trust or
Unitholders, will be entitled to all proceeds of production attributable to the
Royalty Interests following the Termination Date.
In the event that the Company does not purchase the Royalty Interests, the
Trustee may accept any offer for all or any part of the Royalty Interests as it
deems to be in the best interests of the Trust and Unitholders and may continue,
for up to one calendar year after the Termination Date, to attempt to locate a
buyer or buyers of the remaining Royalty Interests in order to sell such
interests in an orderly fashion. If the Royalty Interests have not been sold or
a definitive agreement for sale has not been entered into by the end of such
calendar year, the Trustee is required to sell the remaining Royalty Interests
at a public auction, which sale may be to the Company or any of its affiliates.
The Company's purchase rights, as described above, may be exercised by the
Company and each of its successors in interest and assigns. The Company's
purchase rights are fully assignable by the Company to any person or entity. The
costs of liquidation, including the fees and expenses of the Advisor and the
Trustee's liquidation fee will be paid by the Trust.
The Trust may terminate without Unitholder approval. Unitholders are not
entitled to any rights of appraisal or similar rights in connection with the
termination of the Trust.
ARBITRATION AND ACTIONS BY UNITHOLDERS
Pursuant to the Trust Agreement, any dispute, controversy or claim that may
arise between or among Dominion Resources or the Company, on the one hand, and
the Trustee, the Delaware Trustee or the Trust, on the other hand, in connection
with or otherwise relating to the Trust Agreement or the Conveyance or the
application, implementation, validity or breach thereof or any provision
thereof, shall be settled by final and binding arbitration in Dallas, Texas in
accordance with the Rules of Practice and Procedure for the arbitration of
commercial disputes of Judicial Arbitration & Mediation Services, Inc. (or any
successor thereto) then in effect. The Administrative Services Agreement also
includes a provision that will require Dominion Resources and the Trustee and
the Trust to submit any dispute regarding such contract to alternative dispute
resolution before litigating such matter.
The Trust Agreement requires under certain circumstances that the Trustee
and the Trust pursue any claims against Dominion Resources and the Company with
respect to any breach by Dominion Resources and the Company of the terms of the
Conveyance or the Trust Agreement (and requires that any such claims be brought
in arbitration), without the joinder of any Unitholder. The Trust Agreement does
not provide for any procedure allowing Unitholders to bring an action on their
own behalf to enforce the rights of the Trust under the Conveyance and, except
in the case of the failure of the Trustee to enforce certain performance
obligations of Dominion Resources to the Trust, does not provide for any
procedure allowing Unitholders to direct the Trustee to bring an action on
behalf of the Trust to enforce the Trust's rights under the Conveyance. Each
Unitholder has a statutory right, however, under Section 3816 of the Delaware
Code to bring a derivative action in the Delaware Court of Chancery on behalf of
the Trust to enforce the rights of the Trust if the Trustee has refused to bring
the action or if an effort to cause the Trustee to bring the action is not
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
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(ii) the Unitholder's status as a beneficial owner must have devolved upon it by
operation of law or pursuant to the terms of the governing instrument of the
Trust from a person or entity who was a beneficial owner at the time of the
transaction giving rise to the complaint. If a derivative action is successful,
in whole or in part, or if anything is received by the Trust as a result of a
judgment, compromise or settlement of any such action, the Delaware Chancery
Court may award the plaintiff reasonable expenses, including reasonable
attorney's fees. If any award is so received by the plaintiff, the Delaware
Chancery Court will make such award of the plaintiff's expenses payable out of
those proceeds and direct the plaintiff to remit to the Trust the remainder
thereof. If the proceeds are insufficient to reimburse the plaintiff's
reasonable expenses in bringing the derivative action, the Delaware Chancery
Court may direct that any such award of the plaintiff's expenses or a portion
thereof be paid by the Trust. The rights of the Unitholders to bring a
derivative action on behalf of the Trust provided pursuant to the Trust
Agreement and Section 3816 of the Delaware Code are substantially similar to the
derivative rights afforded stockholders under Section 327 of Chapter 8 of the
Delaware General Corporation Law and applicable Delaware case law.
In the event that any Unitholder was successful in bringing a derivative
action on behalf of the Trust to enforce rights on behalf of the Trust against
Dominion Resources or the Company, then such Unitholder could, on behalf of the
Trust, pursue such rights against Dominion Resources or the Company, as the case
may be, in the Delaware Chancery Court. The Trust Agreement does not require,
and expressly provides that it shall not be construed to require, arbitration of
a claim or dispute solely between the Trustee and the Delaware Trustee or of any
claim or dispute brought by any person or entity, including, without limitation,
any Unitholder (whether in its own right or through a derivative action in the
right of the Trust), who is not a party to the Trust Agreement.
The right of a Unitholder to bring a derivative action on behalf of the
Trust with respect to Dominion Resources' 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 13, 1998, 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 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
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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 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
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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).
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.
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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 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
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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 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
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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 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 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
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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 1997, 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 1997, the
available Section 29 tax credit is approximately
$1.526576 per Unit, based on the first estimate of
the GNP implicit price deflator published by the
Bureau of Economic Analysis.
The availability of Section 29 tax credits is
dependent upon meeting a number of requirements,
many of which are factual in nature. The Company
and Dominion Resources represented 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)).
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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 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
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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 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
1997 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 1997 to materially differ from the Trustee's
estimates contained in the 1997 Tax Information
booklet, the Trustee will promptly mail final tax
credit information to each affected Unitholder.
16
<PAGE> 20
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.
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 and 1996 composite income tax
returns with the DOR on behalf of all Nonresident Unitholders (defined below),
and intends to file a composite return for 1997 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 1997. Accordingly, no Alabama state income tax is
due under the 1997 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 1997 (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
17
<PAGE> 21
attributable to the Royalty Interests. In light of the foregoing, each
Unitholder should consult his tax adviser regarding the requirements for filing
state income tax returns for his state of residence and Alabama.
ALABAMA 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.
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
18
<PAGE> 22
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 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
19
<PAGE> 23
it plans to expend approximately $55,000 during 1998 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 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.
20
<PAGE> 24
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, 1997, 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, 1997, the gross and net producing wells and acreage for the Company
Interests. The net wells and 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."
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<PAGE> 25
Curtailments. The Company has advised the Trust that, during 1997,
production from the Underlying Properties was not curtailed for any reason other
than for routine maintenance.
Federal Lands. Approximately one percent (360 acres) of the Underlying
Properties are leases on land held by the federal government. Royalty payments
due to the U.S. government for natural gas produced from federal lands included
in the Underlying Properties must be calculated in conformance with a working
interest owner's interpretation of regulations issued by the Minerals Management
Service ("MMS"). MMS regulations cover both valuation standards, which establish
the basis for placing a value on production, and cost allowances, which define
those post-production costs that are deductible by the lessee.
The Trust is subject to certain rules of the Bureau of Land Management
under which the holding of interests in leases by persons other than citizens,
nationals and legal resident aliens of the United States ("Eligible Citizens")
are limited. As a result, non-Eligible Citizens are prohibited from owning
Units. If any Units are acquired by persons or entities not constituting
Eligible Citizens, such Unitholders may be required to sell such Units pursuant
to a procedure set forth in the Trust Agreement. See "Business -- Description of
the Trust -- Possible Divestiture of Units."
Additional Wells. Well spacing rules, which are in effect in Alabama,
generally govern the space between wells drilled to the same productive
formation and are promulgated in order to prevent waste and confiscation of
property. Pursuant to such rules, the Existing Wells are located on 40 to 80
acre spacing units. Exceptions or changes to these rules may be granted by the
applicable regulatory agency upon application of an interested party following
notice to other interested parties if, in the agency's opinion, good reasons
exist therefor after consideration of evidence presented by the applicant and
any opponents. The Company has informed the Trust that it is not aware of any
plans to change spacing regulations with respect to the Underlying Properties in
Alabama. No assurances can be made, however, that exceptions or changes will not
be made in the future.
The Company and its affiliates or unrelated third parties may acquire
interests in properties adjoining the Underlying Properties. It is possible that
wells drilled on adjoining properties would drain reserves attributable to the
Underlying Properties.
The Company has agreed for the term of the Trust not to consent to,
cooperate with, assist in or conduct infill drilling (except as required by law)
on any of the Underlying Properties in which the Company owned an interest as of
June 1, 1994. Although the Company believes that it is unlikely that any
additional wells will be drilled, if the Operating Agreement is terminated, the
Company cannot prevent one of the other owners of an interest in the Underlying
Properties from drilling additional wells on the Underlying Properties.
Additional wells, if drilled, could recover a portion 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.
22
<PAGE> 26
Pratt Recompletions. To recover behind pipe reserves, the Company Interests
Owner recompleted certain of the Existing Wells to the Pratt coal seam prior to
March 31, 1997.
Right to Take in Kind. The owner of the Royalty Interests has no right to
take production in-kind.
Pooling and Unitization. The Company Interests Owner has certain pooling
and unitization rights.
Right to Assign Company Interests. The Company Interests Owner has the
right to assign all or any part of the Company Interests, subject to the Royalty
Interests and the terms and provisions of the Conveyance. If any such assignment
is made of part, but not all, of such interests, then effective as of the date
of such assignment the assignee will be required to make a separate computation
of Gross Proceeds attributable to the assigned interests.
Sale or Assignment of Royalty Interests. In certain situations, the Trust
may sell or dispose of all or a part of the Royalty Interests, in which case the
Trust would receive the proceeds therefrom and distribute such proceeds to the
Unitholders, net of any amounts held as a reserve. See "Business -- Description
of the Trust -- Transfer of Royalty Interests" and "Business -- Description of
the Trust -- Duties and Limited Powers of the Trustee."
Books and Records. The Company Interests Owner is required to maintain
books and records sufficient to determine the amounts payable with respect to
the Royalty Interests.
Computation and Payment. The Royalty Interests entitle the Trust to receive
65 percent of the Gross Proceeds. The Royalty Interests bear their proportionate
share of property, production and related taxes (including severance taxes). The
definitions, formulas and accounting procedures and other terms governing the
computation of the Royalty Interests are set forth in the Conveyance.
The Company Interests Owner is required, pursuant to the Conveyance, to pay
to the Trust amounts received by the Company Interests Owner from the sale of
Subject Gas attributable to the Royalty Interests. Under the Conveyance, the
amounts payable by the Company Interests Owner with respect to the Royalty
Interests are computed with respect to each calendar quarter ending prior to
termination of the Trust, and such amounts are paid to the Trust not later than
the last business day before the 45th day following the end of each calendar
quarter. The amounts paid to the Trust do not include interest on any amounts
payable with respect to the Royalty Interests 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.
23
<PAGE> 27
RESERVE ESTIMATE
Reserve Estimate. The following table summarizes net proved reserves
estimated as of January 1, 1998, 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, 1998
----------------- ---------------
<S> <C>
Net Proved Natural Gas Reserves (Bcf)(a)(b):
Developed Producing....................................... 94,466
========
Estimated Future Net Revenues (in thousands)(a)(c):
1998...................................................... $ 26,188
1999...................................................... 24,073
2000...................................................... 21,402
2001...................................................... 18,959
2002...................................................... 16,824
Thereafter................................................ 119,419
--------
Total............................................. $226,865
========
Total Discounted at 10 Percent.................... $128,924
========
</TABLE>
- ---------------
(a) The estimates of reserves and future net revenues summarized in this table
are based upon an unescalated price of $2.55 per MMBtu through 2004, which
was the price being received by the Company under the Gas Purchase
Agreement as of December 31, 1997. 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 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
24
<PAGE> 28
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 1998 to 7.0 Bcf in 2002.
Tax Credits Based on Reserves. Based upon the production estimates used in
the Reserve Estimate for the January 1, 1998 through December 31, 2002 period,
and assuming constant future Section 29 tax credits at the estimated 1998 rate
of $1.0578 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 $46.9 million, having a discounted present value (assuming a 10
percent discount rate) of approximately $37.9 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 years
ended December 31, 1997, December 31, 1996 and December 31, 1995.
<TABLE>
<CAPTION>
YEAR ENDED YEAR ENDED YEAR ENDED
DECEMBER 31, 1997 DECEMBER 31, 1996 DECEMBER 31, 1995
----------------- ----------------- -----------------
<S> <C> <C> <C>
Production attributable to the Royalty
Interests (Bcf)..................... 11.3 11.9 12.4
Weighted average property, production
and related taxes (per Mcf)......... $ .13 $ .13 $ .10
Average Contract Price (per Mcf)...... $2.40 $2.40 $1.84
</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. Beginning effective April 1, 1996, the price payable for Subject Gas in
excess of the Monthly Base Quantity has equaled the Index
25
<PAGE> 29
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 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;
26
<PAGE> 30
(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 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, 1997, 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.
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
27
<PAGE> 31
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.
28
<PAGE> 32
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
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
---------------------- DISTRIBUTION
HIGH LOW PER UNIT
---- --- ------------
<S> <C> <C> <C>
1997
First Quarter............................................. $22 3/4 $20 1/2 $0.844175
Second Quarter............................................ 23 1/2 21 0.808040
Third Quarter............................................. 25 3/16 20 1/4 0.692395
Fourth Quarter............................................ 22 7/8 20 0.755724
1996
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
</TABLE>
At March 13, 1998, there were 7,850,000 Units outstanding and approximately
1,169 Unitholders of record.
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
FOR THE PERIOD
FROM MAY 31,
1994 (DATE OF
YEAR ENDED DECEMBER 31, INCEPTION) TO
------------------------------------------- DECEMBER 31,
1997 1996 1995 1994
----------- ------------ ------------ --------------
<S> <C> <C> <C> <C>
Royalty Income.................... $24,977,563 $ 26,013,428 $ 21,603,550 $ 7,596,511
Distributable Income.............. $24,338,026 $ 25,423,282 $ 20,947,426 $ 7,278,931
Distributable Income per Unit..... $ 3.10 $ 3.24 $ 2.67 $ .93
Distributions per Unit............ $ 3.10 $ 3.24 $ 2.66 $ .91
Total Assets, December 31......... $97,774,353 $109,761,403 $125,641,485 $139,641,366
Total Corpus, December 31......... $97,670,701 $109,562,077 $125,545,839 $139,471,673
</TABLE>
ITEM 7. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.
The Trust collects the proceeds attributable to the Royalty Interests and
makes quarterly cash distributions to Unitholders. The only assets of the Trust,
other than cash and cash equivalents being held for the payment of expenses and
liabilities and for distribution to Unitholders, are the Royalty Interests. The
Royalty Interests owned by the Trust burden the interest in the Underlying
Properties that is owned by the Company.
The Royalty Interests 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.
29
<PAGE> 33
Distributable income of the Trust consists of the excess of royalty income
plus interest income over the administrative expenses of the Trust. Upon receipt
by the Trust, royalty income is invested in short-term investments in accordance
with the Trust Agreement until its subsequent distribution to Unitholders.
The amount of distributable income of the Trust for any calendar year may
differ from the amount of cash available for distribution to the Unitholders in
such year due to differences in the treatment of the expenses of the Trust and
the determination of those amounts. The financial statements of the Trust are
prepared on a modified cash basis pursuant to which the expenses of the Trust
are recognized when they are paid or reserves are established for them.
Consequently, the reported distributable income of the Trust for any year is
determined by deducting from the income received by the Trust the amount of
expenses paid by the Trust during such year. The amount of cash available for
distribution to Unitholders, is determined after adjustment for changes in
reserves for unpaid liabilities in accordance with the provisions of the Trust
Agreement. (See Note 5 to the financial statements of the Trust appearing
elsewhere in this Form 10-K for additional information regarding the
determination of the amount of cash available for distribution to Unitholders.)
The year 1997 marked the third full year of operations for the Trust. The
Trust received royalty income amounting to $24,977,563 during the year ended
December 31, 1997 compared to $26,013,428 for 1996 and $21,603,550 for 1995. 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, 1997 remained relatively stable at $713,380 compared
to $656,019 for 1996 and $713,898 for 1995. Distributable income for the year
ended December 31, 1997 was $24,338,026 or $3.10 per Unit compared to
$25,423,282 or $3.24 per Unit for 1996 and $20,947,426 or $2.67 per Unit for
1995.
Royalty income to the Trust is attributable to the sale of depleting
assets. All of the Underlying Properties burdened by the Royalty Interests
consist of producing properties. Accordingly, the proved reserves attributable
to the Company's interest in the Underlying Properties are expected to decline
substantially during the term of the Trust and a portion of each cash
distribution made by the Trust will, therefore, be analogous to a return of
capital. Accordingly, cash yields attributable to the Units are expected to
decline over the term of the Trust.
Royalty Income received by the Trust in a given calendar year will
generally reflect the proceeds from the sale of gas produced from the Underlying
Properties during the first three quarters of that year and the fourth quarter
of the preceding calendar year due to the timing of the receipt of these
revenues. Accordingly, the royalty income included in distributable income for
the years ended December 31, 1997, 1996 and 1995, was based on production
volumes and natural gas prices for the periods from October 1, 1996 to September
30, 1997, October 1, 1995 through September 30, 1996, and October 1, 1994 to
September 30, 1995, respectively.
The following table sets forth the production volumes attributable to the
Trust's Royalty Interests and the average sales Price and Index Price for such
production for the periods indicated.
<TABLE>
<CAPTION>
FOR 12 MONTHS ENDED
SEPTEMBER 30,
--------------------------
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
Production (Bcf)(1)..................................... 11.515 12.031 12.622
Production (MMBtu)(2)................................... 11.404 11.907 12.488
Average Contract Price Received ($/MMBtu)............... $2.32 $2.31 $1.83
Average Index Price ($/MMBtu)........................... $2.48 $2.18 $1.52
</TABLE>
- ---------------
(1) Billion cubic feet of natural gas.
(2) Trillion British Thermal Units.
Year 2000 Issue
Many existing computer programs use only two digits to identify a year in
the date field. These programs were designed and developed without considering
the impact of the upcoming change in the century. If not
30
<PAGE> 34
corrected, many computer applications could fail or create erroneous results by
or at the Year 2000. The Year 2000 issue affects virtually all companies and
organizations. If a company or organization does not successfully address its
Year 2000 issues, it may face material adverse consequences.
The Trust is reliant on the performance of Dominion Resources and third
party vendors for the receipt of Royalty income, payment of expenses and
disbursement of distributable income. The Trustee can provide no assurance as to
whether Dominion Resources and third party vendors will successfully address the
Year 2000 issue. Failing to successfully address the Year 2000 issue by Dominion
Resources and third party vendors could have a material adverse impact on the
Trust and its Unit holders. The Trust is making every effort that the systems
under its direct control are being addressed and will be ready for year 2000.
The information in this Form 10-K concerning production and prices relating
to the Royalty Interests is based on information prepared and furnished by the
Company to the Trustee. The Trustee has no control over and no responsibility
relating to the operation of or accounting for the Underlying Properties.
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 has equaled 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, 1997, 1996 and 1995, by independent petroleum
engineers. The reserve quantities of 94.466 Bcf for 1997 compared to 82.388 Bcf
for 1996 and 74.841 Bcf for 1995 and 63.148 Bcf for 1994 reflect an upward
revision of reserves of 23.4 Bcf as a result of stronger production and advanced
Pratt recompletions. See "Financial Statements and Supplementary Data -- Notes
to Financial Statements -- Note 8".
31
<PAGE> 35
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
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, 1997 and 1996, and the related statements of distributable income
and changes in trust corpus for each of the three years in the period ended
December 31, 1997. 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, 1997 and 1996, and the
distributable income and changes in trust corpus for each of the three years in
the period ended December 31, 1997, on the basis of accounting described in Note
2.
DELOITTE & TOUCHE LLP
Dallas, Texas
March 4, 1998
32
<PAGE> 36
DOMINION RESOURCES BLACK WARRIOR TRUST
FINANCIAL STATEMENTS
STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1997 1996
----------- ------------
<S> <C> <C>
ASSETS
Cash and cash equivalents................................... $ 54,431 $ 149,707
Royalty interests in gas properties (less accumulated
amortization of $58,097,578 and $46,205,805,
respectively)............................................. 97,719,922 109,611,696
----------- ------------
Total Assets...................................... $97,774,353 $109,761,403
=========== ============
LIABILITIES AND TRUST CORPUS
Trust expenses payable...................................... $ 103,652 $ 199,326
Trust corpus (7,850,000 units of beneficial interest
authorized, issued and outstanding)....................... 97,670,701 109,562,077
----------- ------------
Total Liabilities and Trust Corpus................ $97,774,353 $109,761,403
=========== ============
</TABLE>
STATEMENTS OF DISTRIBUTABLE INCOME
<TABLE>
<CAPTION>
FOR YEAR ENDED
-----------------------------------------------------------
DECEMBER 31, 1997 DECEMBER 31, 1996 DECEMBER 31, 1995
----------------- ----------------- -----------------
<S> <C> <C> <C>
Royalty income............................ $24,977,563 $26,013,428 $21,603,550
Interest income........................... 73,843 65,873 57,774
----------- ----------- -----------
25,051,406 26,079,301 21,661,324
General and administrative expenses....... 713,380 656,019 713,898
----------- ----------- -----------
Distributable income...................... $24,338,026 $25,423,282 $20,947,426
=========== =========== ===========
Distributable income per unit (7,850,000
units).................................. 3.10 $ 3.24 $ 2.67
=========== =========== ===========
Distributions per unit.................... $ 3.10 $ 3.24 $ 2.66
=========== =========== ===========
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
FOR YEAR ENDED
-----------------------------------------------------------
DECEMBER 31, 1997 DECEMBER 31, 1996 DECEMBER 31, 1995
----------------- ----------------- -----------------
<S> <C> <C> <C>
Trust corpus, beginning of period......... $109,562,077 $125,545,839 $139,471,673
Sale of 946,000 units by Dominion
Resources, Inc.......................... -- -- 6,993,213
Amortization of royalty interests......... (11,891,773) (16,005,268) (21,015,965)
Distributable income...................... 24,338,026 25,423,282 20,947,426
Distributions to Unitholders.............. (24,337,629) (25,401,776) (20,850,508)
------------ ------------ ------------
Trust corpus, end of period..... $ 97,670,701 $109,562,077 $125,545,839
============ ============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
33
<PAGE> 37
NOTES TO FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
1. TRUST ORGANIZATION AND PROVISIONS
Dominion Resources Black Warrior Trust (the "Trust") was formed as a
Delaware business trust pursuant to the terms of the Trust Agreement of Dominion
Resources Black Warrior Trust (as amended, the "Trust Agreement"), entered into
effective as of May 31, 1994, among Dominion Black Warrior Basin, Inc., an
Alabama corporation (the "Company"), as trustor, Dominion Resources, Inc., a
Virginia corporation ("Dominion Resources"), and 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.
34
<PAGE> 38
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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.
Impairment
Trust management routinely reviews its royalty interests in oil and gas
properties for impairment whenever events or circumstances indicate that the
carrying amount of an asset may not be recoverable. If an impairment event
occurs and it is determined that the carrying value of the Trust's royalty
interests may not be recoverable, an impairment will be recognized as measured
by the amount by which the carrying amount of the royalty interests exceeds the
fair value of these assets, which would likely be measured by discounting
projected cash flows. Should the aggregate dollar amount of the Trust's reserves
and Section 29 credits decline, an additional impairment provision, which could
be material, will be required. There can be no assurance such a writedown will
not occur.
New Accounting Standards
The Trust has adopted the new computation and disclosure requirements of
Statement of Financial Accounting Standards ("SFAS") No. 128 -- "Earnings Per
Share." Basic earnings per share is computed by dividing net income by the
weighted average shares outstanding. Earnings per share assuming dilution is
35
<PAGE> 39
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
computed by dividing net income by the weighted average number of shares and
equivalent shares outstanding. The Trust had no equivalent shares outstanding
for any period presented and accordingly, the adoption of SFAS No. 128 had no
impact on previously reported distributable income per unit. Also, basic and
assuming dilution distributable income per Unit are the same.
3. FEDERAL INCOME TAXES
The Trust is a grantor trust for Federal income tax purposes. As a grantor
trust, the Trust will not be required to pay Federal or state income taxes.
Accordingly, no provision for income taxes has been made in these financial
statements.
Because the Trust will be treated as a grantor trust, and because a
Unitholder will be treated as directly owning an interest in the Royalty
Interests, each Unitholder will be taxed directly on his per Unit 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 1997 this fee was $327,561 and will increase
annually by three percent. Aggregate fees paid by the Trust to Dominion
Resources in 1997, 1996 and 1995 were $327,561, $318,270 and $331,844,
respectively.
Aggregate fees and expense reimbursements paid by the Trust to the trustees
in 1997, 1996 and 1995 were $32,756, $36,853 and $30,900, 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
36
<PAGE> 40
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
end of such calendar quarter unless such day is not a business day in which case
the record date is the next business day thereafter. The Trustee will distribute
the Quarterly Distribution Amount for each quarter on or prior to 70 days after
the end of such calendar quarter to each person who was a Unitholder of record
on the record date for such calendar quarter.
The Royalty Interests may be sold under certain 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, 1997, the Trust declared and paid the following
distribution:
<TABLE>
<CAPTION>
QUARTERLY DISTRIBUTION
RECORD DATE PAYMENT DATE PER UNIT
- ------------- -------------- ------------
<S> <C> <C>
March 2, 1998 March 11, 1998 $.874820
</TABLE>
The trustee has estimated the Section 29 tax credit associated with the
March 11, 1998 quarterly distribution to be $.35 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, 1997 and 1996 (in thousands, except per Unit amounts):
<TABLE>
<CAPTION>
ROYALTY DISTRIBUTABLE DISTRIBUTABLE
CALENDAR QUARTER INCOME INCOME INCOME PER UNIT
---------------- ------- ------------- ---------------
<S> <C> <C> <C>
1997
First........................................ $ 6,797 $ 6,616 $ .84
Second....................................... 6,537 6,313 .80
Third........................................ 5,597 5,469 .70
Fourth....................................... 6,047 5,940 .76
------- ------- -----
$24,978 $24,338 $3.10
======= ======= =====
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
======= ======= =====
</TABLE>
37
<PAGE> 41
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Selected 1997 fourth quarter data are as follows (in thousands, except per
Unit amounts):
<TABLE>
<S> <C>
Royalty income.............................................. $6,047
Interest income............................................. 17
General and administrative expenses......................... (124)
------
Distributable income........................................ $5,940
======
Distributable income per Unit............................... $ .76
======
Distributions per Unit...................................... $ .76
======
</TABLE>
Due to significant upward revision in estimate of reserve quantities (see
Note 8) estimated amortization of royalty interests was adjusted downward by
approximately $3.4 million and $4 million during the fourth quarters of 1997 and
1996 respectively. 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, 1997, 1996 and 1995 and January 1, 1995 by
independent petroleum engineers.
In accordance with Statement of Financial Accounting Standards No. 69,
estimates of proved reserves and future net cash flows from proved reserves have
been prepared using contractually guaranteed prices and end-of-period natural
gas prices, and related costs. The standardized measure of future net cash flows
from the gas reserves is calculated based on discounting such future net cash
flows at an annual rate of 10 percent. The prices for December 31, 1997, 1996
and 1995 and January 1, 1995 were $2.55, $2.81, $2.26 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 January 1, 1995................ 63,148
Revisions of previous estimates........................... 24,130
Production................................................ (12,437)
-------
Proved developed reserves at December 31, 1995.............. 74,841
Revisions of previous estimates........................... 19,484
Production................................................ (11,937)
-------
Proved developed reserves at December 31, 1996.............. 82,388
Revisions of previous estimates........................... 23,380
Production................................................ (11,302)
-------
Proved developed reserves at December 31, 1997.............. 94,466
=======
</TABLE>
All proved reserve estimates presented above at December 31, 1997, 1996 and
1995 and January 1, 1995 are proved developed.
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
38
<PAGE> 42
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
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, 1997, 1996
and 1995 relating to the Trust's Royalty Interests (thousands of dollars):
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Future cash inflows................................ $241,346 $231,734 $169,501
Future taxes....................................... (14,481) (13,904) (10,170)
-------- -------- --------
Future net cash flows.............................. 226,865 217,830 159,331
10% annual discount for estimated timing of cash
flow............................................. (97,941) (83,155) (58,945)
-------- -------- --------
Standardized measure of discounted future net cash
flows............................................ $128,924 $134,675 $100,386
======== ======== ========
</TABLE>
Future cash flows do not include Section 29 tax credits which in the
aggregate are estimated to be approximately $46,871,000 having a discounted
present value (assuming a 10% discounted rate) of approximately $37,975,000 at
December 31, 1997.
The following table sets forth the changes in the present value of
estimated future net cash flows from proved developed reserves during the period
ended December 31, 1997, 1996 and 1995 (thousands of dollars):
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Balance at beginning of period..................... $134,675 $100,386 $ 78,307
Increase (decrease) due to:
Royalty income, net of taxes..................... (25,096) (27,091) (21,714)
Changes in prices................................ (21,421) 17,516 18,974
Changes in estimated volumes..................... 27,298 33,826 16,988
Accretion of discount............................ 13,468 10,038 7,831
-------- -------- --------
Balance at December 31............................. $128,924 $134,675 $100,386
======== ======== ========
</TABLE>
As of March 20, 1998, published natural gas prices were approximately $2.30
per MMBtu as compared to prices 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 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 has
39
<PAGE> 43
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
equaled the Index Price plus $.02. Assuming the Gas Purchase Agreement is
extended, after December 31, 2001, Sonat Marketing, 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
right to solicit competitive offers from other purchasers and may terminate the
Gas Purchase Agreement if Sonat Marketing does not match any 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 1997,
1996 and 1995, Sonat Marketing purchased all the gas production attributable to
the Royalty Interests.
40
<PAGE> 44
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.
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
1997, the Trustee and the Delaware Trustee received total compensation of
$32,756 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.
41
<PAGE> 45
Security Ownership of Management. The Trust has no directors or executive
officers. As of March 26, 1998, 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 $327,561 and will increase annually by three percent.
A copy of the Administrative Services Agreement is filed as an exhibit to
this Form 10-K. The foregoing summary of the material provisions of the
Administrative Services Agreement does not purport to be complete and is subject
to, and is qualified in its entirety by reference to, all the provisions of the
Administrative Services Agreement.
DOMINION RESOURCES' CONDITIONAL RIGHT OF REPURCHASE
Dominion Resources retains in the Trust Agreement the right to repurchase
all (but not less than all) outstanding Units at any time at which 15 percent or
less of the outstanding Units is owned by persons or entities other than
Dominion Resources and its affiliates. Any such repurchase would generally be at
a price equal to the greater of (i) the highest price at which Dominion
Resources or any of its affiliates acquired Units during the 90 days immediately
preceding the Determination Date and (ii) the average closing price of Units on
the NYSE for the 30 trading days immediately preceding the Determination Date.
Any such repurchase would be conducted in accordance with applicable Federal and
state securities laws. See "Business -- Description of the Trust -- Conditional
Right of Repurchase."
POTENTIAL CONFLICTS OF INTEREST
The interests of Dominion Resources and its affiliates and the interests of
the Trust and the Unitholders with respect to the Underlying Properties could at
times be different. The following is a summary of certain conflicts of interest:
Obligations of Company Interests Owner may exceed its share of
distributions and tax credits. As a working interest owner in the Underlying
Properties, the Company Interests Owner is responsible for an average of
approximately 98 percent of the operating costs of the Existing Wells but only
entitled to approximately 28 percent of the revenues therefrom, after giving
effect to the Royalty Interests. Based on the Reserve Estimate, beginning in the
year 2000, the projected operating costs to be borne by the Company Interests
Owner 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.
42
<PAGE> 46
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.
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 (included in Item 8. of this report)
Independent Auditors' Report
Statements of Assets, Liabilities and Trust Corpus as of December 31,
1997 and 1996
Statements of Distributable Income for the years ended December 31, 1997,
1996 and 1995
Statements of Changes in Trust Corpus for the years ended December 31,
1997, 1996 and 1995
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).
</TABLE>
43
<PAGE> 47
<TABLE>
<CAPTION>
EXHIBIT
NUMBER EXHIBIT
------- -------
<C> <S>
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, 1994 and incorporated herein by
reference).
10.4 -- Gas Purchase Agreement, dated as of May 3, 1994, between
Sonat Marketing and the Company (filed as Exhibit 10.2 to
Dominion Resources, Inc.'s Registration Statement* on
Form S-3 (No. 33-53513), and incorporated herein by
reference).
10.5 -- Amendment to Gas Purchase Agreement dated May 16, 1996,
between Sonat Marketing and the Company (filed as Exhibit
10.1 to the Registrant's Form 10-Q for the quarter ended
June 30,1996 and incorporated herein by reference).
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 4, 1998, on the
estimated reserves, estimated future net revenues and the
discounted estimated future net revenues attributable to
the Royalty Interests as of January 1, 1998, 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.
44
<PAGE> 48
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
By: /s/ RON E. HOOPER
----------------------------------
Ron E. Hooper
Vice President and Administrator
Date: March 20, 1998
(THE REGISTRANT HAS NO DIRECTORS OR EXECUTIVE OFFICERS.)
45
<PAGE> 49
INDEX TO 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, 1994 and incorporated herein by
reference).
10.4 -- Gas Purchase Agreement, dated as of May 3, 1994, between
Sonat Marketing and the Company (filed as Exhibit 10.2 to
Dominion Resources, Inc.'s Registration Statement* on
Form S-3 (No. 33-53513), and incorporated herein by
reference).
10.5 -- Amendment to Gas Purchase Agreement dated May 16, 1996,
between Sonat Marketing and the Company (filed as Exhibit
10.1 to the Registrant's Form 10-Q for the quarter ended
June 30,1996 and incorporated herein by reference).
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 4, 1998, on the
estimated reserves, estimated future net revenues and the
discounted estimated future net revenues attributable to
the Royalty Interests as of January 1, 1998, 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
<PAGE> 1
[RYDER SCOTT COMPANY PETROLEUM ENGINEERS LETTERHEAD]
March 27, 1998
Dominion Resources Black Warrior Trust
NationsBank of Texas, N.A.
NationsBank Plaza - 17th Floor
901 Main Street
Dallas, Texas 75202
Gentlemen:
We hereby consent to the inclusion of our report dated March 4, 1998,
concerning the reserves and revenue, as of January 1, 1998, of certain royalty
interests owned by Dominion Resources Black Warrior Trust in the Form 10-K for
the year ended December 31, 1997, of the Dominion Resources Black Warrior Trust
to be filed with the Security and Exchange Commission.
Very truly yours,
/s/ RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
/ag
<TABLE> <S> <C>
<ARTICLE> 5
<RESTATED>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<CASH> 54,431
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 54,431
<PP&E> 155,817,500
<DEPRECIATION> 58,097,578
<TOTAL-ASSETS> 97,774,353
<CURRENT-LIABILITIES> 103,652
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 97,670,701
<TOTAL-LIABILITY-AND-EQUITY> 97,774,353
<SALES> 24,977,563
<TOTAL-REVENUES> 25,051,406
<CGS> 0
<TOTAL-COSTS> 713,380
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 24,338,026
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 24,338,026
<EPS-PRIMARY> 3.10
<EPS-DILUTED> 3.10
</TABLE>
<PAGE> 1
RYDER SCOTT COMPANY LOGO FAX (713) 651-0849
1100 LOUISIANA SUITE 3800 HOUSTON, TEXAS 77002-5218 TELEPHONE (713) 651-9191
March 4, 1998
Dominion Black Warrior Basin, Inc.
Riverfront Plaza - West Tower
901 E. Byrd Street
Richmond, Virginia 23219-4072
Gentlemen:
At your request, we have prepared an estimate of the reserves,future
production, and income attributable to certain royalty interests of Dominion
Resources Royalty Trust 1994-1 (Dominion) as of January 1, 1998. The subject
properties are located in the Black Warrior Basin, Tuscaloosa County, Alabama.
Two cases of reserve estimates based on different pricing parameters provided by
Dominion are presented herein. The income data for Case 1 were estimated using
escalated cost and price parameters. The income data for Case 2 were estimated
using unescalated cost and price parameters.
It should be noted that due to a combination of economic and political
forces, there is significant uncertainty regarding the forecasting of future
hydrocarbon prices. The recoverable reserves and the income attributable thereto
have a direct relationship to the hydrocarbon prices actually received;
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 results of this study is shown below.
CASE 1
ESCALATED PARAMETERS - YEAR END PRICING
Estimated Net Reserve and Income Data
Certain Royalty Interests of
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
As of January 1, 1998
_______________________________________________
<TABLE>
<CAPTION>
Total
Proved
------------
<S> <C>
NET REMAINING RESERVES
Gas - MMCF . . . . . . . . . . . 94,466
INCOME DATA
Future Gross Revenue . . . . . . $289,488,904
------------
Tax Credits . . . . . . . . . . 48,421,978
Future Net Income (FNI). . . . . $337,910,882
Discounted FNI @ 5% . . . . . . . $240,517,451
</TABLE>
<PAGE> 2
DOMINION BLACK WARRIOR BASIN, INC.
March 4, 1998
Page 2
CASE 2
UNESCALATED PARAMETERS - YEAR END PRICING
Estimated Net Reserve and Income Data
Certain Royalty Interests of
Dominion Resources Royalty Trust 1994-1
65% Overriding Royalty Interest
As of January 1, 1998
_______________________________________________
<TABLE>
<CAPTION>
Total
Proved
------------
<S> <C>
NET REMAINING RESERVES
Gas - MMCF . . . . . . . . . . . 94,466
INCOME DATA
Future Gross Revenue . . . . . $226,865,481
Tax Credits . . . . . .. . . . . 46,871,921
------------
Future Net Income (FNI). . . . . $273,737,402
Discounted FNI @ 5% . . . . . . . $207,130,059
</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.
All of the reserves included herein are comprised of the proved producing
category. The various producing status categories are defined under the tab
"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
your request, the coalbed methane gas reserves presented herein are based on
economic parameters which include your estimates of the future Section 29 Tax
Credit. Your estimates of the future tax credits are presented in detail under
the tab "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 the Section 29 Tax Credit
(presented as "Other Income"). The future net income is before the deduction of
state and federal income taxes and general administrative 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 was 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 was calculated using a discount
rate of 5 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.
<PAGE> 3
DOMINION BLACK WARRIOR BASIN, INC.
MARCH 4, 1998
PAGE 3
<TABLE>
<CAPTION>
Year End Pricing
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
Discounted Future Net Income
As of January 1, 1998
Total Proved
------------------------------------------
<S> <C> <C>
Discount Rate Escalated Unescalated
Percent Case Case
- ------------- ---------- -----------
10 $186,294,886 $166,698,116
15 $152,240,898 $139,659,721
20 $128,906,681 $120,274,988
25 $111,881,285 $105,657,730
</TABLE>
The results shown above are presented for your information and should not be
construed as our estimate of fair market value.
RESERVES INCLUDED IN THIS REPORT
Escalated Parameters
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, except that they
are based on cost and price parameters which allow for future changes in
current economic conditions as discussed in other sections of this report;
whereas, the definition approved by the Securities and Exchange Commission
assumes no change in current economic conditions will occur in the future.
It should be noted that the estimated quantities of reserves presented in
this report, which were based on escalated cost and price parameters, differ
from the quantities of reserves which were estimated using constant cost and
price parameters.
Unescalated Parameters
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.
Our definition of proved reserves is included under the tab "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.
<PAGE> 4
DOMINION BLACK WARRIOR BASIN, INC.
March 4, 1998
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 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.
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 were 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 marketing conditions 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
Escalated Parameters
The future hydrocarbon price parameters used in the escalated pricing
scenario reflect Dominion's current estimates. Estimates of future price
parameters have been revised in the past because of changes in governmental
policies, changes in hydrocarbon supply and demand, and variations in general
economic conditions. There is a possibility that the price parameters used in
this report may be revised in the future for similar reasons.
Unescalated Parameters
Dominion furnished us with gas prices in effect at January 1, 1998
and these prices were held constant to depletion of the reserves in the
unescalated pricing scenario.
Dominion's estimates of future price parameters for gas are presented
in detail under the tab "Reserve Definitions and Pricing Assumptions" in this
report.
COSTS
The income attributable to Dominion Resources Royalty Trust 1994-1 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.
<PAGE> 5
DOMINION BLACK WARRIOR BASIN, INC.
March 4, 1998
Page 5
Escalated Parameters
The escalated case utilized the same operating and cost
parameters as the unescalated except they are escalated according to a scenario
provided by Dominion. Future cost parameters are presented in detail under the
tab "Reserve Definitions and Pricing Assumptions" in this report.
Unescalated Parameters
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 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
Table A presents a one line summary of gross and net reserves
and income data for each of the subject properties. The grand summaries of our
estimated projection of production and income by years beginning January 1, 1998
are presented under the tab "Grant Summary Projections".
The estimates of reserves presented herein are based upon a
detailed study of the properties in which Dominion 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 November 1997.
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.
<PAGE> 6
DOMINION BLACK WARRIOR BASIN, INC.
March 4, 1998
Page 6
This report was prepared for the exclusive use of Dominion Black Warrior
Basin, Inc. 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/ C. PATRICK McINTURFF, P.E.
------------------------------
C. Patrick McInturff, P.E.
Petroleum Engineer
CPM/sw
Approved:
/s/ JOHN R. WARNER
- -------------------------
John R. Warner
Senior Vice President
