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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1994
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 identification number)
incorporation or organization)
NationsBank of Texas, N.A.
NationsBank Center
901 Main Street
12th Floor
Dallas, Texas 75202
(Address of principal executive (Zip Code)
offices)
Registrant's telephone number, including area code:
(214) 508-2400
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
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<S> <C>
Units of Beneficial Interest New York Stock Exchange, Inc.
</TABLE>
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
At March 15, 1995, 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 $150,131,250.
DOCUMENTS INCORPORATED BY REFERENCE
Listed below are documents parts of which are incorporated herein by
reference and the part of this report into which the document is incorporated:
(1) 1994 Annual Report to Unitholders--Part II.
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TABLE OF CONTENTS
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PAGE
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<S> <C>
PART I..................................................................... 1
Item 1. Business......................................................... 1
GLOSSARY............................................................... 1
DESCRIPTION OF THE TRUST............................................... 3
Creation and Organization of the Trust............................... 3
Assets of the Trust.................................................. 4
Duties and Limited Powers of the Trustee and the Delaware Trustee.... 4
Resignation of Trustees.............................................. 5
Transfer of Royalty Interests........................................ 5
Liabilities of the Trust............................................. 5
Liabilities of the Trustee and the Delaware Trustee.................. 6
Termination and Liquidation of the Trust............................. 6
Arbitration and Actions by Unitholders............................... 7
DESCRIPTION OF UNITS................................................... 8
Distributions and Income Computations................................ 9
Conditional Right of Repurchase...................................... 9
Possible Divestiture of Units........................................ 11
Periodic Reports..................................................... 11
Voting Rights of Unitholders......................................... 12
Liability of Unitholders............................................. 13
Transfer Agent....................................................... 13
FEDERAL INCOME TAX CONSIDERATIONS...................................... 13
Summary of Certain Federal Income Tax Consequences................... 14
ERISA CONSIDERATIONS................................................... 18
STATE TAX CONSIDERATIONS............................................... 18
Alabama Income Tax................................................... 18
Alabama Franchise Tax................................................ 19
Other Alabama Taxes.................................................. 19
REGULATION AND PRICES.................................................. 19
Regulation of Natural Gas............................................ 19
Environmental Regulation............................................. 20
Competition, Markets and Prices...................................... 21
Item 2. Properties....................................................... 21
THE ROYALTY INTERESTS.................................................. 21
The Underlying Properties............................................ 22
The Royalty Interests................................................ 24
Reserve Estimate..................................................... 25
Natural Gas Sales Prices and Production.............................. 26
Gas Purchase Agreement............................................... 27
Operation of Properties.............................................. 27
Pratt Recompletion Payments.......................................... 28
Sale and Abandonment of Underlying Properties........................ 29
Dominion Resources' Assurances....................................... 29
Title to Properties.................................................. 30
Item 3. Legal Proceedings................................................ 30
Item 4. Submission of Matters to a Vote of Security Holders.............. 30
</TABLE>
(i)
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<TABLE>
<S> <C>
PART II.................................................................... 30
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters............................................................ 30
Item 6. Selected Financial Data.......................................... 30
Item 7. Trustee's Discussion and Analysis of Financial Condition and
Results of Operations.............................................. 30
Item 8. Financial Statements and Supplementary Data...................... 31
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure............................................... 31
PART III................................................................... 31
Item 10. Directors and Executive Officers of the Registrant.............. 31
Item 11. Executive Compensation.......................................... 31
Item 12. Security Ownership of Certain Beneficial Owners and Management.. 32
Item 13. Certain Relationships and Related Transactions.................. 32
Administrative Services Agreement...................................... 32
Dominion Resources' Conditional Right of Repurchase.................... 32
Potential Conflicts of Interest........................................ 33
PART IV.................................................................... 34
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K. 34
Financial Statements................................................... 34
Financial Statement Schedules.......................................... 34
Exhibits............................................................... 34
Reports on Form 8-K.................................................... 35
</TABLE>
(ii)
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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, pursuant to the Gas Purchase Agreement,
that Sonat Marketing will be obligated to purchase the Subject Gas at the
central delivery delivery points in the gathering system for the Underlying
Properties. The Contract Price equals for each month (a) from June 1, 1994
through December 31, 1998 (i) for quantities of natural gas equal to or less
than the Monthly Base Quantity, the sum of the Index Price and the Premium,
which price shall not be below the Minimum Price or above the Maximum Price,
and (ii) for quantities of natural gas in excess of the Monthly Base Quantity,
the Index Price and (b) after December 31, 1998, a price to be negotiated by
the Company and Sonat Marketing, which price shall not be less than the Index
Price.
"Conveyance" means the Overriding Royalty Conveyance dated effective as of
June 1, 1994, from the Company to the Trust, as amended by instrument dated as
of November 20, 1994, copies of which are filed as exhibits to this Form 10-K.
"Delaware Trustee" means Mellon Bank (DE) National Association.
"Dominion Resources" means Dominion Resources, Inc., a Virginia corporation.
"Existing Wells" means the wells producing on the Underlying Properties as of
June 1, 1994.
"Gas" means natural gas produced and sold from the Underlying Properties.
"Gas Purchase Agreement" means the Gas Purchase Agreement dated as of May 3,
1994, between the Company and Sonat Marketing.
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"Gross Proceeds" means the aggregate amounts received by the Company
Interests Owner attributable to the Company Interests from the sale of Subject
Gas at the central delivery points in the gathering system for the Underlying
Properties.
"Gross Wells" means the total whole number of gas wells.
"Index Price" means the price published by Inside Ferc's Gas Market Report in
its first issue of the month which posts prices for the beginning of such month
for "Prices of Spot Gas Delivered to Pipelines" "Southern Natural Gas Co."
"Louisiana" "Index," for such month.
"Mcf" means thousand cubic feet of natural gas. Natural gas volumes are
stated herein at the legal pressure base of 14.65 or 14.73 pounds per square
inch absolute, as the case may be, at 60 degrees Fahrenheit.
"Maximum Price" means $2.63 per MMBtu, the maximum price payable for the
Monthly Base Quantities pursuant to the Gas Purchase Agreement from June 1,
1994 through December 31, 1998.
"Minimum Price" means $1.85 per MMBtu, the minimum price payable for the
Monthly Base Quantities pursuant to the Gas Purchase Agreement from June 1,
1994 through December 31, 1998.
"MMcf" means million cubic feet of natural gas. As used herein, 1 MMcf is
assumed to have a Btu content of 990 MMBtu.
"MMBtu" means million Btu. As used herein, 990 MMBtu is deemed to be the Btu
content of 1 MMcf.
"Monthly Base Quantity" means the volumes of natural gas designated as such
in the Gas Purchase Agreement.
"Net revenue interest" means working interest or mineral interest less any
applicable royalties, overriding royalties or similar burdens on production
prior to the Royalty Interests.
"Net wells" and "net acres" are calculated by multiplying gross wells or
gross acres by the working interest in such wells or acres.
"Premium" means the premium per MMbtu on a wet basis pursuant to the Gas
Purchase Agreement from June 1, 1994 through December 31, 1998 as follows:
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INDEX PRICE PREMIUM
($/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, pursuant to which the
Units were offered and sold.
"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, 1995, prepared by Ryder Scott.
"River Gas" means The River Gas Corporation, an Alabama corporation.
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"Royalty Interests" means the overriding royalty interests conveyed to the
Trust pursuant to the Conveyance entitling the holder thereof to 65 percent of
the Gross Proceeds derived from the Company Interests.
"Ryder Scott" means Ryder Scott Company Petroleum Engineers, independent
petroleum engineers.
"Section 29 tax credit" means the tax credits for federal income tax purposes
pursuant to Section 29 of the Code to an owner of coal seam gas production,
which tax credits are generated upon the sale of such production.
"Sonat" means Sonat, Inc., a Delaware corporation.
"Sonat Marketing" means Sonat Marketing Company, a Delaware Corporation.
"Subject Gas" means Gas attributable to the Company Interests.
"Trust" means Dominion Resources Black Warrior Trust, a Delaware business
trust formed pursuant to the Trust Agreement.
"Trust Agreement" means the Trust Agreement dated as of May 31, 1994, among
the Company, as grantor, Dominion Resources, the Delaware Trustee and the
Trustee, as amended by instrument dated as of June 27, 1994, copies of which
are filed as exhibits to this Form 10-K.
"Trustee" means NationsBank of Texas, N.A.
"Working interest" generally refers to the lessee's interest in an oil, gas
or mineral lease which entitles the owner to receive a specified percentage of
oil and gas production, but requires the owner of such working interest to bear
such specified percentage of the costs to explore for, develop, produce and
market such oil and gas.
"Underlying Properties" means the natural gas properties in which the Company
has an interest located in the Black Warrior Basin, Tuscaloosa County, Alabama
insofar as such properties include the Pottsville Formation.
"Units" means the 7,850,000 units of beneficial interest issued by, and
evidencing the entire beneficial interest in, the Trust.
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 detailed
provisions concerning the Trust may be found in 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
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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 6,850,000 Units to the public through various underwriters (the
"Underwriters") in June 1994 and sold an additional 54,000 Units to the public
through the Underwriters in August 1994 (collectively, the "Public Offering").
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). "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 Subject Gas at the central delivery points in the gathering system
for the Underlying Properties. 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
Internal Revenue Code of 1986, as amended (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.
The Delaware Trustee has only such powers as are set forth in the Trust
Agreement or are required by law and is not empowered to take part in the
management of the Trust.
The Royalty Interests are passive in nature and neither the Trustee nor the
Delaware Trustee have any control over or any responsibility relating to the
operation of the Underlying Properties. The Company does not have any
contractual commitment to the Trust to develop further the Underlying
Properties, except for recompletions to the Pratt coal seam, or to maintain its
ownership
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interest in any of the Underlying Properties. See "Properties--The Royalty
Interests--Pratt Recompletion Payments." The Company may sell the Company
Interests subject to and burdened by the Royalty Interests and, absent certain
conditions having been met, with the continuing benefit of Dominion Resources'
assurances and the Gas Purchase Agreement. For a description of the Underlying
Properties, the Royalty Interests and other information relating to such
properties, see "Properties--The Royalty Interests."
The Trust Agreement authorizes the Trustee to take such action as in its
judgment is necessary, desirable or advisable to best achieve the purposes of
the Trust. The Trustee is empowered by the Trust Agreement to employ
consultants and agents (including the Company, Dominion Energy and Dominion
Resources) and to make payments of all fees for services or expenses out of the
assets of the Trust. The Trustee is authorized to agree to modifications of the
terms of the Conveyance and to settle disputes with respect thereto, so long as
such modifications or settlements do not result in treatment of the Trust as an
association, taxable as a corporation, for federal income tax purposes and such
modifications or settlements do not alter the nature of the Royalty Interests
as a right to receive a share of production or the proceeds of production from
the Underlying Properties which, with respect to the Trust, are free of any
operating rights, expenses or obligations. The Trust Agreement provides that
cash being held by the Trustee as a reserve for liabilities or for distribution
at the next distribution date will be placed in demand deposit accounts, U.S.
government obligations, repurchase agreements secured by such obligations or
certificates of deposit, but the Trustee is otherwise prohibited from acquiring
any asset other than the Royalty Interests and cash proceeds therefrom or
engaging in any business or investment activity of any kind whatsoever. The
Trustee may deposit funds awaiting distribution in an account with the Trustee
provided the interest rate paid equals the interest rate paid by the Trustee on
similar deposits.
The Trust has no employees. Administrative functions are performed by the
Trustee.
RESIGNATION OF TRUSTEES
The Trustee and the Delaware Trustee may resign at any time upon 60 days'
prior written notice or be removed, with or without cause, by a vote of not
less than a majority of the outstanding Units, provided in each case that a
successor trustee has been appointed and has accepted its appointment. Any
successor must be a bank or trust company meeting certain requirements,
including having capital, surplus and undivided profits of at least
$100,000,000, in the case of the Trustee, and $20,000,000, in the case of the
Delaware Trustee.
TRANSFER OF ROYALTY INTERESTS
Prior to the termination of the Trust, the Trustee is not authorized to sell
or otherwise dispose of all or any part of the Royalty Interests. The Trustee
is authorized and directed to sell and convey the Royalty Interests without
Unitholder approval upon termination of the Trust. No Unitholder approval for
such sales or dispositions is required even though they may constitute a
disposition of all or substantially all the assets of the Trust. Any sales upon
termination may be made to Dominion Resources or its affiliates. See "--
Termination and Liquidation of the Trust."
LIABILITIES OF THE TRUST
Because of the passive nature of the Trust assets and the restrictions on the
activities of the Trustee, it is anticipated that the only liabilities the
Trust will incur will be 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. However, 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
shall be personally or individually liable only for fraud or acts or omissions
in bad faith or which constitute gross negligence (and for taxes, fees and
other charges on, based on or measured by any fees, commissions or compensation
received pursuant to the Trust Agreement) and will not be otherwise liable for
any act or omission of any agent or employee unless such trustee has acted in
bad faith or with gross negligence in the selection and retention of such agent
or employee. Each of the Trustee and the Delaware Trustee (and their respective
agents) is indemnified by Dominion Resources and from the Trust assets for
certain environmental liabilities, and for any other liability, expense, claim,
damage or other loss incurred in performing its duties, unless resulting from
gross negligence, fraud or bad faith (each of the Trustee and the Delaware
Trustee is indemnified from the Trust assets against its own negligence which
does not constitute gross negligence), and will have a first lien upon the
assets of the Trust as security for such indemnification and for reimbursements
and compensation to which it is entitled; provided that the Trustee and the
Delaware Trustee are generally required to first be indemnified from Trust
assets before seeking indemnification from Dominion Resources. Dominion
Resources also has agreed to indemnify the Trustee and the Delaware Trustee
against certain securities laws' liabilities. Neither the Trustee nor the
Delaware Trustee is entitled to indemnification from Unitholders (except in
connection with lost or destroyed Unit certificates). Insofar as
indemnification for liabilities arising under the Securities Act of 1933, as
amended (the "Securities Act"), is permitted to the Trustee pursuant to the
foregoing provisions, the Trustee has been informed that in the opinion of the
Securities and Exchange Commission (the "Commission") such indemnification is
against public policy as expressed in the Securities Act and is therefore
unenforceable.
TERMINATION AND LIQUIDATION OF THE TRUST
The Trust will terminate upon the occurrence of: (i) an affirmative vote of
the holders of not less than 66 2/3 percent of the outstanding Units to
terminate the Trust; (ii) such time as the ratio of the cash amounts received
by the Trust attributable to the Royalty Interests in any calendar quarter to
administrative costs of the Trust for such calendar quarter is less than 1.2 to
1.0 for two consecutive calendar quarters; or (iii) March 1 of any year if it
is determined, based on a reserve report as of December 31 of the prior year
prepared by a firm of independent petroleum engineers mutually selected by the
Trustee and the Company, that the net present value (discounted at 10 percent)
of (a) estimated future net revenues from proved reserves attributable to the
Royalty Interests plus (b) the amount of all remaining Section 29 tax credits
attributable to the Royalty Interests, is equal to or less than $5 million (as
applicable, the "Termination Date"). Upon such occurrence, the remaining assets
of the Trust will be sold, the net proceeds of the sale will be distributed to
the Unitholders and the Trust will be wound up and a certificate of
cancellation filed.
Upon the termination of the Trust, the Trustee will use its best efforts to
sell any remaining Royalty Interests then owned by the Trust for cash pursuant
to the procedures described in the Trust Agreement. The Trustee will retain a
nationally recognized investment banking firm (the "Advisor") on behalf of the
Trust who will assist the Trustee in selling the remaining Royalty Interests.
The Company has the right, but not the obligation, within 60 days following the
Termination Date, to make a cash offer to purchase all of the remaining Royalty
Interests then held by the Trust. In the event such an offer is made by the
Company, the Trustee will decide, based on the recommendation of the Advisor,
to either (i) accept such offer (in which case no sale to the Company will be
made unless a fairness opinion is given by the Advisor that the purchase price
is fair to the Unitholders) or (ii) defer action on the offer for approximately
60 days and seek to locate other buyers for the remaining Royalty Interests. If
the Trustee defers action on the Company's offer, the offer will be deemed
withdrawn and the Trustee will then use its best efforts, assisted by the
Advisor, to locate other buyers for the Royalty Interests. At the end of the
120-day period following the Termination Date, the Trustee is
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required to notify the Company of the highest of any other offers acceptable to
the Trustee (which must be an all cash offer) received during such period (the
"Highest Acceptable Offer"). The Company then has the right (whether or not it
made an initial offer), but not the obligation, to purchase all remaining
Royalty Interests for a cash purchase price computed as follows: (i) if the
Highest Acceptable Offer is more than 105 percent of the Company's original
offer (or if the Company did not make an initial offer), the purchase price
will be 105 percent of the Highest Acceptable Offer, or (ii) if the Highest
Acceptable Offer is equal to or less than 105 percent of the Company's original
offer, the purchase price will be equal to the Highest Acceptable Offer. If no
other acceptable offers are received for all remaining Royalty Interests, the
Trustee may request the Company to submit another offer for consideration by
the Trustee and may accept or reject such offer.
If a sale of the Royalty Interests is made or a definitive contract for sale
of the Royalty Interests is entered into within a 150-day period following the
Termination Date, the buyer of the Royalty Interests, and not the Trust or
Unitholders, will be entitled to all proceeds of production attributable to the
Royalty Interests following the Termination Date.
In the event that the Company does not purchase the Royalty Interests, the
Trustee may accept any offer for all or any part of the Royalty Interests as it
deems to be in the best interests of the Trust and Unitholders and may
continue, for up to one calendar year after the Termination Date, to attempt to
locate a buyer or buyers of the remaining Royalty Interests in order to sell
such interests in an orderly fashion. If the Royalty Interests have not been
sold or a definitive agreement for sale has not been entered into by the end of
such 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 shall 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
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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 (a) at
the time of the transaction subject to such complaint or (b) the Unitholder's
status as a beneficial owner must have devolved upon it by operation of law or
pursuant to the terms of the governing instrument of the Trust from a person or
entity who was a beneficial owner at the time of the transaction giving rise to
the complaint. If a derivative action is successful, in whole or in part, or if
anything is received by the Trust as a result of a judgment, compromise or
settlement of any such action, the Delaware Chancery Court may award the
plaintiff reasonable expenses, including reasonable attorney's fees. If any
award is so received by the plaintiff, the Delaware Chancery Court will make
such award of the plaintiff's expenses payable out of those proceeds and direct
the plaintiff to remit to the Trust the remainder thereof. If the proceeds are
insufficient to reimburse the plaintiff's reasonable expenses in bringing the
derivative action, the Delaware Chancery Court may direct that any such award
of the plaintiff's expenses or a portion thereof be paid by the Trust. The
rights of the Unitholders to bring a derivative action on behalf of the Trust
provided pursuant to the Trust Agreement and Section 3816 of the Delaware Code
are substantially similar to the derivative rights afforded stockholders under
Section 327 of Chapter 8 of the Delaware General Corporation Law and applicable
Delaware case law.
In the event that any Unitholder was successful in bringing a derivative
action on behalf of the Trust to enforce rights on behalf of the Trust against
Dominion Resources or the Company, then such Unitholder could, on behalf of the
Trust, pursue such rights against Dominion Resources or the Company, as the
case may be, in the Delaware Chancery Court. The Trust Agreement does not
require, and expressly provides that it shall not be construed to require,
arbitration of a claim or dispute solely between the Trustee and the Delaware
Trustee or of any claim or dispute brought by any person or entity, including,
without limitation, any Unitholder (whether in its own right or through a
derivative action in the right of the Trust), who is not a party to the Trust
Agreement.
The right of a Unitholder to bring a derivative action on behalf of the Trust
with respect to Dominion Resources' obligation to cure certain deficiencies
under the Trust Agreement is subject to the restriction that such right may
only be exercised by Unitholders owning of record not less than 25 percent of
the Units then outstanding (treated as a single class) and then only absent
action by the Trustee to enforce any such obligation within 10 days following
receipt by the Trustee of a written request served upon the Trustee by such
Unitholders to take such action. In such an event, Unitholders owning of record
not less than 25 percent of the Units then outstanding may, acting as a single
class and on behalf of the Trust, seek to enforce such obligations. See
"Properties--The Royalty Interests--Dominion Resources' Assurances."
DESCRIPTION OF UNITS
Each Unit represents an equal undivided share of beneficial interest in the
Trust and is evidenced by a transferable certificate issued by the Trustee.
Each Unit entitles its holder to the same rights as the holder of any other
Unit, and the Trust has no other authorized or outstanding class of equity
security. At March 24, 1995, there were 7,850,000 Units outstanding. The Trust
may not issue additional Units.
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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 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 is authorized to establish and maintain a
cash reserve, and 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 establish (or increase) that reserve or to repay that loan must be
reported by the Unitholder, even though that cash is not distributed to him.
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
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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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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 and 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. Estimated 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 has 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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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 amendment of required voting percentages
requires approval of at least 80 percent of the outstanding Units), but no
provision of the Trust Agreement may be amended that would (i) increase the
power of the Trustee or the Delaware Trustee to engage in business or
investment activities or (ii) alter the rights of the Unitholders as among
themselves. Without the written consent of Dominion Resources and the approval
of not less than 66 2/3 percent of the outstanding Units, no provision of the
Trust Agreement may be amended with respect to (a) the sale or disposition of
all or any part of the Trust estate, including the Royalty Interests, except as
specifically provided in the Trust Agreement, (b) termination of the Trust and
the disposition of Trust assets upon liquidation of the Trust or (c) the
Company's right of first refusal with respect to the purchase of any remaining
Royalty Interests upon termination of the Trust. Without the written consent of
Dominion Resources and the approval of a majority of the outstanding Units, no
amendment may be made to the Trust Agreement that would alter Dominion
Resources' conditional right to repurchase all outstanding Units at any time at
which 15 percent or less of the outstanding Units is owned by persons or
entities other than Dominion Resources or its affiliates. Additionally, any
amendment that increases the obligations, duties or liabilities of or affects
the rights of the Trustee or the Delaware Trustee must be consented to by such
entity. The Trustee, the Delaware Trustee, Dominion Resources and the Company
may, without approval of the Unitholders, from time to time supplement or amend
the Trust Agreement in order to cure any ambiguity or to correct or supplement
any defective or inconsistent provisions, provided 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
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approved by a majority vote of the Units represented at a meeting at which a
quorum is present or represented.
LIABILITY OF UNITHOLDERS
Consistent with Delaware law, the Trust Agreement provides that the
Unitholders will have the same limitation on liability as is accorded under
Delaware law to stockholders of a corporation for profit. No assurance can be
given, however, that the courts in jurisdictions outside of Delaware will give
effect to such limitation.
TRANSFER AGENT
Mellon Securities Trust Company serves as transfer agent and registrar for
the Units.
FEDERAL INCOME TAX CONSIDERATIONS
THE TAX CONSEQUENCES TO A UNITHOLDER OF THE OWNERSHIP AND SALE OF UNITS WILL
DEPEND IN PART ON THE UNITHOLDER'S TAX CIRCUMSTANCES. EACH UNITHOLDER SHOULD
THEREFORE CONSULT THE UNITHOLDER'S TAX ADVISOR ABOUT THE FEDERAL, STATE AND
LOCAL TAX CONSEQUENCES TO THE UNITHOLDER OF THE OWNERSHIP OF UNITS.
The sections entitled "Federal Income Tax Consequences," and "Risk Factors--
Tax Considerations" appearing in the Prospectus (the "Prospectus") dated June
21, 1994, which constitutes a part of the Registration Statement on Form S-3 of
Dominion Resources (Registration No. 33-53513) filed in connection with the
Public Offering, set forth, respectively, a discussion of the material federal
income tax matters of general application of the ownership and sale of the
Units acquired in the Public Offering 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 Offering, 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 the Public Offering. These
opinions were based on existing provisions of the Code as of June 28, 1994, the
date of the initial closing of the Public Offering, and existing and proposed
regulations thereunder and administrative rulings and court decisions as of
June 28, 1994, 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 Offering. In addition, such
opinions were expressly limited in their application to investors purchasing
Units in the Public Offering and, as a result, provide no assurance to
investors purchasing Units following the Public Offering.
Neither counsel to the Trustee, the Trustee nor the Delaware 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,
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.
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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 the Public Offering.
Each Unitholder should consult the Unitholder's tax advisor with respect to the
effects of the Unitholder's ownership of Units on the Unitholder's personal tax
situation.
Classification and Taxation
of the Trust................
The Trust is a grantor trust and not an
association taxable as a corporation. As a
grantor trust, the Trust is not subject to
federal income tax. There can be no assurance
that the IRS will not challenge this treatment.
The tax treatment of the Trust and Unitholders
would be materially different if the IRS were
to successfully challenge this treatment.
Economic Substance of
Ownership of Units..........
Generally, a taxpayer is entitled to claim
deductions and tax credits generated by an
investment only if the investment has economic
substance. The application of this principle in
the context of the production and sale of
nonconventional fuels (like coal seam gas)
which generate the Section 29 tax credit is
uncertain because such application has not been
addressed either by a court or the IRS. An
investment has economic substance if the
investor can demonstrate that there is a
reasonable possibility of deriving an economic
profit from the investment in excess of a de
minimis amount, apart from tax benefits. In
many cases, economic profit has been computed
by comparing the taxpayer's total cash
investment to the total cash reasonably
expected to be received by the taxpayer as a
result of the investment (a "Pre-Tax Profit
Objective"). At the time of the Public
Offering, Special Counsel to Dominion Resources
expressed the opinion (only in connection with
the Public Offering) that the ownership of
Units purchased in the Public Offering, 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 Offering 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
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from the Underlying Properties. The portion of
the initial distribution made by the Trust on
September 8, 1994, was attributable to natural
gas produced before June 28, 1994, the date the
Units were sold to the public, and, as such,
was not royalty income, but a return of
capital. During 1994, the Trust earned interest
income on funds held for distribution and
established a cash reserve. 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 both
quarterly record dates during 1994, the
available Section 29 tax credit is
approximately $.426795 per Unit, based on the
first estimate of the GNP implicit price
deflator published by the Bureau of Economic
Analysis.
The availability of Section 29 tax credits is
dependent upon meeting a number of
requirements, many of which are factual in
nature. The Company and Dominion Resources
represented in connection with the Public
Offering only that those factual requirements
were met. At the time of the Public Offering,
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 exceed his alternative
minimum tax liability (with certain
adjustments). Any amount of Section 29 tax
credit in excess of a Unitholder's total
regular federal income tax liability for a year
is permanently lost. Section 29 tax credits
cannot be used to reduce a Unitholder's
liability for any alternative minimum tax for
any taxable year but can be carried forward to
reduce his regular tax liability in a
subsequent year (subject to the applicable
rules governing such carryforward(s)).
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Quarterly Allocations........ Under the Code, a Unitholder is entitled to
Section 29 tax credits only to the extent that
he is an owner of the economic interest at the
time the coal seam gas is produced. The Trustee
allocates the income received by the Trust
during a quarter, and the Section 29 tax credit
allocable to such income, to Unitholders of
record on the quarterly record date for such
quarter. Such an allocation may be challenged
by the IRS, but any challenge is likely to have
a material adverse impact only if successful
and only for Unitholders who do not own Units
for a full quarter for each record date,
particularly Unitholders who acquire Units
shortly before a record date and sell shortly
after a record date. At the time of the Public
Offering, 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 Each Royalty Interest is a nonoperating
Interests.................... 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 Each Unitholder is entitled to amortize the
Allowance.................... cost of the Units through cost depletion over
the life of the Royalty Interests (or if
greater, through percentage depletion equal to
15 percent of gross income). If any portion of
the Royalty Interests is treated as a
production payment or is not treated as an
economic interest, however, a Unitholder will
not be entitled to depletion in respect of such
portion. No depletion allowances were available
to Unitholders in respect of production from
the Royalty Interests prior to June 28, 1994.
Non-Passive Activity Income,
Credits and Loss............
The income, credits and expenses of the Trust
are not taken into account in computing the
passive activity losses and income under
Section 469 of the Code for a Unitholder who
acquires and holds Units as an investment and
did not acquire them in the ordinary course of
a trade or business. Section 29 tax credits
generated by an investment in Units, therefore,
can be utilized to offset regular tax liability
on income from any source whether active or
passive, subject to other limitations discussed
herein or arising from the individual tax
circumstances of each Unitholder. See "Limits
on Unitholder's Use of Credits" above.
Tax Shelter Registration..... The Trust is registered as a "tax shelter" and
its tax shelter registration number is 94-
277000355. Issuance of a tax shelter
registration number does not indicate that the
investment in Units or the claimed tax benefits
have been reviewed, examined or approved by the
IRS.
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Substantial Understatement Section 6662 of the Code imposes a penalty in
Penalty...................... certain circumstances for a substantial
understatement of taxes if a taxpayer's tax
liability is understated by more than the
greater of (a) 10 percent of the taxes required
to be shown on the return and (b) $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 Offering should consult
with their personal tax advisors.
Unitholder Reporting The Trustee furnishes to Unitholders tax
Information.................. 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 1994
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 1994 to materially differ from the
Trustee's estimates contained in the 1994 Tax
Information booklet, the Trustee will promptly
mail final tax credit information to each
affected Unitholder.
17
<PAGE>
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 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 such 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 such nonresident Unitholders of any obligation to file Alabama
state income tax returns. The Trust intends to file a composite income tax
return with the DOR on behalf of all Nonresident Unitholders (defined below)
for 1994 and each year thereafter for so long as such 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 1994. Accordingly,
no Alabama state income tax is due under such 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 and determining the
composite taxable income or loss thereunder for Alabama state income tax
purposes. If all or a portion of any such assumptions are not acceptable to the
DOR, the DOR may require the Trust to recompute and refile the composite income
tax return based on certain different assumptions acceptable to the DOR. In the
event the composite income tax return for 1994 (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 (a) because the Trust
would have net Alabama taxable income for such year as a result of the
assumptions required by the DOR or (b) 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 such 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."
18
<PAGE>
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 Alabama Department of Revenue as to the offering of the
Units, special Alabama tax counsel to the Company opined in connection with the
Public Offering that the Trust is not subject to Alabama franchise tax.
Although the Alabama Commissioner of Revenue has the authority to revoke
retroactively Department of Revenue rulings under certain limited
circumstances, special Alabama tax counsel did not believe, based on the above
representations and assumptions, that such 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.
OTHER ALABAMA TAXES
The Trust has been structured to cause the Units to be treated as interests
in intangible personal property rather than as interests in real property for
certain Alabama state law purposes, other than income and franchise taxation.
If the Units are held to be real property or as interests in real property
under the laws of Alabama, Unitholders could be subject to Alabama probate
laws, and estate and similar taxes, whether or not they are residents of
Alabama.
REGULATION AND PRICES
REGULATION OF NATURAL GAS
Certain aspects of production, transportation and sale of natural gas from
the Underlying Properties may be subject to federal and state governmental
regulation, including regulation of transportation tariffs charged by
pipelines, taxes, the prevention of waste, the conservation of natural gas,
pollution controls and various other matters.
As a result of the Natural Gas Policy Act of 1978 ("NGPA") and the Natural
Gas Wellhead Decontrol Act of 1989 ("NGWDA"), as of January 1, 1993, the
wellhead price for natural gas is no longer subject to federal regulation. All
sales of natural gas produced from the Underlying Properties are considered
under NGPA and NGWDA to be sold at the wellhead (as opposed to downstream sales
or resales) for purposes of pricing and therefore are not subject to federal
regulation.
The transportation of natural gas in interstate commerce is subject to
federal regulation by the Federal Energy Regulatory Commission ("FERC") under
the Natural Gas Act ("NGA") and the NGPA. FERC has initiated a number of
regulatory policy initiatives that may affect the transportation of natural gas
from the wellhead to the market and thus may affect the marketing of natural
gas. Such initiatives include regulations which are 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
19
<PAGE>
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 such impacts 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 National Pollutant Discharge Elimination System
permits 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
expires in July 1999. The ADEM permit generally permits 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.
20
<PAGE>
While the Company 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 $1,000,000 during
1995 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 the
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 dependent on,
among other things, the sales prices for Gas produced from the Underlying
Properties and the quantities of Gas sold. Natural gas prices have historically
been volatile and are likely to continue to be volatile. Price volatility and
the risk of production curtailment make it difficult to estimate the future
levels of cash distributions to Unitholders or the value of the Units. While
the Minimum Price will mitigate to some extent the negative effects of such
volatility, the Maximum Price may limit the benefits Unitholders realize from
future price increases. See "Properties--The Royalty Interests--Gas Purchase
Agreement."
ITEM 2. PROPERTIES.
THE ROYALTY INTERESTS
The Royalty Interests held by the Trust generally entitle the Trust to
receive 65 percent of Gross Proceeds. The Royalty Interests were conveyed to
the Trust by means of a single instrument of conveyance. The Conveyance was
recorded in the appropriate real property records in Alabama, so as to give
notice of the Royalty Interests to creditors, and any transferees will take an
interest in the Underlying Properties subject to the Royalty Interests. The
Conveyance was intended to convey the Royalty Interests as real property
interests under Alabama law.
21
<PAGE>
The following description 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 which have production characteristics materially different from
conventional natural gas wells. The primary factor affecting recovery of gas
reserves from coal seams in the Black Warrior Basin is the lowering of
reservoir pressure through "dewatering" operations. In a typical coal seam gas
well on the Underlying Properties, average daily natural gas production
generally will increase as wells are "dewatered" until natural gas production
reaches a "peak" at which time natural gas production will decline. The amount
of time necessary to "dewater" a well and cause it to reach its peak
production, and the ultimate level of a well's peak production, are difficult
to estimate. Since all of the 532 wells included in the Underlying Properties
were producing by mid-1991, the Company believes that production from such
wells is currently at or near its peak and, subject to additional production
that may result from the Pratt coal seam recompletions discussed below, will
decline over the term of the Trust. See "--Pratt Recompletion Payments."
The Royalty Interests were conveyed by the Company to the Trust out of the
Company Interests. The wells producing in the Underlying Properties as of June
1, 1994 ("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, 1994, 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,
1994, 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 Royalty Interests are entitled to approximately 52 percent
of the net revenue from natural gas produced and sold from the Underlying
Properties and the interests (the "Retained Interests") of the Company in the
Underlying Properties (after giving effect to the Royalty Interests) entitle
the Company to receive approximately 28 percent of the net revenue from the
natural gas produced and sold from the Underlying Properties. As a working
interest owner in the Underlying Properties, the Company is responsible for an
average of approximately 98 percent of the operating costs of the Existing
Wells.
22
<PAGE>
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. The ADEM permit generally permits
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."
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 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 owns an interest as of June 1, 1994 for the
term of the Trust. Although the Company believes that it is unlikely that any
additional wells will be drilled, if the Operating Agreement is terminated, the
Company cannot prevent one of the other owners of an interest in the Underlying
Properties from drilling additional wells on the Underlying Properties.
Additional wells, if drilled, could recover a portion of the reserves otherwise
producible from wells burdened by the Company Interests, thereby reducing the
Gross Proceeds attributable to the Royalty Interests.
23
<PAGE>
THE ROYALTY INTERESTS
Conveyance. The Conveyance provides, among other things, that:
(a) 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.
(b) 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.
(c) 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.
(d) The Company Interests Owner is obligated to recomplete certain of the
Existing Wells to the Pratt coal seam to recover behind pipe reserves by
March 31, 1997, the failure or delay of which will entitle the owner of the
Royalty Interests to receive certain penalty payments for each well not so
recompleted. See "--Pratt Recompletion Payments."
(e) The owner of the Royalty Interests has no right to take production
in-kind.
(f) The Company Interests Owner has certain pooling and unitization
rights.
(g) 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.
(h) 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."
(i) The Company Interests Owner is required to maintain books and records
sufficient to determine the amounts payable with respect to the Royalty
Interests.
The Conveyance has been filed as an exhibit to this Form 10-K. The foregoing
summary of the Conveyance is qualified in its entirety by reference to the
terms thereof as set forth in such exhibit.
Computation and Payment. The Royalty Interests entitle the Trust to receive
65 percent of the Gross Proceeds. The Royalty Interests bear their
proportionate share of property, production and related taxes (including
severance taxes). The definitions, formulas and accounting procedures and other
terms governing the computation of the Royalty Interests are set forth in the
Conveyance.
The Company Interests Owner is required, pursuant to the Conveyance, to pay
to the Trust amounts received by the Company Interests Owner from the sale of
Subject Gas attributable to the Royalty Interests. Under the Conveyance, the
amounts payable by the Company Interests Owner with respect to the Royalty
Interests are computed with respect to each calendar quarter ending prior to
termination of the Trust, and such amounts are paid to the Trust not later than
the last business day before the 45th day following the end of each calendar
quarter. The amounts paid to the Trust do not include interest on any amounts
payable with respect to the Royalty Interests which are held by the Company
Interests Owner prior to payment to the Trust. The Company Interests Owner is
entitled to retain all amounts attributable to the Retained Interests. The
Company Interests Owner deducts from the payment to the Trust the Royalty
Interests' share of property, production and related taxes (including severance
taxes) and pays the same on behalf of the Trust.
24
<PAGE>
RESERVE ESTIMATE
Reserve Estimate. The following table summarizes net proved reserves
estimated as of January 1, 1995, 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, 1995
----------------- ---------------
<S> <C>
Net Proved Natural Gas Reserves (Bcf)(a)(b):
Developed Producing..................................... 55.1
Developed Nonproducing Behind Pipe(c)................... 8.0
--------
Total................................................. 63.1
========
Estimated Future Net Revenues
(in thousands)(a)(d):
1995.................................................... $ 21,002
1996.................................................... 18,989
1997.................................................... 16,939
1998.................................................... 13,978
1999.................................................... 10,299
Thereafter.............................................. 24,653
--------
Total................................................. $105,860
========
Discounted Estimated Future Net Revenues
(in thousands)(a)(d)(e):
1995.................................................... $ 20,025
1996.................................................... 16,377
1997.................................................... 13,238
1998.................................................... 9,896
1999.................................................... 6,602
Thereafter.............................................. 12,169
--------
Total................................................. $ 78,307
========
</TABLE>
--------
(a) The estimates of reserves and future net revenues summarized in this table
are based upon an unescalated price of $1.85 per MMBtu through 1998, which
was the price being received by the Company under the Gas Purchase
Agreement as of December 31, 1994, and an unescalated price of $1.70 per
MMBtu thereafter, which was the Index Price at December 31, 1994. See "--
Gas Purchase Agreement." These prices may not be the most representative
prices for estimating reserves or related future net revenues data.
(b) The estimated economic life of the wells comprising the Royalty Interests
has been determined taking into account the Section 29 tax credits.
(c) Based upon information provided by the Company, Ryder Scott assumed for
purposes of the Reserve Estimate that all wells in which developed
nonproducing reserves exist were recompleted to the Pratt coal seam by
December 31, 1996. See "--Pratt Recompletion Payments."
(d) 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.
(e) Discounted estimated future net revenues have been calculated using a 10
percent discount rate.
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 values of natural gas are likely to differ from the
estimated amounts set forth herein, and such differences could be significant.
25
<PAGE>
There are many uncertainties inherent in estimating quantities and values of
proved reserves and in projecting future rates of production. Reserve
engineering is a subjective process of estimating underground accumulations of
natural gas that cannot be measured in an exact manner. The accuracy of any
reserve estimate is a function of the quality of available data and of the
geological and engineering evaluation of that data. Results of testing and
production subsequent to the date of an estimate may justify revision of such
estimate. Further, reserve estimates for any given property may vary from
engineer to engineer even though each engineer bases his estimate on common
data and utilizes techniques and principles customary in the industry.
For properties with short production histories, reserve estimates in many
instances are based upon volumetric calculations and upon analogy to similar
types of production or producing fields. Relative to many conventional natural
gas producing properties, coal seam gas producing properties in general, and
the Underlying Properties in particular, have short production histories. In
addition, there are no significant coal seam reservoirs which have been
produced to depletion that can be used as analogies to the Underlying
Properties.
The discounted estimated future net revenues shown herein were prepared using
guidelines established by the Commission and may not be representative of the
market value for the estimated reserves.
The reserves attributable to the Royalty Interests are expected to decline
substantially during the term of the Trust and a portion of each cash
distribution made by the Trust will, therefore, be analogous to a return of
capital. As a result, cash distributions will decrease materially over time.
For example, based upon the production estimates set forth in the Reserve
Estimate, annual production attributable to the Royalty Interests is estimated
to decline from 12.1 Bcf in 1995 to 5.0 Bcf in 2000.
Tax Credits Based on Reserves. Based upon the production estimates used in
the Reserve Estimate for the January 1, 1995 through December 31, 2002 period,
and assuming constant future Section 29 tax credits at the estimated 1994 rate
of $.9958 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 $59.0 million, having a discounted present value (assuming a
10 percent discount rate) of approximately $44.6 million.
Miscellaneous. Ryder Scott has delivered to the Trust a reserve report as of
January 1, 1995, a summary of which is included as an exhibit to this Form 10-
K. Information concerning historical changes in net proved developed reserves
attributable to the Royalty Interests, and the calculation of the standardized
measure of discounted future net revenues related thereto, is contained in Note
8 of the Notes to the Financial Statements incorporated by reference in Item 8
hereof. Dominion Resources has not filed reserve estimates covering the Royalty
Interests with any other federal authority or agency.
NATURAL GAS SALES PRICES AND PRODUCTION
The following table sets forth the actual net production volumes attributable
to the Royalty Interests, weighted average property, production and related
taxes and information regarding natural gas sales prices for the period from
June 1, 1994 (effective date of the Conveyance) through December 31, 1994:
<TABLE>
<CAPTION>
JUNE 1, 1994
(EFFECTIVE DATE OF THE CONVEYANCE)
THROUGH DECEMBER 31, 1994
----------------------------------
<S> <C>
Production attributable to the Royalty
Interests (Bcf)......................... 7.6
Weighted average property, production and
related taxes (per Mcf)................. $ .10
Average Contract Price (per Mcf)......... $1.83
</TABLE>
26
<PAGE>
GAS PURCHASE AGREEMENT
Sonat Marketing Company, a Delaware corporation ("Sonat Marketing"), is
required to purchase the Subject Gas pursuant to the Gas Purchase Agreement
which extends as long as reserves on the Underlying Properties produce natural
gas. Pursuant to the Gas Purchase Agreement, Sonat Marketing will be obligated
to purchase monthly up to the Monthly Base Quantity designated in the Gas
Purchase Agreement of the Subject Gas at the Central Gathering Point at the
Contract Price which provides for a Premium over the Index Price subject to a
Minimum Price of $1.85 per MMBtu and a Maximum Price of $2.63 per MMBtu until
December 31, 1998. While the Minimum Price assures the Unitholder a minimum
price at which the Monthly Base Quantities of the Subject Gas must be
purchased, until January 1, 1999 Unitholders will not benefit from natural gas
prices in excess of $2.63 per MMBtu. In the case of Subject Gas in excess of
the Monthly Base Quantity, Sonat Marketing is obligated to purchase the Subject
Gas at the Index Price. After December 31, 1998, Sonat Marketing is obligated
to purchase the Subject Gas at the Index Price until such time as the Company
and Sonat Marketing negotiate a different price. After December 31, 1998, the
Company will have the ability to obtain an offer to purchase the Subject Gas
from another purchaser and terminate the Gas Purchase Agreement if Sonat
Marketing does not match such offer.
Sonat Marketing's obligation to purchase natural gas pursuant to the Gas
Purchase Agreement (as well as the Company's obligation to sell such natural
gas) may be suspended to the extent affected by the occurrence of any event not
within the control of the affected party that renders the affected party unable
to perform its obligations under the Gas Purchase Agreement if the event could
not have been prevented by the exercise of reasonable diligence including: acts
of God, strikes, lockouts or other industrial disturbances, acts of the public
enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning,
earthquakes, fires, storms, floods, washouts, arrests and restraints of
governments and people, civil disturbances, explosions, breakage or accident to
machinery or lines of pipe, the necessity for maintenance of or making repairs
or alterations to machinery or lines of pipe, freezing of wells or lines of
pipe, partial or entire failure of wells, curtailment, interruption or other
unavailability of transportation, inability to acquire or delay in acquiring at
reasonable cost and by the exercise of reasonable diligence, servitudes, rights
of way, grants, permits, permissions, licenses, materials or supplies that are
required to enable the affected party to perform its obligations. Following any
such event, the affected party's obligations under the Gas Purchase Agreement
will be suspended during the period of its inability to perform, and such party
will as far as possible remedy the event with reasonable dispatch. During the
pendency of any such suspension, the cash available for distribution, and the
depletion deductions and Section 29 tax credits available for allocation, by
the Trust to Unitholders could be reduced materially or eliminated entirely.
Sonat Marketing has entered into a put and call agreement with a nationally
recognized commodities brokerage firm intended to limit its losses in the event
that the Index Price falls below the Minimum Price. 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. The
foregoing summary of the Gas Purchase 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.
27
<PAGE>
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."
River Gas operates the Underlying Properties pursuant to the Operating
Agreement. Beginning December 31, 1995, either River Gas or the Company may
terminate the Operating Agreement upon six months' prior written notice to the
other party. The Trust will not be able to appoint or control the appointment
of replacement operators.
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 term of the Operating Agreement will continue until
December 31, 1995. Thereafter, the Operating Agreement 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: (1) 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; (2) the other party files a petition for relief under
federal or state bankruptcy laws, the other party's insolvency is determined by
a final court proceeding, the other party's filing of a petition or application
to accomplish such a result or for the appointment of a receiver or trustee for
such party or for a substantial part of its assets, or commencement of any
proceedings relating to the other party under any other reorganization,
arrangement, insolvency, adjustment of debt or liquidation law of any
jurisdiction; provided, however, that if such proceeding is not commenced, the
proceeding will not give rise to a right to terminate the Operating Agreement
unless such party consents or such proceeding has not been finally dismissed
within 90 days after its commencement; or (3) 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 Gathering Point through
the gathering system of 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 (a) are engaged in or accepted by a significant portion of the natural gas
production industry at the time the decision was made or (b) 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.
The Operating Agreement has been filed as an exhibit to this Form 10-K. The
foregoing summary of the Operating Agreement is qualified in its entirety by
reference to the terms of such agreement as set forth in such exhibit.
PRATT RECOMPLETION PAYMENTS
Based on the Reserve Estimate, as of January 1, 1995, approximately 8.0 Bcf
of natural gas reserves attributable to the Royalty Interests represent net
proved developed nonproducing (or
28
<PAGE>
"behind-pipe") reserves for 248 of the Existing Wells scheduled to be
recompleted to the Pratt coal seam. Under the Conveyance, the Company is
committed to recomplete 374 Existing Wells to the Pratt coal seam so that 522
out of a total of 532 Existing Wells will be completed or recompleted to the
Pratt coal seam on or before March 31, 1997. As of December 31, 1994,
approximately 274 of the Existing Wells had been completed or recompleted to
the Pratt coal seam. The schedule provides for not less than 115, 234, 355 and
374 wells to be recompleted through 1994, 1995, 1996 and March 31, 1997,
respectively. The Company will pay the Trust $1,850 per well per quarter
through March 31, 1997 for each well not recompleted in accordance with such
schedule. In addition, if the Company fails to recomplete any of the 374
Existing Wells scheduled to be recompleted under the Conveyance by March 31,
1997, the Company will pay the Trust an amount equal to the value attributed in
the Conveyance to the Royalty Interests' share of the "behind-pipe" reserves
for each well not so recompleted.
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.
The Company may sell its interest in the Underlying Properties, subject to
and burdened by the Royalty Interests, without the consent of the Trust or the
Unitholders. Under the Trust Agreement, the Company has certain rights (but not
the obligation) to purchase the Royalty Interests upon termination of the
Trust. See "Business--Description of the Trust Agreement--Termination and
Liquidation of the Trust."
DOMINION RESOURCES' ASSURANCES
Pursuant to the Trust Agreement, Dominion Resources has agreed to cause each
of the following obligations to be paid in full when due: (i) all liabilities
and operating and capital expenses that any Company Interests Owner becomes
obligated to pay as a result of such Company Interests Owner's obligations
under the Conveyance and (ii) the obligations of the Company to indemnify the
Trust, the Trustee and the Delaware Trustee for certain environmental
liabilities under the Trust Agreement (collectively, the "Payment
Obligations").
The Trustee may, at any time after the 10th day following receipt by Dominion
Resources of written notice from the Trustee that a Payment Obligation has not
been paid when due, make demand of Dominion Resources for payment stating the
amount due. Dominion Resources is obligated to cure any failure to pay the
obligation within 10 days following receipt of the foregoing demand. After
written request of the Unitholders owning of record not less than 25 percent of
the Units then outstanding served upon the Trustee, and absent action by the
Trustee within 10 days following receipt by the Trustee of such written request
to enforce such obligations for the benefit of the Trust, such Unitholders may,
acting as a single class and on behalf of the Trust, seek to enforce Dominion
Resources' performance obligations.
All of Dominion Resources' obligations will terminate upon: (i) the
termination and cancellation of the Trust, (ii) the sale or other transfer by
the Company of all or substantially all of the Company's interest in the
Underlying Properties subject to the terms of the Trust Agreement and (iii) the
sale or other transfer of a majority of Dominion Resources' direct or indirect
equity ownership interest in the Company, provided that, with respect to
clauses (ii) and (iii) above, Dominion Resources' obligations
29
<PAGE>
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.
Certain information with respect to the Units of the Trust and the market
therefor is set forth on the inside front cover of the Trust's Annual Report to
Unitholders for the year ended December 31, 1994 under the section entitled
"Units of Beneficial Interest" and is incorporated herein by reference.
ITEM 6. SELECTED FINANCIAL DATA.
Selected financial data of the Trust is set forth on the inside front cover
of the Trust's Annual Report to Unitholders for the year ended December 31,
1994 under the section entitled "Selected Financial Data" and is incorporated
herein by reference.
ITEM 7. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.
The "Trustee's Discussion and Analysis of Financial Condition and Results of
Operations" appearing on pages two and three of the Trust's Annual Report to
Unitholders for the year ended December 31, 1994 are incorporated herein by
reference.
30
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The financial statements of the Trust and notes thereto, together with the
report thereon of Deloitte & Touche LLP, independent auditors, dated March 10,
1995, appearing on pages four through 11 of the Trust's Annual Report to
Unitholders for the year ended December 31, 1994, are incorporated herein by
reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The Trust has no directors or executive officers. Each of the Trustee and the
Delaware Trustee is a corporate trustee that may be removed as trustee under
the Trust Agreement, with or without cause, at a meeting duly called and held
by the affirmative vote of Unitholders of not less than a majority of all the
Units then outstanding. Any such removal of the Delaware Trustee shall be
effective only at such time as a successor Delaware Trustee fulfilling the
requirements of Section 3807(a) of the Delaware Code has been appointed and has
accepted such appointment, and any such removal of the Trustee shall be
effective only at such time as a successor Trustee has been appointed and has
accepted such appointment.
Dominion Resources, which holds more than ten percent of the outstanding
Units, inadvertently failed to timely file during 1994 two reports required to
be filed with the Commission under Section 16(a) of the Securities Exchange Act
of 1934 with respect to its ownership of its Units. As of March 24, 1995,
however, Dominion Resources had filed subsequent reports on a timely basis
necessary to report such ownership.
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. Dominion Resources has paid to the Trustee an
acceptance fee of $15,000 which has been reimbursed to Dominion Resources by
the Trust. 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 $35,000, 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 beginning January 1, 1995. The Delaware
Trustee is compensated for its administrative services, in an annual
31
<PAGE>
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.
Compensation of the Transfer Agent. The Transfer Agent will receive a
transfer agency fee of $3.25 annually per account, plus $1.50 for each
certificate issued and $.40 for each check issued (minimum of $7,200 annually).
Fees to Dominion Resources. Dominion Resources will receive throughout the
term of the Trust an administrative services fee for accounting, bookkeeping
and other administrative services relating to the Royalty Interests and the
Underlying Properties as described below under "Administrative Services
Agreement."
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Security Ownership of Certain Beneficial Owners. The following table sets
forth as of March 24, 1995 information with respect to the only Unitholder who
was known to the Trustee to be a beneficial owner of more than five percent of
the outstanding Units.
<TABLE>
<CAPTION>
PERCENT
NAME AND ADDRESS NUMBER OF UNITS OF
OF BENEFICIAL OWNER BENEFICIALLY OWNED CLASS
------------------- ------------------ -------
<S> <C> <C>
Dominion Resources, Inc....................... 946,000 12.05%
901 East Byrd Street
Richmond, Virginia 23219
</TABLE>
Security Ownership of Management. The Trust has no directors or executive
officers. As of March 15, 1995, neither NationsBank of Texas, N.A., the
Trustee, nor Mellon Bank (DE) National Association, the Delaware Trustee,
beneficially owned any Units.
Changes in Control. The Trustee knows of no arrangements the operation of
which may at a subsequent date result in a change in control of the Registrant.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
ADMINISTRATIVE SERVICES AGREEMENT
Pursuant to the Trust Agreement, Dominion Resources and the Trust entered
into the Administrative Services Agreement, pursuant to which the Trust is
obligated, throughout the term of the Trust, to pay to Dominion Resources each
quarter an administrative services fee for accounting, bookkeeping and other
administrative services relating to the Royalty Interests and the Underlying
Properties. The annual fee, payable in equal quarterly installments, is
$300,000 ($175,000 for 1994) and will be increased annually by three percent
beginning January 1, 1995.
A copy of the Administrative Services Agreement is filed as an exhibit to
this Form 10-K. The foregoing summary of certain 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
32
<PAGE>
persons or entities other than Dominion Resources and its affiliates. Any such
repurchase would generally be at a price equal to the greater of (i) the
highest price at which Dominion Resources or any of its affiliates acquired
Units during the 90 days immediately preceding the Determination Date and (ii)
the average closing price of Units on the NYSE for the 30 trading days
immediately preceding the Determination Date. Any such repurchase would be
conducted in accordance with applicable Federal and state securities laws. See
"Business--Description of the Trust--Conditional Right of Repurchase."
POTENTIAL CONFLICTS OF INTEREST
The interests of Dominion Resources and its affiliates and the interests of
the Trust and the Unitholders with respect to the Underlying Properties could
at times be different. The following is a summary of certain conflicts of
interest:
Obligations of Company Interests Owner may exceed its share of distributions
and tax credits. As a working interest owner in the Underlying Properties, the
Company Interests Owner is responsible for an average of approximately 98
percent of the operating costs of the Existing Wells but only entitled to
approximately 28 percent of the revenues therefrom, after giving effect to the
Royalty Interests. Based on the Reserve Estimate, beginning in the year 2000,
the projected operating costs to be borne by the Company Interests Owner will
exceed its projected share of Gross Proceeds and Section 29 tax credits. The
terms of the Conveyance provide, however, that the Company Interests Owner will
make decisions with respect to the Company Interests pursuant to the standard
of a reasonably prudent operator.
Sale or abandonment of Underlying Properties may terminate assurances. The
Company Interests Owner's interests may conflict with those of the Trust and
Unitholders in situations involving the sale or abandonment of Underlying
Properties. The Company Interests Owner has the right at any time to sell any
of the Underlying Properties subject to the Royalty Interests and may abandon a
well or lease included in the Underlying Properties if such well or lease is
not capable of producing in commercial quantities determined before giving
effect to the Royalty Interests. Under certain circumstances, a sale or
abandonment will effectively terminate Dominion Resources' assurances of the
Company Interests Owner's obligation to the Trust with respect to the
Underlying Properties sold or abandoned. Such sales or abandonment may not be
in the best interest of the Trust or the Unitholders.
Dominion Resources may profit from contracts with the Trust. The amount that
Dominion Resources may charge for services it renders under the Administrative
Services Agreement is established in such contract at rates that do not
necessarily take into account the actual cost of rendering such services by
Dominion Resources. Accordingly, Dominion Resources may profit or suffer losses
in connection with the performance of such contract.
33
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this report:
1. Financial Statements (incorporated by reference in Item 8. of this
report)
Independent Auditors' Report
Statement of Assets, Liabilities and Trust Corpus as of December 31,
1994
Statement of Distributable Income for the period from May 31, 1994
(date of inception) to December 31, 1994
Statement of Changes in Trust Corpus for the period from May 31,
1994 (date of inception) to December 31, 1994
Notes to Financial Statements
2. Financial Statement Schedules
Financial statement schedules are omitted because of the absence of
conditions under which they are required or because the required
information is included in the financial statements and notes thereto.
3. Exhibits
<TABLE>
<CAPTION>
EXHIBIT
NUMBER EXHIBIT
------- -------
<C> <S> <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 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 Re-
sources, Inc., Mellon Bank (DE) National Association and
NationsBank of Texas, N.A. (filed as Exhibit 3.2 to the
Registrant's Form 10-Q for the quarter ended June 30,
1994 and incorporated herein by reference).
10.1 --Overriding Royalty Conveyance dated as of June 28, 1994,
from Dominion Black Warrior Basin, Inc. to Dominion Re-
sources 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 Domin-
ion 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 Con-
veyance dated as of November 20, 1994, among Dominion
Black Warrior Basin, Inc., NationsBank of Texas, N.A.,
and Mellon Bank (DE) National Association.
13.1 --The following information appearing on the following
pages of the Registrant's 1994 Annual Report to
Unitholders: (i) Trustee's discussion and analysis of fi-
nancial condition and results of operations, pages two
and three; (ii) selected financial data, inside front
cover; (iii) the section entitled "Units of Beneficial
Interest," inside front cover; and (iv) the financial
statements of the Trust, pages four through 11.
23.1 --Consent of Ryder Scott Company Petroleum Engineers, in-
dependent petroleum engineers.
27.1 --Financial Data Schedule.
</TABLE>
34
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NUMBER EXHIBIT
------- -------
<C> <S> <C>
99.1 --Summary of Reserve Report, dated March 3, 1995, on the
estimated reserves, estimated future net revenues and the
discounted estimated future net revenues attributable to
the Royalty Interests as of January 1, 1995, prepared by
Ryder Scott Company Petroleum Engineers, independent pe-
troleum 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.
35
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
DOMINION RESOURCES BLACK WARRIOR
TRUST
By: NationsBank of Texas, N.A.,
Trustee
/s/ Ron E. Hooper
By: _________________________________
Ron E. Hooper
Vice President
Date: March 30, 1995
(The Registrant has no directors or executive officers.)
36
<PAGE>
EXHIBIT 10.3
This instrument prepared by: Source of Title: Deed Book 1138
Page 173
Hugh Tucker, Esquire
Baker & Botts, L.L.P.
1299 Pennsylvania Ave., N.W.
Washington, D.C. 20004-2400
AMENDMENT TO AND RATIFICATION OF
OVERRIDING ROYALTY CONVEYANCE
This AMENDMENT TO AND RATIFICATION OF OVERRIDING ROYALTY CONVEYANCE
("Amendment and Ratification") is entered into as of the 20th day of November,
1994, by and among DOMINION BLACK WARRIOR BASIN, INC., an Alabama corporation
("Assignor"), NATIONSBANK OF TEXAS, N.A., a national banking association
("Trustee"), and MELLON BANK (DE) NATIONAL ASSOCIATION, a national banking
association ("Delaware Trustee") (collectively, the "Parties").
RECITALS
--------
A. The Parties have executed that certain Overriding Royalty Conveyance
recorded in Deed Book 1181 at Page 644 (the "Original Conveyance"). Unless
otherwise defined herein, capitalized terms used herein shall have the meaning
given such terms in the Original Conveyance.
B. The Parties desire to correct Schedule A, Part 1 of the Original
Conveyance with respect to nine (9) of the Proration Units being conveyed
thereby (the "Applicable Units").
<PAGE>
NOW, THEREFORE, in consideration of the premises, and intending to be
legally bound hereby, the Parties hereby agree as follows:
1. Schedule A, Part 1 of the Original Conveyance sets forth the following
information with respect to the Applicable Units:
Total Total APO Royalty Royalty
NRI RI Company Interests Interests
Num Well Name & # % % Interest BPO APO
--- ---------------- ------- ------- -------- --------- ----------
58 Cassidy 22-7-111 80.0791 80.0791 75.0000% 52.0514% 48.7500%
72 Cassidy 28-8-131 80.0106 80.0106 75.0000% 52.0069% 48.7500%
81 Cassidy 30-12-15 83.7500 83.7500 75.0000% 54.4375% 48.7500%
86 Cassidy 30-4-120 83.7500 83.7500 75.0000% 54.4375% 48.7500%
87 Cassidy 30-8-121 83.7500 83.7500 75.0000% 54.4375% 48.7500%
280 Gilbert 15-12-2 83.7500 83.7500 75.0000% 54.4375% 48.7500%
281 Gilbert 15-5-1 83.7500 83.7500 75.0000% 54.4375% 48.7500%
396 USX 14-13-37 83.7500 83.7500 75.0000% 54.4375% 48.7500%
414 USX 23-4-41 80.7247 80.7247 77.1700% 52.4710% 50.1605%
2. The correct Schedule A, Part 1 information for the Applicable Units
with respect to the information set forth in Paragraph 1 above is as follows:
Total Total APO Royalty Royalty
NRI RI Company Interests Interests
Num Well Name & # % % Interest BPO APO
--- ---------------- ------- ------- -------- --------- ----------
58 Cassidy 22-7-111 80.0791 80.0791 75.2372% 52.0514% 48.9042%
72 Cassidy 28-8-131 80.0106 80.0106 75.0319% 52.0069% 48.7707%
81 Cassidy 30-12-15 83.7500 83.7500 81.2500% 54.4375% 52.8125%
86 Cassidy 30-4-120 83.7500 83.7500 81.2500% 54.4375% 52.8125%
87 Cassidy 30-8-121 83.7500 83.7500 81.2500% 54.4375% 52.8125%
280 Gilbert 15-12-2 83.7500 83.7500 81.2500% 54.4375% 52.8125%
281 Gilbert 15-5-1 83.7500 83.7500 81.2500% 54.4375% 52.8125%
396 USX 14-13-37 83.7500 83.7500 81.2500% 54.4375% 52.8125%
414 USX 23-4-41 80.0469 80.0469 75.1406% 52.0305% 48.8414%
<PAGE>
3. The Parties do hereby amend the Original Conveyance by substituting the
information shown in Paragraph 2 above for that shown in Paragraph 1 above and
do hereby, ratify, adopt and confirm the Original Conveyance as herein amended.
4. The purpose of this Amendment and Ratification is to correct Schedule
A, Part 1 of the Original Conveyance so as to properly reflect the interests in
the Applicable Units being conveyed thereby. The correct interests are set forth
in Paragraph 2 above.
<PAGE>
IN WITNESS WHEREOF, each of the Parties hereto has caused this Amendment and
Ratification to be executed in its name and behalf by its proper signatory
officer thereunto duly authorized, in multiple originals, as of the day and year
first above written.
ASSIGNOR:
---------
DOMINION BLACK WARRIOR BASIN, INC.
By: G. E. Lake, Jr.
----------------------------------------
G. E. Lake, Jr.
Vice President
ASSIGNEE:
---------
NATIONSBANK OF TEXAS, N.A. as Trustee for
the Dominion Resources Black Warrior Trust
By: Ron E. Hooper
----------------------------------------
Ron E. Hooper
Vice President
MELLON BANK (DE) NATIONAL ASSOCIATION,
as Delaware Trustee for the Dominion Resources
Black Warrior Trust
By: Sandy S. McKenna
----------------------------------------
Sandy S. McKenna
Assistant Vice President
<PAGE>
COMMONWEALTH OF VIRGINIA
CITY OF RICHMOND
I, the undersigned authority, a Notary Public in an for said City and said
State, hereby certify that G.E. Lake, Jr., whose name as Vice President of
DOMINION BLACK WARRIOR BASIN, INC., an Alabama corporation, is signed to the
foregoing instrument, and who is known to me, acknowledged before me on this day
that, being informed of the contents of the instrument, he, as such officer and
with full authority, executed the same voluntarily for and as the act of said
corporation.
Given under my hand this 21st day of November, 1994.
Michelle C. Smithson
--------------------
Notary Public
My Commission Expires:
My Commission Expires January 31, 1998
--------------------------------------
(Notarial Seal)
<PAGE>
STATE OF _____________________
COUNTY OF ____________________
I, the undersigned authority, a Notary Public in and for said County and
said State, hereby certify that Ron E. Hooper, whose name as Vice President of
NationsBank of Texas, N.A., a national banking association, as Trustee for the
DOMINION RESOURCES BLACK WARRIOR TRUST, a Delaware business trust, is signed
to the foregoing instrument, and who is known to me, acknowledged before me on
this day that, being informed of the contents of the instrument, he, as such
officer and with full authority, executed the same voluntarily for and as the
act of said association, acting in its capacity as Trustee as aforesaid.
Given under my hand this 31st day of January, 1994.
(Sig. of Jana L. Egeler)
------------------------------------
Notary Public
My Commission Expires:
10/22/98
----------------------
(Notarial Seal)
(NOTARY SEAL)
<PAGE>
STATE OF PENNSYLVANIA
COUNTY OF PHILADELPHIA
I, the undersigned authority, a Notary Public in and for said County and
said State, hereby certify that Sandy S. McKenna, whose name as Assistant Vice
President of Mellon Bank (DE) National Association, a national banking
association, as Delaware Trustee for the DOMINION RESOURCES BLACK WARRIOR TRUST,
a Delaware business trust, is signed to the foregoing instrument, and who is
known to me, acknowledged before me on this day that, being informed of the
contents of the instrument, he, as such officer and with full authority,
executed the same voluntarily for and as the act of said association, acting in
its capacity as Delaware Trustee as aforesaid.
Given under my hand this 7th day of February, 1995.
(Sig. of Irene Materna)
------------------------------------
Notary Public
My Commission Expires:
----------------------
(Notarial Seal)
(NOTARY SEAL)
<PAGE>
EXHIBIT 13.1
UNITS OF BENEFICIAL INTEREST
The units of beneficial interest ("Units") in the Trust are listed and traded on
the New York Stock Exchange under the symbol "DOM." Prior to the sale of the
Units on June 28, 1994 there was no public market for the Units. 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 made by the Trust.
<TABLE>
<CAPTION>
Price
----------------------- Distribution
1994 High Low Per Unit
--------------------------------------------------------------------------------
<S> <C> <C> <C>
Second Quarter
(commencing June 28, 1994)....... $20 $19 3/4 $.000000
Third Quarter...................... 20 1/8 19 3/8 0.180147
Fourth Quarter..................... 19 5/8 16 7/8 0.726389
</TABLE>
At March 15, 1995, there were 7,850,000 Units outstanding and 784
Unitholders of record.
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
For The Period From
May 31, 1994
(Date of Inception) To
December 31, 1994
--------------------------------------------------------------------------------
<S> <C>
Royalty Income........................................... $ 7,596,511
Distributable Income..................................... $ 7,278,931
Distributable Income per Unit............................ $ .927252
Distributions per Unit................................... $ .906537
Total Assets, December 31................................ $139,641,366
Trust Corpus, December 31................................ $139,471,673
</TABLE>
1
<PAGE>
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.
Distributable income of the Trust consists of the excess of royalty income
plus interest income over the organizational and administrative expenses
of the Trust. Upon receipt by the Trust, royalty income is invested in
short-term investments in accordance with the Trust Agreement until its
subsequent distribution to Unitholders.
The amount of distributable income of the Trust for any calendar year may
differ from the amount of cash available for distribution to the Unitholders in
such year due to differences in the treatment of the expenses of the Trust and
the determination of those amounts. The financial statements of the Trust are
prepared on a modified cash basis pursuant to which the expenses of the Trust
are recognized when they are paid or reserves are established for them.
Consequently, the reported distributable income of the Trust for any year is
determined by deducting 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, however, is determined after adjustment for changes
in reserves for unpaid liabilities in accordance with the provisions of the
Trust Agreement. (See Note 5 to the financial statements of the Trust appearing
elsewhere in this Annual Report to Unitholders for additional information
regarding the determination of the amount of cash available for distribution to
Unitholders.)
The 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.
PERIOD FROM MAY 31, 1994 (DATE OF INCEPTION)
TO DECEMBER 31, 1994
The Trust received royalty income amounting to $7,596,511 during the period
from May 31, 1994 (date of inception) to December 31, 1994. The royalty
income received by the Trust was net of the Royalty Interest's allocable
share of property, production and related taxes. Administrative expenses
during the period amounted to $335,134. These expenses are primarily related
to administrative services provided by Dominion Resources, the Trustee and
Mellon Bank (DE) National Association, a national banking association, during
the period. These transactions resulted in distributable income for the
period from May 31, 1994 to December 31, 1994, of $7,278,931, or $.93 per
Unit. The Trust made two distributions during the period aggregating
$7,116,317, or $.91 per Unit.
Because the Trust incurs administrative expenses throughout a quarter
but receives its royalty income only once a quarter, the Trustee established
in the third quarter of 1994 a cash reserve in the amount of $135,000 for
the payment of expenses and liabilities of the Trust. The quarterly
distribution made in the 1994 third quarter was reduced by the amount of
this reserve in accordance with the provisions of the Trust Agreement. The
Trust anticipated that it will maintain for the foreseeable future a cash
reserve to enable it to pay administrative expenses as they become due.
The amount of the cash reserve from time to time will fluctuate as expenses
are paid and royalty income is received.
2
<PAGE>
Royalty income received by the Trust in a given calendar year will
generally reflect the proceeds from the sale of gas produced from the Underlying
Properties during the first three quarters of that year and the fourth quarter
of the preceding calendar year due to the timing of the receipt of these
revenues. The conveyance of the Royalty Interests to the Trust was effective
June 1, 1994. Accordingly, the royalty income included in distributable income
for the period ended December 31, 1994, was based on production volumes and
natural gas prices for the period from June 1, 1994 to September 30, 1994, in
accordance with the terms of the conveyance of the Royalty Interests to the
Trust.
Sonat Marketing Company ("Sonat Marketing") is required under a gas
purchase agreement to purchase the gas produced from the Underlying Properties
for as long as reserves on the Underlying Properties produce natural gas. Under
the agreement, Sonat Marketing is obligated to purchase up to a specified
monthly base quantity of gas for a contract price which provides for a specified
premium (between $.05 and $.07 per MMBtu) over the Index Price (as defined
below), subject to a minimum price of $1.85 per MMBtu and a maximum price of
$2.63 per MMBtu, until December 31, 1998. Sonat Marketing is obligated to
purchase gas production in excess of the specified monthly base quantities at
the Index Price. After December 31, 1998, Sonat Marketing is obligated to
purchase gas production at the Index Price until such time as the Company and
Sonat Marketing negotiate a different price, although the Company will have the
ability to obtain an offer from another purchaser and terminate the gas purchase
agreement if Sonat Marketing does not match such offer. The "Index Price", which
is determined on a monthly basis, is Southern Natural Gas Company's posted index
price for deliveries of gas in Louisiana.
The following table sets forth the production volumes attributable to
the Trust's Royalty Interests and the average sales price and Index Price
for such production for the period indicated.
<TABLE>
<CAPTION>
For The Period
from
June 1, 1994 to
September 30, 1994
----------------------------------------------------------------------------
<S> <C>
Production (Bcf)/(1)/................................. 4.382
Production (MMBtu)/(2)/............................... 4.332
Average Contract Price Received ($/MMBtu)............. $1.86
Average Index Price ($/MMBtu)......................... $1.69
</TABLE>
/(1)/ Billion cubic fee of natural gas.
/(2)/ Trillion British Thermal Units.
The information in this Annual Report to Unitholders concerning production
and prices relating to the Royalty Interests is based on information prepared
and furnished by the Company to the Trustee. The Trustee has no control
over and no responsibility relating to the operation of or accounting for
the Underlying Properties.
3
<PAGE>
FINANCIAL STATEMENTS
An audited Statement of Assets, Liabilities and Trust Corpus of the Trust
as of December 31, 1994, and the related Statements of Distributable Income
and Changes in Trust Corpus for the period from May 31, 1994 (date of
inception) to December 31, 1994, are included in this Annual Report to
Unitholders immediately following the Independent Auditors' Report below.
INDEPENDENT AUDITORS' REPORT
NationsBank of Texas, N.A.,
as Trustee of Dominion Resources Black Warrior Trust
We have audited the accompanying statement of assets, liabilities and trust
corpus of Dominion Resources Black Warrior Trust (the "Trust") as of December
31, 1994, and the related statements of distributable income and changes
in trust corpus for the period from May 31, 1994 (date of inception) to
December 31, 1994. These financial statements are the responsibility of
the Trustee. Our responsibility is to express an opinion on these financial
statements based on our audit.
We conducted our audit 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 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 audit provides 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 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, 1994, and its distributable
income and changes in trust corpus for the period from May 31, 1994 (date
of inception) to December 31, 1994, on the basis of accounting described
in Note 2.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Dallas, Texas
March 10, 1995
4
<PAGE>
DOMINION RESOURCES BLACK WARRIOR TRUST
FINANCIAL STATEMENTS
STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
December 31, 1994
--------------------------------------------------------------------------------------------------------
<S> <C>
ASSETS
Cash and cash equivalents.............................................................. $ 1,651
Royalty interests in gas properties (less accumulated amortization of
$9,184,572 at December 31, 1994)..................................................... 139,639,715
---------------------------------------------------------------------------------------------------------
Total Assets....................................................................... $139,641,366
=========================================================================================================
LIABILITIES AND TRUST CORPUS
Trust administration expenses payable.................................................. $ 169,693
Trust corpus (7,850,000 units of beneficial interest authorized, issued
and outstanding)..................................................................... 139,471,673
---------------------------------------------------------------------------------------------------------
Total Liabilities and Trust Corpus................................................. $139,641,366
=========================================================================================================
</TABLE>
STATEMENT OF DISTRIBUTABLE INCOME
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
For the Period from
May 31, 1994
(Date of Inception) to
December 31, 1994
---------------------------------------------------------------------------------------------------------
<S> <C>
Royalty income..................................................................... $ 7,596,511
Interest income.................................................................... 17,554
---------------------------------------------------------------------------------------------------------
7,614,065
General and administrative expenses................................................ 335,134
---------------------------------------------------------------------------------------------------------
Distributable income............................................................... $ 7,278,931
=========================================================================================================
Distributable income per unit (7,850,000 units).................................... $ .927252
=========================================================================================================
Distributions per unit............................................................. $ .906537
=========================================================================================================
</TABLE>
STATEMENT OF CHANGES IN TRUST CORPUS
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
For the Period from
May 31, 1994
(Date of Inception) to
December 31, 1994
---------------------------------------------------------------------------------------------------------
<S> <C>
Trust corpus, beginning of period.................................................. $ 1,000
Conveyance of royalty interests by Dominion Black Warrior Basin, Inc............... 148,824,287
Amortization of royalty interests.................................................. (9,184,572)
Distributable income............................................................... 7,278,931
Trust formation costs.............................................................. (331,656)
Distributions to unitholders....................................................... (7,116,317)
---------------------------------------------------------------------------------------------------------
Trust corpus, end of period........................................................ $139,471,673
=========================================================================================================
</TABLE>
The accompanying notes are an integral part of these financial statements.
5
<PAGE>
Notes to Financial Statements
1. Trust Organization and Provisions
Dominion Resources Black Warrior Trust (the "Trust") was formed as a Delaware
business trust pursuant to the terms of the Trust Agreement of Dominion
Resources Black Warrior Trust (as amended, the "Trust Agreement") entered into
effective as of May 31, 1994, among Dominion Black Warrior Basin, Inc., an
Alabama corporation (the "Company"), as trustor, Dominion Resources, Inc., as
sponsor, a Virginia corporation ("Dominion Resources"), and NationsBank of
Texas, N.A., a national banking association (the "Trustee"), and Mellon Bank
(DE) National Association, a national banking association (the "Delaware
Trustee"), as trustees. The trustees are independent financial institutions.
The Trust is a grantor trust formed to acquire and hold certain overriding
royalty interests (the "Royalty Interests") burdening proved natural gas
properties located in 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 6,850,000 of such Units to the
public through various underwriters (the "Underwriters") in June 1994 and an
additional 54,000 Units through the Underwriters in August 1994 (collectively,
the "Public Offering"). 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, to tax credits pursuant to Section 29 of the Internal
Revenue Code of 1986, as amended, upon the production and sale of such gas.
The 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 Delaware
Trustee nor the 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 Gross Proceeds (as defined below). The Royalty Interests are
non-operating interests and bear only expenses related to property, production
and related taxes (including severance taxes). "Gross Proceeds" consist
generally of the aggregate amounts received by the Company attributable to the
interests of the Company in the Underlying Properties from the sale of coal
seam gas at the central delivery points in the gathering system for the
Underlying Properties. The definitions, formulas and accounting procedures and
other terms governing the computation of the Royalty Interests are set forth in
the Conveyance.
Because of the passive nature of the Trust and the restrictions and
limitations on the powers and activities of the Trustee contained in the Trust
Agreement, the Trustee does not consider any of the officers and employees of
the Trustee to be "officers" or "executive officers" of the Trust as such terms
are defined under applicable rules and regulations adopted under the Securities
Exchange Act of 1934.
6
<PAGE>
2. Basis of Accounting
The financial statements of the Trust are prepared on a modified cash basis
and are not intended to present financial position and results of operations
in conformity with generally accepted accounting principles ("GAAP").
Preparation of the Trust's financial statements on such basis includes the
following:
. Royalty income and interest income are recorded in the period in which
amounts are received by the Trust rather than in the month of production.
. General and administrative expenses are recorded based on liabilities
paid and cash reserves established out of cash received.
. Amortization of the Royalty Interests is calculated on a unit-of-production
basis and charged directly to trust corpus when revenues are received.
. Distributions to Unitholders are recorded when declared by the Trustee
(see Note 5).
The financial statements of the Trust differ from financial statements
prepared in accordance with GAAP because royalty income is not accrued in
the period of production, general and administrative expenses recorded are
based on liabilities paid and cash reserves established rather than on an
accrual basis, and amortization of the Royalty Interests is not charged
against operating results.
Dominion Resources sold an aggregate of 6,904,000 Units in the Public
Offering at a price of $20.00 per Unit. Accordingly, the condensed statement
of assets, liabilities and trust corpus at December 31, 1994, reflects
6,904,000 Units at the Public Offering price of $20.00 per Unit and the
remaining 946,000 Units at Dominion Resources' historical cost ($10,744,287).
If Dominion Resources, in the future, should sell all or a portion of the
946,000 retained Units, at that time the carrying value on the Trust's statement
of assets, liabilities and trust corpus would be adjusted from Dominion
Resources' historical cost to the subsequent sale price with respect to
the Units sold.
The net amount of royalty interest in gas properties is limited to
the sum of the future net cash flows attributable to the Trust's gas reserves
at year end using product prices plus the estimated Section 29 credits for
federal income tax purposes. If the net cost of royalty interests in gas
properties exceeds this amount, an impairment provision will be recorded
and charged to the Trust Corpus.
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.
7
<PAGE>
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. The fee is $75,000 per quarter increased annually by three
percent. Aggregate fees paid by the Trust to Dominion Resources in 1994
were $175,000. During 1994, the Trust reimbursed Dominion Resources $331,656
for formation costs.
Of the Trust expenses payable at December 31, 1994, $212 represents
expense reimbursements to the trustees. Aggregate fees and expense
reimbursements paid by the Trust to the trustees in 1994 were $20,417 and
$3,342, respectively.
5. Distributions to Unitholders
The Trustee determines for each calendar quarter the amount of cash available
for distribution to Unitholders. Such amount (the "Quarterly Distribution
Amount") is an amount equal to the excess, if any, of the cash received
by the Trust attributable to production from the Royalty Interests during
such quarter, provided that such cash is received by the Trust on or before
the last business day prior to the 45th day following the end of such calendar
quarter, plus the amount of interest expected by the Trustee to be earned
on such cash proceeds during the period between the date of receipt by the
Trust of such cash proceeds and the date of payment to the Unitholders of
such Quarterly Distribution Amount, plus all other cash receipts of the
Trust during such quarter (to the extent not distributed or held for future
distribution as a Special Distribution Amount (as defined below) or included
in the previous Quarterly Distribution Amount) (which might include sales
proceeds not sufficient in amount to qualify for a special distribution
as described in the next paragraph), over the liabilities of the Trust paid
during such quarter and not taken into account in determining a prior Quarterly
Distribution Amount, subject to adjustments for changes made by the Trustee
during such quarter in any cash reserves established for the payment of
contingent or future obligations of the Trust. An amount which is not included
in the Quarterly Distribution Amount for a calendar quarter because such
amount is received by the Trust after the last business day prior to the
45th day following the end of such calendar quarter will be included in
the Quarterly Distribution Amount for the next calendar quarter. The Quarterly
Distribution Amount for each quarter will be payable to Unitholders of record
on the 60th day following the end of such calendar quarter unless such day
is not a business day in which case the record date is the next business
day thereafter. The Trustee is to 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.
8
<PAGE>
The first distribution to Unitholders was made on September 8, 1994, to
Unitholders of record on August 29, 1994, and was based upon amounts received
in respect of production attributable to the Royalty Interests during the
period from June 1, 1994 (the effective date of the Conveyance) through June
30, 1994. Depletion deductions and Section 29 tax credits will be available to
Unitholders only with respect to gas attributable to the Royalty Interests that
is produced and sold after June 28, 1994 (the date of the initial closing of
the Public Offering).
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 will be the date that is established for the next 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 Event
Subsequent to December 31, 1994, the Trust declared and paid the following
distribution:
<TABLE>
<CAPTION>
Distribution
Quarterly Record Date Payment Date Per Unit
--------------------------------------------------------------------------------
<S> <C> <C>
March 1, 1995................. March 10, 1995 $0.692117
</TABLE>
The trustee has estimated the Section 29 tax credit associated with the March
10, 1995 quarterly distribution to be $0.40 per unit (unaudited).
7. Quarterly Financial Data (Unaudited)
Summarized quarterly financial data for the period from May 31, 1994 (date of
inception) to December 31, 1994 are as follows (in thousands except per unit
data):
<TABLE>
<CAPTION>
Second Third Fourth
Quarter Quarter Quarter
--------------------------------------------------------------------------------
<S> <C> <C> <C>
Royalty income.......................... 0 $1,877,005 $5,719,506
Distributable income (loss)............. $(27,927) 1,740,104 5,566,754
Distributable income (loss) per Unit.... 0 .22 .71
</TABLE>
Selected 1994 fourth quarter data are as follows:
<TABLE>
<S> <C>
Royalty income.................................................... $5,719,506
Interest income................................................... 13,746
--------------------------------------------------------------------------------
General and administrative expenses............................... 166,498
--------------------------------------------------------------------------------
Distributable income.............................................. $5,566,754
================================================================================
Distributable income per Unit..................................... $ .709139
================================================================================
Distributions per Unit............................................ $ .726389
================================================================================
</TABLE>
9
<PAGE>
8. Supplemental Gas Disclosures (Unaudited)
The net proved reserves attributable to the Royalty Interests have been
estimated as of December 31, 1994 by independent petroleum engineers. A reserve
estimate as of June 1, 1994 was prepared for the Trust even though the
conveyance of the Royalty Interests to the Trust did not occur until June 28,
1994.
In accordance with Statement of Financial Accounting Standards No. 69,
estimates of proved reserves and future net cash flows from proved reserves
have been prepared using contractually guaranteed prices and end-of-period
natural gas prices, and related costs. The standardized measure of future net
cash flows from the gas reserves is calculated based on discounting such future
net cash flows at an annual rate of 10 percent. The average price for December
1994 was $1.83 per Mcf including the effect of the Gas Purchase Agreement.
Numerous uncertainties are inherent in estimating volumes and value of
proved reserves and in projecting future production rates and timing of
development expenditures. Such reserve estimates are subject to change as
additional information becomes available. The reserves actually recovered and
the timing of production may be substantially different from the original
estimates.
The reserve estimates for the Royalty Interests are based on a percentage
share payable to the Trust of 65 percent.
<TABLE>
<CAPTION>
Bcf
--------------------------------------------------------------------------------
<S> <C>
Proved developed reserves at June 1, 1994............................ 63,311
Increases (decreases) due to:
Revisions of previous estimates.................................... 7,480
Production......................................................... (7,643)
--------------------------------------------------------------------------------
Proved developed reserves at December 31, 1994....................... 63,148
================================================================================
</TABLE>
All proved reserve estimates presented above at December 31, 1994 are
proved developed.
Proved developed reserves all located in the United States for the Royalty
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.
Estimated economic quantities have been determined considering the Section 29
tax credit.
The following table sets forth the standardized measure of discounted
estimated future net cash flows from proved reserves at December 31, 1994
relating to the Trust's Royalty Interests (thousands of dollars):
<TABLE>
<CAPTION>
1994
--------------------------------------------------------------------------------
<S> <C>
Future cash inflows................................................. $112,375
Future taxes........................................................ (6,515)
--------------------------------------------------------------------------------
Future net cash flows............................................... 105,860
10% annual discount for estimated timing of
cash flows........................................................ (27,553)
--------------------------------------------------------------------------------
Standardized measure of discounted future net
cash flows........................................................ $ 78,307
================================================================================
</TABLE>
Future cash flows (undiscounted) do not include Section 29 tax credits
which in the aggregate are estimated to be approximately $58,980,000 having a
discounted present value (assuming a 10% discount rate) of approximately
$44,604,000.
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, 1994 (thousands of dollars):
<TABLE>
<S> <C>
Balance at June 1, 1994............................................ $ 95,400
Increase (decrease) due to:
Royalty Income, net of taxes..................................... (13,202)
Changes in prices................................................ (13,796)
Extensions and discoveries....................................... --
Changes in estimated volumes..................................... 4,340
Accretion of discount............................................ 5,565
Other............................................................ --
--------------------------------------------------------------------------------
Balance at December 31, 1994..................................... $ 78,307
================================================================================
</TABLE>
10
<PAGE>
9. Gas Purchase Agreement
Sonat Marketing Company ("Sonat Marketing") is required under a gas
purchase agreement (the "Gas Purchase Agreement") to purchase the natural gas
produced and sold from the Underlying Properties for as long as reserves on the
Underlying Properties ("Gas") produce natural gas. Under such Gas Purchase
Agreement, Sonat Marketing is obligated to purchase up to a specified monthly
base quantity at the central delivery points for Gas in the gathering system for
the Underlying Properties for a contract price which provides for a specified
premium (between $0.5 and $.07 per MMBtu) over the Index Price (as defined
below), subject to a minimum price of $1.85 per MMBtu and a maximum price of
$2.63 per MMBtu, until December 31, 1998. Sonat Marketing is obligated to
purchase gas production in excess of the specified monthly base quantities at
the Index Price. After December 31, 1998, Sonat Marketing is obligated to
purchase gas production at the Index Price until such time as the Company and
Sonat Marketing negotiate a different price, although the Company will have the
ability to obtain an offer from another purchaser and terminate the Gas Purchase
Agreement if Sonat Marketing does not match such offer. The "Index Price," which
is determined on a monthly basis, is Southern Natural Gas Company's posted index
price for deliveries of gas in Louisiana. During 1994, Sonat Marketing purchased
all the gas production attributable to the Royalty Interests.
11
<PAGE>
EXHIBIT 23.1
[LOGO FOR:
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS] FAX (713) 651-0849
1100 LOUISIANA SUITE 3800 HOUSTON, TEXAS 77002-5218 TELEPHONE (713) 651-9191
March 29, 1995
Dominion Resources Black Warrior Trust
NationsBank Center
901 Main Street, 12th Floor
Dallas, Texas 75202
Gentlemen:
In connection with the filing of the Annual Report on Form 10K for
the year ended December 31, 1994 for Dominion Resources Black Warrior Trust (the
"Trust"), we delivered a report dated March 29, 1995 with respect to an
estimate of the net proved reserves, future production, and income attributable
to certain royalty interests of the Trust, as of January 1, 1995.
We understand that you intend that our report be incorporated by
reference in and filed as an exhibit to such Annual Report and any amendments
thereto, and we hereby consent to such use. We also consent to the references in
the Annual Report to our firm and to the information provided therein.
Very truly yours,
/s/ RYDER SCOTT COMPANY
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
LPC/sw
DENVER OFFICE: 600 SEVENTEENTH SUITE 900N DENVER, COLORADO 80202-5401
TELEPHONE (303) 623-9147 FAX (303) 623-4258
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM
ANNUAL REPORT & 10-K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<S> <C>
<PERIOD-TYPE> 7-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> MAY-31-1994
<PERIOD-END> DEC-31-1994
<CASH> 1,651
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,651
<PP&E> 148,824,287
<DEPRECIATION> 9,184,572
<TOTAL-ASSETS> 139,641,366
<CURRENT-LIABILITIES> 169,693
<BONDS> 0
<COMMON> 0
0
0
<OTHER-SE> 139,471,673
<TOTAL-LIABILITY-AND-EQUITY> 139,641,366
<SALES> 7,596,511
<TOTAL-REVENUES> 7,614,065
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 335,134
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 7,278,931
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 7,278,931
<EPS-PRIMARY> .927
<EPS-DILUTED> 0
</TABLE>
<PAGE>
EXHIBIT 99.1
[LOGO FOR:
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS] FAX (713) 651-0849
1100 LOUISIANA SUITE 3800 HOUSTON, TEXAS 77002-5218 TELEPHONE (713) 651-9191
March 29, 1995
Dominion Resources Black Warrior Trust
NationsBank Center
901 Main Street, 12th Floor
Dallas, Texas 75202
Gentlemen:
At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain royalty interests of Dominion
Resources Black Warrior Trust (the Trust) as of January 1, 1995. The subject
properties are located in Black Warrior Basin, Tuscaloosa County, Alabama. The
income data 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 result of this study is shown below.
UNESCALATED PARAMETERS
Estimated Net Reserve and Income Data
Certain Royalty Interests of
Dominion Resources Black Warrior Trust
As of January 1, 1995
--------------------------------------------------------
<TABLE>
<CAPTION>
Proved
-------------------------------------------
Developed
----------------------------- Total
Producing Non-Producing Proved
------------ ------------- ------------
<S> <C> <C> <C>
Net Remaining Reserves
----------------------
Gas - MMCF 55,123 8,025 63,148
Income Data
-----------
Future Gross Revenue $ 92,342,871 $13,516,736 $105,859,607
Tax Credits 50,987,835 7,991,772 58,979,607
------------ ----------- ------------
Future Net Income (FNI) $143,330,706 $21,508,508 $164,839,214
Discounted FNI @ 10% $106,936,772 $15,973,855 $122,910,627
</TABLE>
All gas volumes are sales gas expressed in millions of cubic feet
(MMCF) at the official temperature and pressure bases of the areas in which the
gas reserves are located.
The proved developed non-producing reserves included herein are
comprised of the behind pipe category. All of the behind pipe reserves included
are for the addition of the Pratt coal seam by perforating and fracture
stimulation. The various producing status categories are defined under the tab
"Reserve Definitions and Pricing Assumptions" in this report.
DENVER OFFICE: 600 SEVENTEENTH SUITE 900N DENVER, COLORADO 80202-5401
TELEPHONE (303) 623-9147 FAX (303) 623-4258
<PAGE>
Dominion Resources Black Warrior Trust
March 29, 1995
Page 2
A Staff Accounting Bulletin (S.A.B.) issued September 18, 1989 allows
for oil and gas producing companies to include coalbed methane gas in their
estimate of proved reserves under SEC guidelines. In accordance with the S.A.B.
dated November 30, 1989 these reserves should be included provided they comply
in all other respects with the definition of proved oil and gas reserves.
Included is the requirement that methane production be economical at current
prices, costs (net of the tax credit) and existing operating conditions. At the
request of Dominion Black Warrior Basin, Inc. (Dominion), the coalbed methane
gas reserves presented herein are based on economic parameters which include
Dominion's estimates of the future Section 29 Tax Credit. Dominion's estimates
of the future tax credits are presented in detail 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 Section 29 Tax Credit
(presented as "other income"). The future net income is before the deduction of
state and federal income taxes and has not been adjusted for outstanding loans
which may exist nor does it include any adjustment for cash on hand or
undistributed income. No attempt has been made to quantify or otherwise account
for any accumulated gas production imbalances that may exist. Gas reserves
account for 100 percent of total future gross revenue from proved reserves.
Reserves Included in This Report
--------------------------------
The proved reserves included herein conform to the definition
---------------
as set forth in the Securities and Exchange Commission's Regulation S-X
Part 210.4-10 (a) as clarified by subsequent Commission Staff Accounting
Bulletins. Our definition of proved reserves is included 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.
The reserves included in this report are estimates only and should
not be construed as being exact quantities. They may or may not be actually
recovered, and if recovered, the revenues therefrom and the actual costs
related thereto could be more or less than the estimated amounts. Moreover,
estimates of reserves may increase or decrease as a result of future
operations.
Future Production Rates
-----------------------
Initial production rates are based on the current producing rates for
those wells now on production. Test data and other related information were
used to estimate the anticipated peak production rates for those wells or
locations which are not currently producing at peak rates. If no production
decline trend has been established, future production rates were held constant,
or adjusted for the effects of dewatering where appropriate, until a decline in
ability to produce was anticipated. An estimated rate of decline was then
applied to depletion of the reserves. If a decline trend has
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
<PAGE>
Dominion Resources Black Warrior Trust
March 29, 1995
Page 3
been established, this trend was used as the basis for estimating future
production rates. For reserves not yet on production, sales were estimated to
commence at an anticipated date furnished by Dominion.
In general, we estimate that future gas production rates will
continue to be the same as the average rate for the latest available 12 months
of actual production until such time that the well or wells are incapable of
producing at this rate. The well or wells where then projected to decline at
their decreasing delivery capacity rate. Our general policy on estimates of
future gas production rates is adjusted when necessary to reflect actual gas
market conditions in specific cases.
The future production rates from wells now on production may be more
or less than estimated because of changes in market demand or allowables set by
regulatory bodies. Wells or locations which are not currently producing may
start producing earlier or later than anticipated in our estimates of their
future production rates.
Hydrocarbon Prices
------------------
Dominion furnished us with contract gas prices in effect at January
1, 1995 and these prices were held constant until the contract expires and then
were adjusted to the current market price and held at this adjusted price to
depletion of the reserves.
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
-----
Operating costs for the leases and wells 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. Development costs were furnished to us by
Dominion and are based on authorizations for expenditure for the proposed work
or actual costs for similar projects. The current operating and development
costs were held constant throughout the life of the properties. This study does
not consider the salvage value of the lease equipment or the abandonment cost
since both are relatively insignificant and tend to offset each other. 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.
In those cases where the Pratt coal seam is added as a behind pipe
completion, the lease operating expenses are carried with the proved producing
reserve forecast until its depletion. Upon depletion the lease operating
expense is transferred to the behind pipe forecast.
General
-------
The estimates of reserves presented herein are based upon a detailed
study of the properties in which the Trust owns an interest; however, we have
not made any field examination of the properties. No consideration was given in
this report to potential environmental liabilities which may exist nor were any
costs included for potential liability to restore and clean up damages, if any,
caused by past operating practices. Dominion has informed us that they have
furnished us all of the accounts, records, geological and engineering data, and
reports and other data required for this
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
<PAGE>
Dominion Resources Black Warrior Trust
March 29, 1995
Page 4
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
1994.
Neither we nor any of our employees have any interest in the subject
properties and neither the employment to make this study nor the compensation is
contingent on our estimates of reserves and future income for the subject
properties.
This report was prepared for the exclusive use of the Trust. The
data, work papers, and maps used in the preparation of this report are
available for examination by authorized parties in our offices. Please contact
us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
/s/ LARRY P. CONNOR
Larry P. Connor, P.E.
Petroleum Engineer
LPC/sw
Approved:
/s/ DOUGLAS G. MANNER
----------------------------
Douglas G. Manner, P.E.
Group Vice President
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
<PAGE>
DEFINITIONS OF RESERVES
SEC DEFINITIONS
---------------
Proved reserves of crude oil, condensate, natural gas, and natural
---------------
gas liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing operating conditions using the cost and price
parameters discussed in other sections of this report. Reservoirs are
considered proved if economic producibility is supported by actual production or
formation tests. In certain instances, proved reserves are assigned on the
basis of a combination of core analysis and electrical and other type logs
which indicate the reservoirs are analogous to reservoirs in the same field
which are producing or have demonstrated the ability to produce on a formation
test. The area of a reservoir considered proved includes (1) that portion
delineated by drilling and defined by fluid contacts, if any, and (2) the
adjoining portions not yet drilled that can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of data on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir. Proved reserves
are estimates of hydrocarbons to be recovered from a given date forward. They
may be revised as hydrocarbons are produced and additional data become
available. Proved natural gas reserves are comprised of non-associated,
associated and dissolved gas. An appropriate reduction in gas reserves has been
made for the expected removal of natural gas liquids, for lease and plant fuel,
and for the exclusion of non-hydrocarbon gases if they occur in significant
quantities and are removed prior to sale.
Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot project or the
operation of an installed program in the reservoir provides support for the
engineering analysis on which the project or program was based, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.
Estimates of proved reserves do not include crude oil, natural gas,
or natural gas liquids being held in underground or surface storage.
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
<PAGE>
DEFINITIONS OF PRODUCING STATUS CATEGORIES
Developed Producing
-------------------
Producing reserves are recoverable from completion intervals
---------
currently open and producing to market. Improved recovery reserves are
considered to be producing only after an improved recovery project has been
installed and is in operation.
Developed Non-Producing
-----------------------
Shut-in reserves are recoverable from completion intervals now open,
-------
but which had not started producing as of the date of our estimate.
Behind pipe reserves are recoverable from zones behind casing in
-----------
existing wells, which will require additional completion work or a future
recompletion prior to the start of production.
Undeveloped
-----------
Undeveloped reserves are recoverable by new wells on undrilled
-----------
acreage, from existing wells where a relatively large expenditure is required
for recompletion and from acreage where the application of an improved recovery
project is planned and the costs required to place the project in operation are
relatively large. Reserves on undrilled acreage are limited to those drilling
units offsetting productive units that are reasonably certain of production
when drilled. Proved reserves for other undrilled units are included only where
it can be demonstrated with certainty that there is continuity of production
from the existing productive formation.
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
<PAGE>
HYDROCARBON PRICING AND COST PARAMETERS
Dominion Resources Black Warrior Trust
Dominion Black Warrior Basin, Inc.'s Pricing and Cost Policy
Unescalated Parameters
Effective January 1, 1995
Gas
---
Dominion has furnished the pricing scenario to use at January 1, 1995.
<TABLE>
<CAPTION>
Year $/MMBTU
---------- -----------
<S> <C>
1995 1.85
1996 1.85
1997 1.85
1998 1.85
1999 1.70
2000 1.70
2001 1.70
2002 1.70
2003 1.70
2004 1.70
</TABLE>
<TABLE>
<CAPTION>
Behind Pipe
Lease Operating Compression Compression
Expense Costs Costs
Year $/Well/Month $/MCF $/MCF*
---------- --------------- ----------- -----------
<S> <C> <C> <C>
1995 1,416 .228 .228
1996 1,353 .234 .234
1997 1,263 .233 .233
1998 1,204 .235 .235
1999 1,101 .236 .236
2000 977 .236 .236
2001 873 .235 .235
2002 823 .234 .234
2003 999 .237 .237
2004 958 .239 .239
</TABLE>
<TABLE>
<CAPTION>
Estimated Section 29 Tax Credit
-------------------------------------
Year $/MMBTU
---------- -----------
<S> <C>
1995 .995788
1996 .995788
1997 .995788
1998 .995788
1999 .995788
2000 .995788
2001 .995788
2002 .995788
</TABLE>
---------------
* Behind pipe "Lease Operating Expense" carried with the proved producing
lease until depletion.
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
