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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
---------------------
COMMISSION FILE NUMBER: 001-11335
DOMINION RESOURCES BLACK WARRIOR TRUST
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 75-6461716
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NUMBER)
NATIONSBANK, N.A.
NATIONSBANK CENTER
901 MAIN STREET
17TH FLOOR
DALLAS, TEXAS 75202
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(214) 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 15, 1999, 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 $123,637,500.
DOCUMENTS INCORPORATED BY REFERENCE
None.
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TABLE OF CONTENTS
<TABLE>
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PAGE
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<S> <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......................................18
Regulation of Natural Gas.........................18
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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<TABLE>
<S> <C>
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. Pursuant to an amendment effective January 1, 1999
through December 31, 1999, the Contract Price for each month shall and has
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. From January 1, 2000
through December 31, 2001, the Contract Price shall equal (a) for quantities of
Gas equal to or less than the Monthly Base Quantity, the sum of the Index Price
and the Premium, which price will not be subject to a minimum or 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.
"Conveyance" means the Overriding Royalty Conveyance dated effective as
of June 1, 1994, from the Company to the Trust, as amended by instrument dated
as of November 20, 1994, copies of which are filed as exhibits to this Form
10-K.
"Delaware Trustee" means Mellon Bank (DE) National Association.
"Dominion Resources" means Dominion Resources, Inc., a Virginia
corporation.
"Existing Wells" means the wells producing on the Underlying Properties
as of June 1, 1994.
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"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 and January 1, 1999.
"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.
"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, and from January 1, 1999 through December 31, 1999, $2.63
per MMBtu and $3.07 per MMBtu, respectively
"Minimum Price" means, for the periods from June 1, 1994 through
December 31, 1998, and from January 1, 1999 through December 31, 1999, $1.85
per MMBtu and $2.16 per MMBtu, respectively.
"MMcf" means million cubic feet of natural gas. As used herein, 1 MMcf
is assumed to have a Btu content of 990 MMBtu.
"MMBtu" means million Btu. As used herein, 990 MMBtu is deemed to be the
Btu content of 1 MMcf.
"Monthly Base Quantity" means the volumes of natural gas designated as
such from time to time in the Gas Purchase Agreement.
"Monthly Fixed Price Quantity" means the volumes of natural gas
designated as such from time to time in the Gas Purchase Agreement.
"Net revenue interest" means working interest or mineral interest less
any applicable royalties, overriding royalties or similar burdens on production
prior to the Royalty Interests.
"Net wells" and "net acres" are calculated by multiplying gross wells or
gross acres by the ownership interest in such wells or acres.
"Premium" means the premium per MMbtu on a wet basis pursuant to the Gas
Purchase Agreement from June 1, 1994 through December 31, 2001 as follows:
<TABLE>
<CAPTION>
INDEX PRICE PREMIUM
($/MMBTU) ($ /MMBTU)
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<S> <C>
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, 1999, prepared by Ryder
Scott.
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"River Gas" means The River Gas Corporation, an Alabama corporation.
"Royalty Interests" means the overriding royalty interests conveyed to
the Trust pursuant to the Conveyance entitling the holder thereof to 65 percent
of the Gross Proceeds derived from the Company Interests.
"Ryder Scott" means Ryder Scott Company Petroleum Engineers, independent
petroleum engineers.
"Section 29 tax credit" means the tax credits for federal income tax
purposes pursuant to Section 29 of the Code to an owner of coal seam gas
production, which tax credits are generated upon the sale of such production.
"Sonat" means Sonat, Inc., a Delaware corporation.
"Sonat Marketing" means Sonat Marketing Company, a Delaware Corporation.
"Subject Gas" means Gas attributable to the Company Interests.
"Trust" means Dominion Resources Black Warrior Trust, a Delaware
business trust formed pursuant to the Trust Agreement.
"Trust Agreement" means the Trust Agreement dated as of May 31, 1994,
among the Company, as grantor, Dominion Resources, the Delaware Trustee and the
Trustee, as amended by instrument dated as of June 27, 1994, copies of which
are filed as exhibits to this Form 10-K.
"Trustee" means NationsBank, 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 were to hold
that the Trust is taxable as a corporation, then the Trust would incur
substantial federal income tax liabilities. See also "--State Tax
Considerations--Alabama Franchise Tax."
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LIABILITIES OF THE TRUSTEE AND THE DELAWARE TRUSTEE
Each of the Trustee and the Delaware Trustee may act in its discretion
and is personally or individually liable only for fraud or acts or omissions in
bad faith or which constitute gross negligence (and for taxes, fees and other
charges on, based on or measured by any fees, commissions or compensation
received pursuant to the Trust Agreement) and will not be otherwise liable for
any act or omission of any agent or employee unless such trustee has acted in
bad faith or with gross negligence in the selection and retention of such agent
or employee. Each of the Trustee and the Delaware Trustee (and their respective
agents) is indemnified by Dominion Resources and from the Trust assets for
certain environmental liabilities, and for any other liability, expense, claim,
damage or other loss incurred in performing its duties, unless resulting from
gross negligence, fraud or bad faith (each of the Trustee and the Delaware
Trustee is indemnified from the Trust assets against its own negligence which
does not constitute gross negligence), and will have a first lien upon the
assets of the Trust as security for such indemnification and for reimbursements
and compensation to which it is entitled; provided that the Trustee and the
Delaware Trustee are generally required to first be indemnified from Trust
assets before seeking indemnification from Dominion Resources. Dominion
Resources also has agreed to indemnify the Trustee and the Delaware Trustee
against certain securities laws' liabilities. Neither the Trustee nor the
Delaware Trustee is entitled to indemnification from Unitholders (except in
connection with lost or destroyed Unit certificates). Insofar as
indemnification for liabilities arising under the Securities Act of 1933, as
amended (the "Securities Act"), is permitted to the Trustee pursuant to the
foregoing provisions, the Trustee has been informed that in the opinion of the
Securities and Exchange Commission (the "Commission") such indemnification is
against public policy as expressed in the Securities Act and is, therefore,
unenforceable.
TERMINATION AND LIQUIDATION OF THE TRUST
The Trust will terminate upon the occurrence of: (i) an affirmative vote
of the holders of not less than 662/3 percent of the outstanding Units to
terminate the Trust; (ii) such time as the ratio of the cash amounts received
by the Trust attributable to the Royalty Interests in any calendar quarter to
administrative costs of the Trust for such calendar quarter is less than 1.2 to
1.0 for two consecutive calendar quarters; or (iii) March 1 of any year if it
is determined, based on a reserve report as of December 31 of the prior year
prepared by a firm of independent petroleum engineers mutually selected by the
Trustee and the Company, that the net present value (discounted at 10 percent)
of (a) estimated future net revenues from proved reserves attributable to the
Royalty Interests plus (b) the amount of all remaining Section 29 tax credits
attributable to the Royalty Interests, is equal to or less than $5 million (as
applicable, the "Termination Date"). Upon such occurrence, the remaining assets
of the Trust will be sold, the net proceeds of the sale will be distributed to
the Unitholders and the Trust will be wound up and a certificate of
cancellation filed.
Upon the termination of the Trust, the Trustee will use its best efforts
to sell any remaining Royalty Interests then owned by the Trust for cash
pursuant to the procedures described in the Trust Agreement. The Trustee will
retain a nationally recognized investment banking firm (the "Advisor") on behalf
of the Trust who will assist the Trustee in selling the remaining Royalty
Interests. The Company has the right, but not the obligation, within 60 days
following the Termination Date, to make a cash offer to purchase all of the
remaining Royalty Interests then held by the Trust. In the event such an offer
is made by the Company, the Trustee will decide, based on the recommendation of
the Advisor, to either (i) accept such offer (in which case no sale to the
Company will be made unless a fairness opinion is given by the Advisor that the
purchase price is fair to the Unitholders) or (ii) defer action on the offer for
approximately 60 days and seek to locate other buyers for the remaining Royalty
Interests. If the Trustee defers action on the Company's offer, the offer will
be deemed withdrawn and the Trustee will then use its best efforts, assisted by
the Advisor, to locate other buyers for the Royalty Interests. At the end of the
120-day period following the Termination Date, the Trustee is required to notify
the Company of the highest of any other offers acceptable to the Trustee (which
must be an all cash offer) received during such period (such price, net of any
commissions or other fees payable by the Trust, the "Highest Acceptable Offer").
The Company then has the right (whether or not it made an initial offer), but
not the obligation, to purchase all remaining Royalty Interests for a cash
purchase price computed as follows: (i) if the Highest Acceptable Offer is more
than 105 percent of the Company's original offer (or if the Company did not make
an initial offer), the purchase price will be 105 percent of the Highest
Acceptable Offer, or (ii) if the Highest Acceptable Offer is equal to or less
than 105 percent of the Company's original offer, the purchase price will be
equal to the Highest Acceptable Offer. If no other acceptable offers are
received for all remaining Royalty Interests, the Trustee may request the
Company to submit another offer for consideration by the Trustee and may accept
or reject such offer.
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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 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
7
<PAGE> 11
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 13, 1999, 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).
9
<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 662/3 percent of the outstanding Units, no provision of the
Trust Agreement may be amended with respect to (a) the sale or disposition of
all or any part of the Trust estate, including the Royalty Interests, except as
specifically provided in the Trust Agreement, (b) termination of the Trust and
the disposition of Trust assets upon liquidation of the Trust or (c) the
Company's right of first refusal with respect to the purchase of any remaining
Royalty Interests upon termination of the Trust. Without the written consent of
Dominion Resources and the approval of a majority of the outstanding Units, no
amendment may be made to the Trust Agreement that would alter Dominion
Resources' conditional right to repurchase all outstanding Units at any time at
which 15 percent or less of the outstanding Units is owned by persons or
entities other than Dominion Resources or its affiliates. Additionally, any
amendment that increases the obligations, duties or liabilities of or affects
the rights of the Trustee or the Delaware Trustee must be consented to by such
entity. The Trustee, the Delaware Trustee, Dominion Resources and the Company
may, without approval of the Unitholders, from time to time supplement or amend
the Trust Agreement in order to cure any ambiguity or to correct or supplement
any defective or inconsistent provisions, provided 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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<PAGE> 17
<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 1998,
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
1998, the available Section 29 tax
credit is approximately $1.385503
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 1998 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
1998 to materially differ from the
Trustee's estimates contained in
the 1998 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 and 1997
composite income tax returns with the DOR on behalf of all Nonresident
Unitholders (defined below), and intends to file a composite return for 1998
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 1998. Accordingly,
no Alabama state income tax is due under the 1998 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 1998 (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.
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.
18
<PAGE> 22
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 in exercising its rights to abandon a well and may accelerate the
termination of the Trust. See "Properties--The Royalty Interests--Sale and
Abandonment of Underlying Properties" and "Properties--Description of the
Trust--Termination and Liquidation of the Trust."
Water from the operations on the Underlying Properties is discharged
into the Black Warrior River pursuant to a National Pollutant Discharge
Elimination System permit issued by the Alabama Department of Environmental
Management ("ADEM"). ADEM initially issued five permits in connection with the
Underlying Properties which were consolidated into one permit in February 1994.
The ADEM permit, which expires in July 1999, generally authorizes
19
<PAGE> 23
water disposal based upon the Black Warrior River's minimum flow rate and
maximum chloride level. The Company has advised the Trust that it has applied
for and expects to receive a new permit to take effect upon the expiration of
the existing permit. 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 $296,500 during 1999 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, 1998, 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, 1998, 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 expires in July 1999. The Company has advised
the Trust that it has applied for and expects to receive a new permit to take
effect upon the expiration of the existing permit. The ADEM permit generally
authorizes water disposal based upon the Black Warrior River's minimum flow rate
and maximum chloride level. The Company has advised the Trust that since 1987
water disposal from the Underlying Properties has not been disrupted. Although
the facilities of the Company have the capacity to store several days of water
production, if water disposal into the Black Warrior River is disrupted, natural
gas production from the wells on the Underlying Properties would be curtailed
during the period of such disruption. See "Business--Regulation and
Prices--Environmental Regulation."
Curtailments. The Company has advised the Trust that, during 1998,
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
23
<PAGE> 27
Interests' share of property, production and related taxes (including severance
taxes) and pays the same on behalf of the Trust.
RESERVE ESTIMATE
Reserve Estimate. The following table summarizes net proved reserves
estimated as of January 1, 1999, 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, 1999
----------------- ---------------
<S> <C>
Net Proved Natural Gas Reserves (mmcf)(a)(b):
Developed Producing ................................... 74,679
========
Estimated Future Net Revenues (in thousands) (a)(c):
1999 .................................................. $ 18,809
2000 .................................................. 16,649
2001 .................................................. 14,728
2002 .................................................. 13,055
2003 .................................................. 11,180
Thereafter ............................................ 74,214
--------
Total ............................................ $148,635
========
Total Discounted at 10 Percent ................... $ 88,932
========
</TABLE>
- - -------------------------
(a) The estimates of reserves and future net revenues summarized in this table
are based upon an unescalated price of $2.12 per MCF, which was the price
being received by the Company under the Gas Purchase Agreement as of
December 31, 1998. 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 gas producing properties, coal seam gas producing properties in
general, and the Underlying Properties in particular,
24
<PAGE> 28
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 9.5 Bcf in 1999 to 5.6 Bcf in 2003.
Tax Credits Based on Reserves. Based upon the production estimates used
in the Reserve Estimate for the January 1, 1999 through December 31, 2002
period, and assuming constant future Section 29 tax credits at the estimated
1999 rate of $1.07 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 $34.3 million, having a discounted present
value (assuming a 10 percent discount rate) of approximately $27.6 million.
Miscellaneous. Ryder Scott has delivered to the Trust the Reserve
Estimate, a summary of which is included as an exhibit to this Form 10-K.
Information concerning historical changes in net proved developed reserves
attributable to the Royalty Interests, and the calculation of the standardized
measure of discounted future net revenues related thereto, is contained in Note
8 of the Notes to the Financial Statements incorporated by reference in Item 8
hereof. Dominion Resources has not filed reserve estimates covering the Royalty
Interests with any other federal authority or agency.
NATURAL GAS SALES PRICES AND PRODUCTION
The following table sets forth the actual net production volumes
attributable to the Royalty Interests, weighted average property, production
and related taxes and information regarding natural gas sales prices for the
years ended December 31, 1998, December 31, 1997 and December 31, 1996.
<TABLE>
<CAPTION>
Year ended Year ended Year ended
December 31, 1998 December 31, 1997 December 31, 1996
----------------- ----------------- -----------------
<S> <C> <C> <C>
Production attributable to the Royalty
Interests (Bcf)..................................... 10.6 11.3 11.9
Weighted average property, production and
related taxes (per Mcf)............................. $ .12 $ .13 $ .13
Average Contract Price (per Mcf)....................... $ 2.14 $ 2.40 $ 2.40
</TABLE>
GAS PURCHASE AGREEMENT
Sonat Marketing is required to purchase the Subject Gas pursuant to the
Gas Purchase Agreement. The Company has advised the Trust that the Gas Purchase
Agreement extends until December 31, 2001 and will be automatically renewed each
year unless terminated by either party. Pursuant to the Gas Purchase Agreement,
Sonat Marketing is obligated to purchase monthly up to the Monthly Base Quantity
designated in the Gas Purchase Agreement of the Subject Gas at the Contract
Price; a Premium over the Index Price. Until December 31, 1998, the Contract
Price was subject to a Minimum Price of $1.85 per MMBtu and a Maximum Price of
$2.63 per MMBtu. While the Minimum Price assured the Unitholder a minimum price
at which the Monthly Base Quantities of the Subject Gas must be purchased, until
January 1, 1999, Unitholders did not benefit from natural gas prices in excess
of $2.63 per MMBtu. From January 1, 1999 through December 31, 1999 the Contract
Price is subject to a Minimum Price of $2.16 per MMBtu and a Maximum Price of
$3.07 per MMBtu. 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
25
<PAGE> 29
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 shall equal 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 this
period, the price payable for Subject Gas in excess of the Monthly Fixed Price
Quantity shall equal the sum of the Index Price and $.02. The Company has
advised the Trust that at the end of the primary term or any extensions thereof,
Sonat Marketing will be obligated to purchase the Subject Gas at the Index Price
until such time as the Company and Sonat Marketing negotiate a different price,
and that the Company will have the ability to obtain an offer to purchase the
Subject Gas from another purchaser and terminate the Gas Purchase Agreement if
Sonat Marketing does not match such offer.
Sonat Marketing's obligation to purchase 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. In addition,
up to $10,000,000 of the payment obligations of Sonat Marketing under the Gas
Purchase Agreement are guaranteed by Sonat Marketing.
The Gas Purchase Agreement is filed as an exhibit to this Form 10-K, and
the foregoing summary of the material terms of such agreement is qualified in
its entirety by reference to the terms of such agreement as set forth in such
exhibit.
OPERATION OF PROPERTIES
No Control by Trust. Under the terms of the Conveyance, neither the
Trustee nor the Unitholders will be able to influence or control the operation
or future development of the Underlying Properties. Unitholders will therefore
be reliant on the Company and the other working interest owners to make all
decisions regarding operations on the Underlying Properties. The Trust will not
be able to appoint or control the appointment of operators.
The Conveyance does not prohibit the transfer of the Underlying
Properties by the Company, subject to and burdened by the Royalty Interests.
The Company and the other working interest owners of the Underlying Properties
will have the right, subject to certain restrictions, to abandon any well or
lease on the Underlying Properties under certain circumstances. Upon
abandonment of any such well or lease, that portion of the Royalty Interests
relating thereto will be extinguished. See "--Sale and Abandonment of the
Underlying Properties."
Operating Agreement. Pursuant to the Operating Agreement, River Gas
operates and maintains the Underlying Properties for the Company and the other
working interest owners. The Operating Agreement has a one-year term and will
be automatically renewed for additional one-year periods unless either party
provides written notice to the other party of its desire to terminate the
Operating Agreement at least six months prior to the date on which the
agreement is to terminate. Upon not less than 30 days' notice either River Gas
or the Company may terminate the Operating Agreement if: (i) the other party
has committed a material breach of the Operating Agreement, unless such breach
is cured in the manner specified in the Operating Agreement; (ii) the other
party files a petition for relief under federal
26
<PAGE> 30
or state bankruptcy laws, the other party's insolvency is determined by a final
court proceeding, the other party's filing of a petition or application to
accomplish such a result or for the appointment of a receiver or trustee for
such party or for a substantial part of its assets or commencement of any
proceedings relating to the other party under any other reorganization,
arrangement, insolvency, adjustment of debt or liquidation law of any
jurisdiction; provided, however, that if such proceeding is not commenced, the
proceeding will not give rise to a right to terminate the Operating Agreement
unless such party consents or such proceeding has not been finally dismissed
within 90 days after its commencement; or (iii) after good faith negotiations
River Gas and the Company and the other working interest owners cannot agree on
an annual operating plan or budget for any year.
While the Operating Agreement is in effect, all of the production
attributable to the Company Interests will be gathered, treated and processed
by River Gas pursuant to the Operating Agreement. Such production will be
gathered at the wellhead and transported to the central delivery points in the
gathering system for the Underlying Properties, which is owned by the Company
and the other working interest owners.
Under the terms of the Operating Agreement, River Gas owes a duty to the
Company and the other working interest owners to conduct the operations on the
Underlying Properties in a good and workmanlike manner and following practices
that (i) are engaged in or accepted by a significant portion of the natural gas
production industry at the time the decision was made or (ii) in the exercise
of reasonable judgment in light of the facts known at the time the decision was
made would have been expected to accomplish the desired result at a reasonable
cost consistent with reliability, safety, expeditiousness and protection of the
environment. River Gas has no direct contractual or fiduciary duty to protect
the interests of the Trust or the Unitholders.
SALE AND ABANDONMENT OF UNDERLYING PROPERTIES
The Company has the right to abandon any well or lease included in the
Underlying Properties if, in its opinion, acting as would a reasonably prudent
operator, such well or lease is not capable of producing Gas in commercial
quantities (determined before giving effect to the Royalty Interests). Neither
the Trust nor the Unitholders will control the timing of the plugging and
abandoning of any wells. Through December 31, 1998, 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.
27
<PAGE> 31
All of Dominion Resources' obligations will terminate upon: (i) the
termination and cancellation of the Trust, (ii) the sale or other transfer by
the Company of all or substantially all of the Company's interest in the
Underlying Properties subject to the terms of the Trust Agreement and (iii) the
sale or other transfer of a majority of Dominion Resources' direct or indirect
equity ownership interest in the Company; provided that, with respect to
clauses (ii) and (iii) above, Dominion Resources' obligations will terminate
only if: (a) the transferee has a specified credit rating or the transferee
together with an affiliate which guarantees the transferee's obligations has
not less than a specified net worth or (b) the transferee is approved by the
holders of a majority of the outstanding Units; and provided further, that in
the case of clauses (ii) or (iii) above the transferee also unconditionally
agrees in writing, in form and substance reasonably satisfactory to the
Trustee, to assume Dominion Resources' remaining obligations under the Trust
Agreement with respect to the assets transferred and under the Administrative
Services Agreement.
TITLE TO PROPERTIES
Alabama counsel to Dominion Resources and the Company has opined that
the Company's title to its interest in the Underlying Properties, and the
Trust's title to the Royalty Interests, are good and defensible in accordance
with standards generally accepted in the natural gas industry, subject to such
exceptions which, in the opinion of Alabama counsel, are not so material as to
detract substantially from the use or value of the Company Interests or the
Royalty Interests.
Although the matter is not entirely free from doubt, Alabama counsel has
opined that the Royalty Interests constitute interests in real property under
Alabama law. Consistent therewith, the Conveyance states that the Royalty
Interests constitute real property interests. The Company has recorded the
Conveyance in the appropriate real property records of Alabama in accordance
with local recordation provisions. If, during the term of the Trust, the
Company or any Company Interests Owner becomes involved as a debtor in
bankruptcy proceedings under the Federal Bankruptcy Code, it is not entirely
clear that the Royalty Interests would be treated as real property interests
under the laws of Alabama.
ITEM 3. LEGAL PROCEEDINGS.
There are no material pending legal proceedings to which the Trust is a
party or of which any of its property is the subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
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>
1998
First Quarter .................................... $ 21 - 1/4 $ 18 - 3/8 $ .874821
Second Quarter ................................... 22 - 3/4 19 - 7/8 .670386
Third Quarter .................................... 21 - 11/16 16 - 7/8 .672017
Fourth Quarter ................................... 20 - 1/8 12 - 7/8 .614702
1997
First Quarter .................................... $ 22 - 3/4 $ 20 - 1/2 $ .844175
Second Quarter ................................... 23 - 1/2 21 .808040
Third Quarter .................................... 25 - 3/16 20 - 1/4 .692395
Fourth Quarter ................................... 22 - 7/8 20 .755724
</TABLE>
At March 15, 1999, there were 7,850,000 Units outstanding and approximately
1,242 Unitholders of record.
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
FOR THE PERIOD
FROM MAY 31,
YEAR ENDED DECEMBER 31, 1994 (DATE OF
INCEPTION) TO
------------------------------------------------------------------------ DECEMBER 31,
1998 1997 1996 1995 1994
------------ ------------ ------------ ------------ -------------
<S> <C> <C> <C> <C> <C>
Royalty Income $ 22,849,760 $ 24,977,563 $ 26,013,428 $ 21,603,550 $ 7,596,511
Distributable Income $ 22,226,804 $ 24,338,026 $ 25,423,282 $ 20,947,426 $ 7,278,931
Distributable Income per Unit $ 2.83 $ 3.10 $ 3.24 $ 2.67 $ .93
Distributions per Unit $ 2.83 $ 3.10 $ 3.24 $ 2.66 $ .91
Total Assets, December 31 $ 85,645,529 $ 97,774,353 $109,761,403 $125,641,485 $139,641,366
Total corpus, December 31 $ 85,533,029 $ 97,670,701 $109,562,077 $125,545,839 $139,471,673
</TABLE>
ITEM 7. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
The Trust collects the proceeds attributable to the Royalty Interests
and makes quarterly cash distributions to Unitholders. The only assets of the
Trust, other than cash and cash equivalents being held for the payment of
expenses and liabilities and for distribution to Unitholders, are the Royalty
Interests. The Royalty Interests owned by the Trust burden the interest in the
Underlying Properties that is owned by the Company.
The Royalty Interests consists of overriding royalty interests burdening
the Company's interest in the Underlying Properties. The Royalty Interests
generally entitle the Trust to receive 65 percent of the Gross Proceeds (as
defined below) during the preceding calendar quarter. The Royalty Interests are
non-operating interests and bear only expenses related to property, production
and related taxes (including severance taxes). "Gross Proceeds" consist
generally of the aggregate amounts received by the Company attributable to the
interests of the Company in the Underlying Properties from the sale of coal
seam gas at the central delivery points in the gathering system for the
Underlying Properties.
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 for
them. Consequently, the reported distributable income of the Trust for any year
is determined by deducting from the income received by the Trust the amount of
expenses paid by the Trust during such year. The amount of cash available for
distribution to Unitholders is determined after adjustment for changes in
reserves for unpaid liabilities in accordance with the provisions of the Trust
Agreement. (See Note 5 to the financial statements of the Trust appearing
elsewhere in this Form 10-K for additional information regarding the
determination of the amount of cash available for distribution to Unitholders.)
The year 1998 marked the fourth full year of the existence of the Trust.
The Trust received royalty income amounting to $22,849,760 during the year
ended December 31, 1998 compared to $24,977,563 for 1997 and $26,013,428 for
1996. 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, 1998 remained
relatively stable at $699,832 compared to $713,380 for 1997 and $656,019 for
1996. Distributable income for the year ended December 31, 1998 was $22,226,804
or $2.83 per Unit compared to $24,338,026 or $3.10 per Unit for 1997 and
$25,423,282 or $3.24 per Unit for 1996.
Royalty income to the Trust is attributable to the sale of depleting
assets. All of the Underlying Properties burdened by the Royalty Interests
consist of producing properties. Accordingly, the proved reserves attributable
to the Company's interest in the Underlying Properties are expected to decline
substantially during the term of the Trust and a portion of each cash
distribution made by the Trust will, therefore, be analogous to a return of
capital. Accordingly, cash yields attributable to the Units are expected to
decline over the term of the Trust. The decreases in royalty income and
distributable income noted in the preceding paragraph were due primarily to the
depletion of reserves and to a decrease in the average prices received for gas
attributable to the Royalty Interests.
Royalty Income received by the Trust in a given calendar year will
generally reflect the proceeds from the sale of gas produced from the
Underlying Properties during the first three quarters of that year and the
fourth quarter of the preceding calendar year due to the timing of the receipt
of these revenues. Accordingly, the royalty income included in distributable
income for the years ended December 31, 1998, 1997 and 1996, was based on
production volumes and natural gas prices for the periods from October 1, 1997
to September 30, 1998, October 1, 1996 through September 30, 1997 and October
1, 1995 to September 30, 1996, respectively.
The following table sets forth the production volumes attributable to
the Trust's Royalty Interests and the average sales Price and Index Price for
such production for the periods indicated.
<TABLE>
<CAPTION>
FOR 12 MONTHS ENDED SEPTEMBER 30,
-----------------------------------
1998 1997 1996
- - ------------------------------------------------------------------------------------
<S> <C> <C> <C>
Production (Bcf)(1) 10.588 11.515 12.031
Production (MMBtu)(2) 10.494 11.404 11.907
Average Contract Price Received ($/MMBtu) $ 2.29 $ 2.32 $ 2.31
Average Index Price ($/MMBtu) $ 2.35 $ 2.48 $ 2.18
</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.
30
<PAGE> 34
Sonat Marketing is required to purchase the Subject Gas pursuant to the
Gas Purchase Agreement. The Company has advised the Trust that the Gas Purchase
Agreement extends until December 31, 2001 and will be automatically renewed each
year unless terminated by either party. Pursuant to the Gas Purchase Agreement,
Sonat Marketing is obligated to purchase monthly up to the Monthly Base Quantity
designated in the Gas Purchase Agreement of the Subject Gas at the Contract
Price; a Premium over the Index Price. Until December 31, 1998, the Contract
Price was subject to a Minimum Price of $1.85 per MMBtu and a Maximum Price of
$2.63 per MMBtu. While the Minimum Price assured the Unitholder a minimum price
at which the Monthly Base Quantities of the Subject Gas must be purchased, until
January 1, 1999, Unitholders did not benefit from natural gas prices in excess
of $2.63 per MMBtu. From January 1, 1999 through December 31, 1999 the Contract
Price is subject to a Minimum Price of $2.16 per MMBtu and a Maximum Price of
$3.07 per MMBtu. 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 shall equal 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 this period, the price payable for Subject Gas in excess of
the Monthly Fixed Price Quantity shall equal the sum of the Index Price and
$.02. The Company has advised the Trust that at the end of the primary term or
any extensions thereof, Sonat Marketing will be obligated to purchase the
Subject Gas at the Index Price until such time as the Company and Sonat
Marketing negotiate a different price, and that the Company will have the
ability to obtain an offer to purchase the Subject Gas from another purchaser
and terminate the Gas Purchase Agreement if Sonat Marketing does not match such
offer.
The net proved reserves attributable to the Royalty Interests have been
estimated as of December 31, 1998, 1997, 1996 and 1995, by independent
petroleum engineers. The reserve quantities of 74.7 Bcf for 1998 compared to
94.5 Bcf for 1997, 82.4 Bcf for 1996 and 74.8 Bcf for 1995 reflect a decline in
reserves between 1997 and 1998 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 upcoming change in the century. If not corrected,
many computer applications could fail or create erroneous results by or at the
Year 2000. The Year 2000 issue affects virtually all companies and
organizations. If a company or organization does not successfully address its
Year 2000 issues, it may face material adverse consequences. The Trustee has
identified the General Ledger/Accounts Payable System as the primary system
that is vulnerable to the Year 2000 issue. The current system is Year 2000
compliant. The Trust selected a system that has been warranted to be Year 2000
compliant and completed the installation of the new system at the beginning of
1998. The cost of the system was approximately $6,000. To date the Trustee has
incurred no other costs in connection with its efforts to identify, assess,
remediate and test the Trust's systems for Year 2000 compliance.
The Trustee is in the process of identifying and assessing other
information technology ("IT") systems used in connection with the Trust as well
as other systems for Year 2000 compliance. Non-IT systems are generally more
difficult to assess because they often contain embedded technology that may be
subject to Year 2000 problems. The total cost of the Trustee's Year 2000
efforts is expected to be approximately $10,000 (including the $6,000 referred
to above), all of which was incurred and paid during the last quarter of 1998
and the first quarter of 1999. Of this amount, the Trustee has paid $4,000 for
identification and assessment of affected systems.
The Trustee has additionally identified those vendors it believes could
have an impact on its day-to-day operations if their operations were
interrupted as a result of Year 2000 problems. The Trustee has developed a
questionnaire regarding the vendor's Year 2000 status.
The Trustee has no reason to believe that its vendors will not be Year
2000 compliant. In the event the Trustee learns that a vendor's system will not
be Year 2000 compliant, the Trustee will assess the potential risk and develop
contingency plans at that time.
The Trust is a passive entity with no business operations, and the IT
systems employed by the Trustee in connection with its duties on behalf of the
Trust are less extensive than the systems employed by many business entities.
The Trust has no formal IT budget, and the Trustee does not anticipate making
any other significant expenditures relating to the Trustee's IT systems used in
connection with Trust during 1999. Thus, the expenditures expected to be
31
<PAGE> 35
made in connection with the Year 2000 efforts described above will represent
substantially all of the Trustee's IT-related expenditures on behalf of the
Trust during 1998 and 1999. These expenditures will be treated as Trust
expenses on the financial statements of the Trust.
Because the royalty interests held by the Trust are fixed, the Trustee
is dependent upon the third parties (primarily energy companies) that hold
operating interests with respect thereto for the receipt of royalty income.
Thus, if any such third party failed to deliver royalty income, the Trustee
would have available no alternative source for such income. The Trustee
believes that the worst case scenario would be the failure by the Trustee and
one or more third parties who pay royalties to the trust to identify or
remediate Year 2000 problems on a timely basis, which could cause the Trustee
to be unable to make required distributions to Unitholders. Such inability
could result in the incurrence by the Trust of interest charges or other
liabilities to Unitholders. The Trustee believes that in the event of a failure
of any of its internal systems it would be able to replace such systems in a
relatively short period of time, relying on internal resources of NationsBank,
N.A., which serves as the Trustee, although there can be no assurance that such
replacement would not be costly or that it would be completed without resulting
in a significant delay in the distributions to Unitholders. With respect to a
failure by a third party to deliver royalty income on a timely basis, the
Trustee believes that it would have no control over the efforts of such third
party to correct the problems, and significant delays in the receipt of royalty
income could result.
The Trust will utilize both internal and external resources to achieve
Year 2000 compliance. The Trustee estimates that its identification and
assessment activities are approximately 80 percent complete. It expects that all
of its Year 2000 efforts related to the Trust's internal systems will be
completed by the end of the first quarter of 1999. However, there can be no
guarantee that the Trustee will be able to identify all potential Year 2000
problems or to fully remediate all Year 2000 problems identified on a timely
basis. There also can be no assurance that the systems of third party vendors on
which the Trust relies will be timely remediated. The failure by the Trustee or
any such third party to fully remediate its Year 2000 problems on a timely basis
could have a material adverse affect on the Trustee's ability to account for and
make timely distribution of the Trust's distributable income.
Certain of the statements made above regarding the Trustee's Year 2000
program are forward-looking statements, and there can be no assurance that the
Trustee will be able to achieve Year 2000 compliance in the manner and by the
dates indicated.
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
NationsBank, N.A., as Trustee of
Dominion Resources Black Warrior Trust
We have audited the accompanying statements of assets, liabilities and
trust corpus of Dominion Resources Black Warrior Trust (the "Trust") as of
December 31, 1998 and 1997, and the related statements of distributable income
and changes in trust corpus for each of the three years in the period ended
December 31, 1998. These financial statements are the responsibility of the
Trustee. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
As described in Note 2 to the financial statements, these statements were
prepared on a modified cash basis of accounting, which is a comprehensive basis
of accounting other than generally accepted accounting principles.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the assets, liabilities and trust corpus of Dominion
Resources Black Warrior Trust at December 31, 1998 and 1997, and the
distributable income and changes in trust corpus for each of the three years in
the period ended December 31, 1998, on the basis of accounting described in
Note 2.
DELOITTE & TOUCHE LLP
Dallas, Texas
March 15, 1999
33
<PAGE> 37
DOMINION RESOURCES BLACK WARRIOR TRUST
FINANCIAL STATEMENTS
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
December 31,
--------------------------
1998 1997
--------------------------
<S> <C> <C>
ASSETS
Cash and cash equivalents............................................. $ 59,455 $ 54,431
Royalty interests in gas properties (less accumulated
amortization of $70,231,426 and $58,097,578, respectively) ......... 85,586,074 97,719,922
----------- -----------
Total Assets................................................... $85,645,529 $97,774,353
=========== ===========
LIABILITIES AND TRUST CORPUS
Trust expenses payable................................................. $ 112,500 $ 103,652
Trust corpus (7,850,000 units of beneficial interest
authorized, issued and outstanding) ................................ 85,533,029 97,670,701
----------- -----------
Total Liabilities and Trust Corpus............................. $85,645,529 $97,774,353
=========== ===========
</TABLE>
STATEMENTS OF DISTRIBUTABLE INCOME
<TABLE>
<CAPTION>
For Year Ended
--------------------------------------------------------
December 31, 1998 December 31, 1997 December 31,1996
----------------- ----------------- ----------------
<S> <C> <C> <C>
Royalty income .................................... $22,849,760 $24,977,563 $ 26,013,428
Interest income ................................... 76,876 73,843 65,873
----------- ----------- -----------
22,926,636 25,051,406 26,079,301
General and administrative expenses ............... 699,832 713,380 656,019
----------- ----------- -----------
Distributable income .............................. $22,226,804 $24,338,026 $ 25,423,282
=========== =========== ============
Distributable income per unit (7,850,000 units).... $ 2.83 $ 3.10 $ 3.24
=========== =========== ============
Distributions per unit ............................ $ 2.83 $ 3.10 $ 3.24
=========== =========== ============
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
For Year Ended
--------------------------------------------------------
December 31, 1998 December 31, 1997 December 31,1996
----------------- ----------------- ----------------
<S> <C> <C> <C>
Trust corpus, beginning of period .... $ 97,670,701 $ 109,562,077 $ 125,545,839
Amortization of royalty interests .... (12,133,848) (11,891,773) (16,005,268)
Distributable income ................. 22,226,804 24,338,026 25,423,282
Distributions to Unitholders ......... (22,230,628) (24,337,629) (25,401,776)
------------- ------------- -------------
Trust corpus, end of period .......... $ 85,533,029 $ 97,670,701 $ 109,562,077
============= ============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
34
<PAGE> 38
NOTES TO FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1. TRUST ORGANIZATION AND PROVISIONS
Dominion Resources Black Warrior Trust (the "Trust") was formed as a
Delaware business trust pursuant to the terms of the Trust Agreement of
Dominion Resources Black Warrior Trust (as amended, the "Trust Agreement"),
entered into effective as of May 31, 1994, among Dominion Black Warrior Basin,
Inc., an Alabama corporation (the "Company"), as trustor, Dominion Resources,
Inc., a Virginia corporation ("Dominion Resources"), and NationsBank, 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.
Effective May 6, 1998, NationsBank of Texas, N.A., of Dallas, Texas,
merged with NationsBank, N.A., of Charlotte, North Carolina. NationsBank, N.A.,
as survivor of the merger, has assumed by operation of law all rights,
properties and interests of NationsBank of Texas, N.A., including all rights
and interests as trustee, executor or administrator or in other fiduciary
capacities, in the same manner and to the same extent as such rights,
properties and interests were held by NationsBank of Texas, N.A. at the time of
the merger. In accordance with applicable law and the provisions of the Trust
Agreement, NationsBank, N.A., as successor to NationsBank of Texas, N.A., now
serves as Trustee of the Trust. NationsBank, N.A. is performing such functions
through its Dallas, Texas, branch office, which is the former principal office
of NationsBank of Texas, N.A.
The Trust is a grantor trust formed to acquire and hold certain
overriding royalty interests (the "Royalty Interests") burdening proved natural
gas properties located in the Pottsville coal formation of the Black Warrior
Basin, Tuscaloosa County, Alabama (the "Underlying Properties") owned by 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 1997,
Statement of Financial Accounting Standard ("SFAS") No. 131, "Disclosures about
Segments of an Enterprise and Related Information," which establishes standards
for the way public companies disclose information about operating segments,
products and services, geographic areas and major customers. SFAS No. 131 is
effective for financial statements for periods beginning after December 15,
1997. SFAS No. 131 has no effect on the Trust's reporting since it operates
solely in the United States.
In June 1998, the FASB issued 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 all fiscal
quarters for all fiscal years beginning after June 15, 1999. The Trust has not
completed the process of evaluating the impact, if any, that 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, qualifies upon the sale of such production for the
Federal income tax credit for producing nonconventional fuels under Section 29
of the Internal Revenue Code. This tax credit is calculated annually based on
sales of qualified production for each year through the year 2002. Such credit,
based on the Unitholder's pro rata share of qualifying production, may not be
used to reduce his regular tax liability (after the foreign tax credit and
certain other non-refundable credits) below his alternative minimum tax. Any
part of the Section 29 credit not allowed for any tax year solely because of
this limitation is subject to certain carryover provisions. Each Unitholder
should consult their tax advisor regarding tax consequences.
4. RELATED PARTY TRANSACTIONS
Dominion Resources provides accounting, bookkeeping and informational
services to the Trust in accordance with an Administrative Services Agreement
effective June 1, 1994. During 1998 this fee was $342,515 and will increase
annually by three percent. Aggregate fees paid by the Trust to Dominion
Resources in 1998, 1997 and 1996 were $342,515, $327,561 and $318,270,
respectively.
Aggregate fees and expense reimbursements paid by the Trust to the
trustees in 1998, 1997 and 1996 were $33,765, $32,756 and $36,853,
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
37
<PAGE> 41
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 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, 1998, the Trust declared and paid the
following distribution:
<TABLE>
<CAPTION>
QUARTERLY DISTRIBUTION
RECORD DATE PAYMENT DATE PER UNIT
- - --------------------- ---------------------- --------------------
<S> <C> <C>
March 1, 1999 March 11, 1999 $.600257
</TABLE>
The trustee has estimated the Section 29 tax credit associated with the
March 11, 1999 quarterly distribution to be $.32 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, 1998 and 1997 (in thousands, except per Unit amounts):
<TABLE>
<CAPTION>
ROYALTY DISTRIBUTABLE DISTRIBUTABLE
CALENDAR QUARTER INCOME INCOME INCOME PER UNIT
- - ---------------- -------- ------------- ---------------
<S> <C> <C> <C>
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
========== ========== =========
1997
First......................... $ 6,797 $ 6,616 $ .84
Second........................ 6,537 6,313 .80
Third......................... 5,597 5,469 .70
Fourth........................ 6,047 5,940 .76
---------- ---------- ---------
$ 24,978 $ 24,338 $ $3.10
========== ========== =========
</TABLE>
Selected 1998 fourth quarter data are as follows (in thousands, except per
Unit amounts):
<TABLE>
<S> <C>
Royalty income.......................... $ 4,958
Interest income......................... 17
General and administrative expenses..... (152)
------------
Distributable income.................... $ 4,823
===========
Distributable income per Unit........... $ .61
===========
Distributions per Unit.................. $ .61
===========
</TABLE>
Due to significant revisions in estimates of reserve quantities at year
end (see Note 8), estimated amortization of royalty interests was increased
by approximately $1.2 million and decreased approximately $3.4 million during
the fourth quarters of 1998 and 1997, respectively. This adjustment did not have
an impact on the Trust's distributable income.
8. SUPPLEMENTAL GAS DISCLOSURE (UNAUDITED)
The net proved reserves attributable to the Royalty Interests have
been estimated as of December 31, 1998, 1997 and 1996 and January 1, 1996 by
independent petroleum engineers.
In accordance with Statement of Financial Accounting Standards No. 69,
estimates of proved reserves and future net cash flows from proved reserves
have been prepared using contractually guaranteed prices and end-of-period
natural gas prices, and related costs. The standardized measure of future net
cash flows from the gas reserves is calculated based on discounting such future
net cash flows at an annual rate of 10 percent. The prices for December 31,
1998, 1997 and 1996 and January 1, 1996 were $2.12, $2.55, $2.81 and $2.26 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, 1996.............. 74,841
Revisions of previous estimates.................. 19,484
Production....................................... (11,937)
--------
Proved developed reserves at December 31, 1996............ 82,388
Revisions of previous estimates.................. 23,380
Production....................................... (11,302)
--------
Proved developed reserves at December 31, 1997............ 94,466
Revisions of previous estimates.................. (9,458)
Production....................................... (10,329)
--------
Proved developed reserves at December 31, 1998............ 74,679
========
</TABLE>
All proved reserve estimates presented above at December 31, 1998,
1997 and 1996 and January 1, 1996 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, 1998, 1997
and 1996 relating to the Trust's Royalty Interests (thousands of dollars):
<TABLE>
<CAPTION>
1998 1997 1996
---------- ---------- ---------
<S> <C> <C> <C>
Future cash inflows..................................... $ 158,122 $ 241,346 $ 231,734
Future taxes............................................ (9,487) (14,481) (13,904)
--------- ---------- ----------
Future net cash flows................................... 148,635 226,865 217,830
10% annual discount for estimated timing
of cash flow................................... $ (59,703) (97,941) (83,155)
--------- ---------- ----------
Standardized measure of discounted
future net cash flows............................. $ 88,932 $ 128,924 $ 134,675
========= ========== ==========
</TABLE>
Future cash flows do not include Section 29 tax credits which in the
aggregate are estimated to be approximately $34,346,000 having a discounted
present value (assuming a 10% discounted rate) of approximately $27,611,000 at
December 31, 1998.
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, 1998, 1997 and 1996 (thousands of dollars):
<TABLE>
<CAPTION>
1998 1997 1996
---------- ---------- -----------
<S> <C> <C> <C>
Balance at beginning of period............................ $ 128,924 $ 134,675 $ 100,386
Increase (decrease) due to:
Royalty income, net of taxes......................... (21,722) (25,096) (27,091)
Changes in prices.................................... (16,723) (21,421) 17,516
Changes in estimated volumes......................... (14,439) 27,298 33,826
Accretion of discount................................ 12,892 13,468 10,038
---------- ---------- -----------
Balance at December 31.................................... $ 88,932 $ 128,924 $ 134,675
========== ========== ===========
</TABLE>
40
<PAGE> 44
As of March 29, 1999, published natural gas prices were approximately
$1.82 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 is required to purchase the Subject Gas pursuant to the Gas
Purchase Agreement. The Company has advised the Trust that the Gas Purchase
Agreement extends until December 31, 2001 and will be automatically renewed each
year unless terminated by either party. Pursuant to the Gas Purchase Agreement,
Sonat Marketing is obligated to purchase monthly up to the Monthly Base Quantity
designated in the Gas Purchase Agreement of the Subject Gas at the Contract
Price; a Premium over the Index Price. Until December 31, 1998, the Contract
Price was subject to a Minimum Price of $1.85 per MMBtu and a Maximum Price of
$2.63 per MMBtu. While the Minimum Price assured the Unitholder a minimum price
at which the Monthly Base Quantities of the Subject Gas must be purchased, until
January 1, 1999, Unitholders did not benefit from natural gas prices in excess
of $2.63 per MMBtu. From January 1, 1999 through December 31, 1999 the Contract
Price is subject to a Minimum Price of $2.16 per MMBtu and a Maximum Price of
$3.07 per MMBtu. 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 shall equal 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 this period, the price payable for Subject Gas in excess of
the Monthly Fixed Price Quantity shall equal the sum of the Index Price and
$.02. The Company has advised the Trust that at the end of the primary term or
any extensions thereof, Sonat Marketing will be obligated to purchase the
Subject Gas at the Index Price until such time as the Company and Sonat
Marketing negotiate a different price, and that the Company will have the
ability to obtain an offer to purchase the Subject Gas from another purchaser
and terminate the Gas Purchase Agreement if Sonat Marketing does not match such
offer.
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 1998, the Trustee and the Delaware Trustee received total
compensation of $33,765 and $6,250, 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 15, 1999, neither NationsBank, 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 $342,000 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,
1998 and 1997
Statements of Distributable Income for the years ended December 31,
1998, 1997 and 1996
Statements of Changes in Trust Corpus for the years ended December 31,
1998, 1997 and 1996
Notes to Financial Statements
2. Financial Statement Schedules
Financial statement schedules are omitted because of the absence of
conditions under which they are required or because the required information is
included in the financial statements and notes thereto.
3. Exhibits
<TABLE>
<CAPTION>
Exhibit
Number Exhibit
- - ------- -------
<S> <C>
3.1 -- Trust Agreement of Dominion Resources Black Warrior Trust dated as
of May 31, 1994, by and among Dominion Black Warrior Basin, Inc.,
Dominion Resources, Inc., Mellon Bank (DE) National Association and
NationsBank, N.A. (as successor to NationsBank of Texas, N.A.)
(filed as Exhibit 3.1 to Dominion Resources, Inc.'s Registration
Statement* on Form S-3 (No. 33-53513), and incorporated herein by
reference).
3.2 -- First Amendment of Trust Agreement of Dominion Resources Black
Warrior Trust dated as of June 27, 1994, by and among Dominion
Black Warrior Basin, Inc., Dominion Resources, Inc., Mellon Bank
(DE) National Association and NationsBank, N.A. (as successor to
NationsBank of Texas, N.A.) (filed as Exhibit 3.2 to the
Registrant's Form 10-Q for the quarter ended June 30, 1994 and
incorporated herein by reference).
10.1 -- Overriding Royalty Conveyance dated as of June 28, 1994, from
Dominion Black Warrior Basin, Inc. to Dominion Resources Black
Warrior Trust (filed as Exhibit 10.1 to the Registrant's Form 10-Q
for the quarter ended June 30, 1994 and incorporated herein by
reference).
10.2 -- Administrative Services Agreement dated as of June 1, 1994, by
and between Dominion Resources, Inc. and Dominion Resources Black
Warrior Trust (filed as Exhibit 10.2 to the Registrant's Form 10-Q
for the quarter ended June 30, 1994 and incorporated herein by
reference).
10.3 -- Amendment to and Ratification of Overriding Royalty Conveyance
dated as of November 20, 1994, among Dominion Black Warrior Basin,
Inc., NationsBank, N.A. (as successor to NationsBank of Texas,
N.A.), and Mellon Bank (DE) National Association (filed as Exhibit
10.3 to the Registrant's Form 10-K for the year ended December 31,
1994 and incorporated herein by reference).
</TABLE>
44
<PAGE> 48
<TABLE>
<S> <C>
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.
23.1 -- Consent of Ryder Scott Company Petroleum Engineers, independent
petroleum engineers.
27.1 -- Financial Data Schedule.
99.1 -- Summary of Reserve Report, dated March 5, 1999, on the estimated
reserves, estimated future net revenues and the discounted estimated
future net revenues attributable to the Royalty Interests as of
January 1, 1999, prepared by Ryder Scott Company Petroleum
Engineers, independent petroleum engineers.
</TABLE>
- - ----------
* On its own behalf and as sponsor of the Dominion Resources Black Warrior
Trust
(b) Reports on Form 8-K. No report on Form 8-K was filed by the Registrant
during the last quarter of the period covered by this report.
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: NATIONSBANK, N.A., TRUSTEE
By: /s/ RON E. HOOPER
-------------------------------------
RON E. HOOPER
VICE PRESIDENT AND ADMINISTRATOR
Date: March 31, 1999
(THE REGISTRANT HAS NO DIRECTORS OR EXECUTIVE OFFICERS.)
<PAGE> 50
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
Number Exhibit
- - ------- -------
<S> <C>
3.1 -- Trust Agreement of Dominion Resources Black Warrior Trust dated as
of May 31, 1994, by and among Dominion Black Warrior Basin, Inc.,
Dominion Resources, Inc., Mellon Bank (DE) National Association and
NationsBank, N.A. (as successor to NationsBank of Texas, N.A.)
(filed as Exhibit 3.1 to Dominion Resources, Inc.'s Registration
Statement* on Form S-3 (No. 33-53513), and incorporated herein by
reference).
3.2 -- First Amendment of Trust Agreement of Dominion Resources Black
Warrior Trust dated as of June 27, 1994, by and among Dominion
Black Warrior Basin, Inc., Dominion Resources, Inc., Mellon Bank
(DE) National Association and NationsBank, N.A. (as successor to
NationsBank of Texas, N.A.) (filed as Exhibit 3.2 to the
Registrant's Form 10-Q for the quarter ended June 30, 1994 and
incorporated herein by reference).
10.1 -- Overriding Royalty Conveyance dated as of June 28, 1994, from
Dominion Black Warrior Basin, Inc. to Dominion Resources Black
Warrior Trust (filed as Exhibit 10.1 to the Registrant's Form 10-Q
for the quarter ended June 30, 1994 and incorporated herein by
reference).
10.2 -- Administrative Services Agreement dated as of June 1, 1994, by
and between Dominion Resources, Inc. and Dominion Resources Black
Warrior Trust (filed as Exhibit 10.2 to the Registrant's Form 10-Q
for the quarter ended June 30, 1994 and incorporated herein by
reference).
10.3 -- Amendment to and Ratification of Overriding Royalty Conveyance
dated as of November 20, 1994, among Dominion Black Warrior Basin,
Inc., NationsBank, N.A. (as successor to NationsBank of Texas,
N.A.), and Mellon Bank (DE) National Association (filed as Exhibit
10.3 to the Registrant's Form 10-K for the year ended December 31,
1994 and incorporated herein by reference).
10.4 -- 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.
23.1 -- Consent of Ryder Scott Company Petroleum Engineers, independent
petroleum engineers.
27.1 -- Financial Data Schedule.
99.1 -- Summary of Reserve Report, dated March 5, 1999, on the estimated
reserves, estimated future net revenues and the discounted estimated
future net revenues attributable to the Royalty Interests as of
January 1, 1999, prepared by Ryder Scott Company Petroleum
Engineers, independent petroleum engineers.
</TABLE>
- - ----------
* On its own behalf and as sponsor of the Dominion Resources Black Warrior
Trust
<PAGE> 1
EXHIBIT 10.6
AMENDMENT TO THE
GAS PURCHASE AGREEMENT
DATED MAY 3, 1994
THIS AMENDMENT (the "April 1998" Amendment), made and entered into as
of the 9th day of April 1998, 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, and May 16, 1996
(the "1994 Agreement"); and
WHEREAS, Buyer and Seller desire to further amend the 1994 Agreement
to establish a Floor and Ceiling Prices and related procedures to be effective
during 1999;
NOW, THEREFORE, in consideration of the premises and mutual covenants
contained herein, the parties hereby mutually understand and agree as follows:
1. Effective January 1, 1999, through December 31, 1999, Section 4.3
of the 1994 Agreement shall be deleted in its entirety and the following
Sections 4.2 and 4.3 shall be substituted therefor:
4.2 THE ABOVE SECTION 4.1 NOTWITHSTANDING, THE MONTHLY BASE CONTRACT
PRICE PAYABLE DURING EACH MONTH IN 1999 SHALL, IN NO EVENT, BE LESS
THAN $2.16 PER MMBTU (THE "FLOOR PRICE"), NOR MORE THAN $3.07 PER
MMBTU (THE "CEILING PRICE").
4.3 DURING 1999, THE EXCESS QUANTITY SHALL BE DIVIDED INTO TWO
CATEGORIES. THE FIRST CATEGORY (THE "MONTHLY FIXED PRICE QUANTITY")
SHALL BE EQUAL TO THE DIFFERENCE, IF POSITIVE, BETWEEN (i) THE MONTHLY
FIXED PRICE QUANTITY APPLICABLE DURING THE PARTICULAR MONTH AS
<PAGE> 2
SPECIFIED IN EXHIBIT C HERETO AND (ii) THE MONTHLY BASE QUANTITY FOR
THAT MONTH AS SPECIFIED IN EXHIBIT B HERETO. THE PRICE PAYABLE BY
BUYER FOR EACH MMBTU OF THE MONTHLY FIXED PRICE QUANTITY SHALL BE
EQUAL TO THE SUM OF (i) THE INDEX PRICE AND (ii) $.02 PER MMBTU;
PROVIDED, HOWEVER, THAT IN NO EVENT SHALL THE PRICE FOR THE MONTHLY
FIXED PRICE QUANTITY BE LESS THAN $2.12 PER MMBTU NOR MORE THAN $3.02
PER MMBTU.
THE SECOND CATEGORY OF THE EXCESS QUANTITY (THE "REMAINING EXCESS
QUANTITY") SHALL BE EQUAL TO THE DIFFERENCE, IF POSITIVE, BETWEEN
SELLER'S TOTAL DELIVERIES TO BUYER HEREUNDER DURING A MONTH AND THE
MONTHLY FIXED PRICE QUANTITY FOR SUCH MONTH AS SPECIFIED IN EXHIBIT C
HERETO. THE PRICE PAYABLE BY BUYER FOR EACH MMBTU OF THE REMAINING
EXCESS QUANTITY SHALL BE THE SUM OF (i) THE INDEX PRICE AND (ii) $.02
PER MMBTU.
2. Section 4.3, as amended April 1, 1996, shall be reinstated
effective January 1, 2000.
3. A new Exhibit C in the form attached hereto shall be added to the
1994 Agreement to be effective during calendar year 1999 only.
IN WITNESS WHEREOF, the parties hereto have executed this April 1998
Amendment in duplicate originals as of date hereinabove first written.
Witness: SONAT MARKETING COMPANY L.P.
By /s/ Edward J. Crenshaw
- - ----------------------------------- --------------------------------------
Edward J. Crenshaw
Witness: DOMINION BLACK WARRIOR BASIN, INC.
By /s/ G.E. Lake, Jr.
- - ----------------------------------- --------------------------------------
G.E. Lake, Jr.
<PAGE> 3
EXHIBIT C
DATED APRIL 9, 1998
TO THE
GAS PURCHASE AGREEMENT
BETWEEN
DOMINION BLACK WARRIOR BASIN, INC.
AND
SONAT MARKETING COMPANY
DATED
MAY 3, 1994
<TABLE>
<CAPTION>
Month/Year Monthly Fixed Price Quantity
---------- ----------------------------
<S> <C>
Jan-1999 1,300,000
Feb-1999 1,300,000
Mar-1999 1,300,000
Apr-1999 1,300,000
May-1999 1,300,000
June-1999 1,200,000
July-1999 1,200,000
Aug-1999 1,200,000
Sep-1999 1,200,000
Oct-1999 1,200,000
Nov-1999 1,200,000
Dec-1999 1,200,000
</TABLE>
<PAGE> 1
[RYDER SCOTT COMPANY LETTERHEAD]
March 31, 1999
Dominion Resources Black Warrior Trust
NationsBank of Texas, N.A.
NationsBank Plaza - 17th Floor
901 Main Street
Dallas, Texas 75202
Gentlemen:
We hereby consent to the inclusion of our report dated March 5, 1999,
concerning the reserves and revenue, as of January 1, 1999, of certain royalty
interests owned by Dominion Resources Black Warrior Trust in the Form 10-K for
the year ended December 31, 1998, of the Dominion Resources Black Warrior Trust
to be filed with the Securities and Exchange Commission.
Very truly yours,
/s/ RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
CPM/sw
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 59,455
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 59,455
<PP&E> 155,817,500
<DEPRECIATION> 70,231,426
<TOTAL-ASSETS> 85,645,529
<CURRENT-LIABILITIES> 112,500
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 85,533,029
<TOTAL-LIABILITY-AND-EQUITY> 85,645,529
<SALES> 22,849,760
<TOTAL-REVENUES> 22,926,636
<CGS> 0
<TOTAL-COSTS> 699,832
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 22,226,804
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 22,226,804
<EPS-PRIMARY> 2.83
<EPS-DILUTED> 2.83
</TABLE>
<PAGE> 1
EXHIBIT 99.1
March 5, 1999
Dominion Black Warrior Basin, Inc.
Riverfront Plaza - West Tower
901 E. Byrd Street
Richmond, Virginia 23219-4072
Gentlemen:
At your request, we have prepared an estimate of the reserves,
future production, and income attributable to certain royalty interests of
Dominion Resources Royalty Trust 1994-1 (Dominion) as of January 1, 1999. The
subject properties are located in the Black Warrior Basin, Tuscaloosa County,
Alabama. Two cases of reserve estimates based on different pricing parameters
provided by Dominion are presented herein. The income data for Case 1 were
estimated using escalated cost and price parameters. The income data for Case 2
were estimated using unescalated cost and price parameters.
It should be noted that due to a combination of economic and
political forces, there is significant uncertainty regarding the forecasting of
future hydrocarbon prices. The recoverable reserves and the income attributable
thereto have a direct relationship to the hydrocarbon prices actually received;
therefore, volumes of reserves actually recovered and amounts of income actually
received may differ significantly from the estimated quantities presented in
this report. A summary of the results of this study is shown below.
CASE 1
ESCALATED PARAMETERS - YEAR END PRICING
Estimated Net Reserve and Income Data
Certain Royalty Interests of
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
As of January 1, 1999
- - -------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Total
Proved
------------
NET REMAINING RESERVES
- - ----------------------
<S> <C>
Gas - MMCF 75,481
INCOME DATA
- - -----------
Future Gross Revenue $190,742,281
Tax Credits 35,454,031
------------
Future Net Income (FNI) $226,196,312
Discounted FNI @ 5% $165,966,061
</TABLE>
<PAGE> 2
DOMINION BLACK WARRIOR BASIN, INC.
March 5, 1999
Page 2
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, 1999
- - -------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Total
Proved
------------
NET REMAINING RESERVES
- - ----------------------
<S> <C>
Gas - MMCF 75,481
INCOME DATA
- - -----------
Future Gross Revenue $190,742,281
Tax Credits 35,454,031
------------
Future Net Income (FNI) $226,196,312
Discounted FNI @ 5% $165,966,061
</TABLE>
<PAGE> 3
DOMINION BLACK WARRIOR BASIN, INC.
March 5, 1999
Page 2
CASE 2
UNESCALATED PARAMETERS - YEAR END PRICING
Estimated Net Reserve and Income Data
Certain Royalty Interests of
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
As of January 1, 1999
- - -------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Total
Proved
------------
NET REMAINING RESERVES
- - ----------------------
<S> <C>
Gas - MMCF 74,679
INCOME DATA
Future Gross Revenue $148,635,422
Tax Credits 34,345,694
------------
Future Net Income (FNI) $182,981,116
Discounted FNI @ 5% $142,220,968
</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 Definitions and Pricing Assumptions" in this report.
The future gross revenue is after the deduction of production
taxes and before the addition of Dominion's estimate of the Section 29 Tax
Credit (presented as "Other Income"). The future net income is before the
deduction of state and federal income taxes and general administrative overhead,
and has not been adjusted for outstanding loans that may exist nor does it
include any adjustment for cash on hand or undistributed income. No attempt was
made to quantify or otherwise account for any accumulated gas production
imbalances that may exist. Gas reserves account for 100 percent of total future
gross revenue from proved reserves.
The discounted future net income shown 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.
<PAGE> 4
DOMINION BLACK WARRIOR BASIN, INC.
March 5, 1999
Page 3
<TABLE>
<CAPTION>
Year End Pricing
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
Discounted Future Net Income
As of January 1, 1999
Total Proved
---------------------------------------------------
Discount Rate Escalated Unescalated
Percent Case Case
- - ------------- ------------ ------------
<S> <C> <C>
10 $131,114,970 $116,544,072
15 $108,646,400 $ 98,938,792
20 $ 92,970,271 $ 86,093,687
25 $ 81,380,936 $ 76,279,093
</TABLE>
The results shown above are presented for your information and should not be
construed as our estimate of fair market value.
RESERVES INCLUDED IN THIS REPORT
Escalated Parameters
The proved reserves included herein conform to the definition
as set forth in the Securities and Exchange Commission's Regulation S-X Part
210.4-10 (a) as clarified by subsequent Commission Staff Accounting Bulletins,
except that they are based on cost and price parameters which allow for future
changes in current economic conditions as discussed in other sections of this
report; whereas, the definition approved by the Securities and Exchange
Commission assumes no change in current economic conditions will occur in the
future.
It should be noted that the estimated quantities of reserves
presented in this report, which were based on escalated cost and price
parameters, differ from the quantities of reserves which were estimated using
constant 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 Part
210.4-10 (a) as clarified by subsequent Commission Staff Accounting.
Our definition of proved reserves is included under the tab
"Reserve Definitions and Pricing Assumptions" in this report.
ESTIMATES OF RESERVES
In general, the reserves included herein were estimated by
performance methods or the volumetric method; however, other methods were used
in certain cases where characteristics of the data indicated such other methods
were more appropriate in our opinion. The reserves estimated by the performance
method utilized extrapolations of various historical data in those cases where
such data were definitive. Reserves were estimated by the volumetric method in
those cases where there were inadequate historical performance data to establish
a definitive trend or where the use of production performance data as a basis
for the reserve estimates was considered to be inappropriate.
<PAGE> 5
DOMINION BLACK WARRIOR BASIN, INC.
March 5, 1999
Page 4
The reserves included in this report are estimates only and
should not be construed as being exact quantities. They may or may not be
actually recovered, and if recovered, the revenues therefrom and the actual
costs related thereto could be more or less than the estimated amounts.
Moreover, estimates of reserves may increase or decrease as a result of future
operations.
FUTURE PRODUCTION RATES
Initial production rates are based on the current producing
rates for those wells now on production. Test data and other related information
were used to estimate the anticipated peak production rates for those wells
which are not currently producing at peak rates. If no production decline trend
has been established, future production rates were held constant, or adjusted
for the effects of dewatering where appropriate, until a decline in ability to
produce was anticipated. An estimated rate of decline was then applied to
depletion of the reserves. If a decline trend has been established, this trend
was used as the basis for estimating future production rates.
In general, we estimate that future gas production rates will
continue to be the same as the average rate for the latest available 12 months
of actual production until such time that the well or wells are incapable of
producing at this rate. The well or wells were then projected to decline at
their decreasing delivery capacity rate. Our general policy on estimates of
future gas production rates is adjusted when necessary to reflect actual gas
market conditions in specific cases.
The future production rates from wells now on production may
be more or less than estimated because of changes in marketing conditions or
allowables set by regulatory bodies. Wells or locations which are not currently
producing may start producing earlier or later than anticipated in our estimates
of their future production rates.
HYDROCARBON PRICES
Escalated Parameters
The future hydrocarbon price parameters used in the escalated
pricing scenario reflect Dominion's current estimates. Estimates of future price
parameters have been revised in the past because of changes in governmental
policies, changes in hydrocarbon supply and demand, and variations in general
economic conditions. There is a possibility that the price parameters used in
this report may be revised in the future for similar reasons.
Unescalated Parameters
Dominion furnished us with gas prices in effect at January 1,
1999 and these prices were held constant to depletion of the reserves in the
unescalated pricing scenario.
Dominion's estimates of future price parameters for gas are
presented in detail under the tab "Reserve Definitions and Pricing Assumptions"
in this report.
COSTS
The income attributable to Dominion Resources Royalty Trust
1994-1 is based on a 65 percent overriding royalty interest, and has no
associated deductions or costs. The costs utilized in the evaluation of the
leasehold interest are presented below.
<PAGE> 6
DOMINION BLACK WARRIOR BASIN, INC.
March 5, 1999
Page 5
Escalated Parameters
The escalated case utilized the same operating and cost
parameters as the unescalated except they are escalated according to a scenario
provided by Dominion. Future cost parameters are presented in detail under the
tab "Reserve Definitions and Pricing Assumptions" in this report.
Unescalated Parameters
Operating costs for the leases and wells in the unescalated
case are based on the operating expense reports of Dominion and include only
those costs directly applicable to the leases or wells. When applicable, the
operating costs include a portion of general and administrative costs allocated
directly to the leases and wells under terms of operating agreements. The
current operating costs were held constant throughout the life of the
properties.
At the request of Dominion, their estimate of zero net
abandonment costs after salvage value for the properties was used in this
report. 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,
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, 1999
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 December 1998.
Neither we nor any of our employees have any interest in the
subject properties and neither the employment to make this study nor the
compensation is contingent on our estimates of reserves and future income for
the subject properties.
<PAGE> 7
DOMINION BLACK WARRIOR BASIN, INC.
March 5, 1999
Page 6
This report was prepared for the exclusive use of Dominion
Black Warrior Basin, Inc.. The data, work papers, and maps used in the
preparation of this report are available for examination by authorized parties
in our offices. Please contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
C. Patrick McInturff, P.E.
Petroleum Engineer
CPM/plk
Approved:
- - -----------------------------------
John R. Warner
Senior Vice President
<PAGE> 8
DEFINITIONS OF RESERVES
PROVED RESERVES (SEC DEFINITION)
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing operating conditions, i.e., prices and costs as of the
date the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalation based on
future conditions.
Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation test. In certain instances,
proved reserves are assigned on the basis of a combination of core analysis and
electrical and other type logs which indicate the reservoirs are analogous to
reservoirs in the same field which are producing or have demonstrated the
ability to produce on a formation test. The area of a reservoir considered
proved includes (1) that portion delineated by drilling and defined by fluid
contacts, if any, and (2) the adjoining portions not yet drilled that can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts, the
lowest known structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir.
Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot project or the
operation of an installed program in the reservoir provides support for the
engineering analysis on which the project or program was based, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.
Proved natural gas reserves are comprised of non-associated, associated
and dissolved gas. An appropriate reduction in gas reserves has been made for
the expected removal of natural gas liquids, for lease and plant fuel, and for
the exclusion of non-hydrocarbon gases if they occur in significant quantities
and are removed prior to sale. Estimates of proved reserves do not include crude
oil, natural gas, or natural gas liquids being held in underground or surface
storage.
Proved reserves are estimates of hydrocarbons to be recovered from a
given date forward. They may be revised as hydrocarbons are produced and
additional data become available.
<PAGE> 9
RESERVE STATUS CATEGORIES
Reserve status categories define the development and producing status
of wells and/or reservoirs.
PROVED DEVELOPED (SEC DEFINITION)
Proved developed oil and gas reserves are reserves that can be expected
to be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
Developed reserves may be subcategorized as producing or non-producing
using the SPE/SPEE Definitions:
Producing
Producing reserves are expected to be recovered from completion intervals
open at the time of the estimate and producing. Improved recovery reserves
are considered to be producing only after an improved recovery project is in
operation.
Non-Producing
Non-producing reserves include shut-in and behind pipe reserves. Shut-in
reserves are expected to be recovered from completion intervals open at the
time of the estimate, but which had not started producing, or were shut-in
for market conditions or pipeline connection, or were not capable of
production for mechanical reasons, and the time when sales will start is
uncertain. Behind pipe reserves are expected to be recovered from zones
behind casing in existing wells, which will require additional completion
work or a future recompletion prior to the start of production.
PROVED UNDEVELOPED (SEC DEFINITION)
Proved undeveloped oil and gas reserves are reserves that are expected
to be recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required for recompletion. Reserves on
undrilled acreage shall be limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be demonstrated with
reasonable certainty that there is continuity of production from the existing
productive formation. Estimates for proved undeveloped reserves are attributable
to any acreage for which an application of fluid injection or other improved
technique is contemplated, only when such techniques have been proved effective
by actual tests in the area and in the same reservoir.
<PAGE> 10
HYDROCARBON PRICING AND COST PARAMETERS
DOMINION BLACK WARRIOR BASIN, INC.
Company Pricing and Cost Policy
Unescalated Parameters - Year-End Pricing
Effective January 1, 1999
GAS
Dominion has furnished the pricing scenario to use at January 1, 1999.
<TABLE>
<CAPTION>
Year $/MMBTU(1)
- - ------------- --------------
<S> <C>
1999 2.1379
2000 2.1379
2001 2.1379
2002 2.1379
2003 2.1379
2004 2.1379
</TABLE>
<TABLE>
<CAPTION>
Lease Operating(1) Compression(1)
Expense Costs
Year $/Well/Month $/MCF
- - ------------ ------------------------- -------------------
<S> <C> <C>
1999 1,075 .199
2000 974 .186
2001 906 .172
2002 837 .172
2003 769 .168
2004 700 .161
</TABLE>
<TABLE>
<CAPTION>
Estimated Section 29 Tax Credit
- - ----------------------------------------------------
Year $/MMBTU
- - -------------- ----------------
<S> <C>
1999 1.0914
2000 1.0914
2001 1.0914
2002 1.0914
</TABLE>
- - ---------------------
(1) All prices and costs are held constant after the year 2004.
<PAGE> 11
HYDROCARBON PRICING AND COST PARAMETERS
DOMINION BLACK WARRIOR BASIN, INC.
Company Pricing and Cost Policy
Escalated Parameters - Year-End Pricing
Effective January 1, 1999
GAS
Dominion has furnished the pricing scenario to use at January 1, 1999.
<TABLE>
<CAPTION>
Year $/MMBTU(1)
------------------ -----------------
<S> <C> <C>
1999 2.1379
</TABLE>
<TABLE>
<CAPTION>
Lease Operating(2) Compression(2)
Expense Costs
Year $/Well/Month $/MCF
- - ------------- ------------------------- -------------------
<S> <C> <C>
1999 1,075 .199
2000 974 .186
2001 906 .172
2002 837 .172
2003 769 .168
2004 700 .161
</TABLE>
<TABLE>
<CAPTION>
Estimated Section 29 Tax Credit
--------------------------------------------------------
Year $/MMBTU
------------ ----------------------
<S> <C> <C>
1999 1.0914
2000 1.1166
2001 1.1427
2002 1.1720
</TABLE>
- - -------------------------
(1) Gas price is escalated at 3.5 percent beginning January 1, 2000.
(2) Operating and compression costs are escalated at 3.5 percent beginning
January 1, 2005.
<PAGE> 12
TABLE A
PAGE 1 OF 9
[RYDER SCOTT COMPANY LOGO]
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA
UNESCALATED PARAMETERS - YEAR END PRICING
AS OF JANUARY 1, 1999
<TABLE>
<CAPTION>
------ESTIMATED REMAINING RESERVES-------- --------------ESTIMATED FUTURE DOLLARS------------
-----100% GROSS----- ---------NET--------- GROSS REV. --NET INCOME BEFORE FIT-
(A) (BARRELS) (MMCF) (BARRELS) (MMCF) AFTER PROD. TOTAL DISCOUNTED
STATUS OIL/COND(B) GAS OIL/COND(B) SALES GAS TAXES DEDUCTIONS UNDISCOUNTED AT 5.0%
------ ----------- -------- ----------- --------- ------------ ------------ ------------ -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
ALLGOOD BRANCH FIELD,
TUSCALOOSA COUNTY, ALABAMA
CARNLEY NO. 18-5-3 PV-PD 0 454 0 262 638,065 0 638,065 494,435
CARNLEY NO. 18-12-4 PV-PD 0 1,271 0 733 1,700,846 0 1,700,846 1,179,814
CARNLEY NO. 18-14-5 PV-PD 0 1,873 0 1,079 2,518,087 0 2,518,087 1,760,354
HOLMAN NO. 18-3-2 PV-PD 0 238 0 127 330,290 0 330,290 278,641
STEDMAN NO. 13-1-15 PV-PD 0 109 0 55 152,328 0 152,328 135,711
STEDMAN NO. 13-2-16 PV-PD 0 275 0 137 352,508 0 352,508 295,591
STEDMAN NO. 13-4-17 PV-PD 0 581 0 288 707,230 0 707,230 555,804
STEDMAN NO. 13-6-18 PV-PD 0 249 0 124 325,186 0 325,186 276,599
STEDMAN NO. 13-9-19 PV-PD 0 382 0 189 481,654 0 481,654 396,456
STEDMAN NO. 13-14-21 PV-PD 0 279 0 139 353,235 0 353,235 292,115
STEDMAN NO. 13-15-22 PV-PD 0 985 0 487 1,177,423 0 1,177,423 894,203
STOTHART NO. 24-12-1 PV-PD 0 136 0 72 198,608 0 198,608 175,054
STOTHART NO. 24-13-2 PV-PD 0 352 0 187 479,266 0 479,266 397,437
-------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 7,184 0 3,879 9,414,726 0 9,414,726 7,132,214
ALLGOOD BRANCH, WEST FIELD,
TUSCALOOSA COUNTY, ALABAMA
DAVANT NO. 21-16-16 PV-PD 0 220 0 117 288,799 0 288,799 231,013
FRIEDMAN NO. 22-4-52 PV-PD 0 291 0 146 357,036 0 357,036 281,042
FRIEDMAN NO. 22-12-53 PV-PD 0 558 0 280 673,746 0 673,746 512,276
FRIEDMAN NO. 22-15-54 PV-PD 0 277 0 144 359,698 0 359,698 291,740
FRIEDMAN NO. 22-16-55 PV-PD 0 135 0 68 167,784 0 167,784 135,737
HINDS NO. 14-5-4 PV-PD 0 241 0 130 350,755 0 350,755 306,007
HINDS NO. 14-6-5 PV-PD 0 288 0 154 397,655 0 397,655 333,209
HOLMAN NO. 14-3-2 PV-PD 0 225 0 120 307,789 0 307,789 256,160
HOLMAN NO. 14-4-1 PV-PD 0 248 0 133 343,644 0 343,644 288,947
MILLS NO. 22-14-1 PV-PD 0 716 0 381 914,896 0 914,896 687,960
MOODY NO. 22-6-1 PV-PD 0 527 0 281 694,041 0 694,041 548,754
STEDMAN NO. 13-12-20 PV-PD 0 419 0 208 533,223 0 533,223 441,847
WEST NO. 15-1-83 PV-PD 0 344 0 170 415,772 0 415,772 326,232
WEST NO. 15-3-84 PV-PD 0 115 0 57 154,132 0 154,132 134,426
WEST NO. 15-5-85 PV-PD 0 111 0 55 134,851 0 134,851 108,782
WEST NO. 15-6-86 PV-PD 0 456 0 225 532,318 0 532,318 393,002
WEST NO. 15-9-87 PV-PD 0 302 0 149 354,099 0 354,099 266,062
WEST NO. 15-10-88 PV-PD 0 328 0 162 396,616 0 396,616 310,922
WEST NO. 15-11-89 PV-PD 0 204 0 101 255,446 0 255,446 209,829
WEST NO. 15-14-90A PV-PD 0 172 0 85 213,110 0 213,110 173,644
WEST NO. 15-16-91 PV-PD 0 316 0 157 407,459 0 407,459 343,036
-------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 6,493 0 3,325 8,252,869 0 8,252,869 6,580,627
CASSIDY A FIELD,
TUSCALOOSA COUNTY, ALABAMA
CASSIDY NO. 25-3-11 PV-PD 0 514 0 234 551,508 0 551,508 402,821
CASSIDY NO. 25-4-66 PV-PD 0 418 0 190 436,737 0 436,737 303,431
CASSIDY NO. 25-5-67 PV-PD 0 201 0 93 245,730 0 245,730 211,722
CASSIDY NO. 25-6-13 PV-PD 0 176 0 81 220,699 0 220,699 193,724
CASSIDY NO. 25-10-1 PV-PD 0 176 0 81 220,157 0 220,157 192,681
CASSIDY NO. 25-12-14 PV-PD 0 385 0 175 413,344 0 413,344 304,882
CASSIDY NO. 25-14-21 PV-PD 0 225 0 103 253,276 0 253,276 203,143
CASSIDY NO. 25-15-20 PV-PD 0 109 0 50 140,177 0 140,177 124,496
CASSIDY NO. 25-16-1 PV-PD 0 282 0 129 312,356 0 312,356 243,928
CASSIDY NO. 30-12-15 PV-PD 0 516 0 235 540,703 0 540,703 375,316
CASSIDY NO. 30-13-1 PV-PD 0 233 0 106 257,452 0 257,452 201,082
CASSIDY NO. 30-14-1 PV-PD 0 124 0 57 157,390 0 157,390 139,395
CASSIDY NO. 30-15-12 PV-PD 0 222 0 102 253,547 0 253,547 206,265
CASSIDY NO. 31-1-17 PV-PD 0 236 0 108 267,588 0 267,588 216,076
CASSIDY NO. 31-2-10 PV-PD 0 413 0 188 457,622 0 457,622 355,040
CASSIDY NO. 31-3-16 PV-PD 0 174 0 80 209,374 0 209,374 178,521
CASSIDY NO. 31-4-1 PV-PD 0 137 0 63 164,065 0 164,065 139,490
CASSIDY NO. 31-5-1A PV-PD 0 440 0 201 473,894 0 473,894 349,777
CASSIDY NO. 31-6-18 PV-PD 0 475 0 216 502,761 0 502,761 357,731
CASSIDY NO. 31-8-70 PV-PD 0 183 0 84 209,440 0 209,440 171,318
CASSIDY NO. 31-10-124 PV-PD 0 245 0 113 297,363 0 297,363 254,875
CASSIDY NO. 31-12-125 PV-PD 0 242 0 111 285,768 0 285,768 239,601
CASSIDY NO. 31-14-65 PV-PD 0 208 0 95 236,177 0 236,177 191,415
CASSIDY NO. 36-1-19 PV-PD 0 293 0 134 314,123 0 314,123 232,618
CASSIDY NO. 36-2-1 PV-PD 0 78 0 36 98,760 0 98,760 87,741
CASSIDY NO. 36-3-23 PV-PD 0 211 0 97 235,654 0 235,654 186,599
CASSIDY NO. 36-4-22 PV-PD 0 466 0 212 485,819 0 485,819 333,653
CASSIDY NO. 36-5-24 PV-PD 0 129 0 59 163,266 0 163,266 144,357
</TABLE>
<PAGE> 13
TABLE A
PAGE 2 OF 9
[RYDER SCOTT COMPANY LOGO]
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA
UNESCALATED PARAMETERS - YEAR END PRICING
AS OF JANUARY 1, 1999
<TABLE>
<CAPTION>
------ESTIMATED REMAINING RESERVES-------- --------------ESTIMATED FUTURE DOLLARS------------
-----100% GROSS----- ---------NET--------- GROSS REV. --NET INCOME BEFORE FIT-
(A) (BARRELS) (MMCF) (BARRELS) (MMCF) AFTER PROD. TOTAL DISCOUNTED
STATUS OIL/COND(B) GAS OIL/COND(B) SALES GAS TAXES DEDUCTIONS UNDISCOUNTED AT 5.0%
------ ----------- -------- ----------- --------- ------------ ------------ ------------ -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
CASSIDY A FIELD,
TUSCALOOSA COUNTY, ALABAMA (CONT.)
CASSIDY NO. 36-7-25 PV-PD 0 101 0 46 122,196 0 122,196 105,278
CASSIDY NO. 36-8-4 PV-PD 0 343 0 156 361,702 0 361,702 257,610
CASSIDY NO. 36-9-71 PV-PD 0 175 0 80 200,634 0 200,634 164,688
CASSIDY NO. 36-10-28 PV-PD 0 199 0 91 222,496 0 222,496 177,405
CASSIDY NO. 36-11-27 PV-PD 0 165 0 76 196,950 0 196,950 167,400
CASSIDY NO. 36-12-26 PV-PD 0 163 0 74 179,230 0 179,230 140,738
CASSIDY NO. 36-13-29 PV-PD 0 332 0 152 370,052 0 370,052 290,299
CASSIDY NO. 36-14-30 PV-PD 0 74 0 34 97,100 0 97,100 86,898
CASSIDY NO. 36-15-31 PV-PD 0 121 0 56 153,464 0 153,464 135,386
CASSIDY NO. 36-16-3 PV-PD 0 265 0 121 298,354 0 298,354 237,761
CHEVRON NO. 23-16-18 PV-PD 0 196 0 105 284,109 0 284,109 247,527
CHEVRON NO. 25-2-1 PV-PD 0 409 0 217 497,519 0 497,519 341,401
CHEVRON NO. 25-8-2 PV-PD 0 160 0 86 226,483 0 226,483 194,040
CHEVRON NO. 25-11-3 PV-PD 0 168 0 90 234,151 0 234,151 198,210
CHEVRON NO. 30-10-8 PV-PD 0 171 0 91 221,332 0 221,332 174,681
EARNEST NO. 24-13-1 PV-PD 0 545 0 289 695,721 0 695,721 528,962
---------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 11,098 0 5,197 12,766,243 0 12,766,243 9,989,982
CASSIDY B FIELD,
TUSCALOOSA COUNTY, ALABAMA
CASSIDY NO. 5-2-126 PV-PD 0 540 0 247 591,502 0 591,502 447,948
CASSIDY NO. 5-4-49 PV-PD 0 263 0 120 295,997 0 295,997 236,176
CASSIDY NO. 5-5-50 PV-PD 0 506 0 230 541,753 0 541,753 395,033
CASSIDY NO. 5-6-61 PV-PD 0 628 0 287 687,646 0 687,646 519,459
CASSIDY NO. 5-11-56 PV-PD 0 261 0 120 301,444 0 301,444 247,177
CASSIDY NO. 5-13-48 PV-PD 0 233 0 107 264,046 0 264,046 212,420
CASSIDY NO. 5-14-57 PV-PD 0 52 0 24 65,539 0 65,539 57,748
CASSIDY NO. 6-2-64 PV-PD 0 199 0 91 223,659 0 223,659 179,455
CASSIDY NO. 6-3-44 PV-PD 0 309 0 141 351,373 0 351,373 282,769
CASSIDY NO. 6-4-42 PV-PD 0 316 0 144 357,578 0 357,578 286,555
CASSIDY NO. 6-5-43 PV-PD 0 0 0 0 0 0 0 0
CASSIDY NO. 6-6-53 PV-PD 0 382 0 174 412,705 0 412,705 307,867
CASSIDY NO. 6-7-129 PV-PD 0 235 0 107 265,576 0 265,576 213,379
CASSIDY NO. 6-9-47 PV-PD 0 213 0 97 244,700 0 244,700 200,657
CASSIDY NO. 6-10-52 PV-PD 0 322 0 147 359,714 0 359,714 283,302
CASSIDY NO. 6-11-54 PV-PD 0 162 0 74 175,602 0 175,602 134,418
CASSIDY NO. 6-13-51 PV-PD 0 366 0 166 383,830 0 383,830 270,569
CASSIDY NO. 6-14-55 PV-PD 0 396 0 180 414,218 0 414,218 289,421
CASSIDY NO. 6-16-68 PV-PD 0 138 0 63 155,082 0 155,082 125,432
CASSIDY NO. 8-4-63 PV-PD 0 223 0 102 247,571 0 247,571 195,198
CASSIDY NO. 8-5-60 PV-PD 0 141 0 65 169,474 0 169,474 145,003
CASSIDY NO. 8-12-58 PV-PD 0 37 0 17 51,874 0 51,874 47,212
CASSIDY NO. 8-13-59 PV-PD 0 168 0 77 187,065 0 187,065 148,924
CASSIDY NO. 31-16-69 PV-PD 0 243 0 111 267,320 0 267,320 207,084
CASSIDY NO. 32-2-41 PV-PD 0 207 0 95 251,388 0 251,388 215,862
CASSIDY NO. 32-4-33 PV-PD 0 77 0 36 107,246 0 107,246 98,538
CASSIDY NO. 32-6-40 PV-PD 0 71 0 33 99,381 0 99,381 91,512
CASSIDY NO. 32-7-39 PV-PD 0 337 0 154 365,314 0 365,314 275,418
CASSIDY NO. 32-8-34 PV-PD 0 510 0 234 593,351 0 593,351 486,399
CASSIDY NO. 32-9-37 PV-PD 0 1,027 0 467 1,071,817 0 1,071,817 724,317
CASSIDY NO. 32-10-45 PV-PD 0 195 0 90 242,590 0 242,590 211,724
CASSIDY NO. 32-11-35 PV-PD 0 33 0 16 47,623 0 47,623 44,039
CASSIDY NO. 32-12-62 PV-PD 0 263 0 120 281,468 0 281,468 208,511
CASSIDY NO. 32-13-46 PV-PD 0 162 0 75 196,198 0 196,198 167,984
CASSIDY NO. 32-14-36 PV-PD 0 432 0 197 465,209 0 465,209 344,145
CASSIDY NO. 32-15-38 PV-PD 0 402 0 184 449,382 0 449,382 352,547
DRUMMOND NO. 6-1-1 PV-PD 0 40 0 18 56,086 0 56,086 51,088
MAYFIELD NO. 8-3-1 PV-PD 0 178 0 94 256,523 0 256,523 225,332
USX NO. 5-7-1 PV-PD 0 284 0 131 353,772 0 353,772 308,422
USX NO. 5-10-2 PV-PD 0 390 0 179 452,692 0 452,692 371,260
USX NO. 5-15-3 PV-PD 0 331 0 151 369,309 0 369,309 290,484
USX NO. 8-6-4 PV-PD 0 305 0 140 370,934 0 370,934 318,113
USX NO. 8-11-5 PV-PD 0 277 0 127 304,284 0 304,284 234,124
USX NO. 8-14-39 PV-PD 0 17 0 8 24,890 0 24,890 23,894
WEST NO. 7-2-74 PV-PD 0 232 0 115 277,263 0 277,263 215,905
WEST NO. 7-3-75 PV-PD 0 143 0 71 188,021 0 188,021 161,938
WEST NO. 7-6-76 PV-PD 0 409 0 202 490,924 0 490,924 379,430
WEST NO. 7-8-77 PV-PD 0 275 0 136 309,949 0 309,949 215,477
WEST NO. 7-11-78 PV-PD 0 410 0 202 464,220 0 464,220 321,275
WEST NO. 7-12-79 PV-PD 0 321 0 159 396,758 0 396,758 319,903
WEST NO. 7-13-80 PV-PD 0 124 0 62 166,946 0 166,946 145,873
WEST NO. 7-15-81 PV-PD 0 170 0 85 211,359 0 211,359 172,675
---------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 13,955 0 6,468 15,880,165 0 15,880,165 12,409,395
</TABLE>
<PAGE> 14
TABLE A
PAGE 3 OF 9
[RYDER SCOTT COMPANY LOGO]
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA
UNESCALATED PARAMETERS - YEAR END PRICING
AS OF JANUARY 1, 1999
<TABLE>
<CAPTION>
------ESTIMATED REMAINING RESERVES-------- --------------ESTIMATED FUTURE DOLLARS------------
-----100% GROSS----- ---------NET--------- GROSS REV. --NET INCOME BEFORE FIT-
(A) (BARRELS) (MMCF) (BARRELS) (MMCF) AFTER PROD. TOTAL DISCOUNTED
STATUS OIL/COND(B) GAS OIL/COND(B) SALES GAS TAXES DEDUCTIONS UNDISCOUNTED AT 5.0%
------ ----------- -------- ----------- --------- ------------ ------------ ------------ -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
CASSIDY C FIELD,
TUSCALOOSA COUNTY, ALABAMA
CASSIDY NO. 19-1-72 PV-PD 0 654 0 297 671,546 0 671,546 437,640
CASSIDY NO. 19-2-73 PV-PD 0 254 0 116 276,312 0 276,312 210,650
CASSIDY NO. 19-3-74 PV-PD 0 492 0 224 524,172 0 524,172 378,336
CASSIDY NO. 19-6-96 PV-PD 0 348 0 159 380,889 0 380,889 291,122
CASSIDY NO. 19-7-75 PV-PD 0 238 0 109 258,602 0 258,602 196,601
CASSIDY NO. 19-9-76 PV-PD 0 329 0 151 385,337 0 385,337 319,876
CASSIDY NO. 19-10-77 PV-PD 0 249 0 114 281,189 0 281,189 225,070
CASSIDY NO. 19-11-97 PV-PD 0 109 0 50 129,495 0 129,495 110,030
CASSIDY NO. 19-13-78 PV-PD 0 245 0 121 304,993 0 304,993 249,256
CASSIDY NO. 19-15-79 PV-PD 0 255 0 116 286,835 0 286,835 229,249
CASSIDY NO. 19-16-80 PV-PD 0 380 0 173 423,649 0 423,649 332,219
CASSIDY NO. 20-3-81 PV-PD 0 295 0 135 333,679 0 333,679 266,843
CASSIDY NO. 20-5-82 PV-PD 0 337 0 154 375,521 0 375,521 294,836
CASSIDY NO. 20-6-83 PV-PD 0 98 0 45 131,185 0 131,185 118,821
CASSIDY NO. 20-7-84 PV-PD 0 206 0 94 234,023 0 234,023 189,918
CASSIDY NO. 20-8-85 PV-PD 0 268 0 123 313,770 0 313,770 260,709
CASSIDY NO. 20-10-86 PV-PD 0 669 0 304 696,007 0 696,007 470,744
CASSIDY NO. 20-12-87 PV-PD 0 385 0 175 418,724 0 418,724 316,330
CASSIDY NO. 20-14-88 PV-PD 0 146 0 67 184,101 0 184,101 162,047
CASSIDY NO. 20-16-89 PV-PD 0 55 0 26 79,088 0 79,088 72,994
CASSIDY NO. 21-2-102 PV-PD 0 296 0 135 324,949 0 324,949 250,401
CASSIDY NO. 21-3-116 PV-PD 0 377 0 173 429,887 0 429,887 345,948
CASSIDY NO. 21-4-117 PV-PD 0 91 0 42 113,684 0 113,684 99,440
CASSIDY NO. 21-6-103 PV-PD 0 228 0 104 267,013 0 267,013 222,387
CASSIDY NO. 21-8-104 PV-PD 0 137 0 63 160,242 0 160,242 133,903
CASSIDY NO. 21-10-105 PV-PD 0 147 0 68 187,905 0 187,905 166,438
CASSIDY NO. 21-11-106 PV-PD 0 418 0 190 450,371 0 450,371 333,987
CASSIDY NO. 21-14-118 PV-PD 0 150 0 69 184,443 0 184,443 160,037
CASSIDY NO. 22-1-107 PV-PD 0 174 0 80 206,669 0 206,669 174,545
CASSIDY NO. 22-3-108 PV-PD 0 128 0 58 146,768 0 146,768 121,156
CASSIDY NO. 22-6-110 PV-PD 0 138 0 63 157,596 0 157,596 128,730
CASSIDY NO. 22-7-111 PV-PD 0 0 0 0 0 0 0 0
CASSIDY NO. 22-13-112 PV-PD 0 45 0 21 63,642 0 63,642 58,624
CASSIDY NO. 22-14-113 PV-PD 0 46 0 21 66,026 0 66,026 61,070
CASSIDY NO. 28-1-114 PV-PD 0 138 0 64 178,642 0 178,642 159,301
CASSIDY NO. 28-7-115 PV-PD 0 352 0 160 373,971 0 373,971 271,004
CASSIDY NO. 28-8-131 PV-PD 0 492 0 225 536,456 0 536,456 403,688
CASSIDY NO. 29-1-95 PV-PD 0 244 0 112 278,252 0 278,252 225,340
CASSIDY NO. 29-2-98 PV-PD 0 359 0 163 387,734 0 387,734 290,110
CASSIDY NO. 29-3-90 PV-PD 0 332 0 151 356,655 0 356,655 263,795
CASSIDY NO. 29-4-91 PV-PD 0 399 0 182 424,092 0 424,092 305,576
CASSIDY NO. 29-5-92 PV-PD 0 311 0 142 355,509 0 355,509 288,335
CASSIDY NO. 29-6-93 PV-PD 0 76 0 35 107,553 0 107,553 99,544
CASSIDY NO. 29-9-94 PV-PD 0 678 0 309 721,238 0 721,238 514,456
CASSIDY NO. 29-10-99 PV-PD 0 505 0 231 554,660 0 554,660 422,517
CASSIDY NO. 30-2-119 PV-PD 0 1,290 0 586 1,320,921 0 1,320,921 837,371
CASSIDY NO. 30-4-120 PV-PD 0 270 0 134 328,022 0 328,022 259,580
CASSIDY NO. 30-8-121 PV-PD 0 499 0 247 596,102 0 596,102 456,150
CASSIDY NO. 32-1-101 PV-PD 0 908 0 413 956,798 0 956,798 664,284
CHEVRON NO. 24-16-16 PV-PD 0 142 0 76 207,067 0 207,067 181,418
DAVIS NO. 24-7-1 PV-PD 0 344 0 184 470,770 0 470,770 390,282
DAVIS NO. 24-8-2 PV-PD 0 233 0 125 315,991 0 315,991 260,624
DAVIS NO. 24-9-3 PV-PD 0 388 0 206 483,211 0 483,211 350,428
DAVIS NO. 24-10-4 PV-PD 0 695 0 369 861,416 0 861,416 613,129
DEAL NO. 27-4-1 PV-PD 0 166 0 89 243,860 0 243,860 214,296
DEAL NO. 27-5-2 PV-PD 0 556 0 292 744,225 0 744,225 612,234
HOLMAN NO. 24-1-26 PV-PD 0 222 0 119 329,552 0 329,552 291,650
HOLMAN NO. 24-3-27 PV-PD 0 264 0 141 374,564 0 374,564 321,086
USX NO. 21-15-11 PV-PD 0 55 0 25 78,123 0 78,123 72,180
USX NO. 21-16-12 PV-PD 0 86 0 40 114,539 0 114,539 103,682
USX NO. 22-4-36 PV-PD 0 196 0 90 213,966 0 213,966 164,742
USX NO. 22-11-13 PV-PD 0 235 0 107 260,351 0 260,351 203,917
USX NO. 22-12-14 PV-PD 0 135 0 62 165,616 0 165,616 143,739
USX NO. 23-4-41 PV-PD 0 350 0 165 432,016 0 432,016 365,986
USX NO. 28-3-15 PV-PD 0 314 0 143 338,785 0 338,785 253,903
USX NO. 28-4-16 PV-PD 0 74 0 34 95,737 0 95,737 85,252
USX NO. 28-5-17 PV-PD 0 97 0 45 122,904 0 122,904 108,663
USX NO. 29-8-6 PV-PD 0 183 0 84 225,721 0 225,721 195,567
USX NO. 29-11-7 PV-PD 0 216 0 99 268,909 0 268,909 234,653
USX NO. 29-13-9 PV-PD 0 341 0 156 384,357 0 384,357 306,239
USX NO. 29-14-10 PV-PD 0 116 0 54 152,140 0 152,140 136,500
USX NO. 30-9-18 PV-PD 0 236 0 108 284,001 0 284,001 241,967
---------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 20,884 0 9,811 24,092,738 0 24,092,738 18,703,145
</TABLE>
<PAGE> 15
TABLE A
PAGE 4 OF 9
[RYDER SCOTT COMPANY LOGO]
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA
UNESCALATED PARAMETERS - YEAR END PRICING
AS OF JANUARY 1, 1999
<TABLE>
<CAPTION>
------ESTIMATED REMAINING RESERVES-------- --------------ESTIMATED FUTURE DOLLARS------------
-----100% GROSS----- ---------NET--------- GROSS REV. --NET INCOME BEFORE FIT-
(A) (BARRELS) (MMCF) (BARRELS) (MMCF) AFTER PROD. TOTAL DISCOUNTED
STATUS OIL/COND(B) GAS OIL/COND(B) SALES GAS TAXES DEDUCTIONS UNDISCOUNTED AT 5.0%
------ ----------- -------- ----------- --------- ------------ ------------ ------------ -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
DEERLICK, EAST FIELD,
TUSCALOOSA COUNTY, ALABAMA
DAVANT NO. 7-13-6 PV-PD 0 477 0 253 585,053 0 585,053 408,834
DAVANT NO. 7-14-1 PV-PD 0 71 0 38 99,229 0 99,229 85,048
FRIEDMAN NO. 13-13-3 PV-PD 0 190 0 95 224,401 0 224,401 168,634
FRIEDMAN NO. 18-2-5 PV-PD 0 28 0 14 44,277 0 44,277 41,180
FRIEDMAN NO. 18-3-31 PV-PD 0 149 0 76 206,564 0 206,564 181,660
FRIEDMAN NO. 18-7-30 PV-PD 0 92 0 47 127,499 0 127,499 112,091
FRIEDMAN NO. 18-8-2 PV-PD 0 49 0 25 69,924 0 69,924 62,541
FRIEDMAN NO. 18-9-1 PV-PD 0 183 0 92 239,288 0 239,288 202,010
FRIEDMAN NO. 18-15-4 PV-PD 0 229 0 116 308,890 0 308,890 266,607
MCDANIEL NO. 18-4-1 PV-PD 0 101 0 54 144,844 0 144,844 125,962
MCDANIEL NO. 18-5-2 PV-PD 0 122 0 65 168,274 0 168,274 142,967
MCDANIEL NO. 18-6-3 PV-PD 0 89 0 47 123,479 0 123,479 105,507
SEARCY NO. 7-15-15 PV-PD 0 162 0 87 224,369 0 224,369 189,328
SEARCY NO. 17-5-7 PV-PD 0 152 0 81 190,680 0 190,680 143,667
SEARCY NO. 17-6-20 PV-PD 0 103 0 55 143,919 0 143,919 122,493
SEARCY NO. 17-11-8 PV-PD 0 751 0 399 905,263 0 905,263 595,249
SEARCY NO. 17-14-9 PV-PD 0 326 0 174 422,942 0 422,942 330,067
SEARCY NO. 18-11-18 PV-PD 0 609 0 324 782,425 0 782,425 595,107
SEARCY NO. 18-13-6 PV-PD 0 54 0 29 84,720 0 84,720 76,373
SEARCY NO. 18-14-5 PV-PD 0 521 0 278 703,293 0 703,293 572,658
SEARCY NO. 19-4-1 PV-PD 0 90 0 48 127,292 0 127,292 109,805
SEARCY NO. 19-10-3 PV-PD 0 311 0 166 404,222 0 404,222 316,314
SEARCY NO. 20-3-10 PV-PD 0 110 0 59 146,542 0 146,542 120,220
SEARCY NO. 20-4-11 PV-PD 0 76 0 41 116,761 0 116,761 105,233
SEARCY NO. 20-5-12 PV-PD 0 938 0 498 1,159,722 0 1,159,722 813,573
SEARCY NO. 20-6-13 PV-PD 0 571 0 304 731,615 0 731,615 555,133
SEARCY NO. 24-1-2 PV-PD 0 369 0 196 449,557 0 449,557 311,843
WEST NO. 13-1-15 PV-PD 0 219 0 108 253,903 0 253,903 188,106
WEST NO. 13-2-16 PV-PD 0 328 0 162 373,616 0 373,616 263,679
WEST NO. 13-5-3 PV-PD 0 149 0 74 181,643 0 181,643 146,122
WEST NO. 13-6-1 PV-PD 0 199 0 99 244,712 0 244,712 197,793
WEST NO. 13-7-38 PV-PD 0 76 0 38 96,952 0 96,952 82,206
WEST NO. 13-8-14 PV-PD 0 119 0 59 156,227 0 156,227 134,084
WEST NO. 13-9-9 PV-PD 0 183 0 91 227,885 0 227,885 186,439
WEST NO. 13-11-6 PV-PD 0 528 0 260 592,462 0 592,462 398,223
WEST NO. 13-12-4A PV-PD 0 240 0 119 284,106 0 284,106 217,324
WEST NO. 13-15-23 PV-PD 0 541 0 266 597,217 0 597,217 380,090
WEST NO. 17-12-20 PV-PD 0 0 0 0 0 0 0 0
WEST NO. 17-13-21 PV-PD 0 251 0 124 301,082 0 301,082 235,647
WEST NO. 19-1-19 PV-PD 0 218 0 107 252,044 0 252,044 186,905
WEST NO. 19-2-10 PV-PD 0 267 0 132 306,424 0 306,424 221,541
WEST NO. 19-3-7 PV-PD 0 0 0 0 0 0 0 0
WEST NO. 19-6-18 PV-PD 0 281 0 139 340,546 0 340,546 269,089
WEST NO. 19-7-1 PV-PD 0 52 0 26 70,783 0 70,783 62,025
WEST NO. 19-8-12 PV-PD 0 677 0 334 767,881 0 767,881 526,795
WEST NO. 19-11-13 PV-PD 0 269 0 132 307,797 0 307,797 222,345
WEST NO. 19-12-11 PV-PD 0 399 0 196 450,777 0 450,777 311,572
---------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 11,919 0 6,128 14,741,101 0 14,741,101 11,090,089
DEERLICK, NORTH FIELD,
TUSCALOOSA COUNTY, ALABAMA
ALCUS NO. 12-4-1 PV-PD 0 144 0 74 181,019 0 181,019 144,401
ALCUS NO. 12-5-2 PV-PD 0 71 0 36 92,306 0 92,306 78,034
DAVANT NO. 7-4-2 PV-PD 0 283 0 151 359,221 0 359,221 271,645
DAVANT NO. 7-5-3 PV-PD 0 157 0 84 205,732 0 205,732 164,444
DAVANT NO. 7-11-4 PV-PD 0 352 0 187 429,128 0 429,128 299,207
DAVANT NO. 7-12-5 PV-PD 0 76 0 41 105,910 0 105,910 90,719
FNB NO. 1-3-1 PV-PD 0 211 0 113 296,406 0 296,406 252,349
FRIEDMAN NO. 2-1-15 PV-PD 0 330 0 166 397,748 0 397,748 304,165
FRIEDMAN NO. 2-9-16 PV-PD 0 254 0 133 312,727 0 312,727 232,928
FRIEDMAN NO. 6-4-11 PV-PD 0 220 0 111 277,450 0 277,450 226,755
FRIEDMAN NO. 6-5-12 PV-PD 0 181 0 91 220,669 0 220,669 173,946
FRIEDMAN NO. 6-12-13 PV-PD 0 68 0 34 88,903 0 88,903 75,609
FRIEDMAN NO. 6-13-14 PV-PD 0 168 0 85 211,298 0 211,298 172,372
FRIEDMAN NO. 11-10-8 PV-PD 0 130 0 66 166,394 0 166,394 138,531
FRIEDMAN NO. 12-1-9 PV-PD 0 68 0 34 98,463 0 98,463 88,634
FRIEDMAN NO. 12-2-50 PV-PD 0 210 0 105 254,330 0 254,330 197,933
FRIEDMAN NO. 12-8-10 PV-PD 0 9 0 5 14,042 0 14,042 13,660
FRIEDMAN-ROSENAU NO. 2-16-3 PV-PD 0 123 0 66 169,949 0 169,949 143,584
MAYFIELD NO. 12-9-2 PV-PD 0 481 0 245 558,895 0 558,895 377,972
MAYFIELD NO. 12-10-5 PV-PD 0 271 0 144 344,065 0 344,065 260,598
MAYFIELD NO. 14-1-1 PV-PD 0 45 0 23 63,563 0 63,563 56,068
</TABLE>
<PAGE> 16
TABLE A
PAGE 5 OF 9
[RYDER SCOTT COMPANY LOGO]
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA
UNESCALATED PARAMETERS - YEAR END PRICING
AS OF JANUARY 1, 1999
<TABLE>
<CAPTION>
------ESTIMATED REMAINING RESERVES-------- --------------ESTIMATED FUTURE DOLLARS------------
-----100% GROSS----- ---------NET--------- GROSS REV. --NET INCOME BEFORE FIT-
(A) (BARRELS) (MMCF) (BARRELS) (MMCF) AFTER PROD. TOTAL DISCOUNTED
STATUS OIL/COND(B) GAS OIL/COND(B) SALES GAS TAXES DEDUCTIONS UNDISCOUNTED AT 5.0%
------ ----------- -------- ----------- --------- ------------ ------------ ------------ -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
DEERLICK, NORTH FIELD,
TUSCALOOSA COUNTY, ALABAMA (CONT.)
SEARCY NO. 7-6-17 PV-PD 0 211 0 112 277,952 0 277,952 223,052
SEARCY NO. 11-9-14 PV-PD 0 166 0 89 229,938 0 229,938 193,775
SEARCY NO. 12-3-16 PV-PD 0 39 0 21 62,721 0 62,721 56,977
SEARCY NO. 12-6-19 PV-PD 0 130 0 70 185,212 0 185,212 160,141
THORNHILL NO. 12-13-1 PV-PD 0 178 0 95 247,407 0 247,407 209,239
WEST NO. 1-1-24 PV-PD 0 130 0 65 185,829 0 185,829 167,768
WEST NO. 1-2-25 PV-PD 0 210 0 104 258,188 0 258,188 207,868
WEST NO. 1-5-26 PV-SI 0 0 0 0 0 0 0 0
WEST NO. 1-6-39 PV-PD 0 260 0 129 315,638 0 315,638 250,599
WEST NO. 1-8-27 PV-PD 0 174 0 86 227,423 0 227,423 194,494
WEST NO. 1-9-28 PV-PD 0 86 0 43 122,032 0 122,032 109,717
WEST NO. 1-10-29 PV-PD 0 225 0 112 291,770 0 291,770 246,829
WEST NO. 1-11-30 PV-PD 0 114 0 57 152,826 0 152,826 133,216
WEST NO. 1-13-31 PV-PD 0 278 0 138 343,814 0 343,814 278,034
WEST NO. 1-14-32 PV-PD 0 187 0 93 240,881 0 240,881 203,683
WEST NO. 1-16-33 PV-PD 0 135 0 67 161,036 0 161,036 126,802
WEST NO. 11-1-34 PV-PD 0 13 0 7 20,672 0 20,672 19,801
WEST NO. 11-8-36 PV-PD 0 90 0 45 123,321 0 123,321 108,540
WEST NO. 11-15-37 PV-PD 0 0 0 0 0 0 0 0
WEST NO. 13-4-17 PV-PD 0 470 0 232 546,211 0 546,211 398,813
-------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 6,948 0 3,557 8,841,089 0 8,841,089 7,052,902
LAKE HARRIS FIELD,
TUSCALOOSA COUNTY, ALABAMA
DAVANT NO. 23-2-9 PV-PD 0 308 0 164 397,073 0 397,073 306,968
DAVANT NO. 23-7-7 PV-PD 0 138 0 74 195,765 0 195,765 168,239
DAVANT NO. 23-13-8 PV-PD 0 330 0 175 415,899 0 415,899 310,595
FIRST ALABAMA BANK NO. 27-9- PV-PD 0 54 0 31 82,611 0 82,611 71,251
FIRST ALABAMA BANK NO. 27-16 PV-PD 0 89 0 52 128,706 0 128,706 105,976
FRIEDMAN NO. 22-5-36 PV-SI 0 0 0 0 0 0 0 0
FRIEDMAN NO. 22-14-38 PV-PD 0 49 0 25 68,630 0 68,630 60,707
FRIEDMAN NO. 22-15-39 PV-PD 0 24 0 12 37,753 0 37,753 34,322
FRIEDMAN NO. 23-4-41 PV-PD 0 687 0 355 835,651 0 835,651 606,602
FRIEDMAN NO. 23-5-40 PV-PD 0 248 0 127 303,742 0 303,742 232,396
HOBSON NO. 22-9-1 PV-PD 0 269 0 143 350,756 0 350,756 276,925
WEST NO. 21-8-71 PV-PD 0 0 0 0 0 0 0 0
WEST NO. 27-1-59 PV-PD 0 133 0 66 160,268 0 160,268 127,729
WEST NO. 27-2-60 PV-PD 0 177 0 88 218,728 0 218,728 177,660
WEST NO. 27-4-62 PV-PD 0 60 0 30 78,353 0 78,353 67,550
WEST NO. 27-5-65 PV-PD 0 20 0 10 30,280 0 30,280 28,137
-------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 2,586 0 1,352 3,304,215 0 3,304,215 2,575,057
LAKE NICOL FIELD,
TUSCALOOSA COUNTY, ALABAMA
ALABAMA BASIC NO. 34-3-14 PV-PD 0 470 0 249 570,036 0 570,036 389,308
BEAN NO. 14-15-1 PV-PD 0 354 0 185 444,511 0 444,511 339,865
COLBURN NO. 15-9-1 PV-PD 0 110 0 59 157,326 0 157,326 136,599
COLBURN NO. 15-15-2 PV-PD 0 195 0 104 255,070 0 255,070 202,705
CUNNINGHAM NO. 10-1-1 PV-PD 0 627 0 334 802,784 0 802,784 607,044
CUNNINGHAM NO. 10-2-2 PV-PD 0 417 0 221 505,954 0 505,954 345,995
CUNNINGHAM NO. 34-8-2 PV-PD 0 677 0 359 814,388 0 814,388 534,127
FIRST ALABAMA BANK NO. 34-13 PV-PD 0 156 0 90 226,642 0 226,642 185,766
FRIEDMAN NO. 2-5-42 PV-PD 0 325 0 163 400,947 0 400,947 317,536
FRIEDMAN NO. 2-12-21 PV-PD 0 183 0 92 235,943 0 235,943 196,934
FRIEDMAN NO. 2-14-22 PV-PD 0 188 0 95 246,997 0 246,997 209,929
FRIEDMAN NO. 3-6-23 PV-PD 0 257 0 129 312,250 0 312,250 242,636
FRIEDMAN NO. 3-15-26 PV-PD 0 87 0 44 109,328 0 109,328 90,611
FRIEDMAN NO. 10-10-28 PV-PD 0 278 0 139 341,315 0 341,315 269,374
FRIEDMAN NO. 10-15-29 PV-PD 0 175 0 88 207,578 0 207,578 157,909
FRIEDMAN NO. 11-11-17 PV-PD 0 349 0 174 401,188 0 401,188 280,926
FRIEDMAN NO. 11-13-18 PV-PD 0 224 0 112 270,079 0 270,079 208,875
FRIEDMAN NO. 14-6-33 PV-PD 0 201 0 102 294,960 0 294,960 268,114
FRIEDMAN NO. 14-12-34 PV-PD 0 166 0 84 227,748 0 227,748 199,074
FRIEDMAN NO. 14-13-35 PV-PD 0 447 0 224 526,038 0 526,038 384,213
FRIEDMAN NO. 34-10-57 PV-PD 0 406 0 203 485,681 0 485,681 366,545
FRIEDMAN NO. 34-15-58 PV-PD 0 130 0 66 162,373 0 162,373 132,033
FRIEDMAN-ROSENAU NO. 2-7-2 PV-PD 0 196 0 102 257,331 0 257,331 212,497
FRIEDMAN-ROSENAU NO. 2-15-1 PV-PD 0 107 0 58 154,695 0 154,695 134,676
HOLMAN NO. 10-11-1 PV-PD 0 142 0 76 185,830 0 185,830 149,258
MCGUIRE NO. 34-9-5 PV-PD 0 223 0 119 284,343 0 284,343 217,578
RICE NO. 2-6-1 PV-PD 0 189 0 97 239,826 0 239,826 191,998
WEST NO. 3-2-44 PV-PD 0 226 0 112 263,189 0 263,189 194,023
WEST NO. 3-3-22 PV-PD 0 363 0 179 405,880 0 405,880 272,716
WEST NO. 3-4-45 PV-PD 0 22 0 11 33,690 0 33,690 31,082
</TABLE>
<PAGE> 17
TABLE A
PAGE 6 OF 9
[RYDER SCOTT COMPANY LOGO]
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA
UNESCALATED PARAMETERS - YEAR END PRICING
AS OF JANUARY 1, 1999
<TABLE>
<CAPTION>
------ESTIMATED REMAINING RESERVES-------- --------------ESTIMATED FUTURE DOLLARS------------
-----100% GROSS----- ---------NET--------- GROSS REV. --NET INCOME BEFORE FIT-
(A) (BARRELS) (MMCF) (BARRELS) (MMCF) AFTER PROD. TOTAL DISCOUNTED
STATUS OIL/COND(B) GAS OIL/COND(B) SALES GAS TAXES DEDUCTIONS UNDISCOUNTED AT 5.0%
------ ----------- -------- ----------- --------- ------------ ------------ ------------ -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
LAKE NICOL FIELD,
TUSCALOOSA COUNTY, ALABAMA (CONT.)
WEST NO. 3-8-48 PV-PD 0 324 0 160 387,442 0 387,442 298,875
WEST NO. 3-10-49 PV-PD 0 191 0 96 238,255 0 238,255 193,739
WEST NO. 3-12-67 PV-PD 0 419 0 207 490,212 0 490,212 362,945
WEST NO. 3-13-50 PV-PD 0 235 0 120 280,131 0 280,131 204,472
WEST NO. 11-2-35 PV-PD 0 75 0 38 107,077 0 107,077 96,027
WEST NO. 11-4-41 PV-PD 0 610 0 301 710,921 0 710,921 518,792
WEST NO. 11-5-42 PV-PD 0 336 0 166 402,242 0 402,242 310,816
WEST NO. 15-1-51 PV-PD 0 322 0 165 391,458 0 391,458 292,984
WEST NO. 15-2-52 PV-PD 0 121 0 60 144,082 0 144,082 113,021
WEST NO. 15-3-68 PV-PD 0 47 0 24 66,113 0 66,113 58,090
WEST NO. 15-6-53 PV-PD 0 30 0 15 46,732 0 46,732 42,517
WEST NO. 15-8-55 PV-PD 0 482 0 239 576,330 0 576,330 441,602
WEST NO. 15-12-57 PV-SI 0 0 0 0 0 0 0 0
WEST NO. 15-13-58 PV-PD 0 72 0 36 90,809 0 90,809 76,278
---------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 11,154 0 5,697 13,755,724 0 13,755,724 10,480,104
LITTLE YELLOW CREEK FIELD,
TUSCALOOSA COUNTY, ALABAMA
CUNNINGHAM NO. 28-15-3 PV-PD 0 336 0 179 422,633 0 422,633 314,679
FRIEDMAN NO. 4-8-59 PV-PD 0 428 0 221 513,855 0 513,855 367,423
WEST NO. 33-2-112 PV-PD 0 204 0 101 240,784 0 240,784 185,265
WEST NO. 33-3-120 PV-PD 0 123 0 61 152,118 0 152,118 124,649
WEST NO. 33-6-114 PV-PD 0 90 0 45 115,179 0 115,179 97,347
WEST NO. 33-8-115 PV-PD 0 276 0 137 334,811 0 334,811 264,211
WEST NO. 33-10-116 PV-PD 0 103 0 51 126,713 0 126,713 104,091
WEST NO. 33-16-119 PV-PD 0 328 0 168 401,376 0 401,376 303,006
---------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 1,888 0 962 2,307,469 0 2,307,469 1,760,671
MOORE CREEK FIELD,
TUSCALOOSA COUNTY, ALABAMA
CASSIDY NO. 26-8-122 PV-PD 0 246 0 112 269,256 0 269,256 207,725
CASSIDY NO. 26-10-123 PV-PD 0 329 0 150 346,160 0 346,160 246,789
CHEVRON NO. 26-5-9 PV-PD 0 405 0 216 522,861 0 522,861 403,411
CHEVRON NO. 27-1-10 PV-PD 0 315 0 168 419,026 0 419,026 337,843
CLEMENTS NO. 34-11-1 PV-PD 0 549 0 292 679,357 0 679,357 481,960
CLEMENTS NO. 34-15-1 PV-PD 0 590 0 313 711,150 0 711,150 471,665
CLEMENTS NO. 34-16-2 PV-PD 0 397 0 211 501,688 0 501,688 373,474
FGLIC NO. 26-2-1 PV-PD 0 526 0 279 655,598 0 655,598 473,943
FGLIC NO. 26-6-3 PV-PD 0 539 0 287 682,316 0 682,316 506,944
FIRST ALABAMA BANK NO. 34-1-PV-PD 0 563 0 334 819,913 0 819,913 641,680
FIRST ALABAMA BANK NO. 34-12PV-PD 0 384 0 228 552,793 0 552,793 427,682
FIRST ALABAMA BANK NO. 35-2-PV-PD 0 54 0 33 91,390 0 91,390 81,438
FIRST ALABAMA BANK NO. 35-3-PV-PD 0 462 0 274 659,724 0 659,724 502,389
FIRST ALABAMA BANK NO. 35-5-PV-PD 0 450 0 267 644,112 0 644,112 494,127
HALLMAN NO. 34-8-1 PV-PD 0 471 0 250 588,295 0 588,295 428,288
HOLMAN NO. 34-6-3 PV-PD 0 366 0 206 512,197 0 512,197 410,256
HOLMAN NO. 35-12-4 PV-PD 0 394 0 210 509,135 0 509,135 393,184
MCGUIRE NO. 26-12-6 PV-PD 0 374 0 199 454,011 0 454,011 310,515
MCGUIRE NO. 26-13-3 PV-PD 0 392 0 209 505,856 0 505,856 390,789
MCGUIRE NO. 26-16-1 PV-PD 0 277 0 147 341,341 0 341,341 244,438
MCGUIRE NO. 27-9-4 PV-PD 0 193 0 103 270,294 0 270,294 229,836
NAUGHER NO. 34-7-1 PV-PD 0 364 0 205 500,061 0 500,061 390,950
SESSIONS NO. 35-8-1 PV-PD 0 292 0 156 375,055 0 375,055 289,114
SESSIONS NO. 35-9-2 PV-PD 0 329 0 176 435,185 0 435,185 348,152
SESSIONS NO. 35-15-3 PV-PD 0 858 0 456 1,062,209 0 1,062,209 748,358
---------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 10,119 0 5,480 13,108,983 0 13,108,983 9,834,950
WARRIOR RIDGE FIELD,
TUSCALOOSA COUNTY, ALABAMA
ALABAMA BASIC NO. 36-2-2 PV-PD 0 218 0 93 234,775 0 234,775 192,991
ALABAMA BASIC NO. 36-4-1 PV-PD 0 244 0 104 255,180 0 255,180 202,828
ALABAMA BASIC NO. 36-5-9 PV-PD 0 121 0 50 138,747 0 138,747 122,754
ALABAMA BASIC NO. 36-9-3 PV-PD 0 551 0 234 548,076 0 548,076 393,971
ALABAMA BASIC NO. 36-13-10 PV-PD 0 277 0 118 280,294 0 280,294 211,552
ALABAMA BASIC NO. 36-14-11 PV-PD 0 126 0 54 151,603 0 151,603 135,401
ALABAMA BASIC NO. 36-16-12 PV-PD 0 141 0 61 163,942 0 163,942 143,295
CUNNINGHAM NO. 35-12-1 PV-PD 0 231 0 97 235,410 0 235,410 182,952
FIRST ALABAMA BANK NO. 25-1-PV-PD 0 990 0 480 1,099,239 0 1,099,239 738,951
FIRST ALABAMA BANK NO. 25-2-PV-PD 0 129 0 63 161,999 0 161,999 136,198
FIRST ALABAMA BANK NO. 25-4-PV-PD 0 636 0 309 743,065 0 743,065 561,560
FIRST ALABAMA BANK NO. 25-7-PV-PD 0 161 0 79 203,419 0 203,419 171,553
FIRST ALABAMA BANK NO. 25-10PV-PD 0 292 0 142 360,897 0 360,897 297,082
FIRST ALABAMA BANK NO. 25-11PV-PD 0 262 0 127 316,630 0 316,630 254,774
</TABLE>
<PAGE> 18
TABLE A
PAGE 7 OF 9
[RYDER SCOTT COMPANY LOGO]
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA
UNESCALATED PARAMETERS - YEAR END PRICING
AS OF JANUARY 1, 1999
<TABLE>
<CAPTION>
------ESTIMATED REMAINING RESERVES-------- --------------ESTIMATED FUTURE DOLLARS------------
-----100% GROSS----- ---------NET--------- GROSS REV. --NET INCOME BEFORE FIT-
(A) (BARRELS) (MMCF) (BARRELS) (MMCF) AFTER PROD. TOTAL DISCOUNTED
STATUS OIL/COND(B) GAS OIL/COND(B) SALES GAS TAXES DEDUCTIONS UNDISCOUNTED AT 5.0%
------ ----------- -------- ----------- --------- ------------ ------------ ------------ -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
WARRIOR RIDGE FIELD,
TUSCALOOSA COUNTY, ALABAMA (CONT.)
FIRST ALABAMA BANK NO. 25-12 PV-PD 0 522 0 254 611,620 0 611,620 466,121
FIRST ALABAMA BANK NO. 25-14 PV-PD 0 344 0 167 399,132 0 399,132 302,397
FIRST ALABAMA BANK NO. 25-15 PV-PD 0 246 0 120 291,372 0 291,372 228,303
FIRST ALABAMA BANK NO. 25-16 PV-PD 0 175 0 86 228,241 0 228,241 197,235
FRIEDMAN NO. 30-4-45 PV-PD 0 691 0 275 659,320 0 659,320 496,789
FRIEDMAN NO. 30-5-46 PV-PD 0 489 0 195 502,051 0 502,051 416,981
FRIEDMAN NO. 30-12-47 PV-PD 0 487 0 194 467,114 0 467,114 357,073
FRIEDMAN NO. 30-13-48 PV-PD 0 853 0 340 831,952 0 831,952 647,198
FRIEDMAN NO. 31-12-49 PV-PD 0 238 0 95 246,729 0 246,729 208,269
FRIEDMAN NO. 36-1-43 PV-PD 0 344 0 137 321,741 0 321,741 237,260
FRIEDMAN NO. 36-3-1 PV-PD 0 171 0 69 180,041 0 180,041 153,836
FRIEDMAN NO. 36-7-44 PV-PD 0 72 0 30 80,618 0 80,618 70,429
FRIEDMAN NO. 36-8-2 PV-PD 0 95 0 38 100,067 0 100,067 85,770
FRIEDMAN NO. 36-11-56 PV-PD 0 185 0 77 204,686 0 204,686 176,584
WEST NO. 31-5-82 PV-PD 0 173 0 68 168,920 0 168,920 136,440
WEST NO. 35-2-105 PV-PD 0 272 0 107 280,453 0 280,453 238,728
WEST NO. 35-4-106 PV-PD 0 281 0 114 282,339 0 282,339 224,936
WEST NO. 35-6-107 PV-PD 0 142 0 56 149,811 0 149,811 129,915
WEST NO. 35-8-108 PV-PD 0 156 0 61 166,421 0 166,421 145,568
WEST NO. 35-9-109 PV-PD 0 244 0 96 249,972 0 249,972 211,988
WEST NO. 35-10-110 PV-PD 0 103 0 41 110,200 0 110,200 96,487
WEST NO. 35-14-111 PV-PD 0 75 0 30 78,899 0 78,899 68,372
-------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 10,737 0 4,658 11,504,975 0 11,504,975 9,042,541
WARRIOR RIDGE, WEST FIELD,
TUSCALOOSA COUNTY, ALABAMA
ALABAMA BASIC NO. 23-10-4 PV-PD 0 399 0 167 448,004 0 448,004 386,575
ALABAMA BASIC NO. 23-14-5 PV-PD 0 308 0 128 308,117 0 308,117 236,767
ALABAMA BASIC NO. 23-16-6 PV-PD 0 241 0 101 261,287 0 261,287 220,325
ALABAMA BASIC NO. 26-1-7 PV-PD 0 506 0 210 505,271 0 505,271 382,637
ALABAMA BASIC NO. 27-16-8 PV-PD 0 451 0 189 470,183 0 470,183 375,744
FIRST ALABAMA BANK NO. 26-16 PV-PD 0 671 0 312 730,856 0 730,856 522,932
HOLMAN NO. 26-4-23 PV-PD 0 235 0 99 245,268 0 245,268 196,597
HOLMAN NO. 26-5-29 PV-PD 0 117 0 50 123,580 0 123,580 101,241
HOLMAN NO. 26-6-24 PV-PD 0 404 0 171 414,685 0 414,685 321,862
WEST NO. 23-3-93 PV-PD 0 486 0 191 487,086 0 487,086 401,874
WEST NO. 23-5-94 PV-PD 0 499 0 195 468,645 0 468,645 356,108
WEST NO. 23-6-95 PV-PD 0 199 0 80 198,486 0 198,486 159,714
WEST NO. 23-7-96 PV-PD 0 220 0 86 226,001 0 226,001 192,322
WEST NO. 23-8-92 PV-PD 0 539 0 210 497,031 0 497,031 365,046
WEST NO. 27-2-97 PV-PD 0 423 0 165 397,237 0 397,237 303,124
WEST NO. 27-4-98 PV-PD 0 545 0 212 487,237 0 487,237 333,680
WEST NO. 27-5-99 PV-PD 0 575 0 224 513,140 0 513,140 349,954
WEST NO. 27-7-100 PV-PD 0 563 0 220 512,858 0 512,858 366,581
WEST NO. 27-8-101 PV-PD 0 392 0 153 371,512 0 371,512 287,439
WEST NO. 27-11-102 PV-PD 0 425 0 167 393,846 0 393,846 289,169
WEST NO. 27-13-103 PV-PD 0 235 0 92 226,100 0 226,100 180,443
WEST NO. 27-14-104 PV-PD 0 384 0 150 369,108 0 369,108 291,255
-------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 8,817 0 3,573 8,655,538 0 8,655,538 6,621,389
WATERMELON ROAD FIELD,
TUSCALOOSA COUNTY, ALABAMA
CHRISTIAN NO. 12-5-2 PV-PD 0 190 0 102 274,573 0 274,573 238,903
DAVANT NO. 1-12-10 PV-PD 0 710 0 377 881,092 0 881,092 626,469
DAVANT NO. 1-13-11 PV-PD 0 401 0 207 534,198 0 534,198 446,102
DAVANT NO. 3-1-12 PV-PD 0 1,003 0 531 1,198,443 0 1,198,443 763,802
DAVANT NO. 3-2-13 PV-PD 0 199 0 106 258,717 0 258,717 203,896
FIRST ALABAMA BANK NO. 10-9- PV-PD 0 342 0 197 466,613 0 466,613 347,214
FIRST ALABAMA BANK NO. 10-15 PV-PD 0 152 0 88 223,151 0 223,151 184,684
FIRST ALABAMA BANK NO. 10-16 PV-PD 0 276 0 160 411,207 0 411,207 342,450
FIRST ALABAMA BANK NO. 12-1- PV-PD 0 442 0 249 601,684 0 601,684 462,176
FIRST ALABAMA BANK NO. 12-2- PV-PD 0 137 0 78 211,827 0 211,827 186,179
HINDS NO. 12-6-1 PV-PD 0 197 0 105 266,362 0 266,362 220,152
HINDS NO. 12-7-2 PV-PD 0 286 0 153 381,179 0 381,179 307,862
HINDS NO. 12-11-3 PV-PD 0 271 0 145 384,294 0 384,294 329,285
HOWELL NO. 12-9-1 PV-PD 0 296 0 158 398,503 0 398,503 325,122
HOWELL NO. 12-14-2 PV-PD 0 292 0 156 391,300 0 391,300 318,257
HOWELL NO. 12-15-3 PV-PD 0 202 0 109 288,104 0 288,104 247,913
MAYFIELD NO. 1-3-3 PV-PD 0 428 0 227 535,797 0 535,797 392,581
MAYFIELD NO. 1-7-4 PV-PD 0 426 0 227 557,076 0 557,076 437,671
PRICE NO. 1-1-1 PV-PD 0 169 0 90 225,909 0 225,909 184,313
STEDMAN NO. 1-9-1 PV-PD 0 222 0 110 292,310 0 292,310 250,789
STEDMAN NO. 1-11-3 PV-PD 0 167 0 83 212,175 0 212,175 177,102
STEDMAN NO. 1-15-14 PV-PD 0 367 0 181 436,888 0 436,888 334,945
</TABLE>
<PAGE> 19
TABLE A
PAGE 8 OF 9
[RYDER SCOTT COMPANY LOGO]
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA
UNESCALATED PARAMETERS - YEAR END PRICING
AS OF JANUARY 1, 1999
<TABLE>
<CAPTION>
------ESTIMATED REMAINING RESERVES-------- --------------ESTIMATED FUTURE DOLLARS------------
-----100% GROSS----- ---------NET--------- GROSS REV. --NET INCOME BEFORE FIT-
(A) (BARRELS) (MMCF) (BARRELS) (MMCF) AFTER PROD. TOTAL DISCOUNTED
STATUS OIL/COND(B) GAS OIL/COND(B) SALES GAS TAXES DEDUCTIONS UNDISCOUNTED AT 5.0%
------ ----------- -------- ----------- --------- ------------ ------------ ------------ -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
WATERMELON ROAD FIELD,
TUSCALOOSA COUNTY, ALABAMA (CONT.)
STEDMAN NO. 1-16-4 PV-PD 0 310 0 154 379,092 0 379,092 301,587
STEDMAN NO. 11-1-5 PV-PD 0 267 0 133 353,268 0 353,268 303,537
STEDMAN NO. 11-2-6 PV-PD 0 226 0 113 297,310 0 297,310 254,579
STEDMAN NO. 11-3-24 PV-PD 0 410 0 204 522,654 0 522,654 433,805
STEDMAN NO. 11-4-7 PV-PD 0 374 0 184 430,029 0 430,029 310,204
STEDMAN NO. 11-5-8 PV-PD 0 179 0 89 228,576 0 228,576 191,640
STEDMAN NO. 11-9-9 PV-PD 0 211 0 104 253,464 0 253,464 198,831
STEDMAN NO. 11-10-10 PV-PD 0 210 0 104 278,223 0 278,223 240,082
STEDMAN NO. 11-12-11 PV-PD 0 265 0 131 330,953 0 330,953 270,698
STEDMAN NO. 11-14-12 PV-PD 0 231 0 115 298,505 0 298,505 252,293
STEDMAN NO. 11-16-13 PV-PD 0 287 0 142 349,633 0 349,633 278,085
---------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 10,145 0 5,316 13,153,109 0 13,153,109 10,363,208
YELLOW CREEK FIELD,
TUSCALOOSA COUNTY, ALABAMA
BIGHAM NO. 4-13-1 PV-PD 0 195 0 104 246,492 0 246,492 186,893
EARNEST NO. 15-10-2 PV-PD 0 235 0 126 325,693 0 325,693 273,654
EARNEST NO. 15-15-5 PV-PD 0 97 0 52 142,129 0 142,129 124,674
EARNEST NO. 15-16-4 PV-PD 0 84 0 45 127,667 0 127,667 114,023
FEDERAL NO. 9-4-5 PV-PD 0 541 0 289 721,897 0 721,897 580,180
FEDERAL NO. 9-12-7 PV-PD 0 373 0 199 503,628 0 503,628 411,467
FEDERAL NO. 9-14-8 PV-PD 0 452 0 240 552,140 0 552,140 381,738
GILBERT NO. 15-5-1 PV-PD 0 209 0 96 254,960 0 254,960 219,097
GILBERT NO. 15-6-3 PV-PD 0 605 0 322 784,833 0 784,833 607,012
GILBERT NO. 15-12-2 PV-PD 0 167 0 77 192,325 0 192,325 157,993
HOLMAN NO. 15-1-28 PV-PD 0 237 0 121 316,094 0 316,094 267,240
HOLMAN NO. 15-8-25 PV-PD 0 118 0 60 166,214 0 166,214 146,857
SULLIVAN NO. 4-11-2 PV-PD 0 345 0 183 468,769 0 468,769 389,245
USX NO. 9-6-20 PV-PD 0 411 0 187 440,363 0 440,363 322,315
USX NO. 9-7-21 PV-PD 0 595 0 272 671,142 0 671,142 529,765
USX NO. 9-10-22 PV-PD 0 682 0 311 745,642 0 745,642 561,143
USX NO. 9-15-23 PV-PD 0 360 0 164 407,376 0 407,376 325,750
USX NO. 9-16-38 PV-PD 0 936 0 426 994,162 0 994,162 701,898
USX NO. 14-3-45 PV-PD 0 291 0 134 360,836 0 360,836 313,322
USX NO. 14-5-24 PV-PD 0 218 0 100 242,871 0 242,871 191,819
USX NO. 14-10-43 PV-PD 0 102 0 48 128,025 0 128,025 110,959
USX NO. 14-11-25 PV-PD 0 297 0 135 318,789 0 318,789 237,113
USX NO. 14-13-37 PV-PD 0 65 0 30 89,734 0 89,734 82,188
USX NO. 14-14-44 PV-PD 0 279 0 128 341,634 0 341,634 294,489
USX NO. 15-13-27 PV-PD 0 111 0 51 139,741 0 139,741 123,020
USX NO. 16-2A-40 PV-PD 0 355 0 162 387,346 0 387,346 294,338
USX NO. 16-4-29 PV-PD 0 156 0 71 170,563 0 170,563 133,262
USX NO. 16-5-30 PV-PD 0 166 0 76 196,495 0 196,495 166,073
USX NO. 16-7-31 PV-PD 0 103 0 47 129,053 0 129,053 113,256
USX NO. 16-8-28 PV-PD 0 374 0 170 388,839 0 388,839 266,781
USX NO. 16-11-33 PV-PD 0 292 0 134 337,512 0 337,512 276,615
USX NO. 16-13-34 PV-PD 0 234 0 107 271,732 0 271,732 224,612
USX NO. 16-15-35 PV-PD 0 173 0 79 190,038 0 190,038 148,128
---------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 9,858 0 4,751 11,754,734 0 11,754,734 9,276,919
YELLOW CREEK, WEST FIELD,
TUSCALOOSA COUNTY, ALABAMA
BAUGHMAN NO. 18-3-2 PV-PD 0 175 0 94 250,179 0 250,179 216,178
BAUGHMAN NO. 18-6-3 PV-PD 0 341 0 183 491,667 0 491,667 425,868
BAUGHMAN NO. 18-7-4 PV-PD 0 242 0 130 344,947 0 344,947 296,601
CANTLEY NO. 17-7-2 PV-PD 0 137 0 73 202,521 0 202,521 179,091
FEDERAL NO. 8-9-10 PV-PD 0 165 0 89 229,449 0 229,449 193,912
FEDERAL NO. 8-16-12 PV-PD 0 178 0 95 246,565 0 246,565 207,811
HALLMAN NO. 8-14-1 PV-PD 0 593 0 315 737,456 0 737,456 529,326
HALLMAN NO. 17-2-2 PV-PD 0 206 0 110 293,621 0 293,621 252,850
HAYES NO. 7-16-2 PV-PD 0 683 0 364 873,567 0 873,567 658,350
HAYES NO. 18-13-3 PV-PD 0 373 0 199 493,799 0 493,799 395,206
HAYES NO. 18-14-4 PV-PD 0 455 0 243 607,234 0 607,234 488,639
HOLMAN NO. 13-7-19 PV-PD 0 325 0 174 462,173 0 462,173 396,105
HOLMAN NO. 13-11-20 PV-PD 0 405 0 217 552,248 0 552,248 455,013
HOLMAN NO. 13-14-21 PV-PD 0 147 0 79 210,797 0 210,797 182,752
HOLMAN NO. 13-15-22 PV-PD 0 277 0 148 394,272 0 394,272 338,951
HOLMAN NO. 17-11-31 PV-PD 0 305 0 163 407,529 0 407,529 329,935
HOLMAN NO. 17-12-15 PV-PD 0 307 0 164 421,901 0 421,901 351,072
HOLMAN NO. 17-13-16 PV-PD 0 414 0 220 524,062 0 524,062 392,264
MOORE NO. 13-1-1 PV-PD 0 346 0 184 440,783 0 440,783 334,575
MOORE NO. 13-9-2 PV-PD 0 291 0 156 404,505 0 404,505 340,685
PAYNE NO. 17-15-1 PV-PD 0 195 0 104 272,559 0 272,559 231,491
PETTUS NO. 8-5-3 PV-PD 0 262 0 140 358,704 0 358,704 298,751
</TABLE>
<PAGE> 20
TABLE A
PAGE 9 OF 9
[RYDER SCOTT COMPANY LOGO]
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA
UNESCALATED PARAMETERS - YEAR END PRICING
AS OF JANUARY 1, 1999
<TABLE>
<CAPTION>
------ESTIMATED REMAINING RESERVES-------- --------------ESTIMATED FUTURE DOLLARS------------
-----100% GROSS----- ---------NET--------- GROSS REV. --NET INCOME BEFORE FIT-
(A) (BARRELS) (MMCF) (BARRELS) (MMCF) AFTER PROD. TOTAL DISCOUNTED
STATUS OIL/COND(B) GAS OIL/COND(B) SALES GAS TAXES DEDUCTIONS UNDISCOUNTED AT 5.0%
------ ----------- -------- ----------- --------- ------------ ------------ ------------ -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
YELLOW CREEK, WEST FIELD,
TUSCALOOSA COUNTY, ALABAMA (CONT.)
PETTUS NO. 8-6-2 PV-PD 0 111 0 59 155,077 0 155,077 132,288
SEALY NO. 18-1-1 PV-PD 0 430 0 230 579,886 0 579,886 473,060
TURNER NO. 17-10-1 PV-PD 0 312 0 167 426,549 0 426,549 353,675
TURNER NO. 17-16-1 PV-PD 0 73 0 39 112,937 0 112,937 101,903
WEYERHAEUSER NO. 5-15-2 PV-PD 0 561 0 290 698,642 0 698,642 530,509
WEYERHAEUSER NO. 5-16-1 PV-PD 0 181 0 94 253,809 0 253,809 220,914
---------- -------- ---------- -------- ------------ ------------ ------------ ------------
TOTAL FIELD 0 8,490 0 4,525 11,447,438 0 11,447,438 9,307,775
---------- -------- ---------- -------- ------------ ------------ ------------ ------------
GRAND SUMMARY - PROVED PRODUCING 0 152,275 0 74,679 182,981,116 0 182,981,116 142,220,968
</TABLE>
<TABLE>
<S> <C> <C>
(A) RESERVE TYPES: PV = PROVED STATUS: PD = PRODUCING DP = DEPLETED
PB = PROBABLE BP = BEHIND PIPE NP = NON-PRODUCING
PS = POSSIBLE SI = SHUT IN PB = PAYBACK
UD = UNDEVELOPED
(B) EXCLUDES PLANT PRODUCTS
</TABLE>
<PAGE> 21
[RYDER SCOTT COMPANY] TABLE 1
DOMINION RESOURCES ROYALTY TRUST 1994-1
65% OVERRIDING ROYALTY INTEREST
ESTIMATE OF RESERVES AND FUTURE NET INCOME
UNESCALATED PARAMETERS - YEAR END PRICING
AS OF JANUARY 1, 1999
<TABLE>
<CAPTION>
GRAND SUMMARY
PROVED PRODUCING TOTAL
PROVED
REVENUE INTERESTS PRODUCT PRICES
-------------------------------- ----------------------------- DISCOUNTED
EXPENSE Oil/ Plant Oil/Cond. Pit. Prod. Gas FURNITURE NET INCOME-$
INTEREST Condensate Products Gas $bbL $bbL $/MCF COMPOUNDED MONTHLY
-------- ---------- -------- ------- --------- ---------- -------- -----------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
INITIAL 5.00% - 142,220,968
FINAL 10.00% - 116,544,072
REMARKS 15.00% - 98,938,792
20.00% - 86,093,687
25.00% - 76,279,093
</TABLE>
<TABLE>
<CAPTION>
ESTIMATED 8/8 THS PRODUCTION COMPANY NET PRODUCTION AVERAGE PRICES
--------------------------------- ----------------------------------------- -----------------
Number Oil/Cond. Plant Products Gross Oil/Cond. Plant Products Sales Gas Oil/Cond. Gas
Period of Wells Barrels Barrels MMCF Barrels Barrels MMCF S/bbl S/MCF
- - ------ -------- ---------- ----------- ------ -------------- ------------- -------- --------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1999 526 0 0 18,949 0 0 9,450.370 0.00 2.12
2000 526 0 0 16,768 0 0 8,364.969 0.00 2.12
2001 523 0 0 14,820 0 0 7,399.904 0.00 2.12
2002 523 0 0 13,147 0 0 6,559.176 0.00 2.12
2003 513 0 0 11,612 0 0 5,617.258 0.00 2.12
2004 506 0 0 10,328 0 0 4,995.224 0.00 2.12
2005 498 0 0 9,139 0 0 4,420.984 0.00 2.12
2006 485 0 0 8,095 0 0 3,915.078 0.00 2.12
2007 462 0 0 7,133 0 0 3,445.320 0.00 2.12
2008 433 0 0 6,235 0 0 3,017.045 0.00 2.12
2009 409 0 0 5,474 0 0 2,647.786 0.00 2.12
2010 382 0 0 4,733 0 0 2,295.049 0.00 2.12
2011 342 0 0 4,121 0 0 1,995.652 0.00 2.12
2012 314 0 0 3,569 0 0 1,721.427 0.00 2.12
2013 283 0 0 3,057 0 0 1,483.384 0.00 2.12
Sub-Total 0 0 137,180 0 0 67,328.626 0.00 2.12
Remainder 0 0 15,095 0 0 7,350.013 0.00 2.12
Total Future 0 0 152,275 0 0 74,678.639 0.00 2.12
Cumulative 0 0 200,646
Ultimate 0 0 352,921
</TABLE>
<TABLE>
<CAPTION>
COMPANY FUTURE GROSS REVENUE (fgr) -$ PRODUCTION TAXES
------------------------------------------------------------------- ------------------------ FOR AFTER
From From From PRODUCTION
Period Oil/Cond. Plant Products Gas Other Total Oil/Cond-$ Gas/P.P.-$ TAXES-$
- - ------- -------------- -------------- ---------- ---------- ---------- ----------- ----------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1999 0 0 20,009,999 10,215,121 30,225,120 0 1,200,608 29,024,512
2000 0 0 17,711,785 9,041,878 26,753,663 0 1,062,702 25,690,961
2001 0 0 15,668,376 7,998,717 23,667,093 0 940,100 22,726,993
2002 0 0 13,888,232 7,089,978 20,978,210 0 833,299 20,144,911
2003 0 0 11,893,869 0 11,893,869 0 713,614 11,180,255
2004 0 0 10,576,766 0 10,576,766 0 634,619 9,942,147
2005 0 0 9,360,884 0 9,360,884 0 561,660 8,799,224
2006 0 0 8,289,693 0 8,289,693 0 497,366 7,792,327
2007 0 0 7,295,046 0 7,295,046 0 437,709 6,857,337
2008 0 0 6,388,192 0 6,388,192 0 383,299 6,004,893
2009 0 0 5,606,379 0 5,606,379 0 336,372 5,270,007
2010 0 0 4,859,483 0 4,859,483 0 291,579 4,567,904
2011 0 0 4,225,554 0 4,225,554 0 253,523 3,972,031
2012 0 0 3,644,898 0 3,644,898 0 218,705 3,426,193
2013 0 0 3,140,883 0 3,140,883 0 188,446 2,952,437
Sub-Total 0 0 142,560,039 34,345,694 176,905,733 0 8,553,601 168,352,132
Remainder 0 0 15,562,748 0 15,562,748 0 933,764 14,628,984
Total Future 0 0 158,122,787 34,345,694 192,468,481 0 9,487,365 182,981,116
</TABLE>
<TABLE>
<CAPTION>
DEDUCTIONS- $ FUTURE NET INCOME BEFORE INCOME TAXES-$
------------------------------------------------------------- ------------------------------------------
Undiscounted
Operating Ad Valorem Development ---------------------------- Discounted
Period Costs Taxes Costs Other Total Annual Cumulative 5.00%
- - ------ ------------- ----------- ----------- ----------- ------------ -------------- ------------ -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1999 0 0 0 0 0 29,024,512 29,024,512 28,325,965
2000 0 0 0 0 0 25,690,961 54,715,473 23,853,008
2001 0 0 0 0 0 22,726,993 77,442,466 20,073,751
2002 0 0 0 0 0 20,144,911 97,587,377 16,927,096
2003 0 0 0 0 0 11,180,255 108,767,632 8,937,163
2004 0 0 0 0 0 9,942,147 118,709,779 7,560,548
2005 0 0 0 0 0 8,799,224 127,509,003 6,365,785
2006 0 0 0 0 0 7,792,327 135,301,330 5,363,136
2007 0 0 0 0 0 6,857,337 142,158,667 4,490,018
2008 0 0 0 0 0 6,004,893 148,163,560 3,740,423
2009 0 0 0 0 0 5,270,007 153,433,567 3,122,977
2010 0 0 0 0 0 4,567,904 158,001,471 2,575,302
2011 0 0 0 0 0 3,972,031 161,973,502 2,130,235
2012 0 0 0 0 0 3,426,193 165,399,695 1,748,173
2013 0 0 0 0 0 2,952,437 168,352,132 1,433,161
Sub-Total 0 0 0 0 0 168,352,132 136,646,741
Remainder 0 0 0 0 0 14,628,984 182,981,116 5,574,227
Total Future 0 0 0 0 0 182,981,116 142,220,968
</TABLE>
LIFE OF SUMMARY IS 40.92 YEARS.
