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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, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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COMMISSION FILE NUMBER: 001-11335
DOMINION RESOURCES BLACK WARRIOR TRUST
(Exact name of registrant as specified in its charter)
Delaware 75-6461716
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification number)
Trust Division
Royalty Trust Group
Bank of America, N.A.
901 Main Street
17th Floor
Dallas, Texas 75202
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:
(214) 209-2400
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
------------------- ----------------
Units of Beneficial Interest New York Stock Exchange, Inc.
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
Indicate by check mark 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 10, 2000, 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 $95,181,250.
DOCUMENTS INCORPORATED BY REFERENCE
None.
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TABLE OF CONTENTS
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PAGE
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<S> <C> <C>
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............................................................................................9
Distributions and Income Computations.................................................................9
Conditional Right of Repurchase......................................................................10
Possible Divestiture of Units........................................................................11
Periodic Reports.....................................................................................11
Voting Rights of Unitholders.........................................................................12
Liability of Unitholders.............................................................................12
Transfer Agent.......................................................................................13
FEDERAL INCOME TAX CONSIDERATIONS..............................................................................13
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..........................................................................................19
Regulation of Natural Gas............................................................................19
Environmental Regulation.............................................................................19
Competition, Markets and Prices......................................................................20
Item 2. Properties....................................................................................................21
THE ROYALTY INTERESTS..........................................................................................21
The Underlying Properties............................................................................21
The Royalty Interests................................................................................23
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 .................................................................................................................28
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.........................................28
Item 6. Selected Financial Data.......................................................................................29
Item 7. Trustee's Discussion and Analysis of Financial Condition and Results of Operations............................29
Year 2000............................................................................................31
Item 7A. Quantitative and Qualitative Disclosures About Market Risk....................................................32
Item 8. Financial Statements and Supplementary Data...................................................................33
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..........................42
</TABLE>
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PART III .................................................................................................................42
Item 10. Directors and Executive Officers of the Registrant...........................................................42
Item 11. Executive Compensation.......................................................................................42
Item 12. Security Ownership of Certain Beneficial Owners and Management...............................................42
Item 13. Certain Relationships and Related Transactions...............................................................43
Administrative Services Agreement ...................................................................43
Dominion Resources' Conditional Right of Repurchase..................................................43
Potential Conflicts of Interest......................................................................43
PART IV .................................................................................................................44
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K..............................................44
Financial Statements................................................................................44
Financial Statement Schedules.......................................................................44
Exhibits............................................................................................44
Reports on Form 8-K.................................................................................45
</TABLE>
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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.
From June 1, 1994 through April 1, 1996, the Contract Price for each month
equaled (a) for quantities of Gas equal to or less than the Monthly Base
Quantity, the sum of the Index Price and the Premium, provided that such price
would in no event be below the Minimum Price or above the Maximum Price, and (b)
for quantities of Gas in excess of the Monthly Base Quantity, the Index Price.
From April 1, 1996 to December 31, 1998, the Contract Price for each month
equaled (a) for quantities of Gas equal to or less than the Monthly Base
Quantity, the sum of the Index Price and the Premium, provided that such price
would not be below the Minimum Price or above the Maximum Price, and (b) for
quantities of Gas in excess of the Monthly Base Quantity, the sum of the Index
Price and $.02 per MMBtu. From January 1, 1999 through December 31, 1999, the
Contract Price for each month equaled (a) for quantities of Gas equal to or less
than the Monthly Base Quantity, the Monthly Base Contract Price, provided that
such price will in no event be below the Minimum Price or above the Maximum
Price, (b) for quantities of Gas in excess of the Monthly Base Quantity but
equal to or less than the Monthly Fixed Price Quantity, the sum of the Index
Price and $.02 per MMBtu, provided that such price will not be below $2.12 per
MMBtu or above $3.02 per MMBtu, and (c) for quantities of Gas in excess of the
Monthly Fixed Price Quantity, the sum of the Index Price and $.02 per MMBtu.
Pursuant to an amendment effective January 1, 2000 through December 31, 2000,
the Monthly Base Quantity shall be divided into two categories, a Fixed Price
Quantity and an Index Price Quantity. The price for each Fixed Price Quantity
shall be $2.45 per MMBtu. The price for each Index Price Quantity shall be the
sum of the Index Price and the Premium, provided that such price would in no
event be less than the Minimum Price nor more than the Maximum price. During the
period from January 1, 2000 through December 31, 2000, the Contract Price for
quantities of Gas in excess of the Monthly Fixed Price Quantity shall equal the
sum of the Index Price and $.02 per MMBtu.
"Conveyance" means the Overriding Royalty Conveyance dated effective as
of June 1, 1994, from the Company to the Trust, as amended by instrument dated
as of November 20, 1994, copies of which are filed as exhibits to this Form
10-K.
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"Delaware Trustee" means Mellon Bank (DE) National Association.
"Dominion Resources" means Dominion Resources, Inc., a Virginia
corporation.
"Existing Wells" means the wells producing on the Underlying Properties
as of June 1, 1994.
"Fixed Price Quantity" means the volume of natural gas designated as such
in the Gas Purchase Agreement.
"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 instruments
effective as of April 1, 1996, January 1, 1999 and January 1, 2000.
"Gross Proceeds" means the aggregate amounts received by the Company
Interests Owner attributable to the Company Interests from the sale of Subject
Gas at the central delivery points in the gathering system for the Underlying
Properties.
"Gross Wells" means the total whole number of gas wells without regard to
ownership interest.
"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.
"Index Price Quantity" means the volume of natural gas designated as such
in the Gas Purchase Agreement.
"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, for the periods from June 1, 1994 through December
31, 1998, January 1, 1999 through December 31, 1999 and January 1, 2000 through
December 31, 2000, $2.63 per MMBtu, $3.07 per MMBtu and $2.82 per MMBtu,
respectively.
"Minimum Price" means, for the periods from June 1, 1994 through December
31, 1998, January 1, 1999 through December 31, 1999 and January 1, 2000 through
December 31, 2000, $1.85 per MMBtu, $2.16 per MMBtu and $2.20 per MMBtu,
respectively.
"MMcf" means million cubic feet of natural gas. As used herein, 1 MMcf is
assumed to have a Btu content of 990 MMBtu.
"MMBtu" means million Btu. As used herein, 990 MMBtu is deemed to be the
Btu content of 1 MMcf.
"Monthly Base Quantity" means the volumes of natural gas designated as
such in the Gas Purchase Agreement.
"Monthly Fixed Price Quantity" means the volumes of natural gas
designated as such from time to time in the Gas Purchase Agreement.
"Net revenue interest" means working interest or mineral interest less
any applicable royalties, overriding royalties or similar burdens on production
prior to the Royalty Interests.
"Net wells" and "net acres" are calculated by multiplying gross wells or
gross acres by the ownership interest in such wells or acres.
"Premium" means the premium per MMbtu on a wet basis pursuant to the Gas
Purchase Agreement from June 1, 1994 through December 31, 2001 as follows:
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INDEX PRICE PREMIUM
($/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, 2000, prepared by Ryder
Scott.
"River Gas" means The River Gas Corporation, an Alabama corporation.
"Royalty Interests" means the overriding royalty interests conveyed to
the Trust pursuant to the Conveyance entitling the holder thereof to 65 percent
of the Gross Proceeds derived from the Company Interests.
"Ryder Scott" means Ryder Scott Company Petroleum Engineers, independent
petroleum engineers.
"Section 29 tax credit" means the tax credits for federal income tax
purposes pursuant to Section 29 of the Code to an owner of coal seam gas
production, which tax credits are generated upon the sale of such production.
"Sonat" means Sonat, Inc., a Delaware corporation.
"Sonat Marketing" means Sonat Marketing Company, a Delaware Corporation.
"Subject Gas" means Gas attributable to the Company Interests.
"Trust" means Dominion Resources Black Warrior Trust, a Delaware business
trust formed pursuant to the Trust Agreement.
"Trust Agreement" means the Trust Agreement dated as of May 31, 1994,
among the Company, as grantor, Dominion Resources, the Delaware Trustee and the
Trustee, as amended by instrument dated as of June 27, 1994, copies of which are
filed as exhibits to this Form 10-K.
"Trustee" means Bank of America, N.A., as successor to NationsBank of
Texas, N.A.
"Working interest" generally refers to the lessee's interest in an oil,
gas or mineral lease which entitles the owner to receive a specified percentage
of oil and gas production, but requires the owner of such working interest to
bear such specified percentage of the costs to explore for, develop, produce and
market such oil and gas.
"Underlying Properties" means the natural gas properties in which the
Company has an interest located in the Black Warrior Basin, Tuscaloosa County,
Alabama insofar as such properties include the Pottsville Formation.
"Units" means the 7,850,000 units of beneficial interest issued by, and
evidencing the entire beneficial interest in, the Trust.
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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 has any control over or any responsibility relating to the
operation of the Underlying Properties. The Company does not have any
contractual commitment to the Trust to develop further the Underlying Properties
or to maintain its ownership interest in any of the Underlying Properties. The
Company may sell the Company Interests subject to and burdened by the Royalty
Interests and, absent certain conditions having been met, with the continuing
benefit of Dominion Resources' assurances and the Gas Purchase Agreement. For a
description of the Underlying Properties, the Royalty Interests and other
information relating to such properties, see "Properties--The Royalty
Interests."
The Trust Agreement authorizes the Trustee to take such action as in its
judgment is necessary, desirable or advisable to best achieve the purposes of
the Trust. The Trustee is empowered by the Trust Agreement to employ consultants
and agents (including the Company, Dominion Energy and Dominion Resources) and
to make payments of all fees for services or expenses out of the assets of the
Trust. The Trustee is authorized to agree to modifications of the terms of the
Conveyance and to settle disputes with respect thereto, so long as such
modifications or settlements do not result in 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 sales or dispositions upon termination is required even though they
may constitute a disposition of all or substantially all the assets of the
Trust. Any sales upon termination may be made to Dominion Resources or its
affiliates. See "--Termination and Liquidation of the Trust."
LIABILITIES OF THE TRUST
Because of the passive nature of the Trust assets and the restrictions on
the activities of the Trustee, the only liabilities the Trust has incurred are
those for routine administrative expenses, such as trusteeship fees and
accounting, engineering, legal and other professional fees and the
administrative services fee paid to Dominion Resources. If a court
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were to hold that the Trust is taxable as a corporation, then the Trust would
incur substantial federal income tax liabilities. See also "--State Tax
Considerations--Alabama Franchise Tax."
LIABILITIES OF THE TRUSTEE AND THE DELAWARE TRUSTEE
Each of the Trustee and the Delaware Trustee may act in its discretion
and is personally or individually liable only for fraud or acts or omissions in
bad faith or which constitute gross negligence (and for taxes, fees and other
charges on, based on or measured by any fees, commissions or compensation
received pursuant to the Trust Agreement) and will not be otherwise liable for
any act or omission of any agent or employee unless such trustee has acted in
bad faith or with gross negligence in the selection and retention of such agent
or employee. Each of the Trustee and the Delaware Trustee (and their respective
agents) is indemnified by Dominion Resources and from the Trust assets for
certain environmental liabilities, and for any other liability, expense, claim,
damage or other loss incurred in performing its duties, unless resulting from
gross negligence, fraud or bad faith (each of the Trustee and the Delaware
Trustee is indemnified from the Trust assets against its own negligence which
does not constitute gross negligence), and will have a first lien upon the
assets of the Trust as security for such indemnification and for reimbursements
and compensation to which it is entitled; provided that the Trustee and the
Delaware Trustee are generally required to first be indemnified from Trust
assets before seeking indemnification from Dominion Resources. Dominion
Resources also has agreed to indemnify the Trustee and the Delaware Trustee
against certain securities laws' liabilities. Neither the Trustee nor the
Delaware Trustee is entitled to indemnification from Unitholders (except in
connection with lost or destroyed Unit certificates). Insofar as indemnification
for liabilities arising under the Securities Act of 1933, as amended (the
"Securities Act"), is permitted to the Trustee pursuant to the foregoing
provisions, the Trustee has been informed that in the opinion of the Securities
and Exchange Commission (the "Commission") such indemnification is against
public policy as expressed in the Securities Act and is, therefore,
unenforceable.
TERMINATION AND LIQUIDATION OF THE TRUST
The Trust will terminate upon the occurrence of: (i) an affirmative vote
of the holders of not less than 66 percent of the outstanding Units to terminate
the Trust; (ii) such time as the ratio of the cash amounts received by the Trust
attributable to the Royalty Interests in any calendar quarter to administrative
costs of the Trust for such calendar quarter is less than 1.2 to 1.0 for two
consecutive calendar quarters; or (iii) March 1 of any year if it is determined,
based on a reserve report as of December 31 of the prior year prepared by a firm
of independent petroleum engineers mutually selected by the Trustee and the
Company, that the net present value (discounted at 10 percent) of (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 (such price, net of any
commissions or other fees payable by the Trust, the "Highest Acceptable Offer").
The Company then has the right (whether or not it made an initial offer), but
not the obligation, to purchase all remaining Royalty Interests for a cash
purchase price computed as follows: (i) if the Highest Acceptable Offer is more
than 105 percent of the Company's original offer (or if the Company did not make
an initial offer), the purchase price will be 105 percent of the Highest
Acceptable Offer, or (ii) if the Highest Acceptable
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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 (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
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<PAGE> 11
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."
8
<PAGE> 12
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 10, 2000, 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 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 for federal income tax purposes 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).
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<PAGE> 13
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 or certificates
representing the number of Units specified in such notice of repurchase. On or
after the repurchase date, each holder of Units to be repurchased must present
and surrender its certificates for such Units to Dominion Resources at the place
designated in such notice and thereupon the purchase price of such Units will be
paid to or on the order of the person or entity whose name appears on such
certificate or certificates as the owner thereof. In no event may fewer than all
of the outstanding Units represented by the certificates be repurchased (except
for any Units held by Dominion Resources and any of its affiliates).
If Dominion Resources and the Trustee give a notice of repurchase and if,
on or before the date fixed for repurchase, the funds necessary for such
repurchase are set aside by Dominion Resources, separate and apart from its
other funds in trust for the pro rata benefit of the holders of the Units so
noticed for repurchase, then, notwithstanding that any certificate for such
Units has not been surrendered, at the close of business on the repurchase date
the holders of such Units shall cease to be Unitholders and shall have no
interest in or claims against Dominion Resources, the Company, the Trust, the
Delaware Trustee or the Trustee by virtue thereof and shall have no voting or
other rights with respect to such Units, except the right to receive the
purchase price payable upon such repurchase, without interest thereon and
without any other distributions for record dates after the date of notice of
repurchase, upon surrender (and endorsement, if required by Dominion Resources)
of their certificates, and the Units evidenced thereby shall no longer be held
of record in the names of such Unitholders. Subject to applicable escheat laws,
any monies so set aside by Dominion Resources and unclaimed at the end of two
years from the repurchase date shall revert to the general funds of Dominion
Resources, after which reversion the holders of such Units so noticed for
repurchase could look only to the general funds of Dominion Resources for the
payment of the purchase price. Any interest accrued on funds so deposited would
be paid to Dominion Resources from time to time as requested by Dominion
Resources.
In the event that Dominion Resources exercises and consummates its right
of repurchase, then at its option it may cause the Trust to be terminated by
providing written notice thereof to the Trustee and the Delaware Trustee. Within
30 days following written notice of Dominion Resources' decision to terminate
the Trust, the Trustee must cause any remaining Royalty Interests (and, subject
to the rights of Unitholders with respect to the receipt of distributions for
which a record date has been determined, all proceeds of production attributable
to the Royalty Interests) and any other assets of the Trust to be conveyed to
Dominion Resources or its assignee (subject to the right of such trustees to
create reasonable reserves in connection with the liquidation of the Trust).
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<PAGE> 14
POSSIBLE DIVESTITURE OF UNITS
The Trust Agreement imposes no restrictions based on nationality or
other status of Unitholders. The Trust Agreement provides, however, that in the
event of certain judicial or administrative proceedings seeking the cancellation
or forfeiture of any property in which the Trust has an interest, or asserting
the invalidity of, or otherwise challenging any portion of the Royalty Interests
because of the nationality, citizenship or any other status of any one or more
Unitholders, the Trustee will give written notice thereof to each Unitholder
whose nationality, citizenship or other status is an issue in the proceeding,
which notice will constitute a demand that such Unitholder dispose of his Units
within 30 days. If any Unitholder fails to dispose of his Units in accordance
with such notice, the Trustee will cancel all outstanding certificates issued in
the name of such Unitholder, transfer all Units held by such Unitholder to the
Trustee and sell such Units (including by private sale). The proceeds of such
sale (net of sales expenses), pending delivery of certificates representing the
Units, will be held by the Trustee in a non-interest bearing account for the
benefit of the Unitholder and paid to the Unitholder upon surrender of such
certificates. Cash distributions payable to such Unitholder will also be held in
a non-interest bearing account pending disposition by the Unitholder of the
Units or cancellation of certificates representing the Units by the Trustee,
subject to a maximum retention period of two years or such shorter period as
shall be permitted by applicable laws.
PERIODIC REPORTS
The Trustee causes a reserve report to be prepared for the Trust (by a
firm of independent petroleum engineers mutually selected by the Trustee and the
Company) each year showing estimated proved natural gas reserves and other
reserve information attributable to the Royalty Interests as of December 31 of
such year. Such reserve reports show estimated future net revenues and the net
present value (discounted at 10 percent) of the estimated future net revenues
(using the year-end Contract Price as of December 31) from proved reserves
attributable to the Royalty Interests and the amount of the estimated net
present value (discounted at 10 percent) of the remaining Section 29 tax credits
attributable to the Royalty Interests. The costs of the reserve reports are paid
by the Trust and constitute an administrative expense. The Trustee also provides
to Dominion Resources and the Company, within 15 days after the end of each
calendar quarter, a written itemized report showing all administrative costs of
the Trust paid during such quarter.
Within 75 days following the end of each of the first three calendar
quarters of each calendar year, the Trustee mails to each person or entity who
was a Unitholder of record (i) on the record date for each such calendar quarter
and (ii) on a Special Distribution Amount record date occurring during such
quarter, if any, a report which shows in reasonable detail the assets and
liabilities and receipts and disbursements of the Trust for such calendar
quarter. Within 120 days following the end of each fiscal year, the Trustee
mails to Unitholders of record as of a date to be selected by the Trustee an
annual report containing audited financial statements which includes reserve
information relating to the Trust and the Royalty Interests.
The Trustee files such returns for federal income tax purposes as it is
advised are required to comply with applicable law. The Trustee mails to each
person or entity who was a Unitholder of record (i) on the record date for each
such calendar quarter and (ii) on a Special Distribution Amount record date
occurring during such quarter, if any, a report which shows in reasonable detail
information to permit each Unitholder to make all calculations reasonably
necessary for tax purposes. The Trustee treats all income, credits and
deductions recognized during each calendar quarter during the term of the Trust
as 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.
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<PAGE> 15
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 percent of the outstanding Units, no provision of the Trust
Agreement may be amended with respect to (a) the sale or disposition of all or
any part of the Trust estate, including the Royalty Interests, except as
specifically provided in the Trust Agreement, (b) termination of the Trust and
the disposition of Trust assets upon liquidation of the Trust or (c) the
Company's right of first refusal with respect to the purchase of any remaining
Royalty Interests upon termination of the Trust. Without the written consent of
Dominion Resources and the approval of a majority of the outstanding Units, no
amendment may be made to the Trust Agreement that would alter Dominion
Resources' conditional right to repurchase all outstanding Units at any time at
which 15 percent or less of the outstanding Units is owned by persons or
entities other than Dominion Resources or its affiliates. Additionally, any
amendment that increases the obligations, duties or liabilities of or affects
the rights of the Trustee or the Delaware Trustee must be consented to by such
entity. The Trustee, the Delaware Trustee, Dominion Resources and the Company
may, without approval of the Unitholders, from time to time supplement or amend
the Trust Agreement in order to cure any ambiguity or to correct or supplement
any defective or inconsistent provisions, provided 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.
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<PAGE> 16
TRANSFER AGENT
Chase Mellon Shareholder Services serves as transfer agent and
registrar for the Units.
FEDERAL INCOME TAX CONSIDERATIONS
THE TAX CONSEQUENCES TO A UNITHOLDER OF THE OWNERSHIP AND SALE OF UNITS
WILL DEPEND IN PART ON THE UNITHOLDER'S TAX CIRCUMSTANCES. EACH UNITHOLDER
SHOULD THEREFORE CONSULT THE UNITHOLDER'S TAX ADVISOR ABOUT THE FEDERAL, STATE
AND LOCAL TAX CONSEQUENCES TO THE UNITHOLDER OF THE OWNERSHIP OF UNITS.
The sections entitled "Federal Income Tax Consequences" and "Risk
Factors--Tax Considerations" appearing in the Prospectus set forth,
respectively, a discussion of the material federal income tax matters of general
application of the acquisition, ownership and sale of the Units acquired in the
Public Offerings and a discussion of certain risk factors associated with
matters of federal income taxation as applied to the Trust and such Unitholders.
In connection with the registration of the Units for offer and sale in
the Public Offerings, Dominion Resources and the Underwriters received certain
opinions of special counsel ("Special Counsel") to Dominion Resources (upon
which the Trustee and the Delaware Trustee were entitled to rely), including,
without limitation, opinions as to the material federal income tax consequences
of the ownership and sale of the Units acquired in either of the Public
Offerings. Each of these opinions was based on provisions of the Code existing
as of June 28, 1994 with respect to the opinions given in connection with the
Initial Public Offering and as of June 8, 1995 with respect to the opinions
given in connection with the Secondary Public Offering, and existing and
proposed regulations thereunder, administrative rulings and court decisions as
of such dates, all of which are subject to changes that may or may not be
retroactively applied. Some of the applicable provisions of the Code have not
been interpreted by the courts or the 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.
<TABLE>
<S> <C>
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
</TABLE>
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<TABLE>
<S> <C>
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 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 1999, 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 1999, the
available Section 29 tax credit is approximately
$1.224738 per Unit, based on the first estimate of
the GNP implicit price deflator published by the
Bureau of Economic Analysis.
</TABLE>
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<PAGE> 18
<TABLE>
<S> <C>
The availability of Section 29 tax credits is
dependent upon meeting a number of requirements, many
of which are factual in nature. The Company and
Dominion Resources represented in connection with the
Public Offerings only that those factual requirements
were met. At the time of each of the Public
Offerings, Special Counsel opined as to those
requirements which are statutory or legal in nature.
If any of the factual requirements are not met, or
the opinion not followed, some or all of the expected
Section 29 tax credits may not be available.
Limits on Unitholder's Use of
Credits .................................. In any year, a Unitholder is permitted to reduce his
regular federal income tax liability by the Section
29 tax credits allocated to such Unitholder for such
year on a dollar-for- dollar basis, but only to the
extent such Unitholder's regular tax liability
exceeds his alternative minimum tax liability (with
certain adjustments). Any amount of Section 29 tax
credit in excess of a Unitholder's total regular
federal income tax liability for a year is
permanently lost. Section 29 tax credits cannot be
used to reduce a Unitholder's liability for any
alternative minimum tax for any taxable year but can
be carried forward to reduce his regular tax
liability in a subsequent year (subject to the
applicable rules governing such carryforward(s)).
Quarterly Allocations ........................ Under the Code, a Unitholder is entitled to Section
29 tax credits only to the extent that he is an owner
of the economic interest at the time the coal seam
gas is produced. The Trustee allocates the income
received by the Trust during a quarter, and the
Section 29 tax credit allocable to such income, to
Unitholders of record on the quarterly record date
for such quarter. Such an allocation may be
challenged by the IRS, but any challenge is likely to
have a material adverse impact only if successful and
only for Unitholders who do not own Units for a full
quarter for each record date, particularly
Unitholders who acquire Units shortly before a record
date and sell shortly after a record date. At the
time of each of the Public Offerings, Special Counsel
declined to express an opinion as to whether the IRS
would accept quarterly allocations or would require
income, credits and deductions of the Trust to be
determined and allocated daily based on ownership at
the time of production or on some other basis.
Treatment of the Royalty
Interests ................................ Each Royalty Interest is a nonoperating economic
interest in an Underlying Property because it is a
right to a fixed percentage of the gross proceeds
from the sale of gas as, if and when produced from
such properties, the right 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.
</TABLE>
15
<PAGE> 19
<TABLE>
<S> <C>
Non-Passive Activity Income,
Credits and Loss ......................... The income, credits and expenses of the Trust are not
taken into account in computing the passive activity
losses and income under Section 469 of the Code for a
Unitholder who acquires and holds Units as an
investment and did not acquire them in the ordinary
course of a trade or business. Section 29 tax credits
generated by an investment in Units, therefore, can
be utilized to offset regular tax liability on income
from any source whether active or passive, subject to
other limitations discussed herein or arising from
the individual tax circumstances of each Unitholder.
See "Limits on Unitholder's Use of Credits" above.
Tax Shelter Registration ..................... The Trust is registered as a "tax shelter" and its
tax shelter registration number is 94-277000355.
Issuance of a tax shelter registration number does
not indicate that the investment in Units or the
claimed tax benefits have been reviewed, examined or
approved by the IRS.
Substantial Understatement
Penalty .................................. Section 6662 of the Code imposes a penalty in certain
circumstances for a substantial understatement of
taxes if a taxpayer's tax liability is understated by
more than the greater of (i) 10 percent of the taxes
required to be shown on the return and (ii) $5,000
($10,000 for most corporations). The penalty (which
is not deductible) is 20 percent of the
understatement.
Except in the case of understatements attributable to
"tax shelter" items, which are subject to special
rules discussed below, an item of understatement will
not give rise to the penalty if: (i) there is or was
"substantial authority" for the taxpayer's treatment
of the item or (ii) all the facts relevant to the tax
treatment of the item are adequately disclosed on the
return or on a statement attached to the return and
there is a reasonable basis for the tax treatment of
such item. In the case of Units, an individual
Unitholder may 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.
</TABLE>
16
<PAGE> 20
<TABLE>
<S> <C>
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 1999 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
1999 to materially differ from the Trustee's
estimates contained in the 1999 Tax Information
booklet, the Trustee will promptly mail final tax
credit information to each affected Unitholder.
</TABLE>
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, 1996, 1997 and 1998
composite income tax returns with the DOR on behalf of all Nonresident
Unitholders (defined below), and intends to file a composite return for 1999 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 1999. Accordingly,
no Alabama state income tax is due under the 1999 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 1999 (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
17
<PAGE> 21
year as a result of the assumptions required by the DOR or (ii) because the
refiling of the composite income tax return imposes an unreasonable burden on
the Trust in the judgment of the Trustee (based on its sole discretion). In that
event, each Nonresident Unitholder would be required to file a separate Alabama
state income tax return and pay any Alabama state income tax due as well as any
penalties and interest due thereon. For purposes of the filing of the composite
income tax return for any taxable year, "Nonresident Unitholders" will consist
of those Unitholders to whom the Trust has provided an individualized tax
information letter (together with its tax information booklet) for such tax year
which shows a mailing address outside the State of Alabama. All other
Unitholders will be treated by the Trust for purposes of the filing of the
composite income tax return as "Resident Unitholders."
The filing of the composite income tax return by the Trust does not
relieve any resident of the State of Alabama or any Resident Unitholder from the
obligation to file an Alabama state income tax return individually (and pay
Alabama state income tax thereon, if any) with respect to the revenues and
expenses attributable to the Royalty Interests. In light of the foregoing, each
Unitholder should consult his tax adviser regarding the requirements for filing
state income tax returns for his state of residence and Alabama.
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.
18
<PAGE> 22
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
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
19
<PAGE> 23
in exercising its rights to abandon a well and may accelerate the termination of
the Trust. See "Properties--The Royalty Interests--Sale and Abandonment of
Underlying Properties" and "Properties--Description of the Trust--Termination
and Liquidation of the Trust."
Water from the operations on the Underlying Properties is discharged into
the Black Warrior River pursuant to a National Pollutant Discharge Elimination
System permit issued by the Alabama Department of Environmental Management
("ADEM"). ADEM initially issued five permits in connection with the Underlying
Properties which were consolidated into one permit in February 1994. The ADEM
permit was renewed in 1999 and will expire in July 2004. It generally authorizes
water disposal based upon the Black Warrior River's minimum flow rate and
maximum chloride level. The Company has advised the Trust that since 1987 water
disposal from the Underlying Properties has not been disrupted.
While the Company has informed the Trust that it believes the Underlying
Properties are in material compliance with all environmental laws and
regulations, such regulations have generally become more stringent and costly
over time. As a royalty holder the Trust may not be directly subject to
increased costs; however, such costs may be taken into account by the Company in
exercising its rights to abandon a well, which may accelerate the termination of
the Trust. The Company has informed the Trust that it estimates that it plans to
expend approximately $92,000 during 2000 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."
20
<PAGE> 24
ITEM 2. PROPERTIES.
THE ROYALTY INTERESTS
The Royalty Interests held by the Trust generally entitle the Trust to
receive 65 percent of Gross Proceeds. The Royalty Interests were conveyed to the
Trust by means of a single instrument of conveyance. The Conveyance was recorded
in the appropriate real property records in Alabama, so as to give notice of the
Royalty Interests to creditors, and any transferees will take an interest in the
Underlying Properties subject to the Royalty Interests. The Conveyance was
intended to convey the Royalty Interests as real property interests under
Alabama law.
The following description of the material provisions of the Conveyance
and the Trust Agreement is subject to and qualified by the more detailed
provisions of the Conveyance and the Trust Agreement included as exhibits to
this Form 10-K.
THE UNDERLYING PROPERTIES
Black Warrior Basin. The Black Warrior Basin covers 6,000 square miles in
west central Alabama and contains seven Pennsylvania age multi-seam coal groups
in the Pottsville formation: the Black Creek, Mary Lee, Pratt, Cobb, Gwin, Utley
and Brookwood coal groups. The Pottsville coal formation ranges from the surface
to a depth of 4,100 feet.
Wells in the Black Warrior Basin produce natural gas from coal seam
formations that have production characteristics materially different from
conventional natural gas wells. The primary factor affecting recovery of gas
reserves from coal seams in the Black Warrior Basin is the lowering of reservoir
pressure through "dewatering" operations. In a typical coal seam gas well on the
Underlying Properties, average daily natural gas production generally will
increase as wells are "dewatered" until natural gas production reaches a "peak"
at which time natural gas production will decline. The amount of time necessary
to "dewater" a well and cause it to reach its peak production, and the ultimate
level of a well's peak production, are difficult to estimate. Since all of the
532 wells included in the Underlying Properties were producing by mid- 1991, the
Company believes that production from such wells is currently past its peak and
will decline over the term of the Trust.
The Royalty Interests were conveyed by the Company to the Trust out of
the Company Interests. The Existing Wells are operated by 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, 1999, 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, 1999, 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
21
<PAGE> 25
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 will expire in July 2004. The ADEM permit
generally authorizes water disposal based upon the Black Warrior River's minimum
flow rate and maximum chloride level. The Company has advised the Trust that
since 1987 water disposal from the Underlying Properties has not been disrupted.
Although the facilities of the Company have the capacity to store several days
of water production, if water disposal into the Black Warrior River is
disrupted, natural gas production from the wells on the Underlying Properties
would be curtailed during the period of such disruption. See
"Business--Regulation and Prices--Environmental Regulation."
Curtailments. The Company has advised the Trust that, during 1999,
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
22
<PAGE> 26
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.
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.
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<PAGE> 27
RESERVE ESTIMATE
Reserve Estimate. The following table summarizes net proved reserves
estimated as of January 1, 2000, 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, 2000
----------------- ---------------
<S> <C>
Net Proved Natural Gas Reserves (MMcF)(a)(b):
Developed Producing .............................................. 69,180
=========
Estimated Future Net Revenues (in thousands) (a)(c):
2000 ............................................................. $ 26,203
2001 ............................................................. 23,326
2002 ............................................................. 20,789
2003 ............................................................. 11,732
2004 ............................................................. 10,496
Thereafter ....................................................... 72,185
--------
Total ......................................................... $ 164,731
=========
Total Discounted at 10 Percent ................................ $ 102,854
=========
</TABLE>
- ----------
(a) The estimates of reserves and future net revenues summarized in this table
are based upon an unescalated price of $2.16 per MCF, which was the price
being received by the Company under the Gas Purchase Agreement as of
December 31, 1999. 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 conventional natural
24
<PAGE> 28
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 8.4 Bcf in 2000 to 5.2 Bcf in 2004.
Tax Credits Based on Reserves. Based upon the production estimates used
in the Reserve Estimate for the January 1, 2000 through December 31, 2002
period, and assuming constant future Section 29 tax credits at the estimated
2000 rate of $1.08 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 $24.3 million, having a discounted present
value (assuming a 10 percent discount rate) of approximately $20.3 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, 1999, December 31, 1998 and December 31, 1997.
<TABLE>
<CAPTION>
YEAR ENDED Year ended Year ended
DECEMBER 31, 1999 December 31, 1998 December 31, 1997
----------------- ----------------- -----------------
<S> <C> <C> <C>
Production attributable to the Royalty
Interests (Bcf) .................................. 9.2 10.6 11.3
Weighted average property, production and
related taxes (per Mcf) .......................... $ .13 $ .12 $ .13
Average Contract Price (per Mcf) .................... $ 2.37 $ 2.14 $ 2.40
</TABLE>
GAS PURCHASE AGREEMENT
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). Until December 31, 1998, the contract price paid was subject to a
minimum price of $1.85 per MMBtu and a maximum price of $2.63 per MMBtu. From
January 1, 1999 through December 31, 1999, the Contract Price paid was subject
to a minimum price of $2.16 per MMBtu and a maximum price of $3.07 per MMBtu.
Beginning effective January 1, 2000 and through December 31, 2000, the price
paid on Index Price Quantities is subject to a minimum price of $2.20 and a
maximum price of $2.82. Prior to April 1, 1996, Sonat Marketing was obligated to
purchase gas production in
25
<PAGE> 29
excess of the specified monthly base quantities at the Index Price. Effective
April 1, 1996 through December 31, 1998, the price payable for such excess gas
production equaled the Index Price plus $.02. Effective January 1, 1999, the
price payable for such excess gas production equaled the Index Price plus $.02.
Effective January 1, 2000, the price payable for such excess gas production
shall equal the Index Price plus $.02. 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.
Sonat Marketing's obligation to purchase 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 terminated on January 1, 1999.
The Gas Purchase Agreement is filed as an exhibit to this Form 10-K, and
the foregoing summary of the material terms of such agreement is qualified in
its entirety by reference to the terms of such agreement as set forth in such
exhibit.
OPERATION OF PROPERTIES
No Control by Trust. Under the terms of the Conveyance, neither the
Trustee nor the Unitholders will be able to influence or control the operation
or future development of the Underlying Properties. Unitholders will therefore
be reliant on the Company and the other working interest owners to make all
decisions regarding operations on the Underlying Properties. The Trust will not
be able to appoint or control the appointment of operators.
The Conveyance does not prohibit the transfer of the Underlying
Properties by the Company, subject to and burdened by the Royalty Interests. The
Company and the other working interest owners of the Underlying Properties will
have the right, subject to certain restrictions, to abandon any well or lease on
the Underlying Properties under certain circumstances. Upon abandonment of any
such well or lease, that portion of the Royalty Interests relating thereto will
be extinguished. See "--Sale and Abandonment of the Underlying Properties."
Operating Agreement. Pursuant to the Operating Agreement, River Gas
operates and maintains the Underlying Properties for the Company and the other
working interest owners. The Operating Agreement has a one-year term and will be
automatically renewed for additional one-year periods unless either party
provides written notice to the other party of its desire to terminate the
Operating Agreement at least six months prior to the date on which the agreement
is to terminate. Upon not less than 30 days' notice either River Gas or the
Company may terminate the Operating Agreement if: (i) the other party has
committed a material breach of the Operating Agreement, unless such breach is
cured in the manner specified in the Operating Agreement; (ii) the other party
files a petition for relief under federal or state bankruptcy laws, the other
party's insolvency is determined by a final court proceeding, the other party's
filing of a petition or application to accomplish such a result or for the
appointment of a receiver or trustee for such party or
26
<PAGE> 30
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, 1999, 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
Underlying Properties subject to the terms of the Trust Agreement and (iii) the
sale or other transfer of a majority of Dominion
27
<PAGE> 31
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.
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.
28
<PAGE> 32
<TABLE>
<CAPTION>
PRICE
----------------------------
DISTRIBUTION
HIGH LOW PER UNIT
---------- ---------- ------------
<S> <C> <C> <C>
1999
First Quarter ........... $ 16.000 $ 14.25 $ .600258
Second Quarter .......... 15.875 14.6875 .567476
Third Quarter ........... 15.75 14.50 .600583
Fourth Quarter .......... 14.8125 10.3125 .694369
1998
First Quarter ........... $ 21.25 $ 18.375 $ .874821
Second Quarter .......... 22.75 19.8750 .670386
Third Quarter ........... 21.6875 16.8750 .672017
Fourth Quarter .......... 20.125 12.8750 .614702
</TABLE>
At March 10, 2000, there were 7,850,000 Units outstanding and approximately
1,408 Unitholders of record.
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Royalty Income $ 20,031,958 $ 22,849,760 $ 24,977,563 $ 26,013,428 $ 21,603,550
Distributable Income $ 19,385,356 $ 22,226,804 $ 24,338,026 $ 25,423,282 $ 20,947,426
Distributable Income per Unit $ 2.47 $ 2.83 $ 3.10 $ 3.24 $ 2.67
Distributions per Unit $ 2.46 $ 2.83 $ 3.10 $ 3.24 $ 2.66
Total Assets, December 31 $ 75,397,111 $ 85,645,529 $ 97,774,353 $109,761,403 $125,641,485
Total corpus, December 31 $ 75,273,180 $ 85,533,029 $ 97,670,701 $109,562,077 $125,545,839
</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 consist of overriding royalty interests burdening
the Company's interest in the Underlying Properties. The Royalty Interests
generally entitle the Trust to receive 65 percent of the Gross Proceeds (as
defined below) during the preceding calendar quarter. The Royalty Interests are
non-operating interests and bear only expenses related to property, production
and related taxes (including severance taxes). "Gross Proceeds" consist
generally of the aggregate amounts received by the Company attributable to the
interests of the Company in the Underlying Properties from the sale of coal seam
gas at the central delivery points in the gathering system for the Underlying
Properties.
Production from coal seam gas wells drilled after December 31, 1979 and
prior to January 1, 1993, is believed to qualify 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 each year's
qualified production through the year 2002. Such credit, based on a Unitholder's
pro rata share of qualifying production, may not 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 the tax year solely because of this limitation is subject to
certain carryover provisions. The Trustee is provided Section 29 tax credit
information related to Trust Properties by Dominion Resources, which is then
passed along to the Unitholders. In 1997, the Tax Court upheld the Internal
Revenue Service ("IRS") position that nonconventional fuel such as coal seam gas
does not qualify for the Section 29 credit unless the producer received a formal
certification from the Federal Energy Regulatory Commission ("FERC"). The FERC's
certification authority expired effective January 1, 1993. During March 1999,
the U.S. Court of Appeals for the 10th Circuit affirmed that decision. The
appeal (which is not binding as precedent) suggests that lack of a certification
from FERC may render Section 29 credits unavailable in respect of production
from wells recompleted in a qualified formation after January 1, 1993, the date
that the FERC's certification authority expired (so that obtaining the requisite
determination for any such well was impossible). Many producers believe that
wells meeting the certification requirements are eligible for the Section 29
credits regardless of FERC certification. However, this position is not in
accordance with the IRS position, the decision of the Tax Court or the decision
of the U.S. Court of Appeals. The ability of the Trust to realize the carrying
value of its reserves and the ability of the Unitholders to utilize allocated
Section 29 credits could be in question with respect to any uncertificated
wells. In some cases the extent to which production from the various coal seam
gas wells in which the Trust holds an interest would qualify for the Section 29
credit under the standards applied in the appealed case is unclear, and the
Trustee has requested that Dominion Resources provide clarification and an
assessment of the effects of the foregoing, if any, on the Trust and its
Unitholders. Pending such clarification and assessment, or further developments,
or both, however, the availability of Section 29 credits to Unitholders in
respect of some portion of the Trust's coal seam gas production could be subject
to debate and challenge.
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.
29
<PAGE> 33
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. 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 1999 marked the fifth full year of the existence of the Trust.
The Trust received royalty income amounting to $20,031,958 during the year ended
December 31, 1999 compared to $22,849,760 for 1998 and $24,977,563 for 1997. 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, 1999 remained relatively stable at $703,308 compared
to $699,832 for 1998 and $713,380 for 1997. Distributable income for the year
ended December 31, 1999 was $19,385,356 or $2.47 per Unit compared to
$22,226,804 or $2.83 per Unit for 1998 and $24,338,026 or $3.10 per Unit for
1997.
Royalty income to the Trust is attributable to the sale of depleting
assets. All of the Underlying Properties burdened by the Royalty Interests
consist of producing properties. Accordingly, the proved reserves attributable
to the Company's interest in the Underlying Properties are expected to decline
substantially during the term of the Trust and a portion of each cash
distribution made by the Trust will, therefore, be analogous to a return of
capital. Accordingly, cash yields attributable to the Units are expected to
decline over the term of the Trust. The decreases in royalty income and
distributable income noted in the preceding paragraph were due primarily to this
depletion of reserves and to a decrease in the average prices received for gas
attributable to the Royalty Interests.
Royalty Income received by the Trust in a given calendar year will
generally reflect the proceeds from the sale of gas produced from the Underlying
Properties during the first three quarters of that year and the fourth quarter
of the preceding calendar year due to the timing of the receipt of these
revenues. Accordingly, the royalty income included in distributable income for
the years ended December 31, 1999, 1998 and 1997, was based on production
volumes and natural gas prices for the periods from October 1, 1998 to September
30, 1999, October 1, 1997 through September 30, 1998 and October 1, 1996 to
September 30, 1997, respectively.
30
<PAGE> 34
The following table sets forth the production volumes attributable to the
Trust's Royalty Interests and the average sales Price and Index Price for such
production for the periods indicated.
<TABLE>
<CAPTION>
FOR 12 MONTHS ENDED SEPTEMBER 30,
----------------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Production (Bcf)(1) 9.482 10.588 11.515
Production (MMBtu)(2) 9.391 10.494 11.404
Average Contract Price Received ($/MMBtu) $ 2.24 $ 2.29 $ 2.32
Average Index Price ($/MMBtu) $ 2.25 $ 2.35 $ 2.48
</TABLE>
(1) Billion cubic feet of natural gas
(2) Trillion British Thermal Units.
- ----------
The information in this Form 10-K concerning production and prices
relating to the Royalty Interests is based on information prepared and furnished
by the Company to the Trustee. The Trustee has no control over and no
responsibility relating to the operation of or accounting for the Underlying
Properties.
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). Until December 31, 1998, the contract price paid was subject to
a minimum price of $1.85 per MMBtu and a maximum price of $2.63 per MMBtu.
Beginning effective January 1, 1999, the Contract Price paid was subject to a
minimum price of $2.16 per MMBtu and a maximum price of $3.07 per MMBtu.
Beginning effective January 1, 2000 and through December 31, 2000, the price
paid on Index Price Quantities is subject to a minimum price of $2.20 and a
maximum price of $2.82. Prior to April 1, 1996, Sonat Marketing was obligated
to purchase gas production in excess of the specified monthly base quantities
at the Index Price. Effective April 1, 1996 through December 31, 1998, the
price payable for such excess gas production equaled the Index Price plus $.02
per MMBtu. Effective January 1, 1999, the price payable for such excess gas
production equaled the Index Price plus $.02 per MMBtu. Effective January 1,
2000, the price payable for such excess gas production shall equal The Index
Price plus $.02 per MMBtu. 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, 1999, 1998, 1997 and 1996, by independent petroleum
engineers. The reserve quantities of 69.2 Bcf for 1999 compared to 74.7 Bcf for
1998, 94.5 Bcf for 1997 and 82.4 Bcf for 1996 reflect a decline in reserves
between 1998 and 1999 as a result of production. See "Financial Statements and
Supplementary Data --Notes to Financial Statements-- Note 8."
YEAR 2000
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 recent change in the century. If not corrected, it was
believed that many computer applications could fail or create erroneous results
by or at the Year 2000. The Year 2000 issue potentially affected virtually all
companies and organizations, and it was believed that material adverse
consequences could result if a company or organization did not successfully
address its Year 2000 issues.
The Trustee took various steps to identify, assess and remediate its
potential Year 2000 problems that might have affected the Trust. The total cost
of the Trustee's Year 2000 efforts was approximately $10,000, all of which was
incurred and paid during the last quarter of 1998 and during 1999. Of this
amount, the Trustee has paid $9,000 for identification, assessment and
remediation of affected systems. The expenditures made in connection with the
Year 2000 efforts described above represent substantially all of the Trustee's
information technology-related expenditures
31
<PAGE> 35
on behalf of the Trust during 1999. These expenditures have been treated as
Trust expenses on the financial statements of the Trust.
The Trustee identified and contacted those vendors it believed could have
an impact on its day-to-day operations if their operations were interrupted as a
result of Year 2000 problems. Substantially all essential vendors reported to
the Trustee that they had addressed and resolved their internal Year 2000 issues
prior to January 1, 2000.
Neither the Trustee, nor to the Trustee's knowledge any of the Trustee's
important vendors experienced any material Year 2000 system failures. To the
Trustee's knowledge, Year 2000 issues have had no material adverse impact on the
Trust or on the Trust's ability to make timely Trust distributions to
Unitholders.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Trust invests in no derivative financial instruments, and has no
foreign operations or long-term debt instruments. The Trust is a passive entity
and other than the Trust's ability to periodically borrow money as necessary to
pay expenses, liabilities and obligations of the Trust that cannot be paid out
of cash held by the Trust, the Trust is prohibited from engaging in borrowing
transactions. The amount of any such borrowings is unlikely to be material to
the Trust. The Trust periodically holds short term investments acquired with
funds held by the Trust pending distribution to Unitholders and funds held in
reserve for the payment of Trust expenses and liabilities. Because of the
short-term nature of these borrowings and investments and certain limitations
upon the types of such investments which may be held by the Trust, the Trustee
believes that the Trust is not subject to any material interest rate risk. The
Trust does not engage in transactions in foreign currencies which could expose
the Trust or Unitholders to any foreign currency related market risk.
32
<PAGE> 36
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEPENDENT AUDITORS' REPORT
Unitholders of Dominion Resources Black Warrior Trust and Bank of America,
N.A., Trustee
We have audited the accompanying statements of assets, liabilities and
trust corpus of Dominion Resources Black Warrior Trust (the "Trust") as of
December 31, 1999 and 1998, and the related statements of distributable income
and changes in trust corpus for each of the three years in the period ended
December 31, 1999. 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, such financial statements present fairly, in all material
respects, the assets, liabilities and trust corpus of the Trust at December 31,
1999 and 1998, and the distributable income and changes in trust corpus for each
of the three years in the period ended December 31, 1999, on the basis of
accounting described in Note 2.
/s/ DELOITTE & TOUCHE LLP
Dallas, Texas
March 9, 2000
33
<PAGE> 37
DOMINION RESOURCES BLACK WARRIOR TRUST
FINANCIAL STATEMENTS
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
December 31,
--------------------------------
1999 1998
------------ ------------
ASSETS
<S> <C> <C>
Cash and cash equivalents ......................................... $ 124,159 $ 59,455
Royalty interests in gas properties (less accumulated
amortization of $80,544,548 and $70,231,426, respectively) ..... 75,272,952 85,586,074
------------ ------------
Total Assets ............................................... $ 75,397,111 $ 85,645,529
============ ============
LIABILITIES AND TRUST CORPUS
Trust expenses payable ............................................. $ 123,931 $ 112,500
Trust corpus (7,850,000 units of beneficial interest
authorized, issued and outstanding) ............................ 75,273,180 85,533,029
------------ ------------
Total Liabilities and Trust Corpus ......................... $ 75,397,111 $ 85,645,529
============ ============
</TABLE>
STATEMENTS OF DISTRIBUTABLE INCOME
<TABLE>
<CAPTION>
Year Ended
---------------------------------------------------------
December 31, 1999 December 31, 1998 December 31, 1997
----------------- ----------------- -----------------
<S> <C> <C> <C>
Royalty income ...................................... $ 20,031,958 $ 22,849,760 $ 24,977,563
Interest income ..................................... 56,706 76,876 73,843
------------ ------------ ------------
20,088,664 22,926,636 25,051,406
General and administrative expenses ................. 703,308 699,832 713,380
------------ ------------ ------------
Distributable income ................................ $ 19,385,356 $ 22,226,804 $ 24,338,026
============ ============ ============
Distributable income per unit (7,850,000 units) ..... $ 2.47 $ 2.83 $ 3.10
============ ============ ============
Distributions per unit .............................. $ 2.46 $ 2.83 $ 3.10
============ ============ ============
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
Year Ended
---------------------------------------------------------
December 31, 1999 December 31, 1998 December 31, 1997
----------------- ----------------- -----------------
<S> <C> <C> <C>
Trust corpus, beginning of period ................ $ 85,533,029 $ 97,670,701 $ 109,562,077
Amortization of royalty interests ................ (10,313,122) (12,133,848) (11,891,773)
Distributable income ............................. 19,385,356 22,226,804 24,338,026
Distributions to Unitholders ..................... (19,332,083) (22,230,628) (24,337,629)
------------- ------------- -------------
Trust corpus, end of period ...................... $ 75,273,180 $ 85,533,029 $ 97,670,701
============= ============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
34
<PAGE> 38
NOTES TO FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
1. TRUST ORGANIZATION AND PROVISIONS
Dominion Resources Black Warrior Trust (the "Trust") was formed as a
Delaware business trust pursuant to the terms of the Trust Agreement of Dominion
Resources Black Warrior Trust (as amended, the "Trust Agreement"), entered into
effective as of May 31, 1994, among Dominion Black Warrior Basin, Inc., an
Alabama corporation (the "Company"), as trustor, Dominion Resources, Inc., a
Virginia corporation ("Dominion Resources"), and Bank of America, N.A. (as
successor to NationsBank of Texas, N.A.), a national banking association (the
"Trustee"), and Mellon Bank (DE) National Association, a national banking
association (the "Delaware Trustee"), as trustees. The trustees are independent
financial institutions.
The Trust is a grantor trust formed to acquire and hold certain
overriding royalty interests (the "Royalty Interests") burdening proved natural
gas properties located in the Pottsville coal formation of the Black Warrior
Basin, Tuscaloosa County, Alabama (the "Underlying Properties") owned by the
Company. The Trust was initially created by the filing of its Certificate of
Trust with the Delaware Secretary of State on May 31, 1994. In accordance with
the Trust Agreement, the Company contributed $1,000 as the initial corpus of the
Trust. On June 28, 1994, the Royalty Interests were conveyed to the Trust by the
Company pursuant to the Overriding Royalty Conveyance (the "Conveyance")
effective as of June 1, 1994, from the Company to the Trust, in consideration
for all the 7,850,000 authorized units of beneficial interest ("Units") in the
Trust. The Company transferred all the Units to its parent, Dominion Energy,
Inc., a Virginia corporation, 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.
35
<PAGE> 39
Because of the passive nature of the Trust and the restrictions and
limitations on the powers and activities of the Trustee contained in the Trust
Agreement, the Trustee does not consider any of the officers and employees of
the Trustee to be "officers" or "executive officers" of the Trust as such terms
are defined under applicable rules and regulations adopted under the Securities
Exchange Act of 1934.
2. BASIS OF ACCOUNTING
The financial statements of the Trust are prepared on a modified cash
basis and are not intended to present financial position and results of
operations in conformity with generally accepted accounting principles ("GAAP").
Preparation of the Trust's financial statements on such basis includes the
following:
o 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
or when earned.
o General and administrative expenses are recorded based on liabilities
paid and cash reserves established out of cash received.
o Amortization of the Royalty Interests is calculated on a
unit-of-production basis and charged directly to trust corpus based upon
when revenue is received.
o 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 interests in gas properties is limited to the
sum of the future net cash flows attributable to the Trust's gas reserves at
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 the aggregate of these amounts, an impairment provision
is 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.
36
<PAGE> 40
Distributable Income Per Unit
Basic earnings per share is computed by dividing net income by the
weighted average shares outstanding. Earnings per share assuming dilution is
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. As a result basic diluted earnings per unit and
distributable income per unit are the same.
New Accounting Standards
The Financial Accounting Standards Board ("FASB") issued in June 1998
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities," which establishes accounting and
reporting standards for derivative instruments. SFAS No. 133 is effective for
the Trust January 1, 2001. The Trust has evaluated the impact and determined
that none will result from adopting this SFAS.
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, is believed to qualify 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 each year's
qualified production through the year 2002. Such credit, based on a Unitholder's
pro rata share of qualifying production, may not 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 the tax year solely because of this limitation is subject to
certain carryover provisions. The Trustee is provided Section 29 tax credit
information related to Trust Properties by Dominion Resources, which is then
passed along to the Unitholders. In 1997, the Tax Court upheld the Internal
Revenue Service ("IRS") position that nonconventional fuel such as coal seam gas
does not qualify for the Section 29 credit unless the producer received a formal
certification from the Federal Energy Regulatory Commission ("FERC"). The FERC's
certification authority expired effective January 1, 1993,. During March 1999,
the U.S. Court of Appeals for the 10th Circuit affirmed that decision. The
appeal (which is not binding as precedent) suggests that lack of a certification
from FERC may render the Section 29 credit unavailable in respect of production
from wells recompleted in a qualified formation after January 1, 1993, the date
that FERC's certification authority expired (so that obtaining the requisite
determination of any such well was impossible). Many producers believe that
wells meeting the certification requirements are eligible for the Section 29
credits regardless of FERC certification. However, this position is not in
accordance with the IRS position, the decision of the Tax Court or the decision
of the U.S. Court of Appeals. The ability of the Trust to realize the carrying
value of its reserves and the ability of the Unitholders to utilize allocated
Section 29 credits could be in question with respect to any uncertificated
wells. In some cases the extent to which production from the various coal seam
gas wells in which the Trust holds an interest would qualify for the Section 29
credit under the standards applied in the appealed case is unclear, and the
Trustee has requested that Dominion Resources provide clarification and an
assessment of the effects of the foregoing, if any, on the Trust and its
Unitholders. Pending such clarification and assessment, or further developments,
or both, however, the availability of Section 29 credits to Unitholders in
respect of some portion of the Trust's coal seam gas production could be subject
to debate and challenge.
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 1999 this fee was $352,817 and will increase
37
<PAGE> 41
annually by three percent. Aggregate fees paid by the Trust to Dominion
Resources in 1999, 1998 and 1997 were $352,817, $342,515 and $327,561,
respectively.
Aggregate fees and expense reimbursements paid by the Trust to the
trustees in 1999, 1998 and 1997 were $34,778, $33,765 and $32,756, respectively.
5. DISTRIBUTIONS TO UNITHOLDERS
The Trustee determines for each calendar quarter the amount of cash
available for distribution to Unitholders. Such amount (the "Quarterly
Distribution Amount") is an amount equal to the excess, if any, of the cash
received by the Trust attributable to production from the Royalty Interests
during such quarter, provided that such cash is received by the Trust on or
before the last business day prior to the 45th day following the end of such
calendar quarter, plus the amount of interest expected by the Trustee to be
earned on such cash proceeds during the period between the date of receipt by
the Trust of such cash proceeds and the date of payment to the Unitholders of
such Quarterly Distribution Amount, plus all other cash receipts of the Trust
during such quarter (to the extent not distributed or held for future
distribution as a Special Distribution Amount (as defined below) or included in
the previous Quarterly Distribution Amount)(which might include sales proceeds
not sufficient in amount to qualify for a special distribution as described in
the next paragraph), over the liabilities of the Trust paid during such quarter
and not taken into account in determining a prior Quarterly Distribution Amount,
subject to adjustments for changes made by the Trustee during such quarter in
any cash reserves established for the payment of contingent or future
obligations of the Trust. An amount which is not included in the Quarterly
Distribution Amount for a calendar quarter because such amount is received by
the Trust after the last business day prior to the 45th day following the end of
such calendar quarter will be included in the Quarterly Distribution Amount for
the next calendar quarter. The Quarterly Distribution Amount for each quarter
will be payable to Unitholders of record on the 60th day following the end of
such calendar quarter unless such day is not a business day in which case the
record date is the next business day thereafter. The Trustee will distribute the
Quarterly Distribution Amount for each quarter on or prior to 70 days after the
end of such calendar quarter to each person who was a Unitholder of record on
the record date for such calendar quarter.
The Royalty Interests may be sold under certain circumstances and will be
sold following termination of the Trust. A special distribution will be made of
undistributed net sales proceeds and other amounts received by the Trust
aggregating in excess of $10 million (a "Special Distribution Amount"). The
record date for a Special Distribution Amount will be the 15th day following the
receipt by the Trust of amounts aggregating a Special Distribution Amount
(unless such day is not a business day, in which case the record date will be
the next business day thereafter) unless such day is within 10 days or less
prior to the record date for a Quarterly Distribution Amount, in which case the
record date for the Special Distribution Amount will be the same as the record
date for the Quarterly Distribution Amount. Distribution to Unitholders of a
Special Distribution Amount will be made no later than 15 days after the Special
Distribution Amount record date.
6. SUBSEQUENT EVENTS
Subsequent to December 31, 1999, the Trust declared and paid the
following distribution:
<TABLE>
<CAPTION>
QUARTERLY DISTRIBUTION
RECORD DATE PAYMENT DATE PER UNIT
- ----------------------- ---------------------- --------------------
<S> <C> <C>
February 29, 2000 March 10, 2000 $.674578
</TABLE>
The trustee has estimated the Section 29 tax credit associated with the
March 10, 2000 quarterly distribution to be $.28 per unit (unaudited).
38
<PAGE> 42
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, 1999 and 1998 (in thousands, except per Unit amounts):
<TABLE>
<CAPTION>
ROYALTY DISTRIBUTABLE DISTRIBUTABLE
CALENDAR QUARTER INCOME INCOME INCOME PER UNIT
- ---------------- -------- ------------- ----------------
<S> <C> <C> <C>
1999
First .............. $ 4,859 $ 4,672 $ .60
Second ............. 4,660 4,446 .57
Third .............. 4,901 4,782 .60
Fourth ............. 5,612 5,485 .70
-------- -------- --------
$ 20,032 $ 19,385 $ 2.47
======== ======== ========
1998
First .............. $ 6,917 $ 6,749 $ .86
Second ............. 5,524 5,311 .68
Third .............. 5,451 5,344 .68
Fourth ............. 4,958 4,823 .61
-------- -------- --------
$ 22,850 $ 22,227 $ 2.83
======== ======== ========
</TABLE>
Selected 1999 fourth quarter data are as follows (in thousands, except per
Unit amounts):
<TABLE>
<S> <C>
Royalty income............................... $ 5,612,344
Interest income.............................. 17,856
General and administrative expenses.......... (144,713)
--------------
Distributable income......................... $ 5,485,487
==============
Distributable income per Unit................ $ .70
==============
Distributions per Unit....................... $ .70
==============
</TABLE>
Due to significant revisions in estimate of reserve quantities (see
Note 8), estimated amortization of royalty interests was increased by
approximately $2 million and $1.2 million and decreased approximately $3.4
million during the fourth quarters of 1999, 1998 and 1997, respectively. These
adjustments did not have an impact on the Trust's distributable income.
8. SUPPLEMENTAL GAS DISCLOSURE (UNAUDITED)
The net proved reserves attributable to the Royalty Interests have been
estimated as of December 31, 1999, 1998 and 1997 and January 1, 1997 by
independent petroleum engineers.
In accordance with SFAS 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, 1999, 1998 and 1997 and January 1, 1997
were $2.16, $2.12, $2.55 and $2.81 per Mcf, respectively, including the effect
of the Gas Purchase Agreement (see Note 9).
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.
39
<PAGE> 43
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, 1997.............. 82,388
Revisions of previous estimates.................. 23,380
Production....................................... (11,302)
------------
Proved developed reserves at December 31, 1997............ 94,466
Revisions of previous estimates.................. ( 9,458)
Production....................................... (10,329)
------------
Proved developed reserves at December 31, 1998............ 74,679
Revisions of previous estimates.................. 3,687
Production....................................... (9,186)
------------
Proved developed reserves at December 31, 1999............ 69,180
===========
</TABLE>
All proved reserve estimates presented above at December 31, 1999, 1998
and 1997 and January 1, 1997 are proved developed.
Proved developed reserves, all located in the United States, for the
Trust's Interests are estimated quantities of coal seam gas which geological and
engineering data indicate with reasonable certainty to be recoverable in future
years from the coal formation under existing economic and operating conditions.
Proved developed reserves are proved reserves which can be expected to be
recovered through existing wells with existing equipment and operating methods.
Estimated economic quantities have been determined considering the Section 29
tax credits.
The following table sets forth the standardized measure of discounted
estimated future net cash flows from proved reserves at December 31, 1999, 1998
and 1997 relating to the Trust's Royalty Interests (thousands of dollars):
<TABLE>
<CAPTION>
1999 1998 1997
---------- ---------- ----------
<S> <C> <C> <C>
Future cash inflows .............................. $ 149,364 $ 158,122 $ 241,346
Future taxes ..................................... (8,962) (9,487) (14,481)
---------- ---------- ----------
Future net cash flows ............................ 140,402 148,635 226,865
10% annual discount for estimated timing
of cash flow ............................... (57,863) (59,703) (97,941)
---------- ---------- ----------
Standardized measure of discounted
future net cash flows ...................... $ 82,539 $ 88,932 $ 128,924
========== ========== ==========
</TABLE>
Future cash flows do not include Section 29 tax credits which in the
aggregate are estimated to be approximately $ 24,328,162 having a discounted
present value (assuming a 10% discounted rate) of approximately $20,315,000 at
December 31, 1999.
The following table sets forth the changes in the present value of
estimated future net cash flows from proved reserves during the period ended
December 31, 1999, 1998 and 1997 (thousands of dollars):
<TABLE>
<CAPTION>
1999 1998 1997
---------- ---------- ----------
<S> <C> <C> <C>
Balance at beginning of period.......................... $ 88,932 $ 128,924 $ 134,675
Increase (decrease) due to:
Royalty income, net of taxes....................... (21,493) (21,722) (25,096)
Changes in prices.................................. 1,534 (16,723) (21,421)
Changes in estimated volumes....................... 4,673 (14,439) 27,298
Accretion of discount.............................. 8,893 12,892 13,468
---------- ---------- ----------
Balance at December 31.................................. $ 82,539 $ 88,932 $ 128,924
========== ========== ==========
</TABLE>
40
<PAGE> 44
As of March 24, 2000, published natural gas prices were approximately
$2.23 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 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). Until December 31, 1998, the contract price paid was subject to a
minimum price of $1.85 per MMBtu and a maximum price of $2.63 per MMBtu.
Beginning effective January 1, 1999, the Contract Price paid was subject to a
minimum price of $2.16 per MMBtu and a maximum price of $3.07 per MMBtu.
Beginning effective January 1, 2000 and through December 31, 2000 the price paid
on Index Price Quantities is subject to a minimum price of $2.20 and a maximum
price of $2.82. Prior to April 1, 1996, Sonat Marketing was obligated to
purchase the Subject Gas in excess of the Monthly Base Quantity at the Index
Price. From April 1, 1996 through December 31, 1998, the price payable for
Subject Gas in excess of the Monthly Base Quantity equaled the Index Price plus
$.02. Beginning effective January 1, 1999 through December 31, 1999, the price
payable for Subject Gas in excess of the Monthly Base Quantity but less than or
equal to the Monthly Fixed Price Quantity equaled the Index Price plus $.02
subject to a minimum price of $2.12 per MMBtu and a maximum price of $3.02 per
MMBtu. Also during the period, the price payable for Subject Gas in excess of
the Monthly Fixed Price Quantity equaled the sum of the Index Price and $.02.
Effective January 1, 2000 through December 31, 2000, the price payable for
Subject Gas in excess of the Monthly Fixed Price Quantity shall equal the sum of
the Index Price and $.02 per MMBtu. 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.
41
<PAGE> 45
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
1999, the Trustee and the Delaware Trustee received total compensation of
$34,778 and $3,750, respectively.
Compensation of the Transfer Agent. The Transfer Agent receives a
transfer agency fee of $3.25 annually per account, plus $1.50 for each
certificate issued and $.40 for each check issued (subject to an annual minimum
of $7,200).
Fees to Dominion Resources. Dominion Resources will receive throughout
the term of the Trust an administrative services fee for accounting, bookkeeping
and other administrative services relating to the Royalty Interests and the
Underlying Properties as described in Item 13 under "Administrative Services
Agreement."
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.
42
<PAGE> 46
Security Ownership of Management. The Trust has no directors or executive
officers. As of March 10, 2000, neither Bank of America, 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 $352,817 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
43
<PAGE> 47
Company Interests Owner's obligation to the Trust with respect to the Underlying
Properties sold or abandoned. Such sales or abandonment may not be in the best
interest of the Trust or the Unitholders.
Dominion Resources may profit from contracts with the Trust. The amount
that Dominion Resources may charge for services it renders under the
Administrative Services Agreement is established in such contract at rates that
do not necessarily take into account the actual cost of rendering such services
by Dominion Resources. Accordingly, Dominion Resources may profit or suffer
losses in connection with the performance of such contract.
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,
1999 and 1998
Statements of Distributable Income for the years ended December 31,
1999, 1998 and 1997
Statements of Changes in Trust Corpus for the years ended December
31, 1999, 1998 and 1997
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
Exhibit
Number Exhibit
3.1 --Trust Agreement of Dominion Resources Black Warrior Trust
dated as of May 31, 1994, by and among Dominion Black
Warrior Basin, Inc., Dominion Resources, Inc., Mellon Bank
(DE) National Association and NationsBank, N.A. (as
successor to NationsBank of Texas, N.A.) (filed as Exhibit
3.1 to Dominion Resources, Inc.'s Registration Statement* on
Form S-3 (No. 33-53513), and incorporated herein by
reference).
3.2 --First Amendment of Trust Agreement of Dominion Resources
Black Warrior Trust dated as of June 27, 1994, by and among
Dominion Black Warrior Basin, Inc., Dominion Resources,
Inc., Mellon Bank (DE) National Association and NationsBank,
N.A. (as successor to NationsBank of Texas, N.A.) (filed as
Exhibit 3.2 to the Registrant's Form 10-Q for the quarter
ended June 30, 1994 and incorporated herein by reference).
10.1 --Overriding Royalty Conveyance dated as of June 28, 1994,
from Dominion Black Warrior Basin, Inc. to Dominion
Resources Black Warrior Trust (filed as Exhibit 10.1 to the
Registrant's Form 10-Q for the quarter ended June 30, 1994
and incorporated herein by reference).
10.2 --Administrative Services Agreement dated as of June 1, 1994,
by and between Dominion Resources, Inc. and Dominion
Resources Black Warrior Trust (filed as Exhibit 10.2 to the
Registrant's Form 10-Q for the quarter ended June 30, 1994
and incorporated herein by reference).
10.3 --Amendment to and Ratification of Overriding Royalty
Conveyance dated as of November 20, 1994, among Dominion
Back Warrior Basin, Inc., NationsBank, N.A. (as successor
to NationsBank of Texas, N.A.), and Mellon Bank (DE)
National Association (filed as Exhibit 10.3 to the
Registrant's Form 10-K for the year ended December 31, 1994
and incorporated herein by reference).
44
<PAGE> 48
10.4 --Gas Purchase Agreement, dated as of May 3, 1994, between
Sonat Marketing and the Company (filed as Exhibit 10.2 to
Dominion Resources, Inc.'s Registration Statement* on Form
S-3 (No. 33-53513), and incorporated herein by reference).
10.5 --Amendment to Gas Purchase Agreement dated May 16, 1996,
between Sonat Marketing and the Company (filed as Exhibit
10.1 to the Registrant's Form 10-Q for the quarter ended
June 30, 1996 and incorporated herein by reference).
10.6 --Amendment to Gas Purchase Agreement dated April 9, 1998,
between Sonat Marketing and the Company (filed as Exhibit
10.6 to the Registrant's Form 10-K for the year ended
December 31, 1998 and incorporated herein by reference).
10.7 --Amendment to Gas Purchase Agreement dated July 1, 1999,
between Sonat Marketing and the Company.
23.1 --Consent of Ryder Scott Company Petroleum Engineers,
independent petroleum engineers.
27.1 --Financial Data Schedule.
99.1 --Summary of Reserve Report, dated February 23, 2000, on the
estimated reserves, estimated future net revenues and the
discounted estimated future net revenues attributable to the
Royalty Interests as of January 1, 2000, prepared by Ryder
Scott Company Petroleum Engineers, independent petroleum
engineers.
- ----------
* 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.
45
<PAGE> 49
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
DOMINION RESOURCES BLACK WARRIOR TRUST
By: BANK OF AMERICA, N.A., TRUSTEE
By: /s/ RON E. HOOPER
-------------------------------------
RON E. HOOPER
VICE PRESIDENT AND ADMINISTRATOR
Date: March 30, 2000
(THE REGISTRANT HAS NO DIRECTORS OR EXECUTIVE OFFICERS.)
46
<PAGE> 50
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
10.7 --Amendment to Gas Purchase Agreement dated July 1, 1999,
between Sonat Marketing and the Company.
23.1 --Consent of Ryder Scott Company Petroleum Engineers,
independent petroleum engineers.
27.1 --Financial Data Schedule.
99.1 --Summary of Reserve Report, dated February 23, 2000, on the
estimated reserves, estimated future net revenues and the
discounted estimated future net revenues attributable to the
Royalty Interests as of January 1, 2000, prepared by Ryder
Scott Company Petroleum Engineers, independent petroleum
engineers.
</TABLE>
<PAGE> 1
EXHIBIT 10.7
AMENDMENT TO THE
GAS PURCHASE AGREEMENT
DATED MAY 3, 1994
THIS AMENDMENT (the "July 1999 Amendment"), made and entered into as of the
1st day of July 1999, between Dominion Black Warrior Basin, Inc. ("Seller") and
Sonat Marketing Company L.P. ("Buyer").
WITNESSETH
WHEREAS, Buyer and Seller entered into a Gas Purchase Agreement dated May
3, 1994, as amended by Amendments dated April 1, 1996, May 16, 1996, and April
9, 1998 ("the 1994 Agreement"); and
WHEREAS, Buyer and Seller desire to further amend the 1994 Agreement to
establish Floor and Ceiling Prices for a given quantity and a fixed price for an
equal quantity and related procedures to be effective during the calendar year
2000;
NOW THEREFORE, in consideration of the premises and mutual covenants
contained herein, the parties hereby mutually understand and agree as follows:
1. Section 2.1 of the 1994 Agreement shall be deleted in its entirety
and the following Section 2.1 substituted therefor:
2.1 Subject to the terms and conditions hereinafter set forth,
commencing on the Effective Date, Seller agrees to sell and deliver,
and Buyer agrees to purchase and receive one hundred percent (100%) of
the gas produced in the Field attributable to Seller's interest therein
as described on Exhibit A hereto. On Revised Exhibit B attached hereto,
Seller has designated for each month of the primary term hereof
commencing on the Effective Date, the projected production for such
month (the "Monthly Base Quantity"). Any gas produced during a month in
excess of the Monthly Base Quantity shall be deemed the "Excess
Quantity".
1
<PAGE> 2
2. Effective January 1, 2000 through December 31, 2000, Sections 4.1,
4.2 and 4.3 of the 1994 Agreement shall be deleted in its entirety and the
following Sections 4.1, 4.2 and 4.3 shall be substituted therefor:
4.1 The price payable by Buyer for each MMBtu of Monthly Base quantity
purchased hereunder during each month of the primary term hereof
commencing on January 1, 2000 shall be divided into two categories, a
Fixed Price Quantity and an Index Price Quantity, as described in
Revised Exhibit D hereto. The price for each MMBtu of Fixed Price
Quantity shall be $2.45 per MMBtu (the "Monthly Fixed Contract
Price"). The price for each MMBtu of Index Price Quantity shall be the
sum of (a) the price published in the price table dated the first
(1st) day of the applicable month by Inside F.E.R.C.'s Gas Market
Report for "Prices of Spot Gas Delivered to Pipelines" "Southern
Natural Gas Co." "Louisiana" "Index" (the "Index Price") and (b) a
Premium per MMBtu as described below (the "Monthly Index Contract
Price"):
<TABLE>
<CAPTION>
Index Price Premium
($/MMBtu) ($/MMBtu)
--------- ---------
<S> <C>
Below 2.00 0.050
2.00 - 2.25 0.060
2.26 - 2.50 0.065
Above 2.50 0.070
</TABLE>
4.2 The above Section 4.1 notwithstanding, the Index Price component
of the Monthly Index Contract Price payable during each month shall,
in no event, be less than $2.20 per MMBtu (the "Floor Price"), nor
more than $2.82 per MMBtu (the "Ceiling Price"); provided, however,
that the Premium shall be based on the actual Index Price regardless
whether such Index Price falls below the Floor Price.
4.3 The price payable by Buyer for each MMBtu of Excess Quantity
during the primary term hereof commencing on January 1, 2000 shall be
the sum of the Index Price and $.02 per MMBtu (the "Excess Quantity
Contract Price").
3. Exhibit B is deleted in its entirety and the attached Revised
Exhibit B is substituted therefor.
4. Exhibit D is deleted in its entirety and the attached Revised
Exhibit D is substituted therefor and is effective during the calendar
year 2000 only.
2
<PAGE> 3
IN WITNESS WHEREOF, the parties hereto have executed this July 1999
Amendment in duplicate originals as of date hereinabove first written.
Witness: SONAT MARKETING COMPANY L.P.
By /s/ Edward J. Crenshaw
-------------------------- -------------------------------
Edward J. Crenshaw
-------------------------- Vice President - Marketing
Witness: DOMINION BLACK WARRIOR BASIN, INC.
/s/ G.E. Lake, Jr.
-------------------------------
G.E. Lake, Jr.
3
<PAGE> 4
REVISED EXHIBIT B
DATED JULY 1, 1999
TO THE
GAS PURCHASE AGREEMENT
BETWEEN
DOMINION BLACK WARRIOR BASIN, INC.
AND
SONAT MARKETING COMPANY L.P., SUCCESSOR-IN-INTEREST
TO SONAT MARKETING COMPANY
DATED
MAY 3, 1994
<TABLE>
<CAPTION>
Month/Year Monthly Base Quantity
---------- ---------------------
<S> <C>
Jun-94 2,049,266
Jul-94 2,024,890
Aug-94 1,997,383
Sep-94 1,973,850
Oct-94 1,951,089
Nov-94 1,927,251
Dec-94 1,906,933
Jan-95 1,885,876
Feb-95 1,863,385
Mar-95 1,843,489
Apr-95 1,823,962
May-95 1,805,450
Jun-95 1,787,173
Jul-95 1,771,348
Aug-95 1,756,032
Sep-95 1,740,875
Oct-95 1,726,083
Nov-95 1,711,675
Dec-95 1,698,140
Jan-96 1,685,535
Feb-96 1,673,928
Mar-96 1,663,482
Apr-96 1,652,832
May-96 1,643,705
Jun-96 1,633,814
Jul-96 1,625,079
Aug-96 1,614,930
Sep-96 1,604,315
Oct-96 1,593,147
Nov-96 1,581,881
Dec-96 1,571,915
Jan-97 1,562,875
</TABLE>
4
<PAGE> 5
<TABLE>
<CAPTION>
Month/Year Monthly Base Quantity
---------- ---------------------
<S> <C>
Feb-97 1,554,163
Mar-97 1,540,578
Apr-97 1,525,042
May-97 1,510,269
Jun-97 1,494,454
Jul-97 1,477,976
Aug-97 1,461,398
Sep-97 1,444,593
Oct-97 1,427,214
Nov-97 1,408,676
Dec-97 1,389,533
Jan-97 1,368,701
Feb-98 1,342,469
Mar-98 1,319,441
Apr-98 1,296,269
May-98 1,272,573
Jun-98 1,249,204
Jul-98 1,225,774
Aug-98 1,201,433
Sep-98 1,178,126
Oct-98 1,154,755
Nov-98 1,131,388
Dec-98 1,109,349
Jan-99 1,198,000
Feb-99 1,171,000
Mar-99 1,136,000
Apr-99 1,140,000
May-99 1,106,000
Jun-99 1,094,000
Jul-99 1,096,000
Aug-99 1,071,000
Sep-99 1,053,000
Oct-99 1,045,000
Nov-99 1,007,000
Dec-99 1,008,000
Jan-00 1,200,000
Feb-00 1,200,000
Mar-00 1,200,000
Apr-00 1,200,000
May-00 1,150,000
Jun-00 1,150,000
Jul-00 1,150,000
Aug-00 1,150,000
</TABLE>
5
<PAGE> 6
<TABLE>
<CAPTION>
Month/Year Monthly Base Quantity
---------- ---------------------
<S> <C>
Sep-00 1,100,000
Oct-00 1,100,000
Nov-00 1,100,000
Dec-00 1,100,000
Jan-01 1,050,000
Feb-01 1,050,000
Mar-01 1,050,000
Apr-01 1,050,000
May-01 1,000,000
Jun-01 1,000,000
Jul-01 1,000,000
Aug-01 1,000,000
Sep-01 950,000
Oct-01 950,000
Nov-01 950,000
Dec-01 950,000
</TABLE>
6
<PAGE> 7
REVISED EXHIBIT D
DATED JULY 1, 1999
TO THE
GAS PURCHASE AGREEMENT
BETWEEN
DOMINION BLACK WARRIOR BASIN, INC.
AND
SONAT MARKETING COMPANY L.P., SUCCESSOR-IN-INTEREST
TO SONAT MARKETING COMPANY
DATED
MAY 3, 1994
<TABLE>
<CAPTION>
Fixed Price Quantities Index Quantities
Month/Year (MMBtu) (MMBtu)
---------- ---------------------- ----------------
<S> <C> <C>
Jan-00 600,000 600,000
Feb-00 600,000 600,000
Mar-00 600,000 600,000
Apr-00 600,000 600,000
May-00 575,000 575,000
Jun-00 575,000 575,000
Jul-00 575,000 575,000
Aug-00 575,000 575,000
Sep-00 550,000 550,000
Oct-00 550,000 550,000
Nov-00 550,000 550,000
Dec-00 550,000 550,000
</TABLE>
7
<PAGE> 1
EXHIBIT 23.1
March 28, 2000
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 February 23,
2000, concerning the reserves and revenue, as of January 1, 2000, of certain
royalty interests owned by Dominion Resources Black Warrior Trust in the Form
10-K for the year ended December 31, 1999, of the Dominion Resources Black
Warrior Trust to be filed with the Securities and Exchange Commission.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
CPM/sw
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 124,159
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 124,159
<PP&E> 155,817,500
<DEPRECIATION> 80,544,548
<TOTAL-ASSETS> 75,397,111
<CURRENT-LIABILITIES> 123,931
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 75,273,180
<TOTAL-LIABILITY-AND-EQUITY> 75,397,111
<SALES> 20,031,958
<TOTAL-REVENUES> 20,088,664
<CGS> 0
<TOTAL-COSTS> 703,308
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 19,385,356
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 19,385,356
<EPS-BASIC> 2.47
<EPS-DILUTED> 2.46
</TABLE>
<PAGE> 1
Ryder Scott Company
Petroleum Consultants
1100 Louisiana, Suite 3800
Houston, TX 77002-5218
February 23, 2000
Dominion Black Warrior Basin, Inc.
Riverfront Plaza - West Tower
901 E. Byrd Street
Richmond, VA 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, 2000. 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 was
estimated using escalated 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, 2000
-----------------------------------------------------------
<TABLE>
<CAPTION>
Total
Proved
------------
NET REMAINING RESERVES
<S> <C>
Gas - MMCF 70,235
INCOME DATA
Future Gross Revenue $182,805,658
Tax Credits $ 24,858,955
------------
Future Net Income (FNI) $207,663,955
Discounted FNI @ 5% $149,458,540
</TABLE>
<PAGE> 2
Dominion Black Warrior Basin, Inc.
February 23, 2000
Page 2
CASE 2
UNESCALATED PARAMETERS - YEAR-END PRICING
Estimated Net Reserve and Income Data
Certain Royalty Interest of
DOMINION RESOURCES TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
As of January 1, 2000
----------------------------------------------------------------
<TABLE>
<CAPTION>
Total
Proved
------------
NET REMAINING RESERVES
- ----------------------
<S> <C>
Gas - MMCF 69,180
INCOME DATA
Future Gross Revenue $140,402,560
Tax Credits $ 24,328,162
------------
Future Net Income (FNI) $164,730,722
Discounted FNI @ 5% $126,467,437
</TABLE>
All gas volumes are sales gas expressed in millions of cubic feet
(MMCF) at the official temperature and pressure base of the area 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 Definition 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
<PAGE> 3
Dominion Black Warrior Basin, Inc.
February 23, 2000
Page 3
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 above 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.
Year End Pricing
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
Discounted Future Net Income
As of January 1, 2000
Total Proved
-------------------------------------------------------
<TABLE>
<CAPTION>
Discount Rate Escalated Unescalated
Percent Case Case
---------------- ------------- -------------
<S> <C> <C>
10 $ 116,638,533 $ 102,854,098
15 $ 95,964,656 $ 86,958,053
20 $ 81,813,050 $ 75,533,178
25 $ 71,505,369 $ 66,904,940
</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 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.
<PAGE> 4
Dominion Black Warrior Basin, Inc.
February 23, 2000
Page 4
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 current 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 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
The reserves included herein were estimated by the performance method.
The reserves estimated by the performance method utilized extrapolations of
various historical data.
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 on 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.
<PAGE> 5
Dominion Black Warrior Basin, Inc.
February 23, 2000
Page 5
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, 2000 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.
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 costs 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 properties was used in this report. We have not
performed a detailed study of the abandonment costs nor the salvage value and
make no warranty for Dominion's estimate. No deduction was made for indirect
costs such as general administration and overhead expenses,
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Dominion Black Warrior Basin, Inc.
February 23, 2000
Page 6
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, 2000
are presented under the tab "Grand 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 1999.
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 of the subject
properties.
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, L.P.
C. Patrick McInturff, P.E.
Petroleum Engineer
Approved:
- ----------------------------------
John R. Warner, P.E.
Senior Vice President
