SUBJECT TO COMPLETION, DATED MAY 17, 1995
Filed pursuant to Rule 424(b)(3)
File number 33-53513
PROSPECTUS SUPPLEMENT (Dominion Resources logo)
(To Prospectus dated May 16, 1995)
946,000 Trust Units
Dominion Resources Black Warrior Trust
Each unit of beneficial interest ("Unit") offered hereby evidences an
undivided interest in the assets and liabilities of Dominion Resources Black
Warrior Trust (the "Trust"). The Trust is a fixed investment trust formed to
hold overriding royalty interests (the "Royalty Interests") burdening proved
developed natural gas properties (the "Underlying Properties") in the Pottsville
coal formation of the Black Warrior Basin, Tuscaloosa County, Alabama. The
Royalty Interests have been carved out of the interests (the "Company
Interests") in the Underlying Properties owned by Dominion Black Warrior Basin,
Inc., an Alabama corporation (the "Company"), which is an indirect wholly-owned
subsidiary of Dominion Resources, Inc., a Virginia corporation ("Dominion
Resources").
A total of 7,850,000 Units are outstanding, all of which were held by
Dominion Resources immediately prior to an initial public offering of 6,850,000
Units at a price to the public of $20.00 per Unit which was completed on June
28, 1994. The Units offered hereby were subject to a 45-day underwriters'
over-allotment option pursuant to which 54,000 out of 1,000,000 Units were sold.
The Trust will not receive any of the proceeds from the offering made hereby.
The Units are listed on the New York Stock Exchange, under the symbol "DOM." The
last reported sales price of the Units on the New York Stock Exchange on May 16,
1995 was $20.00 per share. See "Distributions and Market Prices."
SEE "RISK FACTORS" FOR CERTAIN CONSIDERATIONS RELEVANT TO AN INVESTMENT IN
THE UNITS, INCLUDING RISKS ASSOCIATED WITH THE AVAILABILITY TO A UNITHOLDER OF
TAX BENEFITS SUCH AS SECTION 29 TAX CREDITS AND DEPLETION DEDUCTIONS. SEE ALSO
"FEDERAL INCOME TAX CONSEQUENCES -- SECTION 29 TAX CREDITS."
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS
THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES
COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS
PROSPECTUS SUPPLEMENT OR PROSPECTUS. ANY REPRESENTA-
TION TO THE CONTRARY IS A CRIMINAL OFFENSE.
[CAPTION]
<TABLE>
Underwriting Proceeds to
Price to Discounts and Dominion
Public Commissions (1) Resources(2)
<S> <C> <C> <C>
Per Unit.............................................. $ $ $
Total................................................. $ $ $
</TABLE>
(1) Dominion Resources has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933. See
"Underwriting."
(2) Before deducting expenses of this offering estimated to be $125,000 payable
by Dominion Resources.
The Units are being offered by the Underwriters named herein, subject to
prior sale, when, as and if accepted by them and subject to certain conditions.
It is expected that certificates for the Units offered hereby will be available
for delivery on or about , 1995, at the offices of Lehman
Brothers Inc., New York, New York.
LEHMAN BROTHERS WHEAT FIRST BUTCHER SINGER
, 1995
INFORMATION CONTAINED IN THIS PRELIMINARY PROSPECTUS SUPPLEMENT IS
SUBJECT TO COMPLETION OR AMENDMENT. A REGISTRATION STATEMENT RELATING TO
THESE SECURITIES HAS BEEN FILED WITH THE SECURITIES AND EXCHANGE
COMMISSION. THESE SECURITIES MAY NOT BE SOLD NOR MAY OFFERS TO BUY BE
ACCEPTED PRIOR TO THE TIME THAT A FINAL PROSPECTUS SUPPLEMENT IS
DELIVERED. THIS PRELIMINARY PROSPECTUS SUPPLEMENT AND ACCOMPANYING
PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF
AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF THESE SECURITIES IN ANY
STATE IN WHICH SUCH OFFER, SOLICITATION OR SALE WOULD BE UNLAWFUL PRIOR
TO REGISTRATION OR QUALIFICATION UNDER THE SECURITIES LAWS OF ANY SUCH
STATE.
<PAGE>
(A MAP OF SOUTHEASTERN UNITED STATES, ALABAMA AND THE BLACK WARRIOR BASIN
IDENTIFYING THE LOCATION OF THE UNDERLYING PROPERTIES.)
IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE UNITS OFFERED
HEREBY AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET.
SUCH TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE, IN THE
OVER-THE-COUNTER MARKET, OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE
DISCONTINUED AT ANY TIME.
S-2
<PAGE>
PROSPECTUS SUPPLEMENT SUMMARY
THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY THE MORE DETAILED
INFORMATION AND FINANCIAL STATEMENTS APPEARING ELSEWHERE IN THE PROSPECTUS (AS
SUPPLEMENTED BY THIS PROSPECTUS SUPPLEMENT, THE "PROSPECTUS") AND SHOULD BE READ
ONLY IN CONJUNCTION WITH THE ENTIRE PROSPECTUS. A GLOSSARY OF CERTAIN DEFINED
TERMS USED IN THIS PROSPECTUS IS SET FORTH IN THE GLOSSARY INCLUDED AS EXHIBIT B
TO THIS PROSPECTUS.
THE TRUST
Dominion Resources Black Warrior Trust (the "Trust") was formed as a
Delaware business trust pursuant to the Trust Agreement of Dominion Resources
Black Warrior Trust entered into effective as of May 31, 1994 by and among
Dominion Black Warrior Basin, Inc. (the "Company"), as trustor, Dominion
Resources, Inc., the parent corporation of the Company ("Dominion Resources"),
as sponsor, and NationsBank of Texas, N.A. (the "Trustee") and Mellon Bank (DE)
National Association (the "Delaware Trustee"), as trustees. The Trust owns
certain overriding royalty interests (the "Royalty Interests") burdening proved
developed natural gas properties in the Pottsville coal formation of the Black
Warrior Basin in Alabama (the "Underlying Properties"). The Royalty Interests
are the only assets of the Trust other than cash and temporary investments being
held for the payment of expenses and liabilities and for distribution to
Unitholders.
The Trust makes quarterly cash distributions to Unitholders. The record
date for the quarterly cash distribution of the Trust is the 60th day following
the end of the calendar quarter unless such day is not a business day in which
case the record date will be the next business day. The quarterly cash
distribution is payable on or before the 70th day after the end of the calendar
quarter. Set forth below are the scheduled record dates and approximate
distribution dates for each quarter of 1995 production attributable to the
Trust.
<TABLE>
<CAPTION>
PRODUCTION PERIOD JANUARY 1--MARCH 31, 1995 APRIL 1--JUNE 30, 1995 JULY 1--SEPTEMBER 30, 1995 OCTOBER 1--DECEMBER 31, 1995
<S> <C> <C> <C> <C>
Record Dates May 30, 1995 August 29, 1995 November 29, 1995 February 29, 1996
Distribution Dates June 9, 1995 September 8, 1995 December 8, 1995 March 11, 1996
</TABLE>
THE OFFERING
<TABLE>
<S> <C>
UNITS OFFERED............................................ 946,000 Units
UNITS OUTSTANDING........................................ 7,850,000 Units, 946,000 of which are currently owned by Dominion
Resources.
USE OF PROCEEDS.......................................... Dominion Resources will receive all of the net proceeds from the
offering and intends to use such proceeds for general corporate
purposes, which may include acquisition of oil and natural gas
properties. See "Use of Proceeds." The Trust will not receive any
of the proceeds from the sale of the Units.
INITIAL CASH DISTRIBUTION AND ALLOCATION
OF SECTION 29 TAX CREDITS.............................. The first cash distribution and allocation of Section 29 tax
credits to purchasers of the Units offered hereby will be made on
or before September 8, 1995 to holders of record on August 29,
1995 and will be based upon amounts received in respect of
production attributable to the Royalty Interests during the period
April 1, 1995 through June 30, 1995, provided certain requirements
are met. See "Risk Factors -- Tax Considerations," "Federal Income
Tax Consequences" and "Description of Trust
Agreement -- Distributions and Income Computations."
</TABLE>
S-3
<PAGE>
SELECTED FINANCIAL DATA
DOMINION RESOURCES BLACK WARRIOR TRUST
<TABLE>
<CAPTION>
FOR THE PERIOD FROM
MAY 31, 1994
(DATE OF INCEPTION) TO THREE MONTHS ENDED
DECEMBER 31, 1994 MARCH 31, 1995
<S> <C> <C>
Royalty Income........................................... $ 7,596,511 $ 5,608,705
Distributable Income..................................... 7,278,931 5,517,607
Distributable Income per Unit............................ .927252 .702879
Distributions per Unit................................... .906537 .692117
Total Assets, end of period.............................. 139,641,366 132,433,849
Trust Corpus, end of period.............................. $139,471,673 $132,339,021
</TABLE>
DISTRIBUTIONS AND MARKET PRICES
The Units are listed and traded on the New York Stock Exchange under the
symbol "DOM". Prior to the initial public offering 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 (1)
<S> <C> <C> <C>
Second Quarter (commencing June 28, 1994)................ $ 20 $ 19 3/4 $ 0.000000
Third Quarter............................................ 20 1/8 19 3/8 0.180147
Fourth Quarter........................................... 19 5/8 16 7/8 0.726389
<CAPTION>
1995
<S> <C> <C> <C>
First Quarter............................................ 19 5/8 17 1/4 0.692117
Second Quarter (through May 16, 1995).................... 20 1/8 18 3/4 --
</TABLE>
(1) Unitholders of record on the 60th day following the last day of each
calendar quarter receive cash distributions related to such calendar quarter
within 70 days following the end of the calendar quarter. Distributions per
Unit for a quarter represent distributions made to Unitholders during such
quarter. See "Description of the Trust Agreement -- Distributions and Income
Computations."
At March 15, 1995, there were 7,850,000 Units outstanding and 784
Unitholders of record.
RECENT DEVELOPMENTS
Natural gas prices since the initial offering of the Units have been at
levels below the Minimum Price provided for in the Gas Purchase Agreement for
all but one month, July 1994. As a result, the presence of the Minimum Price
provisions in the Gas Purchase Agreement has resulted in $2,226,000, or $0.28
per Unit, in additional revenues to Unitholders for the period June 1, 1994
through March 31, 1995.
Under the Conveyance, the Company is required to complete or recomplete 374
of the Existing Wells to the Pratt coal seam between January 1, 1994 and March
31, 1997. The Company has chosen to accelerate the Pratt recompletions ahead of
the schedule contained in the Conveyance. In accordance with this acceleration,
by March 31, 1995, the Company had performed 163 Pratt recompletions, exceeding
the requirement of performing 144 Pratt recompletions by that date set by the
Conveyance. Although the Conveyance requires that 234 Existing Wells be
recompleted to the Pratt coal seam by December 31, 1995, the Company plans to
recomplete 256 Existing Wells by that date.
For the period June 1, 1994 through March 31, 1995, actual production
attributable to the Royalty Interests was 10.7 Bcf versus the estimated
production from the Original Reserve Estimate of 10.3 Bcf, or 4.5% higher than
anticipated. This can be attributed primarily to the acceleration of the Pratt
recompletions and continued experience of better production rates than
anticipated. The Reserve Estimate, dated January 1, 1995, reflects a 6.2 Bcf, or
a 12.8%, increase in reserves projected as of such date in the Original Reserve
Estimate. This can be primarily attributed to a hyperbolic performance trend of
certain Existing Wells.
S-4
<PAGE>
ALABAMA SEVERANCE TAXES
The Alabama Department of Revenue (the "DOR") has proposed a set of
regulations that indicate the DOR is considering changing the way it computes
the amount of severance taxes due by disallowing certain deductions previously
allowed on audit. Such a change could result in an increase in the amount of
severance taxes due for natural gas production. Since the Trust, as owner of the
Royalty Interests, bears its proportionate share of severance taxes, any
increase in the amount of severance taxes will decrease the amount of cash
distributions payable to Unitholders. The Company has been advised by Alabama
tax counsel that, as of the date hereof, it is impossible to predict whether
this change will be implemented (by regulation or otherwise) and, if so, whether
and in what amount severance taxes may be increased.
UNDERWRITING
Subject to the terms and conditions set forth in the Underwriting
Agreement, Dominion Resources has agreed to sell to each of the Underwriters
named below, and each of the Underwriters, for whom Lehman Brothers Inc. and
Wheat, First Securities, Inc. are acting as representatives (the
"Representatives"), has severally agreed to purchase the respective number of
Units set forth opposite its name below.
<TABLE>
<CAPTION>
NUMBER
OF FIRM
UNDERWRITER UNITS
<S> <C>
Lehman Brothers Inc. .......................................
Wheat, First Securities, Inc................................
Total................................................ 946,000
</TABLE>
Under the terms and conditions of the Underwriting Agreement, the
Underwriters are committed to take and pay for all of such Units offered hereby,
if any are taken.
The Underwriters propose to offer the Units in part directly to the public
at the price to the public set forth on the cover of this Prospectus Supplement
and in part to certain securities dealers at such price, less a concession of
$ per Unit. The Underwriters may allow, and such dealers may reallow, a
concession not in excess of $ per Unit to certain brokers and dealers. After
the completion of the initial offering of the Units, the offering price and
other selling terms may from time to time be varied by the Representatives.
Because the National Association of Securities Dealers, Inc. ("NASD") is
expected to view the Units offered hereby as interests in a direct participation
program, the offering is being made in compliance with Appendix F of the NASD's
Rules of Fair Practice. Investor suitability of the Units should be judged
similarly to the suitability of other securities which are listed for trading on
a national securities exchange. The Underwriters do not intend to confirm sales
to any accounts over which they exercise discretionary authority without the
prior written approval of the transaction by the customer.
Prior to the initial public offering of the Units which was completed on
June 28, 1994, there was no public market for the Units. The initial public
offering price of $20.00 per Unit in connection with the initial public offering
completed on June 28, 1994 was negotiated among Dominion Resources and the
underwriters. Among the factors that were considered in determining the initial
public offering price of the Units in connection with the initial public
offering completed on June 28, 1994, in addition to prevailing market
conditions, were the terms of the Gas Purchase Agreement, current and historical
natural gas prices, current and prospective conditions in the supply and demand
for natural gas, estimated reserve and production quantities attributable to the
Royalty Interests, the financial multiples of publicly-traded securities of
comparable entities, earnings of comparable entities in recent periods, the
value of Section 29 tax credits and the Trust's earnings prospects.
Dominion Resources has agreed in the Underwriting Agreement to indemnify
the several Underwriters against certain liabilities, including liabilities
under the Securities Act.
Certain of the Underwriters or agents and their associates may be customers
of, engage in transactions with and perform services for, Dominion Resources and
its subsidiaries in the ordinary course of business and for which they receive
customary compensation.
S-5
<PAGE>
PROSPECTUS (Dominion Resources logo)
7,850,000 Trust Units
Dominion Resources Black Warrior Trust
Each unit of beneficial interest ("Unit") offered hereby evidences an
undivided interest in the assets and liabilities of Dominion Resources Black
Warrior Trust (the "Trust"). The Trust is a fixed investment trust formed to
hold overriding royalty interests (the "Royalty Interests") burdening proved
developed natural gas properties (the "Underlying Properties") in the Pottsville
coal formation of the Black Warrior Basin, Tuscaloosa County, Alabama. The
Royalty Interests have been carved out of the interests (the "Company
Interests") in the Underlying Properties owned by Dominion Black Warrior Basin,
Inc., an Alabama corporation (the "Company"), which is an indirect wholly-owned
subsidiary of Dominion Resources, Inc., a Virginia corporation ("Dominion
Resources").
The coal seam gas produced from the Underlying Properties and sold prior to
2003 qualifies for the tax credit allowed by Section 29 of the Internal Revenue
Code of 1986, as amended. The Royalty Interests are entitled to the Section 29
tax credits attributable to their share of the natural gas production from the
Underlying Properties. A holder of Units (a "Unitholder") is able to use the
Section 29 tax credits only if he is the owner of the Units at the time the coal
seam gas is produced and only to the extent that he has sufficient regular tax
liability in excess of his alternative minimum tax liability. See "Federal
Income Tax Consequences" and "Risk Factors -- Tax Considerations."
The Trust receives quarterly payments based on the revenues received from
the sale of natural gas produced from the Underlying Properties attributable to
the Royalty Interests. The cash proceeds from the payments made to the Trust
(net of Trust administrative expenses) are distributed to Unitholders on a
quarterly basis with respect to periods prior to termination of the Trust. In
addition, the Section 29 tax credits are allocated quarterly to Unitholders
through December 31, 2002.
A total of 7,850,000 Units are outstanding, all of which are being offered
by Dominion Resources. Of the 7,850,000 Units offered hereby, 6,850,000 were
sold pursuant to an underwritten public offering which was completed on June 28,
1994, and an additional 54,000 Units were sold thereafter pursuant to a 45-day
over-allotment option exercised by the underwriters. The Trust will not receive
any of the proceeds from the offering made hereby. Prior to the initial public
offering of the Units which was completed on June 28, 1994, there was no public
market for the Units. The Units are listed on the New York Stock Exchange under
the symbol "DOM".
The Units offered hereby may be offered at prices and on terms to be
determined at the time of sale and to be set forth in a supplement to this
Prospectus (a "Prospectus Supplement"). The Units may be sold for public
offering to underwriters or dealers, which may be a group of underwriters
represented by one or more managing underwriters, which may include Lehman
Brothers Inc. or Wheat, First Securities, Inc., or through such firms or other
firms acting alone or through dealers. The Units may also be sold through agents
to investors. See "Plan of Distribution." The names of any agents, dealers or
managing underwriters, and of any underwriters, involved in the sale of the
Units in respect of which this Prospectus is being delivered and the initial
public offering price, the applicable agent's commission, dealer's purchase
price or underwriter's discount will be set forth in the Prospectus Supplement.
The net proceeds to Dominion Resources from such sale will also be set forth in
the Prospectus Supplement. Any underwriters, dealers or agents participating in
the offering of Units may be deemed "underwriters" within the meaning of the
Securities Act of 1933, as amended.
This Prospectus may not be used to consummate the sale of the Units unless
accompanied by a Prospectus Supplement.
SEE "RISK FACTORS" FOR CERTAIN CONSIDERATIONS RELEVANT TO AN INVESTMENT IN
THE UNITS, INCLUDING RISKS ASSOCIATED WITH THE AVAILABILITY TO A UNITHOLDER OF
TAX BENEFITS SUCH AS SECTION 29 TAX CREDITS AND DEPLETION DEDUCTIONS. SEE ALSO
"FEDERAL INCOME TAX CONSEQUENCES -- SECTION 29 TAX CREDITS."
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION
PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
LEHMAN BROTHERS WHEAT FIRST BUTCHER SINGER
May 16, 1995
<PAGE>
AVAILABLE INFORMATION
Dominion Resources and the Trust are each subject to the informational
requirements of the Securities Exchange Act of 1934, as amended (the "Exchange
Act"), and in accordance therewith file reports, proxy statements (in the case
of Dominion Resources only) and other information with the Securities and
Exchange Commission (the "Commission"). Such reports, proxy statements and other
information can be inspected and copied at the public reference facilities
maintained by the Commission at 450 Fifth Street, N.W., Room 2120, Washington,
D.C. 20549 and at its regional offices located at Northwestern Atrium Center,
500 West Madison Street, Suite 1400, Chicago, Illinois 60661-2511 and at 7 World
Trade Center, Suite 1300, New York, New York 10048. Copies of such materials can
be obtained from the Public Reference Section of the Commission, 450 Fifth
Street, N.W., Judiciary Plaza, Washington, D.C. 20549, on payment of prescribed
rates. Such reports, proxy statements and other information concerning Dominion
Resources or the Trust can also be inspected at the offices of the New York
Stock Exchange, 20 Broad Street, New York, New York 10005, on which certain
securities of Dominion Resources and the Units are listed.
This Prospectus does not contain all of the information set forth in the
Registration Statement (the "Registration Statement") of which this Prospectus
is a part, and exhibits relating thereto, which have been filed with the
Commission. Statements contained herein concerning the provisions of documents
are necessarily summaries of such documents, and each statement is qualified in
its entirety by reference to the copy of the applicable document filed with the
Commission. Copies of the Registration Statement and the exhibits thereto are on
file at the offices of the Commission and may be obtained upon payment of the
fees prescribed by the Commission, or may be examined without charge at the
public reference facilities of the Commission described above.
Unitholders will be furnished with annual reports containing audited
financial statements of the Trust consisting of a statement of assets,
liabilities and Trust corpus, a statement of distributable income and a
statement of changes in Trust corpus and certain additional information and with
comparable quarterly reports on a condensed basis showing the assets,
liabilities, receipts and disbursements of the Trust. See "Description of the
Trust Agreement -- Periodic Reports." Annual financial statements will be
audited and reported on with an opinion expressed by a firm of independent
public accountants.
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The following documents have been filed by Dominion Resources (Commission
File No. 1-8489) with the Commission pursuant to the Exchange Act and are
incorporated herein by reference:
(1) Dominion Resources' Annual Report on Form 10-K for the year ended
December 31, 1994;
(2) Dominion Resources' Quarterly Report on Form 10-Q for the period ended
March 31, 1995; and
(3) Dominion Resources' Current Report on Form 8-K dated April 17, 1995.
The following documents have been filed by the Trust (Commission File No.
1-11335) with the Commission pursuant to the Exchange Act and are incorporated
herein by reference:
(1) The Trust's Annual Report on Form 10-K for the year ended December 31,
1994; and
(2) The Trust's Quarterly Report on Form 10-Q for the period ended March
31, 1995.
All documents filed by Dominion Resources and the Trust pursuant to Section
13(a), 13(c), 14 or 15(d) of the Exchange Act subsequent to the date of this
Prospectus and prior to the termination of the offering made by this Prospectus
shall be deemed to be incorporated by reference herein and to be a part hereof
from the date of filing thereof. Any statement contained in a document
incorporated or deemed to be incorporated by reference herein shall be deemed to
be modified or superseded for purposes of this Prospectus to the extent that a
statement contained herein, or in any other subsequently filed document that
also is or is deemed to be incorporated by reference herein, modifies or
supersedes such statement. Any such statement so modified or superseded shall
not be deemed, except as so modified or superseded, to constitute a part of this
Prospectus.
Dominion Resources hereby undertakes to provide without charge to each
person to whom a copy of this Prospectus has been delivered, including any
beneficial owner of Units, upon the written or oral request of any such person,
a copy of any and all information filed by Dominion Resources or the Trust that
has been incorporated by reference in this Prospectus (not including exhibits to
the information that is incorporated by reference herein unless such exhibits
are specifically incorporated by reference in such information). Requests for
such copies should be directed to Dominion Resources, Inc. at P.O. Box 26532,
901 East Byrd Street, Richmond, Virginia 23261-6532, Attention: Corporate
Secretary (telephone (804) 775-5700).
2
<PAGE>
PROSPECTUS SUMMARY
THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY THE MORE DETAILED
INFORMATION AND FINANCIAL STATEMENTS APPEARING ELSEWHERE IN THIS PROSPECTUS AND
SHOULD BE READ ONLY IN CONJUNCTION WITH THE ENTIRE PROSPECTUS. A GLOSSARY OF
CERTAIN DEFINED TERMS USED IN THIS PROSPECTUS IS SET FORTH IN THE GLOSSARY
INCLUDED AS EXHIBIT B TO THIS PROSPECTUS. THROUGHOUT THIS PROSPECTUS NATURAL GAS
PRICES ARE EXPRESSED IN MILLION BRITISH THERMAL UNITS ("MMBTU") AND PRODUCTION
IS EXPRESSED IN MILLION CUBIC FEET ("MMCF "). FOR PURPOSES HEREIN, NATURAL GAS
IS ASSUMED TO HAVE A BTU CONTENT OF 990 MMBTU PER MMCF.
DOMINION RESOURCES BLACK WARRIOR TRUST
Each unit of beneficial interest ("Unit") offered hereby evidences an
undivided interest in the assets and liabilities of Dominion Resources Black
Warrior Trust (the "Trust"), a fixed investment trust formed under the Delaware
Business Trust Act. The Trust was formed to hold overriding royalty interests
(the "Royalty Interests") burdening proved developed natural gas properties (the
"Underlying Properties") in the Pottsville coal formation of the Black Warrior
Basin, Tuscaloosa County, Alabama. The Royalty Interests owned by the Trust have
been carved out of the interests of Dominion Black Warrior Basin, Inc., an
Alabama corporation (the "Company"), in the Underlying Properties (the "Company
Interests"). The Company is an indirect wholly-owned subsidiary of Dominion
Resources, Inc., a Virginia corporation ("Dominion Resources").
All of the natural gas production attributable to the Underlying Properties
(the "Gas") is from the Pottsville coal formation and currently constitutes coal
seam gas. Under current law, Gas from the wells currently existing on the
Underlying Properties (the "Existing Wells") qualifies for a federal income tax
credit allowed by Section 29 of the Internal Revenue Code of 1986, as amended
(the "Code"), which is available to an owner of natural gas that is produced and
sold through December 31, 2002, provided certain requirements are met.
Unitholders will receive quarterly distributions of the cash proceeds received
by the Trust attributable to the Royalty Interests (net of Trust administrative
expenses) and quarterly allocations of Section 29 tax credits for production
attributable to the Royalty Interests. For a detailed discussion of the risks
associated with the ability of a Unitholder to use the Section 29 tax credits,
see "Risk Factors -- Tax Considerations" and "Federal Income Tax Consequences."
Sonat Marketing Company, a Delaware corporation ("Sonat Marketing"), is
required to purchase all of the Gas production attributable to the Company
Interests (the "Subject Gas") pursuant to a gas purchase agreement between the
Company and Sonat Marketing (the "Gas Purchase Agreement") that extends as long
as reserves on the Underlying Properties produce natural gas. The Gas Purchase
Agreement provides a minimum price of $1.85 per MMBtu (the "Minimum Price") and
a maximum price of $2.63 per MMBtu (the "Maximum Price") for the estimated
production of Subject Gas (the "Monthly Base Quantities") through December 31,
1998. Sonat Marketing has entered into a put and call agreement with a
nationally recognized commodities brokerage firm intended to limit its potential
losses as a result of the Minimum Price. In addition, the payment obligations of
Sonat Marketing under the Gas Purchase Agreement are guaranteed (up to $10
million) by Sonat Inc., a Delaware corporation ("Sonat"). See "The Royalty
Interests -- Gas Purchase Agreement."
As of January 1, 1995, net proved reserves attributable to the Royalty
Interests were estimated by Ryder Scott Company Petroleum Engineers ("Ryder
Scott"), independent petroleum engineers, to be 63.1 Bcf based on estimated
future net revenues and considering the Section 29 tax credits. The estimated
future net revenues, discounted at 10 percent and based on the Contract Price at
December 31, 1994 of $1.85 per MMBtu, through 1998, and $1.70 per MMBtu
thereafter, were approximately $78.3 million. As of January 1, 1995, Section 29
tax credits attributable to estimated production from the Royalty Interests had
an estimated value, discounted at 10 percent, of approximately $44.6 million,
assuming a constant tax credit of approximately $0.99 per MMBtu. The Section 29
tax credit is adjusted annually for inflation (or deflation). See " -- Summary
Reserve Information," "The Royalty Interests -- Historical Natural Gas Sales
Price and Production" and "Federal Income Tax Consequences."
Because no additional properties will be contributed to or purchased by the
Trust, the assets of the Trust will deplete over time and a portion of each cash
distribution made by the Trust will, therefore, be analogous to a return of
capital. The Trust will terminate only under certain circumstances. See
"Description of the Trust Agreement -- Termination and Liquidation of the
Trust."
THE TRUST ASSETS
THE UNDERLYING PROPERTIES. The Underlying Properties consist of interests
in the Pottsville coal formation in the Black Warrior Basin located along the
Black Warrior River in Tuscaloosa County, Alabama. The Underlying Properties
comprise
3
<PAGE>
34,212 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.
The Pottsville coal formation ranges from the surface to a depth of 4,100 feet,
and the deepest Existing Well is 2,600 feet. Initial production of coal seam gas
(the main constituent of which is methane) from the Underlying Properties began
in December 1988. The Company acquired its interest in the Underlying Properties
in December 1992. As of January 1, 1995, the Underlying Properties contained 532
wells that were producing natural coal seam gas, all of which were drilled prior
to 1993 and all of which currently qualify for Section 29 tax credits.
Initially, 122 of the Existing Wells were completed to the Pratt coal seam.
All of the Existing Wells penetrate depths below the Pratt coal seam, which has
a depth ranging from 900 to 1200 feet. In 1993, the Company implemented a
program to recomplete Existing Wells to the Pratt coal seam so that a total of
522 out of a total of 532 Existing Wells would be completed or recompleted to
the Pratt coal seam as of March 31, 1997. As of January 1, 1995, approximately
274 of the Existing Wells had been completed or recompleted to the Pratt coal
seam. The Company will pay the Trust $1,850 per well per quarter through March
31, 1997 for each well not so recompleted in accordance with the schedule of
recompletions set forth in the Conveyance (as defined below). In addition, if
the Company fails to recomplete any of the 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. See "The Royalty
Interests -- Pratt Recompletion Payments."
The Underlying Properties are operated by The River Gas Corporation, an
Alabama corporation ("River Gas"), pursuant to an operating agreement among the
Company, River Gas and the other working interest owners of the Underlying
Properties (the "Operating Agreement"). See "The Royalty Interests -- Operation
of the Properties."
Wells in the Black Warrior Basin produce natural gas from coal seam
formations that have production characteristics materially different from
conventional natural gas wells. The primary factor affecting recovery of coal
seam gas reserves in the Black Warrior Basin is the lowering of reservoir
pressure through "dewatering" operations. In a typical coal seam 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. In general, the Company
believes that production from the Existing Wells is currently at or near its
peak.
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. Since June 1986, over 16 coalbed methane natural gas developments
have been initiated in the Black Warrior Basin and over 4,000 wells have been
permitted by the State Oil and Gas Board of Alabama in the Black Warrior Basin.
As of December 31, 1994, cumulative production in the coalbed methane portion of
the Black Warrior Basin was over 500 Bcf. In addition to the Company and River
Gas, other significant producers in the coalbed methane portion of the Black
Warrior Basin include Taurus Exploration, Inc., Torch Operating Company, Black
Warrior Methane, Chevron USA, Inc., Amoco Production Company and Meridian Oil
Inc. Annual coalbed methane natural gas production in the Black Warrior Basin
has increased from approximately 13 Bcf in 1986 to approximately 110 Bcf in
1994, and five interstate pipelines provide ready access to markets throughout
the United States.
THE ROYALTY INTERESTS. The Royalty Interests entitle the Trust to receive
65 percent of the Gross Proceeds from the production and sale of the Subject
Gas. The term "Gross Proceeds" generally means the aggregate amounts received by
the Company from the sale of the Subject Gas, at the central delivery points in
the gathering system for the Underlying Properties (collectively, the "Central
Gathering Point"). The definitions, formulas and accounting procedures and other
terms governing the computation of the Royalty Interests are set forth in the
overriding royalty conveyance pursuant to which the Company has conveyed the
Royalty Interests to the Trust, which conveyance, as amended by the Conveyance
Amendment (the "Conveyance"), is included as an exhibit to the Registration
Statement of which this Prospectus is a part.
SUMMARY RESERVE INFORMATION
The following table sets forth, as of January 1, 1995, estimated net proved
natural gas reserves, estimated future net revenues and the discounted estimated
future net revenues attributable to the Company Interests and the Royalty
Interests. All such reserves constitute proved developed reserves. These amounts
are based upon a reserve estimate as of January 1, 1995 (the "Reserve Estimate")
which was prepared by Ryder Scott, using the terms applicable under the Gas
Purchase Agreement. The Reserve Estimate was prepared in accordance with
criteria established by the Securities and Exchange Commission (the
"Commission"). Ryder Scott has delivered to the Company a reserve report as of
January 1, 1995, a summary of which is
4
<PAGE>
included as Exhibit A to this Prospectus. The estimated economic life of each of
the Existing Wells used in calculating the estimated net reserves has been
determined taking into account the Section 29 tax credits.
<TABLE>
<CAPTION>
ESTIMATED ESTIMATED FUTURE NET
NET PROVED REVENUES
NATURAL GAS
RESERVES (DOLLARS IN MILLIONS)
(BCF) UNDISCOUNTED DISCOUNTED
<S> <C> <C> <C>
The Company Interests
Proved Developed Producing............................. 84.8 $ 59.7 $ 47.4
Proved Developed Nonproducing.......................... 12.4 11.3 7.4
Total............................................... 97.2 $ 71.0 $ 54.8
The Royalty Interests
Proved Developed Producing............................. 55.1 $ 92.3 $ 68.3
Proved Developed Nonproducing.......................... 8.0 13.6 10.0
Total............................................... 63.1 $105.9 $ 78.3
</TABLE>
Based upon the production estimates used in the Reserve Estimate for the
period January 1, 1995 through December 31, 2002, and assuming constant future
Section 29 tax credits at the 1994 rate of $0.99 per MMBtu, the estimated total
future tax credits available from the production and sale of the net proved
reserves from the Company Interests and the Royalty Interests would be
approximately $90.7 million and $59.0 million, respectively, and would have a
discounted present value (assuming a 10 percent discount rate) of approximately
$68.6 million and $44.6 million, respectively. The Reserve Estimate includes
proved developed nonproducing reserves which are in connection with the
Company's program to complete or recomplete 522 out of a total of 532 Existing
Wells to the Pratt coal seam by the end of the first quarter of 1997, of which
approximately 274 were completed or recompleted as of January 1, 1995. The
proved developed nonproducing reserves in the Reserve Estimate were attributable
to the 248 Existing Wells which are scheduled to be, but had not been,
recompleted to the Pratt coal seam as of January 1, 1995. The Reserve Estimate
assumes these 248 Existing Wells will be recompleted on or before October 31,
1996. See "The Royalty Interests -- The Underlying Properties -- Behind Pipe
Production" and " -- Pratt Recompletion Payments."
Unitholders who purchase Units in the offering made hereby and continue to
hold such Units on the applicable record dates will receive, on a quarterly
basis, cash distributions relating to their share of the Subject Gas produced
and sold from and after April 1, 1995, and will be allocated Section 29 tax
credits relating to their share of the Subject Gas produced and sold after April
1, 1995, provided certain requirements are met. For a detailed discussion of the
risks associated with the ability of a Unitholder to use the Section 29 tax
credits, see "Risk Factors -- Tax Considerations" and "Federal Income Tax
Consequences."
As the owner of the Royalty Interests, the Trust is not entitled to receive
a specific quantity of natural gas in-kind. Rather, the Trust is generally
entitled to receive 65 percent of the Gross Proceeds. For a discussion of the
uncertainties associated with estimating reserves, see "Risk Factors -- Risks
Associated with the Oil and Gas Industry -- Reduced Value of Units if Reserve
Estimate is Inaccurate" and "The Royalty Interests -- Reserve Estimate." The
Company will own the Company Interests subject to and burdened by the Royalty
Interests, and is entitled to any proceeds realized from its retained interest
in the Underlying Properties.
THE OFFERING
<TABLE>
<S> <C>
LISTING AND TRADING SYMBOL............................... The Units are listed on the New York Stock Exchange, under the
symbol "DOM."
QUARTERLY CASH DISTRIBUTIONS............................. Unitholders of record on the 60th day following the last day of
each calendar quarter prior to the termination of the Trust (or if
such day is not a business day, the next business day) receive
cash distributions within 70 days following the end of the
calendar quarter generally consisting of the payments received by
the Trust from the production and sale of the Subject Gas during
such calendar quarter (net of Trust cash reserves and expenses).
THE TRUST AND THE TRUSTEE................................ The Trust is a passive entity formed and existing pursuant to a
Trust Agreement, as amended by the Trust Agreement
</TABLE>
5
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<TABLE>
<S> <C>
Amendment (the "Trust Agreement"), among the Company, as grantor,
Dominion Resources, as sponsor, Mellon Bank (DE) National
Association, as Delaware trustee (the "Delaware Trustee"), and
NationsBank of Texas, N.A., as trustee (the "Trustee").
TRUST TERMINATION........................................ The Trust will be terminated 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 (calculated in accordance with criteria
established by the Commission except that it will be based upon a
constant delivered average Contract Price for such prior year and
will use substantially the same methodology and assumptions used
by Ryder Scott in estimating the proved reserves attributable to
the Company Interests in the Reserve Estimate) plus (b) the amount
of all remaining Section 29 tax credits attributable to the
Royalty Interests, is equal to or less than $5.0 million. Upon
such occurrence, the remaining assets of the Trust will be sold,
the proceeds therefrom (after expenses) will be distributed to the
Unitholders and the Trust will be terminated. Although not
required to do so, Dominion Resources or one of its affiliates may
purchase the remaining assets of the Trust. With respect to any
sale of the Royalty Interests, the Trustee first must receive an
opinion of a nationally recognized investment banking firm that
the price paid was at least equal to such assets' fair market
value or that the price is fair from a financial point of view to
the Unitholders.
CONDITIONAL RIGHT OF REPURCHASE.......................... Dominion Resources has the right to repurchase all (but not less
than all) of the outstanding Units from Unitholders at any time
if, at the time of exercise of such right, 15 percent or less of
the outstanding Units is owned by persons or entities other than
Dominion Resources and its affiliates, at a repurchase price
generally 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") that is three New York Stock Exchange trading days prior to
the date on which notice of such exercise is delivered to
Unitholders and (ii) the average closing price of Units on the New
York Stock Exchange for the 30 trading days immediately preceding
the Determination Date.
</TABLE>
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<TABLE>
<S> <C>
THE ROYALTY INTERESTS
GENERAL................................................ The Royalty Interests entitle the Trust to receive 65 percent of
the Gross Proceeds. The Trust has no right to take in-kind its
share of the production of the Subject Gas. The Royalty Interests
are non-operating interests and bear only expenses related to
property, production and related taxes (including severance
taxes). The Trust is paid 65 percent of the Gross Proceeds for
each calendar quarter in arrears on or before the last business
day prior to the 45th day following the end of such calendar
quarter.
GAS PURCHASE AGREEMENT................................. Gas production attributable to the Company Interests is subject to
a Gas Purchase Agreement between the Company and Sonat Marketing,
extending as long as reserves on the Underlying Properties produce
natural gas. Under the terms of the Gas Purchase Agreement, Sonat
Marketing is obligated to purchase at the Central Gathering Point
the Subject Gas for the Contract Price.
OPERATING AGREEMENT.................................... Pursuant to the Operating Agreement dated December 31, 1992, River
Gas operates and maintains the Underlying Properties for the
Company and the other working interest owners of Existing Wells on
the Underlying Properties. The term of the agreement continues
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.
ADMINISTRATIVE SERVICES AGREEMENT...................... Pursuant to the Administrative Services Agreement between the
Trust and Dominion Resources, Dominion Resources provides all
accounting, bookkeeping and other administrative services and
certain reports for the Trust. In consideration of the
satisfactory performance of the services on the part of Dominion
Resources, the Trust agreed to pay Dominion Resources for the
period beginning June 1, 1994 and ending June 30, 1994 and for
each calendar quarter thereafter, throughout the term of the
Trust, the administrative services fee. The administrative
services fee was $25,000 for the period beginning June 1, 1994 and
ending June 30, 1994, was $75,000 per calendar quarter commencing
July 1, 1994 and was, and annually will be, increased by three
percent beginning January 1, 1995. The administrative services fee
will be paid quarterly no later than the 70th day following the
end of each calendar quarter for the services performed during
such calendar quarter.
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 its 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").
</TABLE>
7
<PAGE>
<TABLE>
<S> <C>
All of Dominion Resources' obligations will terminate upon: (i)
termination and cancellation of the Trust, (ii) the sale or other
transfer by the Company of all or substantially all of the
Company's interest in the Underlying Properties subject to the
terms of the Trust Agreement and (iii) the sale or other transfer
of a majority of Dominion Resources' direct or indirect equity
ownership interest in the Company, PROVIDED THAT, with respect to
clauses (ii) and (iii) above, Dominion Resources' obligations will
terminate only if: (a) the transferee has, at the time of the
assignment or transfer, a rating assigned to its outstanding
unsecured long-term debt from Moody's Investors Service of at
least Baa3 or from Standard & Poor's Ratings Group of at least
BBB- (or an equivalent rating from another nationally recognized
statistical rating organization); (b) the transferee (and such of
its affiliates which (1) constitute an "affiliated group" for
federal income tax purposes and (2) have executed guarantees of
such transferee's performance assurance obligations) does not have
a rating assigned to its unsecured long-term debt from a
nationally recognized statistical rating organization and, at the
time of the transfer, has a consolidated net worth (determined in
accordance with generally accepted accounting principles) of not
less than $200 million PROVIDED that such net worth requirement
was reduced by $10 million on January 1, 1995 and will continue to
be reduced on January 1 of each year (PROVIDED, HOWEVER, if such
transferee is an affiliate of Dominion Resources, then Dominion
Resources' obligations shall not terminate until the later of (x)
December 31, 1995 and (y) the date such transferee meets the
requirements set forth in clause (a)) or (c) 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 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.
PRATT RECOMPLETION PAYMENTS.............................. Based on the Reserve Estimate, approximately 12.4 Bcf of natural
gas reserves attributable to the Company Interests and
approximately 8.0 Bcf of natural gas reserves attributable to the
Royalty Interests represent net proved developed nonproducing (or
"behind-pipe") reserves for 248 of the Existing Wells scheduled to
be recompleted to the Pratt coal seam. The Reserve Estimate
assumes that the Company will complete its program to recomplete
such Existing Wells to the Pratt coal seam so that a total of 522
out of a total of 532 Existing Wells would be completed or
recompleted to the Pratt coal seam by October 31, 1996. As of
January 1, 1995, approximately 274 of the Existing Wells had been
completed or recompleted to the Pratt coal seam. The Company will
pay the Trust $1,850 per well per quarter through March 31, 1997
for each well not so recompleted in accordance with the schedule
of recompletions set forth in the Conveyance. In addition, if the
Company fails to recomplete any of the 272 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 to the Royalty Interests' share of the "behind-pipe"
reserves in the Reserve Estimate for each well not so recompleted,
as set forth in the Conveyance. See "The Royalty
Interests -- Pratt Recompletion Payments."
</TABLE>
8
<PAGE>
SUMMARY UNAUDITED PRO FORMA DISTRIBUTABLE CASH AND SECTION 29 TAX CREDITS
Pro forma distributable cash for the year ended December 31, 1994 was $3.05
per Unit assuming formation of the Trust and conveyance of the Royalty Interests
at the beginning of 1994. The pro forma Section 29 tax credit per Unit arising
from the sale of production from the Royalty Interests for the year ended
December 31, 1994 was $1.64. All pro forma financial information assumes cash is
received by the Trust and distributed to Unitholders and Section 29 tax credits
are allocated to Unitholders at the time of production, rather than at the time
such distributions and allocations would actually have been made. To illustrate,
Unitholders will receive four distributions of cash and allocations of Section
29 tax credits during calendar year 1995, the first in March, which includes
cash distributions based upon the Subject Gas sold and an allocation of Section
29 tax credits based on the Subject Gas produced during the fourth quarter of
1994, the second in June consisting of cash distributions and Section 29 tax
credits relating to the Subject Gas sold during the first quarter of 1995, the
third in September consisting of cash distributions and Section 29 tax credits
relating to the Subject Gas sold during the second quarter of 1995, and the
fourth in December consisting of cash distributions and Section 29 tax credits
relating to the Subject Gas sold during the third quarter of 1995. The actual
distribution of cash and allocation of Section 29 tax credits for the Subject
Gas sold during the fourth quarter of 1995 will not be made until March 1996.
See "Federal Income Tax Consequences" and the unaudited Pro Forma Statement of
Distributable Cash of the Trust included elsewhere in this Prospectus.
HYPOTHETICAL 1996 CASH DISTRIBUTIONS AND TAX INFORMATION
Based upon the 1996 production estimates used in the Reserve Estimate, a
hypothetical Contract Price of $1.85 per MMBtu, property, production and related
taxes (including severance taxes) at currently effective rates and estimated
Trust administrative expenses, the hypothetical cash distributions for 1996
would be $2.35 per Unit. See "Hypothetical 1996 Cash Distributions and After-Tax
Returns -- Assumptions and Methodology." Under this hypothetical case and based
upon an assumed purchase price of $18.50 per Unit and a Section 29 tax credit of
approximately $1.05 per MMBtu for 1996 coal seam gas production (1994 Section 29
tax credit of $0.99 per MMBtu increased by estimated inflation of approximately
three percent for each of 1995 and 1996), Dominion Resources estimates that a
purchaser of a Unit in this offering who continues to own that Unit through
December 31, 1996 would recognize a loss for 1996 federal income tax purposes
resulting in a federal income tax benefit of $0.30 per Unit and would be
entitled to a Section 29 tax credit for 1996 totaling $1.46 per Unit. Such
estimates are based upon numerous additional assumptions as described in greater
detail in "Hypothetical 1996 Cash Distributions and After-Tax Returns." THE
ASSUMPTIONS UTILIZED (INCLUDING, WITHOUT LIMITATION, THE $1.85 PER MMBTU
CONTRACT PRICE) IN THE HYPOTHETICAL EXAMPLE SHOULD NOT BE VIEWED AS ESTIMATES OR
PROJECTIONS BY DOMINION RESOURCES. ACTUAL PRICES, COSTS, PRODUCTION AND OTHER
FACTORS COULD DIFFER SIGNIFICANTLY FROM THE ASSUMPTIONS UTILIZED IN THE
HYPOTHETICAL EXAMPLE. WHILE THE INFORMATION UTILIZED FOR PURPOSES OF
ILLUSTRATING THE AMOUNT OF LOSS AND SECTION 29 TAX CREDITS AVAILABLE TO
UNITHOLDERS FOR CALENDAR YEAR 1996 IS DERIVED FROM, AMONG OTHER THINGS,
PRODUCTION ESTIMATES FOR CALENDAR YEAR 1996, THE ACTUAL AMOUNT OF LOSS AND
SECTION 29 TAX CREDITS AVAILABLE TO UNITHOLDERS FOR CALENDAR YEAR 1996 WILL BE
DERIVED FROM ACTUAL PRODUCTION IN THE FOURTH QUARTER OF 1995 AND THE FIRST THREE
QUARTERS OF 1996. BECAUSE ROYALTY PAYMENTS TO THE TRUST WILL BE GENERATED BY
DEPLETING ASSETS, A PORTION OF EACH CASH DISTRIBUTION WILL BE ANALOGOUS TO A
RETURN OF CAPITAL. ACCORDINGLY, CASH RETURNS ATTRIBUTABLE TO THE UNITS ARE
EXPECTED TO DECLINE OVER THE TERM OF THE TRUST.
DOMINION RESOURCES
Dominion Resources was organized in 1983 as a holding company and its
principal assets are its investments in its subsidiaries. Dominion Resources
owns all of the outstanding common stock of Virginia Electric and Power Company
("Virginia Power"), its largest subsidiary. In addition, Dominion Resources owns
all of the outstanding common stock of Dominion Energy, Inc. ("Dominion Energy")
and Dominion Capital, Inc. ("Dominion Capital"). Dominion Energy owns all of the
outstanding common stock of the Company. The Company was formed in 1992 to hold
Dominion Energy's investment in the Underlying Properties.
Virginia Power is a regulated public utility engaged in the generation,
transmission, distribution and sale of electric energy within a
30,000-square-mile area in Virginia and northeastern North Carolina. It
transacts business under the name VIRGINIA POWER in Virginia and under the name
NORTH CAROLINA POWER in North Carolina. Virginia Power sells electricity to
retail customers (including governmental agencies) and to wholesale customers
such as rural electric cooperatives and municipalities. The Virginia service
area comprises about 65 percent of Virginia's total land area but accounts for
over 80 percent of its population.
9
<PAGE>
Dominion Energy is active in a number of partnerships to develop nonutility
electric power generation projects outside the territory served by Virginia
Power. Dominion Energy is involved in projects in six states, as well as
Argentina and Belize, which total approximately 2,031 Mw. Projects in operation
throughout 1994 in which Dominion Energy has an interest include three natural
gas-fueled units totaling 1,290 Mw owned by Enron/Dominion Cogen Corporation,
two geothermal units in California, a waste coal-fueled project in West
Virginia, a solar project in California, four small hydroelectric units in New
York, a wood- and coal-fueled project in Maine, a hydroelectric and a gas-fired
project in Argentina and two gas-fired projects in California. During 1991,
Dominion Energy announced its plans to develop a 25 Mw run-of-river
hydroelectric unit in Belize, which began construction in 1992. This facility is
scheduled to begin commercial operation in the summer of 1995. Dominion Energy
also participates in partnerships to acquire and develop natural gas reserves.
In 1994, it added 82 Bcf of natural gas reserves. Production from Dominion
Energy holdings in 1994 totaled 36 Bcf of natural gas reserves. By the end of
1994, Dominion Energy held 325 Bcf in natural gas reserves.
Dominion Capital provides financial services to Dominion Resources and
other nonutility subsidiaries and also uses its own assets to make equity and
fixed-income investments. In addition, Dominion Capital, through its
wholly-owned subsidiary Dominion Lands, Inc., is involved in joint venture real
estate development projects in Virginia and North Carolina.
Dominion Resources' executive offices are located at 901 East Byrd Street,
Richmond, Virginia 23219, telephone
(804) 775-5700.
RIVER GAS
The River Gas Corporation, an Alabama corporation ("River Gas"), was formed
in November 1987 to develop the Underlying Properties. River Gas has engaged in
coal bed methane well development and operation since that time. It currently
operates 605 coal bed methane wells, 532 in the Black Warrior Basin (all of
which are contained within the Underlying Properties) and 73 in Carbon County,
Utah. Texaco and Dominion Reserves-Utah, Inc., an affiliate of Dominion
Resources, are joint venture partners with River Gas in the joint venture in
Utah.
SUMMARY OF FEDERAL INCOME TAX CONSEQUENCES
THE TAX CONSEQUENCES OF AN INVESTMENT IN UNITS TO A PARTICULAR INVESTOR
WILL DEPEND IN PART ON HIS TAX CIRCUMSTANCES, PARTICULARLY THE ALTERNATIVE
MINIMUM TAX CIRCUMSTANCES. EACH PROSPECTIVE INVESTOR SHOULD CONSULT HIS TAX
ADVISOR ABOUT THE FEDERAL, STATE AND LOCAL TAX CONSEQUENCES OF INVESTING IN
UNITS.
The following is a summary of certain federal income tax consequences of
acquiring, owning, and disposing of Units and is based on the opinions of Baker
& Botts, L.L.P., special counsel to Dominion Resources on oil and gas and
federal income tax matters ("Special Counsel"). For a more detailed discussion
of these consequences and the qualifications to and limitations of the opinions
of Special Counsel and the risks associated with the ability of a Unitholder to
use the Section 29 tax credits, see "Federal Income Tax Consequences " and "Risk
Factors -- Tax Considerations."
<TABLE>
<S> <C>
TAXATION OF THE TRUST.................................... The Trust is not a taxable entity for federal income tax purposes.
TAXATION OF UNITHOLDERS.................................. The income, deductions, and credits of the Trust are reported
directly by the Unitholders based on each Unitholder's taxable
year and method of accounting and without regard to the timing or
amount of distributions from the Trust.
INCOME AND DEDUCTIONS.................................... The income of the Trust consists primarily of a specified share of
the proceeds from the sale of coal seam gas produced from the
Underlying Properties. The Trust may also earn interest income on
any funds being held for distribution or as a reserve. The
deductions of the Trust consist of state taxes and administrative
expenses. In addition, each Unitholder is entitled to amortize the
cost of the Units through cost depletion over the life of the
Royalty Interests (or if greater, through percentage depletion
equal to 15 percent of gross income).
</TABLE>
10
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<TABLE>
<S> <C>
SECTION 29 TAX CREDITS................................... Unitholders are entitled, provided certain requirements are met,
to Section 29 tax credits with respect to natural gas that is
produced from the Existing Wells from currently producing and
behind pipe reserves and the proceeds from the sale of which prior
to 2003 are attributable to the Royalty Interests. The amount of
the credit for 1994 is $0.99 per MMBtu, adjusted for inflation or
deflation subsequent to 1994. (Because the Btu content of each
MMcf of gas from the Existing Wells is approximately 990 MMBtu per
MMcf, the credit is approximately $0.98 per Mcf before
adjustment.)
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 intends to
allocate 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 effect 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.
USE OF CREDITS........................................... The Section 29 tax credits allocable to a Unitholder are allowable
as a dollar-for-dollar reduction of what would otherwise be his
regular federal income tax liability. The credits cannot be used
to reduce his 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. Any amount of tax credit in excess
of a Unitholder's total tax liability for a year is permanently
lost.
UNITHOLDER REPORTING INFORMATION......................... The Trustee will furnish to Unitholders tax information concerning
royalty income, depletion, and the Section 29 tax credits on an
annual basis. Estimated year-end tax information will be furnished
to Unitholders no later than March 15 of the following year. The
Trustee will notify Unitholders in the event the final Section 29
tax credit rate published by the IRS differs materially from the
Trustee's estimate.
TAX SHELTER REGISTRATION................................. The Trust is registered as a tax shelter.
</TABLE>
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RISK FACTORS
RISKS ASSOCIATED WITH THE OIL AND GAS INDUSTRY
REDUCED VALUE OF UNITS IF RESERVE ESTIMATE IS INACCURATE
The value of the Units will be substantially dependent upon the proved
reserves attributable to the Royalty Interests. 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.
There are many uncertainties inherent in estimating quantities and values
of proved reserves and in projecting future rates of production and the amount
and timing of development expenditures. 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, both 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 present values of reserves shown herein were prepared using
guidelines established by the Commission for disclosure of reserves and may not
be representative of the market value of such reserves or the Units. A market
value determination would include many additional factors. For a description of
the procedures used to establish the initial public offering price for the
Units, see "Plan of Distribution" and "Underwriting."
POTENTIALLY REDUCED DISTRIBUTIONS AND RETURNS TO UNITHOLDERS DUE TO VOLATILITY
OF NATURAL GAS PRICES AND PRODUCTION
The Trust's revenues and distributions to Unitholders will be dependent on,
among other things, the sales prices for natural gas produced from the
Underlying Properties and the quantities of natural gas sold. Natural gas prices
have historically been volatile and are likely to continue to be volatile. Such
volatility makes 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 "The Royalty Interests -- Gas Purchase Agreement." The natural
gas prices utilized in preparing the estimates of proved reserves and future net
revenues included in this Prospectus are based upon the Contract Price at
December 31, 1994 of $1.85 per MMBtu, the Minimum Price, through 1998, and $1.70
per MMBtu thereafter. See "The Royalty Interests -- Reserve Estimate."
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 Dominion
Resources. These factors include Btu content, political conditions worldwide,
the price and available quantities of imported oil and natural gas, the price of
residual and distilled fuel oils, the level of consumer product demand, the
severity of weather conditions, government regulations, the price and
availability of alternative fuels and overall economic conditions.
Since early 1980, nationwide natural gas production capacity on occasion
has exceeded demand, which has caused lower prices and periods of cutback or
proration of production. In addition, excess natural gas production capacity in
the United States and Canada generally has resulted in downward pressure on
natural gas prices in recent times. 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.
DISTRIBUTIONS AND RETURNS TO UNITHOLDERS COULD BE REDUCED IF PRODUCTION IS
INTERRUPTED
The value of the Units will be dependent upon the production levels
attributable to the Royalty Interests. There are many uncertainties inherent in
projecting future rates of production, including factors beyond the control of
the producer. Distributions to Unitholders and allocations of tax credits could
be adversely affected if any of the risks typically associated with the
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development, production and transportation of natural gas and the operation of
natural gas producing properties were to occur, including personal injuries,
property damage or damage to productive formations or equipment.
SEASONAL DEMAND MAY CAUSE DISTRIBUTIONS TO VARY SUBSTANTIALLY
Due to the seasonal nature of demand for natural gas and its effect on
natural gas prices, the amount of cash distributions by the Trust may vary
substantially on a seasonal basis. Generally, natural gas prices tend to be
higher during the first and fourth quarters of a calendar year. Because of the
delay between the receipt of revenues related to the Royalty Interests and the
dates on which distributions will be made to Unitholders, however, any
seasonality that affects prices generally should be reflected in distributions
to Unitholders in later periods. See "Description of the Trust
Agreement -- Distributions and Income Computations."
GOVERNMENTAL REGULATIONS COULD REDUCE DISTRIBUTIONS AND RETURNS TO UNITHOLDERS
The operations on the Underlying Properties associated with the production
and sale of natural gas produced from such properties are subject to various
federal, state and local laws and regulations relating to, among other things,
the transportation of natural gas, allowable production and environmental
matters. On January 1, 1993, all federal price controls on the wellhead price of
natural gas were removed. See "The Royalty Interests -- Competition and Markets"
and " -- Regulation of Natural Gas."
Activities on the Underlying Properties are subject to existing federal,
state and local laws, rules and regulations governing health, safety and the
environment. It is anticipated that, absent the occurrence of an extraordinary
event, compliance with existing federal, state and local laws, rules and
regulations governing health and safety will not have a material adverse effect
upon the Trust or Unitholders. However, federal, state and local laws, rules and
regulations regulating environmental matters, such as, for example, water
discharge and wastewater regulations, are constantly changing, and Dominion
Resources cannot predict the effect that any such change to existing laws, rules
and regulations governing environmental matters would have on the distributions
and returns to Unitholders. Dominion Resources cannot predict what effect
additional regulation or legislation, enforcement policies thereunder, or claims
for damages to property, employees, other persons or from operations on the
Underlying Properties could have on the Trust or Unitholders, and such impacts
could be significant.
Alabama regulatory agencies have authority to set the allowable production
levels for natural gas production for the Underlying Properties. Reductions in
allowable production may extend the timing of recovery of reserves. Although
Dominion Resources 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 and may reduce returns attributable to
the Units.
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 and
may accelerate the termination of the Trust. See "The Royalty Interests -- Sale
and Abandonment of Underlying Properties" and "Description of the Trust
Agreement -- Termination and Liquidation of the Trust."
RISKS ASSOCIATED WITH THE UNITS
RESERVES CONSTITUTE DEPLETING ASSETS; CASH DISTRIBUTIONS AND RETURNS TO
UNITHOLDER WILL DECREASE OVER TIME
Payments to the Trust will consist of proceeds from the sale of natural gas
which constitute depleting assets. The reserves attributable to the Underlying
Properties are expected to decline substantially during the term of the Trust
and a portion of each cash distribution made by the Trust will, therefore, be
analogous to a return of capital. As a result, cash distributions and pre- and
after-tax returns attributable to Units will decrease materially over time. For
example, based upon the production estimates set forth in the Reserve Estimate,
annual production attributable to the Company Interests is estimated to decline
from 18.6 Bcf in 1995 to 7.7 Bcf in 2000. See "Hypothetical 1996 Cash
Distributions and After-Tax Returns" and "Description of the Trust
Agreement -- Termination and Liquidation of the Trust."
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TERMS OF THE GAS PURCHASE AGREEMENT LIMIT A UNITHOLDER'S PARTICIPATION IN
INCREASES IN NATURAL GAS PRICES
In formulating the terms of the Gas Purchase Agreement through December 31,
1998 Sonat Marketing agreed to the Minimum Price commitment for natural gas set
forth in the Gas Purchase Agreement in return for a Maximum Price. Therefore,
while the Minimum Price assures a Unitholder a minimum price at which the Base
Quantity of the Subject Gas must be purchased, until January 1, 1999 Unitholders
will not benefit from natural gas prices in excess of $2.63 per MMBtu.
THE TRUSTEE AND THE UNITHOLDERS WILL HAVE NO CONTROL OVER OPERATIONS AND
DEVELOPMENT OF THE UNDERLYING PROPERTIES
Under the terms of the Conveyance, neither the Trustee nor the Unitholders
are able to influence or control the operation or future development of the
Underlying Properties. Unitholders will therefore be reliant on the Company and
the other working interest owners to make all decisions regarding operations on
the Underlying Properties.
The 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 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 "The Royalty Interests -- 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 month's prior written notice to the
other party. The Trust will not be able to appoint or control the appointment of
replacement operators.
OPERATORS OF WELLS WILL NOT OWE A DIRECT DUTY TO UNITHOLDERS
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.
PRODUCTION MAY BE LESS THAN ESTIMATED IN RESERVE ESTIMATE
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 coal
seam reserves in the Black Warrior Basin is the lowering of reservoir pressure
through "dewatering" operations. In a typical coal seam 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. Substantially all
of the Existing Wells have reached their peak production, subject to additional
production that may result from the Pratt coal seam recompletions. Although the
assumptions used to prepare the Reserve Estimate for the Underlying Properties
are based on dewatering history and peak production levels from similar wells
within the Underlying Properties that had already reached their peak production,
no assurances can be given that such assumptions will accurately predict actual
production. In addition, such assumptions are based on the Company's
recompletion by the end of the first quarter of 1997 of 522 Existing Wells to
the Pratt coal seam so that as of such date 522 out of a total of 532 Existing
Wells will be completed or recompleted to the Pratt coal seam (of which
approximately 274 were completed or recompleted as of January 1, 1995), and no
assurance can be given that such recompletions will occur, or if they do occur
that the actual production will be in the amounts set forth in the Reserve
Estimate. Reserves in the Underlying Properties are therefore subject to an
additional risk that actual quantities, peak levels and timing of natural gas
recovery may vary from the estimates included in the Reserve Estimate, and such
levels could be significant. See "The Royalty Interests -- The Underlying
Properties -- Behind Pipe Production" and " -- Water Removal and Disposal."
SUSPENSION OF SONAT MARKETING'S OBLIGATION TO PURCHASE PRODUCTION MAY REDUCE
DISTRIBUTIONS, DEDUCTIONS AND SECTION 29 TAX CREDITS
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
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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.
ADDITIONAL WELLS COULD REDUCE GROSS PROCEEDS ATTRIBUTABLE TO ROYALTY INTERESTS
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. 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 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 owned 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.
NO APPRAISAL OF ROYALTY INTERESTS OR PRIOR MARKET FOR UNITS
The number of Units delivered to Dominion Resources in exchange for the
Royalty Interests and the initial public offering price of the Units in
connection with the initial public offering completed on June 28, 1994 were
determined by negotiation among Dominion Resources and the Underwriters. Among
the factors considered in determining such number of Units and the initial
public offering price in connection with the initial public offering completed
on June 28, 1994, in addition to prevailing market conditions, were the terms of
the Gas Purchase Agreement, current and historical natural gas prices, current
and prospective conditions in the supply and demand for natural gas, estimated
reserve and production quantities attributable to the Royalty Interests, the
financial multiples of publicly-traded securities of comparable entities,
earnings of comparable entities in recent periods, the value of Section 29 tax
credits and the Trust's earnings prospects. None of Dominion Resources, the
Company, the Trust or the Underwriters has obtained any independent appraisal or
other opinion of the value of the Royalty Interests from any investment banking
firm or financial advisor, although Ryder Scott has estimated the reserves
attributable to the Royalty Interests in their report, a summary of which is
attached hereto as Exhibit A.
The Trust was organized by Dominion Resources in order to enable Dominion
Resources to make a public offering of the Units as contemplated hereby.
PAYMENTS TO DOMINION RESOURCES REDUCE DISTRIBUTIONS AND RETURNS TO UNITHOLDERS
Pursuant to the Administrative Services Agreement, Dominion Resources
receives payments for services rendered to the Trust, which payments reduce,
effectively, the amounts available to the Trust for distribution to Unitholders.
Such payment rates were determined by Dominion Resources without the involvement
of any non-affiliated third party. However, Dominion Resources believes that the
payments that it will receive are reasonable in light of the services to be
provided, and that the payment rates are similar to those that could have been
negotiated in each case by non-affiliated parties.
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ROYALTY INTERESTS POSSIBLY SUBJECT TO REJECTION IN BANKRUPTCY OF THE COMPANY
Although the matter is not entirely free from doubt, Alabama counsel has
issued a legal opinion 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 and 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.
UNITHOLDERS MAY LACK LIMITED LIABILITY
Consistent with Delaware law, the Trust Agreement provides that the
Unitholders will have the same limitation on liability as is accorded under the
laws of such state 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.
UNITHOLDERS HAVE LIMITED VOTING RIGHTS
Pursuant to the Delaware Business Trust Act, Unitholders have no voting
rights with respect to the management of the Trust except as provided in the
Trust Agreement. While Unitholders will have certain voting rights pursuant to
the terms of the Trust Agreement, these rights are more limited than those of
stockholders of a corporation. For example, there is no requirement for annual
meetings of Unitholders or for an annual or other periodic reelection of the
Trustee or the Delaware Trustee. In addition, sales and dispositions of the
Royalty Interests may be made without Unitholder approval under certain
circumstances, including 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 of the assets of the Trust. Also, the
Trust may terminate without Unitholder approval. See "Description of the Trust
Agreement -- Termination and Liquidation of the Trust." Unitholders are not
entitled to any rights of appraisal or similar rights in connection with the
termination of the Trust. For a further description of Unitholder voting rights,
see "Description of the Trust Agreement -- Voting Rights of Unitholders."
LIMITED ABILITY OF UNITHOLDERS TO ENFORCE RIGHTS OR INSTITUTE PROCEEDINGS
The Trust Agreement requires under certain circumstances that the Trustee
and the Trust pursue claims against Dominion Resources and the Company with
respect to any breach by Dominion Resources or 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 does not
provide for any procedure allowing Unitholders to direct the Trustee to bring an
action on behalf of the Trust to enforce the Trust's rights under the
Conveyance. Each Unitholder has a statutory right, however, under the Delaware
Business Trust Act 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 rights of the Unitholders to
bring a derivative action on behalf of the Trust under the Delaware Business
Trust Act are substantially similar to the derivative rights afforded to
stockholders of a Delaware corporation under the Delaware General Corporation
Law. See "Description of the Trust Agreement -- Arbitration and Actions by
Unitholders."
DOMINION RESOURCES' CONDITIONAL RIGHT OF REPURCHASE
Dominion Resources retains under 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 are owned by persons or entities other
than Dominion Resources and its affiliates. Any such repurchase would generally
be at a price equal to the greater of (i) the highest price at which Dominion
Resources or any of its affiliates acquired Units during the 90 days immediately
preceding the date (the "Determination Date") that is three New York Stock
Exchange trading days prior to the date on which notice of such exercise is
delivered to Unitholders and (ii) the average closing price of Units on the New
York Stock Exchange 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 "Description of the Trust
Agreement -- Conditional Right of Repurchase."
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:
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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 1999, 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.
ENVIRONMENTAL CONSIDERATIONS
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 and
may accelerate the termination of the Trust. See "The Royalty Interests -- Sale
and Abandonment of Underlying Properties" and " -- The Underlying
Properties -- Water Removal and Disposal" and "Description of the Trust
Agreement -- Termination and Liquidation of the Trust."
TAX CONSIDERATIONS
The principal tax risk is the possibility that a Unitholder will be unable
to use the Section 29 tax credits allocated to him for one or more of the
following reasons:
(a) The Unitholder has insufficient regular tax liability in excess of his
alternative minimum tax liability and other tax credits.
(b) Certain facts and representations upon which Special Counsel has relied
for its opinion prove to be incorrect.
(c) The opinion of Special Counsel proves to be incorrect as to one or more
of the unresolved tax issues that are critical to the use of the
Section 29 tax credit, including the opinion relating to economic
substance.
(d) The Code or regulations are amended in a way that would deny or limit
use of the Section 29 tax credit by the Unitholders.
See "Federal Income Tax Consequences."
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USE OF PROCEEDS
Dominion Resources, as the seller of the Units, will receive all of the net
proceeds from the sale of the Units offered hereby and the Trust will not
receive any proceeds from the offering. Dominion Resources intends to use the
net proceeds received from the offering for general corporate purposes, which
may include the acquisition of oil and natural gas properties.
HYPOTHETICAL 1996 CASH DISTRIBUTIONS AND AFTER-TAX RETURNS
The amount of Trust revenues and cash distributions to Unitholders will be
directly dependent on the sales price for the Subject Gas sold and the volumes
of the Subject Gas produced as described elsewhere in this Prospectus, and other
factors. The following tables within this section demonstrate the hypothetical
effect that changes in the Reserve Estimate's 1996 estimated natural gas
production and the price paid for such production could have on Trust
distributions to a Unitholder who purchases a Unit in the offering made hereby
and holds such Unit through March 1, 1997.
The tables below set forth: (a) the hypothetical annual cash distributions
per Unit for calendar year 1996 on the accrual or production basis; (b) the
resulting hypothetical annual cash distributions per Unit as a percentage of the
purchase price of the Unit ("Hypothetical 1996 Pre-Tax Cash Returns"); and (c)
the resulting hypothetical annual return following the payment of associated
federal income taxes at an assumed individual tax rate of 36 percent
("Hypothetical 1996 After-Tax Returns") based upon (i) the assumption that a
total of 7,850,000 Units are issued and outstanding after the closing of the
offering made hereby, (ii) an assumed purchase price of $18.50 per Unit in the
offering made hereby, (iii) full utilization of Section 29 tax credits, (iv)
various realizations of natural gas production levels as set forth in the
Reserve Estimate, (v) various hypothetical natural gas sales prices, and (vi)
other assumptions described below under " -- Assumptions and Methodology."
After-tax returns to Unitholders may be affected by future tax legislation. The
hypothetical sales prices of natural gas production shown have been chosen
solely for illustrative purposes. See "The Royalty Interests -- Historical
Natural Gas Sales Prices and Production" for historical weighted average sales
prices for natural gas produced from the Underlying Properties.
THE TABLES ARE NOT A PROJECTION OR FORECAST OF THE ACTUAL OR ESTIMATED
RESULTS FROM AN INVESTMENT IN THE UNITS. THE PURPOSE OF THE TABLES IS TO
ILLUSTRATE THE SENSITIVITY OF CASH DISTRIBUTIONS, HYPOTHETICAL PRE-TAX CASH
RETURNS AND HYPOTHETICAL AFTER-TAX RETURNS TO VARIATIONS IN PRODUCTION LEVELS
AND THE PRICE OF NATURAL GAS. NO ASSURANCE IS OR CAN BE PROVIDED THAT THE
ASSUMPTIONS SET FORTH BELOW ARE ENTIRELY ACCURATE OR THAT PRODUCTION LEVELS AND
THE PRICE OF NATURAL GAS WILL NOT DECLINE OR WILL NOT INCREASE BY SOME AMOUNT
OTHER THAN THOSE USED FOR PURPOSES OF THE TABLES.
THE ASSUMED PRICE OF $18.50 PER UNIT HAS BEEN CHOSEN ARBITRARILY BY
DOMINION RESOURCES. THE ACTUAL PRICE, WHICH WILL BE SET FORTH ON THE COVER PAGE
OF THE PROSPECTUS SUPPLEMENT, MAY BE HIGHER OR LOWER THAN THE ASSUMED PRICE. SEE
"PLAN OF DISTRIBUTION" AND "UNDERWRITING."
While the information utilized for purposes of illustrating the
hypothetical cash distributions and Section 29 tax credits available to
Unitholders for calendar year 1996 is derived from, among other things,
production estimates for calendar year 1996, the actual amount of cash
distributions and Section 29 tax credits available to Unitholders for calendar
year 1996 will be derived from actual production in the fourth quarter of 1995
and the first three quarters of 1996. To illustrate, Unitholders will receive
three distributions of cash and three allocations of Section 29 tax credits
during calendar year 1996 from 1996 production, the first in June based upon the
Subject Gas produced and sold between January 1, 1996 and March 31, 1996, the
second in September based upon the Subject Gas produced and sold between April
1, 1996 and June 30, 1996 and the third in December relating to the Subject Gas
produced and sold between July 1, 1996 and September 30, 1996. Unitholders will
also receive in March 1996 a distribution of cash and allocation of Section 29
tax credits relating to the Subject Gas produced and sold between October 1,
1995 and December 31, 1995. The actual distribution of cash and allocation of
Section 29 tax credits for production during the fourth quarter of 1996 will not
be made until March 1997.
A Unitholder's pre-tax and after-tax returns will be affected by numerous
factors, including natural gas prices and quantities of natural gas produced and
sold. See "Risk Factors." The hypothetical amounts demonstrated in the following
tables for 1996 reflect the terms of the Gas Purchase Agreement, including the
Minimum and Maximum Price. Due to the seasonal demand for natural gas, the
amount of quarterly cash distributions from the Trust may vary on a seasonal
basis. Amounts of cash available for distribution to Unitholders will also be
affected by changes in the volumes of natural gas produced. See "Risk
Factors -- Risks Associated with the Oil and Gas Industry -- Potentially
Decreased Distributions and
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Returns to Unitholders Due to Volatility of Natural Gas Prices and Production"
and " -- Reduced Value of Units if Reserve Estimate is Inaccurate" and "The
Royalty Interests -- Gas Purchase Agreement."
BECAUSE OF NATURAL PRODUCTION DECLINES, PRODUCTION ESTIMATES GENERALLY FOR
THE UNDERLYING PROPERTIES SHOW MATERIAL DECREASES IN PRODUCTION FROM YEAR TO
YEAR. AS A RESULT, THE HYPOTHETICAL CASH DISTRIBUTIONS AND RETURNS ATTRIBUTABLE
TO 1996 PRODUCTION ARE NOT INDICATIVE OF RESULTS FOR FUTURE YEARS. IN ADDITION,
BECAUSE PAYMENTS TO THE TRUST AND ASSOCIATED DISTRIBUTIONS TO UNITHOLDERS WILL
BE GENERATED BY DEPLETING ASSETS, A PORTION OF EACH CASH DISTRIBUTION WILL BE
ANALOGOUS TO A RETURN OF CAPITAL. ACCORDINGLY, ANNUAL CASH DISTRIBUTIONS AND
RETURNS ATTRIBUTABLE TO 1996 PRODUCTION ARE EXPECTED TO BE MATERIALLY HIGHER
THAN DISTRIBUTIONS AND RETURNS IN FUTURE YEARS. FOR EXAMPLE, ASSUMING THAT
PRODUCTION AND OTHER ASSUMPTIONS ARE CONSISTENT WITH LEVELS ESTIMATED IN THE
RESERVE ESTIMATE AND FURTHER ASSUMING THAT TRUST ADMINISTRATION COSTS AND OTHER
AMOUNTS REMAIN CONSTANT AS DESCRIBED UNDER " -- ASSUMPTIONS AND METHODOLOGY,"
CASH DISTRIBUTIONS, TAX SAVINGS (LIABILITIES) AND SECTION 29 TAX CREDITS WILL
DECREASE FROM $2.35, $0.30 AND $1.46 PER UNIT IN 1996, RESPECTIVELY, TO $1.32,
$0.05 AND $0.76 PER UNIT IN 2000, RESPECTIVELY. For the reasons described under
"Risk Factors -- Risks Associated with the Oil and Gas Industry -- Reduced Value
of Units if Reserve Estimate is Inaccurate" and elsewhere herein, no assurance
can be given that actual results will not materially vary from projected
results.
ASSUMPTIONS AND METHODOLOGY
THE ASSUMPTIONS DESCRIBED BELOW ON WHICH THE HYPOTHETICAL 1996 CASH
DISTRIBUTIONS AND AFTER-TAX CASH FLOW CALCULATIONS ARE BASED MAY NOT PROVE TO BE
CORRECT AND ARE OUTSIDE THE CONTROL OF THE COMPANY AND THE TRUST. ACTUAL 1996
RESULTS COULD DIFFER MATERIALLY FROM THE HYPOTHETICAL RESULTS REFLECTED BELOW.
The hypothetical 1996 cash distributions and returns set forth in the
following tables reflect estimates of revenues and expenses of the Trust
calculated in accordance with the terms and provisions of the Conveyance and the
Trust Agreement except that calculations were made on an accrual or production
basis rather than the cash basis prescribed by the Conveyance (the differences
between the two bases constitute timing differences, relating to timing of
allocations of Section 29 credits and distributions of cash). The terms of the
Gas Purchase Agreement were taken into account in determining the Hypothetical
Cash Distributions. An assumed purchase price of $18.50 per Unit in the offering
made hereby was utilized in the following hypothetical calculations. In
addition, the following assumptions were made:
NATURAL GAS PRICES. Natural gas prices shown in the following tables are
hypothetical Contract Prices. The price indicated is the gross price received
for natural gas sold and delivered to Sonat Marketing. The Contract Prices for
the last six months of 1994 and for the first three months of 1995 averaged
$1.86 and $1.85 per MMBtu, respectively. See "The Royalty Interests -- Gas
Purchase Agreement." The natural gas prices reflected in the following
hypothetical distribution and return analyses are for illustrative purposes
only. The range of natural gas prices utilized in the following hypotheticals is
intended to illustrate the sensitivity of distributions and returns to different
price levels, and not to indicate any range of natural gas prices expected by
Dominion Resources. Actual natural gas prices could be substantially different
than those covered by the natural gas price range shown for the Contract Price.
BTU ADJUSTMENT. Production from the Underlying Properties is assumed to
have a Btu content of 990 MMBtu per MMcf.
PRODUCTION ESTIMATES. Production attributable to the Company Interests and
the Royalty Interests for 1996 was based on the Reserve Estimate, which
estimates production to be approximately 17.0 Bcf and approximately 11.0 Bcf,
respectively, and which assumes recompletion of 108 wells to the Pratt coal seam
during 1996, included in the Reserve Estimate. See "The Royalty Interests -- The
Underlying Properties -- Behind Pipe Production."
19
<PAGE>
The following graph reflects the estimated annual net production
attributable to the Company Interests.
On this page is a bar graph titled "Production Profile of the Company
Interests." The Chart shows production in billions of cubic feet (Bcf)
and the year associated with such production. The following is a numeric
table of the Company Interests' production:
Production
Year (BCF)
1995 18.6
1996 17.0
1997 15.1
1998 12.5
1999 10.0
2000 7.7
2001 5.7
2002 4.5
2003 2.1
2004 1.4
2005 0.9
2006 0.6
2007 0.4
2008 0.2
20
<PAGE>
Production from the Underlying Properties is generated by depleting assets
and is expected to decline significantly during the term of the Trust.
Production attributable to the Royalty Interests during 2000 is estimated to be
approximately 45 percent of the production estimated for 1996. If such estimated
production is realized in 2000 and if the average prices realized during such
period are the same as those realized during 1996, payments to the Trust and,
therefore, cash distributions paid to Unitholders will be significantly less
than amounts expected to be paid in 1996. Since the Section 29 tax credits are
generated by coal seam gas production, such tax credits will also decline. The
tax credits available for coal seam gas production expire for production sold
after December 31, 2002. Under certain circumstances, the Trust may terminate
even though the coal seam reserves in the Underlying Properties have not been
produced to depletion. See "Description of the Trust -- Termination and
Liquidation of the Trust."
PRODUCTION REALIZATION. The production realization range utilized in the
following hypotheticals is intended to illustrate the sensitivity of cash
distribution and pre- and after-tax returns to different levels of production,
and not to indicate a range of production expected by the Company. Actual
production realization from the Underlying Properties could be substantially
different than that covered by the production realization range shown.
OPERATING AND CAPITAL EXPENSES. The Royalty Interests will bear their
proportionate share of 1996 production, property and related taxes (including
severance taxes) which are assumed to remain at currently effective rates. Lease
operating expenses and capital expenses will not be deducted in calculating
Gross Proceeds.
ADMINISTRATIVE EXPENSES. Trust administrative expenses for 1996 are assumed
to be $530,000 (approximately $0.07 per Unit). See "Description of the Trust
Agreement -- Fees and Expenses." Such expenses include an administrative
services fee of $318,000 payable to Dominion Resources in four installments
during 1996.
TIMING OF ACTUAL DISTRIBUTIONS. Pursuant to the Conveyance, with respect to
the Company's interest in the Underlying Properties, the Trust will receive
payments in respect of each calendar quarter's production on or before the last
business day prior to the 45th day following the end of such calendar quarter in
which the related production takes place, and will make distributions to
Unitholders on or prior to the 70th day following each such calendar quarter.
Since the Trust will make cash distributions quarterly, the hypothetical cash
distributions reflected in the following table effectively represent cash
distributions in respect of estimated 1996 production that would be made from
June 1996 through March 1997.
SECTION 29 TAX CREDITS AND TAX LOSS. Section 29 tax credits in 1996 are
assumed to be approximately $1.05 per MMBtu. Such estimates represent the actual
1994 Section 29 tax credit of $0.99 per MMBtu increased by estimated inflation
for each of 1995 and 1996 of approximately three percent. The actual amount of
Section 29 tax credits and tax losses available to a cash basis Unitholder for
calendar year 1996 federal income tax purposes, however, will be different than
these estimates because 1996 tax amounts will reflect production sold during and
after the fourth quarter of 1995, and before the fourth quarter of 1995.
Different levels of production and other factors also will result in different
amounts of Section 29 tax credits. See "Federal Income Tax Consequences."
DEPLETION DEDUCTIONS. Unitholders are entitled to deductions for depletion.
Subject to certain limitations, Unitholders may use the greater of cost and
percentage depletion (15 percent of gross production income from the property).
Based on an assumed purchase price of $18.50 per Unit in the offering being made
hereby and the proved reserves used in the Reserve Estimate, for 1996
Unitholders are assumed to receive a cost depletion deduction equivalent to
approximately $2.26 per Mcf for their allocated share of production from the
Underlying Properties. Depletion deductions will reduce the tax basis of a
Unitholder in his Units, which will increase the gain (or reduce the loss)
realized upon the disposition of such Units. In order for the Unitholders to
utilize percentage depletion, the price for natural gas sales would have to be
substantially in excess of the prices shown in the above tables. See "Federal
Income Tax Consequences -- The Royalty Interests -- Cost Depletion,"
" -- The Royalty Interests -- Percentage Depletion" and " -- Sale of Units."
21
<PAGE>
THE AMOUNTS SET FORTH IN THE TABLES BELOW ARE NOT NECESSARILY
INDICATIVE OF FUTURE RESULTS
HYPOTHETICAL ANNUAL CASH DISTRIBUTIONS PER UNIT FOR ESTIMATED 1996 PRODUCTION
(A)(F)
<TABLE>
<CAPTION>
AVERAGE CONTRACT PRICE(B)
($ PER MMBTU)
$1.85 $2.00 $2.25 $2.50 $2.63
<S> <C> <C> <C> <C> <C>
PRODUCTION REALIZATION
(% OF RESERVE REPORT ESTIMATE FOR 1996)
90% $2.11 $2.29 $2.58 $2.88 $3.03
95% $2.23 $2.42 $2.73 $3.04 $3.20
100% $2.35 $2.55 $2.88 $3.20 $3.37
105% $2.47 $2.68 $3.02 $3.37 $3.55
110% $2.59 $2.81 $3.17 $3.53 $3.72
</TABLE>
HYPOTHETICAL PRE-TAX CASH RETURNS FOR ESTIMATED 1996 PRODUCTION(A)(C)(D)(F)
<TABLE>
<CAPTION>
AVERAGE CONTRACT PRICE(B)
($ PER MMBTU)
$1.85 $2.00 $2.25 $2.50 $2.63
<S> <C> <C> <C> <C> <C>
PRODUCTION REALIZATION
(% OF RESERVE REPORT ESTIMATE FOR 1996)
90% 11.4 % 12.4 % 14.0 % 15.6 % 16.4 %
95% 12.1 % 13.1 % 14.8 % 16.4 % 17.3 %
100% 12.7 % 13.8 % 15.6 % 17.3 % 18.2 %
105% 13.4 % 14.5 % 16.3 % 18.2 % 19.2 %
110% 14.0 % 15.2 % 17.1 % 19.1 % 20.1 %
</TABLE>
HYPOTHETICAL AFTER-TAX TOTAL RETURNS FOR ESTIMATED 1996 PRODUCTION(A)(D)(E)(F)
<TABLE>
<CAPTION>
AVERAGE CONTRACT PRICE(B)
($ PER MMBTU)
$1.85 $2.00 $2.25 $2.50 $2.63
<S> <C> <C> <C> <C> <C>
PRODUCTION REALIZATION
(% OF RESERVE REPORT ESTIMATE FOR 1996)
90% 20.0 % 20.6 21.6 % 22.6 % 23.2 %
95% 21.1 % 21.8 % 22.8 % 23.9 % 24.5 %
100% 22.2 % 22.9 % 24.0 % 25.2 % 25.8 %
105% 23.4 % 24.1 % 25.3 % 26.4 % 27.1 %
110% 24.5 % 25.2 % 26.5 % 27.7 % 28.4 %
</TABLE>
(FOOTNOTES ON NEXT PAGE)
22
<PAGE>
(a) Cash distributions in respect of estimated 1996 production will be
distributed to Unitholders from June 1996 through March 1997. See
" -- Assumptions and Methodology -- Timing of Actual Distributions."
(b) Natural gas prices shown are hypothetical Contract Prices for natural
gas produced from the Underlying Properties. See " -- Assumptions and
Methodology -- Natural Gas Prices" and "The Royalty Interests -- Gas
Purchase Agreement."
Under the Gas Purchase Agreement, a $1.85 per MMBtu Contract Price in
1996 is equal to the Minimum Price and a $2.63 per MMBtu Contract Price
is equal to the Maximum Price. As a result, gas prices at or lower than
the Minimum Price or at or higher than the Maximum Price during 1996
will not generate cash distributions and returns materially different
than those presented in the tables. See "The Royalty Interests -- Gas
Purchase Agreement."
(c) The amounts reflected in this table are equal to the quotient of the
Hypothetical Annual Cash Distributions per Unit from the preceding
table divided by $18.50 (the assumed purchase price per Unit utilized
in such hypothetical calculations).
(d) The differentials between hypothetical 1996 pre-tax cash returns and
after-tax returns are primarily attributable to the full utilization of
available Section 29 tax credits but also reflect federal tax savings
or federal tax liabilities. See " -- Assumptions and
Methodology -- Section 29 Tax Credits and Tax Loss" and "Federal Income
Tax Consequences."
(e) The amounts reflected in this table are equal to the quotient of (i)
the sum of Hypothetical Annual Cash Distributions per Unit from the
preceding table, plus hypothetical federal tax savings or liability
available per Unit (using an assumed 36 percent federal income tax
rate), and plus hypothetical Section 29 tax credits available per Unit
in respect of estimated production for 1996 divided by (ii) $18.50 (the
assumed purchase price per Unit utilized in such hypothetical
calculations).
(f) A portion of the cash distributions and returns is analogous to a
return of capital. As used herein, "return of capital" means the return
of a Unitholder's original investment in a Unit, such return determined
by the sum of (a) cash distributions received from the Trust in respect
of such Unit plus (b) the effective reduction or increase in federal
income taxes realizable in respect of such Unit by reason of tax losses
or taxable income and Section 29 tax credits plus (c) the net cash
proceeds, if any, received in respect of such Unit upon liquidation of
the Trust or, if the Unit is sold prior to liquidation, the net cash
proceeds received by such Unitholder upon the sale of such Unit. A
portion of each cash distribution and of the allocations of tax losses
or taxable income and Section 29 tax credits made per Unit will
effectively constitute a return of capital, and the remaining portion
of such cash distribution and allocations will effectively constitute a
return on capital (that is, a return on such Unitholder's original
investment). Such portions may be accurately determined only after
termination of a Unitholder's investment in a Unit (either upon sale of
such Unit or upon liquidation of the Trust).
23
<PAGE>
HYPOTHETICAL 1996 AFTER-TAX RETURN CALCULATIONS
(DOLLARS IN THOUSANDS, UNLESS INDICATED OTHERWISE)
The hypothetical returns set forth below are for 1996 only and actual
returns may differ materially from those set forth below. Additionally, cash
returns attributable to the Units are expected to decline over the term of the
Trust and, therefore, in subsequent years may be substantially lower than those
set forth below.
<TABLE>
<S> <C> <C>
HYPOTHETICAL CASH DISTRIBUTIONS
Contract price ($/MMBtu)(a)................................................. $1.85
Less: Btu Adjustment................................................... -0.02
Contract Price ($/Mcf)...................................................... $1.83
Less: Property, Production and Related Taxes ($/Mcf)................... -0.11
Gross Proceeds ($/Mcf)...................................................... $1.72
1996 Estimated Production Attributable to Company Interests (MMcf).......... 16,977
Royalty Interests Percentage........................................... x65%
1996 Estimated Production Attributable to Royalty Interests (MMcf).......... 11,035
Cash Flow Payable to Trust.................................................. $18,980
Less Estimated Trust Administrative Expenses(b)........................ -530
Cash Available for Distribution to Unitholders.............................. $18,450
Number of Units Outstanding (000s)..................................... /7,850
Cash Distribution per Unit (c)(d)........................................... $2.35
HYPOTHETICAL FEDERAL TAX SAVINGS
Cash Available for Distribution to Unitholders.............................. $18,450
1996 Estimated Production Attributable to Royalty Interests (MMcf).......... 11,035
Depletion Rate ($/Mcf)...................................................... x$2.26
Less: Cost Depletion........................................................ -24,939
Taxable Income (Loss)....................................................... ($6,489)
Assumed Federal Income Tax Rate........................................ x 36%
Federal Tax Savings $2,336
Number of Units Outstanding (000s)..................................... 7,850
Tax Savings per Unit (c)(d)................................................. $0.30
HYPOTHETICAL SECTION 29 TAX CREDITS
1996 Estimated Production Attributable to Royalty Interests (MMcf).......... 11,035
1996 Estimated Section 29 Tax Credit ($/MMBtu).............................. $1.05
Less: Btu Adjustment..................................................... -0.01
1996 Estimated Section 29 tax credit ($/Mcf)................................ $1.04
Section 29 tax credits...................................................... $11,476
Number of Units Outstanding(000s)..................................... /7,850
Section 29 tax credits per Unit............................................. $1.46
HYPOTHETICAL PER UNIT SUMMARY ($/UNIT)
Cash Distribution per Unit.................................................. $2.35
Tax Savings per Unit........................................................ 0.30
Section 29 tax credits per Unit............................................. +1.46
After-Tax Return per Unit................................................... $4.11
Cost per Unit (based upon an assumed purchase price of $18.50 per Unit)..... /$18.50
After-Tax Return (c)(d)(e)............................................. 22.2%
</TABLE>
(FOOTNOTES ON NEXT PAGE)
24
<PAGE>
(a) The actual average Contract Price for 1996 could be significantly
different than $1.85 per MMBtu, and the price used herein should not be
viewed as a projection by the Company of the actual price. The average
Contract Prices for the last six months of 1994 and for the first three
months of 1995 were $1.86 and $1.85 per MMBtu, respectively.
(b) Reflects assumed Trust administrative expenses, consisting of $212,000
for ongoing administrative costs and $318,000 in administrative service
fees to Dominion Resources.
(c) A portion of such hypothetical amounts is analogous to a return of
capital. As used herein, "return of capital" means the return of a
Unitholder's original investment in a Unit, such return determined by
the sum of (a) cash distributions received from the Trust in respect of
such Unit plus (b) the effective reduction or increase in federal
income taxes realizable in respect of such Unit by reason of tax losses
or taxable income and Section 29 tax credits plus (c) the net cash
proceeds, if any, received in respect of such Unit upon liquidation of
the Trust or, if the Unit is sold prior to liquidation, the net cash
proceeds received by such Unitholder upon the sale of such Unit. A
portion of each cash distribution and of the allocations of tax losses
or taxable income and Section 29 tax credits made per Unit will
effectively constitute a return of capital, and the remaining portion
of such cash distribution and allocations will effectively constitute a
return on capital (that is, a return on such Unitholder's original
investment). Such portions may be accurately determined only after
termination of a Unitholder's investment in a Unit (either upon sale of
such Unit or upon liquidation of the Trust).
(d) Because payments to the Trust and distributions and allocations of tax
items to Unitholders are subject to certain timing differences, a
portion of the amounts reflected herein will not be distributed or
allocated to Unitholders until 1997. Therefore, if the assumptions
reflected in this hypothetical table are realized during 1996, actual
distributions and allocations received during 1996 would be different
than indicated herein and would relate, in part, to production during
the fourth quarter of 1995. See " -- Assumptions and
Methodology -- Timing of Actual Distributions."
(e) The assumed price of $18.50 per Unit has been chosen arbitrarily by
Dominion Resources. The actual price, which will be set forth on the
cover page of the Prospectus Supplement, may be higher or lower than
the assumed price. See "Plan of Distribution" and "Underwriting." If
the actual purchase price was higher than the assumed purchase price of
$18.50 per Unit, then the after-tax return to the Unitholder would be
lower than 22.2%, and, conversely, if the actual purchase price was
lower than the assumed purchase price of $18.50 per Unit, then the
after-tax return to the Unitholder would be higher than 22.2%. For
example, based on the assumptions set forth above, the following chart
depicts after-tax returns at prices ranging from $17.50 to $19.50:
<TABLE>
<CAPTION>
PRICE
$17.50 $18.00 $18.50 $19.00 $19.50
<S> <C> <C> <C> <C> <C>
After-Tax Return 23.5% 22.8% 22.2% 21.6% 21.1%
</TABLE>
25
<PAGE>
THE ROYALTY INTERESTS
The Royalty Interests conveyed to the Trust entitle the Unitholders to
receive 65 percent of the Gross Proceeds received by the Company Interests Owner
from the sale of the Subject Gas. The Royalty Interests have been conveyed to
the Trust by means of a single instrument of Conveyance. The Conveyance has been
recorded in the appropriate real property records in Alabama, so as to give
notice of the Royalty Interests to creditors and any transferees who will take
an interest in the Underlying Properties subject to the Royalty Interests. The
Conveyance was intended to convey the Royalty Interests as real property
interests under Alabama law.
The following description is subject to and qualified by the more detailed
provisions of the Conveyance and the Trust Agreement included as exhibits to the
Registration Statement of which this Prospectus constitutes a part. Executed
copies of the Conveyance and the Trust Agreement have been delivered to the
Trustee.
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.
On January 1, 1980, the federal government, through the Crude Oil Windfall
Profit Tax Act of 1980, provided tax credits for natural gas produced from
nonconventional fuel sources such as coal seams and made the prospect of
drilling a coal seam gas well in the Black Warrior Basin more economical. The
tax credit encouraged the development of coal seam gas wells. Since June 1986,
over 16 coalbed methane natural gas developments have been initiated in the
Black Warrior Basin and over 4,000 wells have been permitted in the Black
Warrior Basin. The Pottsville coal formation ranges from the surface to a depth
of 4,100 feet, and the deepest Existing Well is 2,600 feet. As of December 31,
1994, cumulative production in the coalbed methane portion of the Black Warrior
Basin was over 500 Bcf. In addition to the Company and River Gas, the other
significant producers in the coalbed methane portion of the Black Warrior Basin
include Taurus Exploration, Inc., Torch Operating Company, Black Warrior
Methane, Chevron USA, Inc., Amoco Production Company and Meridian Oil Inc.
Annual coalbed methane natural gas production in the Black Warrior Basin has
increased from approximately 13 Bcf per annum in 1986 to approximately 110 Bcf
in 1994, and five interstate pipelines provide ready access to markets
throughout the United States. From 1987 through December 31, 1994, cumulative
production attributable to the Company Interests was approximately 108 Bcf of
natural gas.
WELLS. The Royalty Interests have been conveyed by the Company to the Trust
out of the Company Interests. The Existing Wells are operated by River Gas in
accordance with the Operating Agreement. See " -- Operation of Properties."
River Gas has been an owner or operator of the Underlying Properties since
development began in 1987 and is not affiliated with Dominion Resources or any
of its affiliates. The Underlying Properties comprise 34,212 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. The following table sets forth the monthly Gas
production from the Underlying Properties attributable to the Company Interests
during the 27 months from January 1993 to March 1995:
26
<PAGE>
NET MONTHLY PRODUCTION
OF THE COMPANY INTERESTS
JANUARY 1993 TO MARCH 1995
<TABLE>
<CAPTION>
MCF
<S> <C> <C>
1993 January.................................................................................................. 1,771,618
February................................................................................................. 1,625,977
March.................................................................................................... 1,759,833
April.................................................................................................... 1,749,641
May...................................................................................................... 1,805,107
June..................................................................................................... 1,730,699
July..................................................................................................... 1,844,815
August................................................................................................... 1,736,035
September................................................................................................ 1,750,680
October.................................................................................................. 1,830,430
November................................................................................................. 1,758,802
December................................................................................................. 1,810,478
1994 January.................................................................................................. 1,737,628
February................................................................................................. 1,605,416
March.................................................................................................... 1,679,974
April.................................................................................................... 1,680,694
May...................................................................................................... 1,729,333
June..................................................................................................... 1,667,559
July..................................................................................................... 1,715,151
August................................................................................................... 1,702,746
September................................................................................................ 1,636,960
October.................................................................................................. 1,701,788
November................................................................................................. 1,635,549
December................................................................................................. 1,681,441
1995 January.................................................................................................. 1,655,751
February................................................................................................. 1,479,203
March.................................................................................................... 1,648,878
</TABLE>
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>
532 519 34,212 33,391
</TABLE>
BEHIND PIPE PRODUCTION. Production of Gas from Existing Wells has the
potential to be increased through completion of certain of the Existing Wells to
the Pratt coal seam. When the Underlying Properties were first developed, the
initial owners of the Underlying Properties did not believe that it would be
economical to complete wells drilled on the Underlying Properties to the Pratt
coal seam. Later in the development of the Underlying Properties the initial
owners completed 122 wells to the Pratt coal seam. The Company has determined
that it would be economical to recomplete most of the remaining Existing Wells
to the Pratt coal seam. The Company has implemented a program to recomplete
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 as of March 31,
1997, as required under the terms of the Conveyance. The Company will pay the
Trust $1,850 per well per quarter through March 31, 1997 for each well not so
recompleted in accordance with the schedule of recompletions set forth in the
Conveyance. In addition, if the Company fails to recomplete such wells by March
31, 1997, it will be required to pay the Trust an amount equal to the value
attributed to the Royalty Interests' share of the "behind-pipe" reserves in the
Reserve Estimate for each well not so recompleted as set forth in the
Conveyance. As of January 1, 1995, approximately 274 of these wells had been so
completed or recompleted to the Pratt coal seam. Existing Wells penetrate depths
below the Pratt coal seam and to recomplete such wells to the Pratt coal seam,
the well pipe is perforated and the Pratt coal seam is fractured. See " --
Operation of Properties" and " -- Pratt Recompletion Payments."
27
<PAGE>
ROYALTY INTERESTS, COMPANY INTERESTS AND RETAINED INTERESTS. As of April 1,
1995, the Company had an average aggregate working interest in the Existing
Wells of approximately 98 percent. As of April 1, 1995, the Company had 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) are
entitled to approximately 28 percent of the net revenue from the natural gas
produced and sold from the Underlying Properties.
The Royalty Interests conveyed in the Conveyance to the Trust 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. 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 coal seam reserves in the Black Warrior Basin is the
lowering of reservoir pressure through "dewatering" operations. 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. 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 currently producing were producing by mid-1991, the Company believes
that production from the Existing Wells is currently at or near its peak and,
subject to additional production that may result from the Pratt coal seam
recompletions discussed above, will decline over the term of the Trust. See
" -- Behind Pipe Production" and the report of Ryder Scott, a summary of which
is included as Exhibit A to this Prospectus.
Water from the operations on the Underlying Properties is discharged into
the Black Warrior River pursuant to a National Pollutant Discharge Elimination
System permit issued by the Alabama Department of Environmental Management
("ADEM"). ADEM initially issued five permits in connection with the Underlying
Properties which were consolidated into one permit in February 1994, which was
reissued for a five year period beginning in July 1994. The ADEM permit expires
in July 1999 and generally authorizes water disposal based upon the Black
Warrior River's minimum flow rate and maximum chloride level. 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.
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 and
may accelerate the termination of the Trust. The Company estimates that it will
expend approximately $1,000,000 during 1995 for anticipated expenditures related
to compliance with environmental laws. See " -- Sale and Abandonment of
Underlying Properties" and "Description of the Trust Agreement -- Termination
and Liquidation of the Trust."
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 may be 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 "Description of the Trust
Agreement -- Possible Divestiture of Units."
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<PAGE>
COMPUTATION OF THE ROYALTY INTERESTS
COMPUTATION. The Royalty Interests entitle the Trust to receive 65 percent
of the Gross Proceeds (as defined). The term "Gross Proceeds" generally means
the aggregate amounts received by the Company Interests Owner from the sale, at
the Central Gathering Point, of Subject Gas. 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.
PAYMENT. 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 will be computed with respect to each calendar quarter
ending prior to termination of the Trust, and such amounts will be paid to the
Trust not later than the last business day before the 45th day following the end
of each calendar quarter. Under the Trust Agreement, the Trust will make
distributions on or prior to the 70th day following each calendar quarter to
Unitholders of record as of the 60th day following the end of each quarter,
unless such day is not a business day in which case the record date will be the
next business day. The amounts paid to the Trust will 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 will deduct from the payment to the Trust the
Royalty Interests' share of property, production and related taxes (including
severance taxes) and pay the same on behalf of the Trust.
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 and the Company Interests from the Reserve Estimate prepared by Ryder
Scott. All of such reserves constitute proved developed gas reserves. The
Royalty Interests are royalty interests rather than working interests. The
Reserve Estimate was prepared in accordance with criteria established by the
Commission.
<TABLE>
<CAPTION>
ROYALTY INTERESTS COMPANY INTERESTS
<S> <C> <C>
Net Proved Natural Gas Reserves (Bcf)(a)(b)
Developed Producing.......................................... 55.1 84.8
Developed Nonproducing Behind Pipe(c)........................ 8.0 12.4
Total................................................... 63.1 97.2
Estimated Future Net Revenues
(in millions) (a)(d)...................................... $ 105.9 $71.0(e)
Discounted Estimated Future Net Revenues
(in millions) (d)......................................... $ 78.3 $54.8(e)
</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. These prices may
not be the most representative prices for estimating reserves or related
future net revenues data. See "Risk Factors -- Risks Associated with the Oil
and Gas Industry -- Reduced Value of Units if Reserve Estimate is
Inaccurate" and " -- Gas Purchase Agreement."
(b) The natural gas reserves were estimated by Ryder Scott by applying
volumetric and decline curve analyses.
(c) Based upon information provided by the Company, Ryder Scott assumed for
purposes of this estimate that all wells in which developed nonproducing
reserves exist were recompleted to the Pratt coal seam by October 31, 1996.
(d) Estimated future net revenues have been discounted using a 10 percent
discount rate and are defined as the total revenues attributable to the
Company Interests or the Royalty Interests, as applicable, less the relevant
share of production, property and related taxes (including severance taxes).
In the case of the Company Interests, but not the Royalty Interests,
operating and capital costs attributable thereto also have been deducted.
Overhead costs have not been included, nor have the effects of depreciation,
depletion and federal income tax. 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.
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<PAGE>
(e) The future net revenues attributable to the Company Interests are prior to
giving effect to the Royalty Interests and assume the Company Interests bear
its working interest share of the lease operating expenses.
TAX CREDITS BASED ON RESERVES. Based upon the production estimates used in
the Reserve Estimate for the December 31, 1994 through December 31, 2002 period,
and assuming constant future Section 29 tax credits at the 1994 rate of $0.99
per MMBtu, the estimated total future tax credits available from the production
and sale of the net proved reserves from the Company Interests, prior to giving
effect to the Royalty Interests, and the Royalty Interests would be
approximately $90.7 million and $59.0 million, respectively, having a discounted
present value (assuming a 10 percent discount rate) of approximately $68.6
million and $44.6 million, respectively.
REPORTS. Ryder Scott has delivered to the Company a reserve report as of
January 1, 1995, a summary of which is included as Exhibit A to this Prospectus.
MISCELLANEOUS. Information concerning historical changes in net proved
developed reserves attributable to the Company Interests, and the calculation of
the standardized measure of discounted future net revenues related thereto, is
contained in the unaudited supplemental information contained elsewhere in this
Prospectus. Dominion Resources has not filed reserve estimates covering the
Company Interests with any other federal authority or agency.
HISTORICAL NATURAL GAS SALES PRICES AND PRODUCTION
The following table sets forth the actual net production volumes from the
Company Interests, weighted average operating expenses and property, production
and related taxes and information regarding historical natural gas sales prices
for each of the years ended December 31, 1992, 1993 and 1994 and for each of the
three month periods ended March 31, 1994 and 1995 (fiscal year 1992 includes
information regarding interests in the Underlying Properties of the Company's
predecessors in title, which interests the Company acquired in December 1992):
<TABLE>
<CAPTION>
THREE MONTHS
ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
1992 1993 1994 1994 1995
<S> <C> <C> <C> <C> <C>
Production from the Company Interests (Bcf).............. 20.1 21.2 20.2 5.0 4.8
Weighted average operating expenses (dollars per
Mcf)(a)................................................ $0.55 $0.58 $0.64 $0.63 $0.60
Weighted average property, production and related taxes
(dollars per Mcf)...................................... $0.07 $0.08 $0.09 $0.08 $0.07
Weighted average sales price of natural gas produced from
the Company Interests (dollars per Mcf)................ $1.80 $2.09 $1.95 $2.28 $1.81
Pro Forma Average Contract Price (dollars per Mcf)(b).... $1.75 $2.10 $1.96 $2.25 $1.81
</TABLE>
(a) The Royalty Interests are not burdened by operating expenses.
(b) Price at which the Subject Gas would have been sold had the Gas Purchase
Agreement been in effect for the periods specified without giving effect to
the Minimum Price provision prior to June 1, 1994, the date on which the Gas
Purchase Agreement became effective.
GAS PURCHASE AGREEMENT
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
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. In the
case of Subject Gas in excess of the Monthly Base Quantities 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.
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<PAGE>
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, the payment
obligations of Sonat Marketing under the Gas Purchase Agreement are guaranteed
by Sonat. Sonat's guaranty is limited to $10 million in the aggregate.
The Gas Purchase Agreement has been filed as an exhibit to the Registration
Statement of which this Prospectus is a part. 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
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. If
for any reason the Operating Agreement is terminated, the Company reasonably
believes that it can find a suitable replacement to serve as operator for the
Underlying Properties. 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.
The Company believes that River Gas is a competent operator who has in the
past operated the Underlying Properties in accordance with standards expected in
the oil and gas industry. River Gas was formed in November 1987 to develop the
Underlying Properties. River Gas has engaged in coal bed methane well
development and operation since that time. It currently operates 605 coal bed
methane wells, 532 in the Black Warrior Basin (all of which are contained within
the Underlying Properties) and 73 in Carbon County, Utah. Texaco and Dominion
Reserves-Utah, Inc., an affiliate of Dominion Resources, are joint venture
partners with River Gas in the joint venture in Utah.
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.
The Operating Agreement has been filed as an exhibit to the Registration
Statement of which this Prospectus is a part. 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.
CONVEYANCE. The Conveyance provides INTER ALIA 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
will not be 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 will 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 will not 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 required 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."
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<PAGE>
(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 "Description of the Trust
Agreement -- 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 the Registration Statement
of which this Prospectus is a part. The foregoing summary of such Conveyance is
qualified in its entirety by reference to the terms thereof as set forth in such
exhibit.
PRATT RECOMPLETION PAYMENTS
Based on the Reserve Estimate, approximately 12.4 Bcf of natural gas
reserves attributable to the Company Interests and approximately 8.0 Bcf of
natural gas reserves attributable to the Royalty Interests represent net proved
developed nonproducing (or "behind-pipe") reserves for 248 of the Existing Wells
scheduled to be recompleted to the Pratt coal seam. The Reserve Estimate assumes
that the Company completes its program to recomplete Existing Wells to the Pratt
coal seam so that a total of 522 out of a total of 532 Existing Wells would be
completed or recompleted to the Pratt coal seam as of October 31, 1996. As of
January 1, 1995, approximately 274 of the Existing Wells had been completed or
recompleted to the Pratt coal seam. The Company will pay the Trust $1,850 per
well per quarter through March 31, 1997 for each well not so recompleted in
accordance with the schedule of recompletions set forth in the Conveyance. In
addition, if the Company fails to recomplete any of the 248 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 to the Royalty
Interests' share of the "behind-pipe" reserves in the Reserve Estimate for each
well not so recompleted, as set forth in the Conveyance.
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).
Unitholders will not 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 "Description of the Trust Agreement -- Termination and Liquidation of the
Trust."
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 is 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
issued a legal opinion 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 and the Company will record
the Conveyance in the appropriate real property records of Alabama, in
accordance with local recordation provisions. The Conveyance has been recorded
in accordance therewith. 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
32
<PAGE>
as real property interests under the laws of Alabama. See "Risk Factors -- Risks
Associated with Units -- Royalty Interests Possibly Subject to Rejection in
Bankruptcy of the Company."
COMPETITION AND MARKETS
The natural gas industry is highly competitive in all of its phases. The
Company will encounter competition from major oil and gas companies, independent
oil and gas concerns, and individual oil and gas producers and operators. Many
of these competitors may 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.
The supply of natural gas capable of being produced in the United States
has exceeded demand in recent years as a result of decreased demand for natural
gas in response to economic factors, conservation, lower prices for alternative
energy sources and other factors. As a result of this relationship of supply of
and demand from excess supply of natural gas, natural gas producers have
experienced increased competitive pressure and significantly lower prices. Due
to the restructuring of the industry over the last five years and the producers'
method of marketing their natural gas production, caused mainly by the Federal
Energy Regulatory Commission ("FERC") regulations, minimal volumes of natural
gas are sold to pipelines. Instead, natural gas is sold by producers directly to
users or marketing companies.
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. In view of the many uncertainties affecting the supply and demand for
natural gas, the Company is unable to make reliable predictions of future
natural gas prices and demand or the overall effect they will have on the Trust.
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. The United States has governmental power to
impose pollution control measures.
FEDERAL REGULATION OF NATURAL GAS WELLHEAD SALES. 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.
FEDERAL REGULATION OF NATURAL GAS TRANSPORTATION. The transportation of
natural gas in interstate commerce is subject to federal regulation by 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.
In 1992, FERC issued Order Nos. 636 and 636-A 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 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.
LEGISLATIVE PROPOSALS. 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.
STATE REGULATION. Many state jurisdictions have at times imposed
limitations on the production of natural gas by restricting the rate of flow for
natural gas wells below their actual capacity to produce and by imposing acreage
limitations for the drilling of a well. States may also impose additional
regulation of these matters. 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
33
<PAGE>
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.
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. They require the
acquisition of certain permits and they impose substantial liabilities for
pollution resulting from exploration and production operations. Such laws and
regulations may also restrict air or other pollution resulting from operations.
Historically, state and federal environmental laws and regulations have become
more stringent over time. The Company cannot predict what 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 " -- Sale and Abandonment of
Underlying Properties" and "Description of the Trust Agreement -- Termination
and Liquidation of the Trust."
FEDERAL INCOME TAX CONSEQUENCES
This section discusses the material federal income tax matters relevant to
individual citizens or residents of the United States who acquire Units, but it
does not describe the actual tax effect that any of such matters will have on a
particular investor in light of his tax status and his other income, deductions,
and credits. Except where noted, the conclusions have limited application to
domestic corporations; to persons subject to specialized federal income tax
treatment, such as Individual Retirement Accounts and other Section 501(a)
organizations ("Tax Exempt Entities"), regulated investment companies, and
insurance companies; and to persons who are not citizens or residents of the
United States.
Unless otherwise expressly stated, the legal conclusions contained in this
section are the opinions of Baker & Botts, L.L.P., special counsel to Dominion
Resources on oil and gas and federal income tax matters ("Special Counsel"). The
section is addressed to investors who acquire Units pursuant to the offering or
during the period that a copy of the Prospectus is required to be delivered to
purchasers of Units. The opinions are based on current law (which could be
changed by Congress, the Treasury Department, or the courts) and rely upon the
accuracy of the facts and representations contained in this Prospectus. Unless
otherwise indicated, section references are to the Code; regulatory references
are to the regulations thereunder; and "tax" means federal income tax.
No IRS rulings have been requested (other than as described in " -- The
Royalty Interests -- Basis Allocation"), and there is a risk the IRS might
dispute one or more of the recited facts and representations upon which Special
Counsel relies or one or more of its legal conclusions. In such event,
litigation may be required, with its attendant costs and risks. In addition, any
such dispute might also result in the IRS's auditing other income, deductions,
and credits of the Unitholder.
IN LIGHT OF THE FOREGOING, EACH PROSPECTIVE INVESTOR IS ADVISED TO CONSULT
A TAX ADVISOR BEFORE PURCHASING UNITS.
PRINCIPAL TAX ISSUES.
In order for a Unitholder to achieve substantially all of the contemplated
tax benefits of Unit ownership, the following propositions must be true for tax
purposes:
(a) The Unitholder's ownership of the Units has economic substance.
(b) The Trust is classified as a trust and not a corporation.
(c) The Royalty Interests are nonoperating economic interests.
(d) The Gas produced from the Existing Wells and sold prior to 2003
otherwise qualifies for the tax credit provided in Section 29.
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<PAGE>
In the succeeding parts of this section, Special Counsel opines favorably
on each of the above propositions, subject to certain expressed qualifications.
A Unitholder, however, is entitled to use the Section 29 tax credits only if he
is the owner of the Units at the time the coal seam gas is produced and only to
the extent that he has sufficient regular tax liability in excess of his
alternative minimum tax liability. See " -- Timing and Allocation Issues" and
" -- Limitations on Use of Section 29 Tax Credit."
ECONOMIC SUBSTANCE
GENERAL RULE. A taxpayer is entitled to claim deductions and credits ("tax
benefits") attributable to an investment only if the investment has economic
substance. In most cases, an investment has economic substance only if the
investor has at least an actual and honest objective of making a profit apart
from the tax benefits associated with the activity, and perhaps only if such
objective is reasonable or primary or both ("Pre-Tax Profit Objective"). Such a
conclusion is based on a judicial perception that Congress generally does not
intend tax benefits to be used to encourage activities that are inherently
unprofitable apart from the tax benefits. In commercial transactions, the
requirement of a Pre-Tax Profit Objective is usually, if not always, invoked in
situations in which the taxpayer is very likely to realize an economic loss but
is very unlikely to realize an economic loss in excess of the tax benefits.
Neither such congressional intent nor such facts are present here.
SECTION 29 AND PROFIT POTENTIAL. In the present case, the Unitholder's
realization of profit or loss before or after tax, and the amount of either, is
dependent on the volume and rate of production, the market price for natural gas
within an extended range over a number of years, the market price of the Units
from time to time, and other economic factors. Equally important, both the
statutory language and the legislative history indicate that the purpose of the
Section 29 tax credit is to provide the producers of alternative fuels with the
equivalent of a "price subsidy" or "guaranteed price floor" in order to
encourage their continued development and production even when low market prices
would otherwise make such production uneconomic. In other contexts, the IRS has
recognized the price subsidy purpose of Section 29, but it has not published
regulations or a revenue ruling which holds that a purchaser of an economic
interest in natural gas subject to Section 29 need not have a Pre-Tax Profit
Objective; and no court has addressed the issue. If the IRS were to hold that a
Pre-Tax Profit Objective is required, and a court were to sustain this position,
an investor who had no Pre-Tax Profit Objective would not be entitled to any
Section 29 tax credits or to any depletion deductions for a year in excess of
the royalty income for such year.
OPINION. Because Special Counsel cannot know a Unitholder's actual intent
and because the possibility of a pre-tax profit is dependent on economic facts
over a long period of time that cannot be predicted with certainty, Special
Counsel can express no view whether any Unitholder has a Pre-Tax Profit
Objective. However, although the issue has not been definitively resolved and
the proposition that a Unitholder must have a Pre-Tax Profit Objective cannot be
dismissed as frivolous, Special Counsel is of the opinion that the ownership of
Units that are not subject to puts, calls, or other risk allocation devices has
economic substance even if the owner has no Pre-Tax Profit Objective.
CLASSIFICATION OF THE TRUST
OPINION. The Trust is a trust for tax purposes and not a corporation
because neither the Trustee nor the Unitholders will have the power to vary the
investment of the Trust or otherwise to cause the Trust to engage in business.
For purposes of the foregoing, the ownership of the Royalty Interests is not
engaging in business; and the power to sell the Royalty Interests is not a power
to vary the investment so long as the sale proceeds and all other Trust receipts
in excess of Trust expenses cannot be reinvested and must be distributed to the
Unitholders. Moreover, because the Company is the grantor and initial
beneficiary of the Trust and the Unitholders are assignees of the Company, the
Trust is a grantor trust under existing IRS rulings. As so classified, the Trust
is not subject to tax, and the Unitholders PRO RATA are deemed to own undivided
interests in the assets of the Trust, subject to its liabilities.
CONSEQUENCES OF CORPORATE CLASSIFICATION. If, contrary to the opinion of
Special Counsel, the Trust were determined to be taxable as a corporation, the
Trust would be subject to the normal corporate tax on its taxable income without
any reduction for distributions to Unitholders, and the taxes paid by the Trust
would reduce the amount of distributions to the Unitholders. More importantly,
Unitholders would not be entitled to any income, deductions, or credits of the
Trust; and distributions from the Trust in respect of a Unit would be taxable as
dividends to the extent of a proportionate share of the Trust's current and
accumulated earnings and profits, as a tax-free return of capital to the extent
of the Unitholder's basis in the Unit, and as capital gain to the extent of any
excess.
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TAX REPORTING BY TRUST AND UNITHOLDERS
TRUST REPORTS. The Trustee has stated that the Trust files an information
return reporting all items that must be included in the tax return of
Unitholders. The Trustee furnishes to Unitholders of record the necessary
information to permit computation of their taxable income from ownership of
Units. Each Unitholder receives a tax booklet containing the information
necessary to compute federal and state taxable income, deductions, and credits
attributable to their Units. In addition, if an investor holds his Units of
record in his name, then the information provided by the Trustee may also
include individualized tax information for such investor. See "Description of
the Trust Agreement -- Periodic Reports."
TYPES OF TAX ITEMS. The taxable items included in the Trust report consist
primarily of royalty income, depletion, and the Section 29 tax credit
attributable to the Royalty Interests. See " -- The Royalty Interests -- Royalty
Payments," " -- Cost Depletion" and " -- Percentage Depletion" and " -- Section
29 Tax Credits." The only other income of the Trust is expected to be interest
income earned on funds held as a reserve or until the next distribution date.
Other expenses of the Trust will include state and local taxes imposed on the
Trust or Unitholders and administrative expenses of the Trustee. Such expenses
may be classified as "miscellaneous itemized deductions" under Section 67(a) of
the Code, which are allowable as deductions only to the extent that the
aggregate of such deductions exceed two percent of adjusted gross income. The
more likely conclusion, however, is that the Trust expenses qualify under
Section 62(a)(4) of the Code as deductions attributable to property held for the
production of royalties, which are above-the-line deductions that are not
subject to the two percent limit. Reg. 1.67-1T(a) and (b).
UNITHOLDER REPORTING. Each Unitholder is required to take into account his
proportionate share of the income, deductions and credits of the Trust based on
his accounting method and taxable year without regard to the accounting method
or taxable year of the Trust and without regard to the timing or amount of
distributions from the Trust. See " -- Timing and Allocation Issues."
THE ROYALTY INTERESTS
CLASSIFICATION. Each Royalty Interest is a nonoperating economic interest
in an Underlying Property because it is a right to a fixed percentage of the
gross proceeds from the sale of gas as, if, and when produced from such
properties, the right endures for the economic life of the burdened reserves,
and the right is not required to bear any cost in developing or producing such
gas. The conclusion that each Royalty Interest endures for the life of the
burdened reserves is not altered by the Trustee's obligation to sell the Royalty
Interests for their fair market value when the revenues decline to the point
that continued ownership by the Trust is no longer feasible.
ROYALTY PAYMENTS. All amounts payable with respect to the Royalty Interests
will be ordinary income that qualifies for the greater of cost or percentage
depletion, subject to the following:
NON-DEVELOPMENT PENALTY PAYMENTS. Any quarterly payment made to
the Trust because the Company delays in recompleting the Existing
Wells to the Pratt coal seam will probably constitute ordinary income
that is not subject to depletion or other amortization and that does
not give rise to any Section 29 tax credit. A final lump sum payment
that is made because the Company fails to complete such wells by March
31, 1997 will not constitute royalty income or give rise to any
Section 29 tax credit, but no opinion is expressed whether such
payment will be treated for tax purposes as ordinary income, capital
gain, an adjustment in the purchase price, or a combination of the
foregoing. Any portion not treated as income or capital gain will
reduce a Unitholder's basis in the Royalty Interests and the Units.
ADVANCE PAYMENTS. Any payment to the Trust in respect of any take
or pay provision, advance payment, production payment, or other amount
not based on the actual production and sale of gas may be included in
income when received or when the gas is produced depending upon the
circumstances, but such payment will not in any event give rise to the
Section 29 tax credit until the Gas is produced and sold.
BASIS ALLOCATION. The IRS has granted the Trust's request to treat the
Royalty Interests as a single property for basis allocation and depletion
purposes. Therefore, no allocation of basis will be required unless either the
Trustee holds cash reserves that were accumulated before a Unitholder acquires
his Units and are not distributable to a prior owner of the Units, or unless the
IRS challenges the Trustee's quarterly allocation of income. See " -- Timing and
Allocation Issues."
COST DEPLETION. Cost depletion may be computed for a period by multiplying
the Unitholder's depletable basis in the property at the beginning of such
period by the depletion rate. The depletion rate for a period is the percentage
obtained by dividing the units of natural gas attributable to the property that
are sold during such period by the sum of such natural gas
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and the additional natural gas estimated to be recovered and sold from such
property in the future. The Trustee will furnish each Unitholder of record with
the appropriate depletion rate for the Royalty Interests, but the Unitholder
must maintain the records reflecting his depletable basis.
PERCENTAGE DEPLETION. A Unitholder's cost depletion will exceed percentage
depletion, at least for a number of years and in the absence of a substantial
increase in the market price of gas or subsequent increases in natural gas
reserves. Percentage depletion is generally available only to persons who are
defined in the Code as independent producers (generally persons who are not
substantial refiners or retailers of oil or natural gas or their primary
products) and, as to each, is allowable only on oil or natural gas produced
during a year to the extent that the average daily production does not exceed
1,000 barrels per day (treating 6,000 cubic feet of natural gas as one barrel).
Because of the quantity limitation, the acquisition of a Unit may reduce a
Unitholder's right to percentage depletion on other oil and gas properties even
if percentage depletion is not claimed in respect of the Royalty Interests.
Percentage depletion for coal seam gas production is equal to 15 percent of the
Unitholder's gross production income. Percentage depletion is limited to 100
percent of the taxpayer's taxable income from the property, computed without
regard to depletion deductions and certain other deductions, and to 65 percent
of the taxpayer's taxable income for the year, before percentage depletion and
certain loss carrybacks. Unlike cost depletion, percentage depletion is not
limited to the adjusted tax basis of the property, although it reduces that
adjusted tax basis (but not below zero).
SECTION 29 TAX CREDITS
CREDIT GAS. For purposes of Section 29, Unitholders PRO RATA are allocated
65% of the coal seam gas that but for the creation of the Royalty Interests
would have been allocated to the Company Interests. Each Unitholder is entitled
to the tax credit allowed by Section 29 with respect to his share of the coal
seam gas produced from the Existing Wells and sold prior to 2003 ("Credit Gas"),
subject to the following:
(a) The persons to whom the natural gas is sold must be unrelated to the
Unitholder claiming the Section 29 tax credit.
(b) The Existing Well cannot be producing natural gas from a property from
which coal seam gas was being produced in marketable quantities before 1980
("Ineligible Property"). Property for this purpose is not defined by the Code;
no regulations have been issued; and no other authority provides clear guidance.
In a series of private letter rulings, however, the IRS has treated each
proration unit for a well as a separate property. Under this standard, no
Existing Well is producing from an Ineligible Property. Even if regulations
adopt a more expansive definition, it is unlikely that many, if any, of the
Existing Wells would be deemed to be producing from an Ineligible Property.
(c) Natural gas attributable to a Royalty Interest will not be Credit Gas
if the natural gas is produced from a well that is drilled to replace an
Existing Well, is attributable through unitization to wells other than the
Existing Wells or is attributable to a deposit below the level at which an
Existing Well was completed before 1993 and is penetrated after 1993 by
deepening the well. However, natural gas attributable to a coal seam gas deposit
that was penetrated by an Existing Well before 1993 qualifies as Credit Gas even
though the Existing Well is not recompleted to produce natural gas from such
deposit until after 1993. Gas produced from the Pratt coal seam as a result of
the recompletion of the Existing Wells will qualify as Credit Gas. See "The
Royalty Interests -- The Underlying Properties -- Behind Pipe Production."
CREDIT AMOUNT. The Section 29 tax credit for each year is a specified
amount for each 5.8 million Btu of Credit Gas that is sold during such year,
subject to reduction or elimination if the "reference price" for oil for such
year is above a specified amount for such year. (The annual reference price for
a year is the Treasury Department's estimate of the average wellhead price per
barrel for all domestic crude oil produced in that year, which estimate is made
by April 1 of the immediately succeeding year.) For 1994,
(a) the Section 29 tax credit for Credit Gas was $5.76 per 5.8 million Btu
(I.E., $0.99 per MMBtu);
(b) the reference price was $13.19 per barrel;
(c) the reference price at which a reduction in the credit would have
commenced was $45.14 per barrel; and
(d) the reference price at which the credit would be completely eliminated
was $56.66 per barrel.
The Company believes that the Btu content of the production attributable to the
Underlying Properties is approximately 990 MMBtu per MMcf, resulting in a 1994
tax credit for that production of $0.98 per Mcf. The amount of credit and the
reference price for Credit Gas will be further adjusted in 1995 and subsequent
years for inflation (or deflation).
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LIMITATIONS ON USE OF SECTION 29 TAX CREDIT
INSUFFICIENT TOTAL TAX LIABILITY. If the amount of a Unitholder's Section
29 tax credit for a year exceeds his total tax liability for such year, the
excess credit cannot be carried backward or forward to any other year.
INSUFFICIENT REGULAR TAX LIABILITY. Section 55 of the Code imposes a
minimum tax (known as an "alternative minimum tax" or "AMT"), currently at 26
percent to 28 percent, on a taxpayer to the extent that his "tentative minimum
tax" in any taxable year exceeds his regular tax for that year. For purposes of
computing his tentative minimum tax, a taxpayer's taxable income is recomputed
with various "adjustments" plus "items of tax preference." The Section 29 tax
credits allowable to a Unitholder for any taxable year cannot exceed the excess
of his regular tax liability for such taxable year, as reduced by his foreign
tax credits and certain nonrefundable credits, over his "tentative minimum tax"
liability for that year. Any amount of Section 29 tax credit disallowed for a
tax year solely because of this limitation will be available in a subsequent
year to reduce his regular tax liability but not his AMT liability.
TIMING AND ALLOCATION ISSUES
QUARTERLY ALLOCATIONS. The Trust allocates income received and deductions
paid during each calendar quarter to Unitholders of record on the record date
for such quarter and allocates to such Unitholders the credits attributable to
the production giving rise to such income rather than to the production
occurring during such quarter. Generally, the amount of net income allocable to
Unitholders for a quarter is the same as the amount of cash distributed for such
quarter. In certain circumstances, however, Unitholders for a quarter will not
receive the cash giving rise to the net income realized during a quarter. For
example, if the Trustee establishes or increases a reserve or borrows money to
satisfy liabilities of the Trust, income associated with the cash used to
establish or increase that reserve or to repay that liability must be reported
by the Unitholders of record, even though that cash is not distributed until a
later date.
NO OPINION. Special Counsel does not know whether the IRS will accept
quarterly allocations or will 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. If the IRS were to require credits to be
allocable to the persons owning Units at the time the gas is produced, the
credits allocable to a Unitholder for one or two record dates immediately after
he acquires a Unit would be decreased and the credits allocable to a Unitholder
for one or two record dates immediately after he disposes of such Unit would be
increased. An IRS challenge, however, would have a cumulative adverse effect
only for Unitholders who do not own Units for a full quarter, particularly
Unitholders who acquire Units shortly before a record date and sell shortly
after a record date.
SALE OF UNITS
Generally, a Unitholder will realize gain or loss on the sale of a Unit
measured by the difference between the amount realized on the sale and the
Unitholder's basis in the Unit. A Unitholder who purchases a Unit will have a
basis in the Unit equal to the amount paid, less depletion or other amortization
deduction thereafter allowable with respect to the Unit. However, if the Trust
establishes a cash reserve (other than cash distributable to a predecessor
Unitholder) or incurs liabilities, the Unitholder's Unit basis will be decreased
by the cash reserve balance at the time of purchase and increased by the Trust
liabilities in existence at the time of purchase, and the amount realized on
sale will be increased by the amount of Trust liabilities in existence at the
time of sale and decreased by the cash reserve at the time of sale. Moreover,
the IRS may contend that a portion of the sale proceeds is allocable to royalty
income that has accrued to the Trust at the time of the sale. Any gain on the
sale of Units will be treated as ordinary income to the extent of any depletion
deductions taken by the seller. The remaining gain and any loss by a Unitholder
who is not a dealer with respect to such Units will be capital gain or loss.
Special rules exist in the case of charitable and noncharitable gifts and
tax-free exchanges, as to which a Unitholder should consult a tax adviser.
SALE OF ROYALTY INTERESTS
A sale by the Trust of the Royalty Interests will be treated for federal
income tax purposes as a sale of Royalty Interests by the Unitholders. Thus, a
Unitholder will recognize gain or loss on a sale of the Royalty Interests by the
Trust in substantially the same manner as if the Unitholder had sold his Units.
NON-PASSIVE ACTIVITY INCOME, CREDITS AND LOSS
The income, credits, and expenses of the Trust are not taken into account
in computing a Unitholder's passive activity losses and income. Any tax losses
and Section 29 tax credits generated by an investment in the Units can therefore
be utilized
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to offset regular tax liability on income from any source, whether active or
passive, subject to the limitations discussed in this section.
UNRELATED BUSINESS TAXABLE INCOME
Tax Exempt Entities are subject to tax on certain types of business income
defined as unrelated business taxable income ("UBTI"). The income of the Trust
will not be UBTI so long as the Units are not "debt-financed property" within
the meaning of Section 514(b) of the Code. In general, a Unit would be
debt-financed if the Unitholder incurs debt to acquire a Unit or otherwise
incurs or maintains a debt that would not have been incurred or maintained if
such Unit had not been acquired. Legislative proposals have been made from time
to time which, if adopted, would result in the treatment of income attributable
to the Royalty Interests as UBTI.
TAXATION OF FOREIGN HOLDERS
ELECTION. Unitholders who are nonresident alien individuals or foreign
corporations ("Foreign holders") may elect under Section 871 or 882 of the Code
or similar provisions of applicable treaties to treat income attributable to the
Royalty Interests as income that is effectively connected with the conduct of a
United States business ("U.S. Business Election"). In such event, the Foreign
holder will be taxed at regular rates on the net income attributable to the
Royalty Interests (including gain recognized on the disposition of Units).
Absent a treaty exception, such net income of a corporate Foreign holder will
also be subject to the "branch profits tax" imposed under Section 884 of the
Code. To claim the deductions allowable in computing net income, including cost
depletion, an electing Foreign holder will have to file a United States income
tax return. The U.S. Business Election once made is irrevocable (unless an
applicable treaty allows the election to be made annually) and is applicable to
all income and gain realized by the Foreign holder with respect to any real
property interests located in the United States (including those interests held
through partnerships, fixed investment trusts and other pass-through entities).
Even if a U.S. Business Election is made, interest attributable to a Unit will
be treated as periodical income that is subject to federal income tax and to
withholding at a 30 percent rate (or any lower rate permitted by an applicable
treaty).
NO ELECTION. If no U.S. Business Election is made, a Foreign holder's share
of gross royalty income, without any deductions, will be treated as periodical
income subject to the 30 percent tax, but gain realized on a sale of a Unit will
not be subject to federal income tax unless (i) the gain is otherwise
effectively connected with business conducted by the Foreign holder in the
United States; (ii) the Foreign holder is an individual who is present in the
United States for more than 183 days in the year of the sale; (iii) the Foreign
holder owns more than a 5 percent interest in the Trust; or (iv) the Units cease
to be regularly traded on an established securities exchange. Gain realized by a
Foreign holder upon the sale by the Trust of all or any part of the Royalty
Interest would be subject to United States tax. The Section 29 tax credit is not
allowable as a credit against withholding tax.
BACKUP WITHHOLDING
Distributions of Trust income may be subject to "backup withholding" under
Section 3406 of the Code at a rate of 31 percent if Unitholders fail to furnish
certain information to the Trustee, including their taxpayer identification
number, or otherwise fail to establish an exemption from such provision. Amounts
deducted and withheld from a distribution to a Unitholder would be allowed as a
credit against such Unitholder's federal income tax.
TAX SHELTER REGISTRATION
Section 6111 of the Code requires a tax shelter organizer to register a
"tax shelter" with the IRS by the first day on which interests in the tax
shelter are offered for sale. Because it is possible that the Trust meets the
regulatory definition of tax shelter contained in the regulations, the Trust is
registered as a tax shelter with the IRS. A Unitholder who sells or otherwise
transfers a Unit in a subsequent transaction must furnish the tax shelter
registration number to the transferee. The penalty for failure of the transferor
of a Unit to furnish such tax shelter registration number to a transferee is
$100 for each such failure. It is anticipated that the Trustee will furnish the
tax shelter registration number to transferees. Unitholders must disclose the
tax shelter registration number of the Trust on Form 8271 to be attached to the
tax return on which any deduction, loss, credit or other benefit generated by
the Trust is claimed or income of the Trust is included. A Unitholder who fails
to disclose the tax shelter registration number on his return, without
reasonable cause for such failure, will be subject to a $50 penalty for each
such failure. (Any penalties discussed herein are not deductible for income tax
purpose.)
ISSUANCE OF A TAX SHELTER REGISTRATION NUMBER DOES NOT INDICATE THIS
INVESTMENT OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED
BY THE IRS.
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SIGNIFICANT TAX BENEFITS
Based upon the representations and assumptions set forth in this
Prospectus, Special Counsel is of the opinion that the federal income tax
benefits described that are a significant feature of an investment in the Units
will more likely than not, in the aggregate, be realized by Unitholders.
Utilization of such tax benefits is subject to a number of limitations, however,
as described in this discussion of federal income tax consequences.
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
the 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."
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 advisor 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 this Prospectus and on a private letter ruling issued
June 10, 1994 by the Alabama Department of Revenue as to this offering, Tanner &
Guin, P.C., special Alabama tax counsel, is of the opinion that the Trust will
not be 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 does not
believe, based on the above representations and assumptions, that such
circumstances exist
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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.
ERISA CONSIDERATIONS
The Employee Retirement Income Security Act of 1974, as amended ("ERISA"),
imposes certain requirements on pension, profit-sharing and other employee
benefit plans to which it applies ("Plans"), and contains standards applicable
to those persons who are fiduciaries with respect to such Plans. In addition,
under the Code, there are similar requirements and standards which are
applicable to certain Plans and individual retirement accounts (whether or not
subject to ERISA) (collectively, together with Plans subject to ERISA, referred
to herein as "Qualified Plans").
A fiduciary of a Qualified Plan should carefully consider fiduciary
standards under ERISA regarding the Qualified Plan's particular circumstances
before authorizing an investment in Units. A fiduciary should first consider (i)
whether the investment satisfies the prudence requirements of Section
404(a)(l)(B) of ERISA; (ii) whether the investment satisfies the diversification
requirements of Section 404(a)(l)(C) of ERISA; and (iii) whether the investment
is in accordance with the documents and instruments governing the Qualified Plan
as required by Section 404(a)(l)(D) of ERISA.
In order to avoid the application of certain penalties, a fiduciary must
also consider whether the acquisition of Units and/or operation of the Trust
might result in direct or indirect nonexempt prohibited transactions under
Section 406 of ERISA and Section 4975 of the Code. In determining whether there
are such prohibited transactions, a fiduciary must determine the "plan assets"
involved in the transaction. On November 13, 1986, the Department of Labor
published final regulations (the "DOL Regulations") concerning whether a
Qualified Plan's assets (such as a Unit) would be deemed to include an interest
in the underlying assets of an entity (such as the Trust) for purposes of the
reporting, disclosure and fiduciary responsibility provisions of ERISA and
analogous provisions of the Code, if the Qualified Plan acquires an "equity
interest" in such entity. The DOL Regulations provide that the underlying assets
of an entity will not be considered "plan assets" if the interests in the entity
are publicly offered. Units are considered to be "publicly offered" for this
purpose if they are part of a class of securities that is (i) widely held (I.E.,
owned by 100 or more independent investors); (ii) freely transferable; and (iii)
registered under Section 12(b) or 12(g) of the Exchange Act or sold to the
Qualified Plan as part of an offering of securities to the public pursuant to an
effective registration statement under the Securities Act and the class of
securities of which such security is a part is registered under the Exchange Act
within 120 days (or such later time as may be allowed by the Commission) after
the end of the fiscal year of the issuer during which the offering of such
securities to the public occurred. Although no assurances can be given, it is
expected that all of these requirements will be satisfied with respect to Units
offered hereunder and that the assets of a Qualified Plan that invests in the
Trust will include the Units but not an interest in the underlying assets of the
Trust. Fiduciaries, however, will need to determine whether the acquisition of
Units is a nonexempt prohibited transaction under the general requirements of
ERISA Section 406 and Section 4975 of the Code.
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.
DESCRIPTION OF THE TRUST AGREEMENT
The following information is subject to the detailed provisions of the
Trust Agreement and the Conveyance. Copies of the Trust Agreement and the
Conveyance have been filed as exhibits to the Registration Statement of which
this Prospectus is a part. Although the material provisions of the Trust
Agreement are described herein, 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.
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CREATION AND ORGANIZATION OF THE TRUST
On June 28, 1994, the Company conveyed the Royalty Interests to the Trust
in consideration for the issuance by the Trust of 7,850,000 Units which were
distributed indirectly as a dividend to Dominion Resources. While holding Units,
Dominion Resources will have an interest in the Trust and rights identical to
the other Unitholders. Units constitute undivided beneficial interests in the
assets of the Trust.
The Trust has been formed under Delaware law pursuant to the terms of the
Trust Agreement to acquire and hold the Royalty Interests for the benefit of the
Unitholders. 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 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. 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
interest in any of the Underlying Properties. However, the Company has retained
an interest in each of the Underlying Properties. The Company may sell the
Company Interests subject to and burdened by the Royalty Interests and, absent
certain conditions having been met, with the continuing benefit of Dominion
Resources' assurances and the Gas Purchase Agreement. For a description of the
Underlying Properties, the Company Interests and other information relating to
such properties, see "The Royalty Interests."
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 behalf of the Trust to enforce the Trust's rights under the
Conveyance. Each Unitholder has a statutory right, however, under the Delaware
Business Trust Act 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 Delaware Trustee and the 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 $20,000,000, in the case of
the Delaware Trustee, and $100,000,000, in the case of the Trustee. See
" -- Fees and Expenses -- Compensation of the Trustee and the Transfer Agent."
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. See "The Royalty Interests."
DUTIES AND LIMITED POWERS OF THE TRUSTEE
Under the Trust Agreement, the Trustee receives the payments attributable
to the Royalty Interests and pays 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 to pay expenses, liabilities and obligations that cannot
be paid out of cash held by the Trust. The Trustee is entitled to cause the
Trust to borrow 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 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
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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 Trustee is authorized and directed to sell and convey the Royalty
Interests without Unitholder approval upon termination 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 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 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 accounts payable on demand, 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.
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.
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The terms of the Trust Agreement seek to assure to the extent practicable
that gross income attributable to cash being distributed 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, if the Trustee establishes a reserve or borrows money to satisfy debts
and liabilities of the Trust, income associated with the cash used to establish
that reserve or to repay that loan must be reported by the Unitholder, even
though that cash is not distributed to him.
TRANSFER OF ROYALTY INTERESTS
Upon termination of the Trust, any remaining Royalty Interests will be sold
by the Trust and any such sales may be made to Dominion Resources or its
affiliates. See " -- Termination and Liquidation of the Trust."
POSSIBLE DIVESTITURE OF UNITS
The Trust Agreement imposes no restrictions based on nationality or other
status of Unitholders. The Trust Agreement provides, however, that in the event
of certain judicial or administrative proceedings seeking the cancellation or
forfeiture of any property in which the Trust has an interest, or asserting the
invalidity of, or otherwise challenging any portion of the Royalty Interests
because of the nationality, citizenship or any other status of any one or more
Unitholders, the Trustee will give written notice thereof to each Unitholder
whose nationality, citizenship or other status is an issue in the proceeding,
which notice will constitute a demand that such Unitholder dispose of his Units
within 30 days. If any Unitholder fails to dispose of his Units in accordance
with such notice, the Trustee shall 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) as of December 31 of 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 Contract Price on such 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
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 will include 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 have the right
during reasonable business hours upon reasonable prior notice to examine and
inspect records of the Trust and the Trustee and the Delaware Trustee.
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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 in number of the then 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 such meetings shall be
held in Dallas, Texas and written notice of every such meeting setting forth the
time and place of the meeting and the matters proposed to be acted upon shall 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 shall 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. Unitholders have the right to vote at all meetings of Unitholders and
each Unitholder shall be 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 shall 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 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 shall 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 " -- Termination
and Liquidation of the Trust," all other actions may be approved by a majority
vote of the Units represented at a meeting at which a quorum is present or
represented.
UNITS ELIGIBLE FOR FUTURE SALE
On June 28, 1994, the Company conveyed the Royalty Interests to the Trust
in exchange for 7,850,000 Units which were distributed indirectly as a dividend
to Dominion Resources. Of such 7,850,000 Units, 6,850,000 were sold pursuant to
an underwritten public offering on June 28, 1994, an additional 54,000 Units
were sold in August 1994 pursuant to a 45-day over-allotment option and up to
946,000 may be sold by Dominion Resources pursuant to one or more Prospectus
Supplements. See "Plan of Distribution.".
No prediction can be made as to the effect, if any, that market sales of
Units or the availability of Units for sale will have on the market price of the
Units prevailing from time to time. Nevertheless, if Dominion Resources does not
sell all of the
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946,000 Units pursuant to the offering described in a Prospectus Supplement, any
sales by Dominion Resources of any such unsold Units in the public market could
adversely affect prevailing market prices.
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 will 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) termination
and cancellation of the Trust, (ii) the sale or other transfer by the Company of
all or substantially all of the Company's interest in the Underlying Properties
subject to the terms of the Trust Agreement and (iii) the sale or other transfer
of a majority of Dominion Resources' direct or indirect equity ownership
interest in the Company, PROVIDED THAT, with respect to clauses (ii) and (iii)
above, Dominion Resources' obligations will terminate only if: (a) the
transferee has, at the time of the assignment or transfer, a rating assigned to
its outstanding unsecured long-term debt from Moody's Investors Service of at
least Baa3 or from Standard & Poor's Ratings Group of at least BBB- (or an
equivalent rating from another nationally recognized statistical rating
organization); (b) the transferee (and such of its affiliates which (1)
constitute an "affiliated group" for federal income tax purposes and (2) have
executed guarantees of such transferee's performance assurance obligations) does
not have a rating assigned to its unsecured long-term debt from a nationally
recognized statistical rating organization and, at the time of the transfer, has
a consolidated net worth (determined in accordance with generally accepted
accounting principles) of not less than $200 million PROVIDED that such net
worth requirement shall be reduced by $10 million on January 1 of each year
commencing January 1, 1995 (PROVIDED, HOWEVER, if such transferee is an
affiliate of Dominion Resources, then Dominion Resources' obligations shall not
terminate until the later of (x) December 31, 1995 and (y) the date such
transferee meets the requirements set forth in clause (a)) or (c) 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.
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
trustee's fees and accounting, engineering, legal and other professional fees
and the administrative services fee paid to Dominion Resources. However, as
discussed under "Federal Income Tax Consequences," if a court were to hold that
the Trust is taxable as a corporation, then the Trust would incur substantial
federal income tax liabilities.
In reliance upon the representations and assumptions set forth in this
Prospectus and on a private letter ruling issued June 10, 1994 by the Alabama
Department of Revenue as to this offering, Tanner & Guin, P.C., special Alabama
tax counsel, is of the opinion that the Trust will not be 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 does 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.
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,
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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) will be
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
will be 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 shall
be entitled to indemnification from Unitholders (except in connection with lost
or destroyed Unit certificates). Insofar as indemnification for liabilities
arising under the Securities Act may be permitted to the Trustee pursuant to the
foregoing provisions, the Trustee has been informed that in the opinion of the
Commission such indemnification is against public policy as expressed in the
Securities Act and is therefore unenforceable.
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 the
laws of such state 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.
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 (calculated in accordance with criteria established by the
Commission except that it will be based upon a constant delivered average
Contract Price for such prior year and it will use substantially the same
methodology and assumptions used by Ryder Scott in estimating the proved
reserves attributable to the Company Interests in the Reserve Estimate) plus (b)
the amount of all remaining Section 29 tax credits attributable to the Royalty
Interests, is equal to or less than $5.0 million. Upon such occurrence, the
remaining assets of the Trust will be sold, the proceeds therefrom (after
expenses) 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
(as defined in the Trust Agreement) to sell any remaining Royalty Interests 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 then owned by the Trust. The Company has the right, but not the
obligation, to purchase all remaining Royalty Interests following termination of
the Trust as described in the following paragraph.
The Company may, within 60 days following the Termination Date, 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 best efforts (as defined in the Trust Agreement), assisted by the Advisor,
to locate other buyers for the Royalty Interests. At the end of a 120-day period
following the Termination Date, the Trustee is required to notify the Company of
the highest of any other offers acceptable to the Trustee (which must be an all
cash offer) received during such period (the "Highest Acceptable Offer"). The
Company then has the right (whether or not it made an initial offer), but not
the obligation, to purchase all remaining Royalty Interests for a cash purchase
price computed as follows: (i) if the Highest Acceptable Offer is more than 105
percent of the Company's original offer (or if the Company did not make an
initial offer), the purchase price will be 105 percent of the Highest Acceptable
Offer, or (ii) if the Highest Acceptable Offer is equal to or less than 105
percent of the Company's original offer, the purchase price will be equal to the
Highest Acceptable Offer. If no other acceptable offers are received for all
remaining
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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, 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. Unitholders are not
entitled to any rights of appraisal or similar rights in connection with the
termination of the Trust.
CONDITIONAL RIGHT OF REPURCHASE
Dominion Resources and any of its successor and affiliates will retain 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 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 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 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 shall 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 shall
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 shall have been 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.
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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).
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 finally, conclusively and exclusively 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 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 Business Trust Act (the "Delaware Code") to bring a
derivative action. Pursuant to the Trust Agreement and Section 3816 of the
Delaware Code, a derivative action in the right of the Trust may be brought by a
Unitholder in the Delaware Court of Chancery against Dominion Resources or the
Company (or any other person) to recover a judgment in favor of the Trust if the
Trustee has refused to bring such action or if an effort to cause the Trustee to
bring such action is not likely to succeed.
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
plaintiff to remit to the Trust the remainder thereof. If the proceeds are
insufficient to reimburse plaintiff's reasonable expenses in bringing the
derivative action, the Delaware Chancery Court may direct that any such award of
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 any deficiency in
the Payment Obligations 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.
49
<PAGE>
FEES AND EXPENSES
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
affiliates.
ONGOING ADMINISTRATIVE EXPENSES. The Trust will be 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, 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 fees and expenses of legal counsel
for the Trustee and the Trust incurred by or at the direction of the Trustee and
the out-of-pocket expenses of the Transfer Agent. The total of all Trust
administrative expenses is anticipated to aggregate approximately $200,000 on an
annual basis. Such costs could be greater or less depending on future events
(including changes in inflation indices) that cannot be predicted. In addition,
the Trust paid (or reimbursed Dominion Resources for), out of the first cash
payment received by the Trust, the Trustee's legal expenses incurred in forming
the Trust and the Trustee's acceptance fees estimated to total approximately
$115,000 and approximately $185,000 for recording fees relating to the filing of
the Conveyance in Alabama.
COMPENSATION OF THE TRUSTEE AND THE TRANSFER AGENT. Dominion Resources has
paid to the Trustee an acceptance fee of $15,000 which was reimbursed to
Dominion Resources by the Trust. The Trust Agreement provides that the Trustee
will 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 will be compensated for its administrative services, in an annual amount
of $5,000 which will be paid by the Trustee. Each of the Trustee and the
Delaware Trustee is entitled to reimbursement for out-of-pocket expenses. Upon
termination of the Trust, the Trustee will receive, in addition to its
out-of-pocket expenses, a termination fee in the amount of $10,000. If the
Trustee resigns and a successor has not been appointed in accordance with the
terms of the Trust Agreement within 210 days after the notice of resignation is
received, the fee payable to the Trustee will increase significantly until a new
trustee is appointed. The Transfer Agent receives a transfer agency fee of $3.25
annually per account, plus $1.50 for each certificate issued and $.40 for each
check issued (minimum of $7,200 annually).
FEES TO DOMINION RESOURCES. Pursuant to an Administrative Services
Agreement between Dominion Resources and the Trust, the Trust is obligated,
throughout the term of the Trust, to pay to Dominion Resources each calendar
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 increases annually by three percent beginning January 1,
1995. Such annual fee was determined by Dominion Resources on the basis of the
value of the services to be provided by Dominion Resources to the Trust, and
Dominion Resources believes that such fee is not substantially more or less
favorable to the Trust than the fee which the Trust would have been required to
pay to a party unaffiliated with Dominion Resources for the provision of such
services.
TRANSFER AGENT
Mellon Securities Trust Company will serve as transfer agent and registrar
for the Units.
PLAN OF DISTRIBUTION
The Units offered hereby may be offered at prices and on terms to be
determined at the time of sale and to be set forth in a Prospectus Supplement.
The Units may be sold for public offering to underwriters or dealers, which may
be a group of underwriters represented by one or more managing underwriters,
which may include Lehman Brothers Inc. or Wheat, First Securities, Inc., or
through such firms or other firms acting alone or through dealers. The Units may
also be sold through agents to investors. The names of any agents, dealers or
managing underwriters, and of any underwriters, involved in the sale of the
Units in respect of which this Prospectus is being delivered and the applicable
agent's commission, dealer's purchase price or underwriter's discount will be
set forth in the Prospectus Supplement. The net proceeds to Dominion Resources
from such sale will also be set forth in the Prospectus Supplement. Any
underwriters, dealers or agents participating in the offering of Units may be
deemed "underwriters" within the meaning of the Securities Act.
Any underwriting compensation paid by the Company to underwriters or agents
in connection with the offering of Units and any discounts, concessions or
commissions allowed by underwriters to participating dealers will be set forth
in the Prospectus Supplement. Underwriters, dealers and agents participating in
the distribution of the Units may be deemed to be
50
<PAGE>
underwriters, and any discounts and commissions received by them and any profit
realized by them on resale of the Units may be deemed to be underwriting
discounts and commissions under the Securities Act.
Dominion Resources may sell Units from time to time on the New York Stock
Exchange, in the over-the-counter market, on any other national securities
exchange on which the Units are listed or traded, in negotiated transactions or
otherwise, at prices then prevailing or related to the then current market price
or at negotiated prices. Such Units may be sold directly or through brokers or
dealers, or in a distribution by one or more underwriters, which may include
Lehman Brothers Inc. or Wheat, First Securities, Inc. on a firm commitment or
best efforts basis. The methods by which such Units may be sold include (i) a
block trade (which may involve crosses) in which the broker or dealer so engaged
will attempt to sell the securities as agent but may position and resell a
portion of the block as principal to facilitate the transaction; (ii) purchases
by a broker or dealer as principal and resales by such broker or dealer for its
account pursuant to this Prospectus; (iii) exchange distributions and/or
secondary distributions in accordance with the rules of the New York Stock
Exchange; (iv) ordinary brokerage transactions and transactions in which the
broker solicits purchasers; and (v) privately-negotiated transactions. Dominion
Resources and any broker-dealers participating in the distribution of such Units
may be deemed to be "underwriters" within the meaning of the Securities Act and
any profit on the sale of such Units and any commissions received by any such
broker-dealers may be deemed to be underwriting commissions under the Securities
Act. There is no assurance that Dominion Resources will sell any or all of the
Units offered by it. No prediction can be made as to the effect that market
sales of Units, or the availability of Units for sale, will have on the market
price prevailing from time to time. The availability for sale, or actual sales,
of substantial amounts of Units in the public market could adversely affect
prevailing market prices. All such sales by Dominion Resources will be made
pursuant to an effective registration statement under the Securities Act, or an
exemption from such registration.
The Units are listed on the New York Stock Exchange under the symbol "DOM."
If an underwriter or underwriters are utilized in the sale of the Units,
Dominion Resources will execute an underwriting agreement with such underwriter
or underwriters at the time an agreement for such sale is reached. The
underwriter or underwriters with respect to an underwritten offering of Units
will be set forth in the Prospectus Supplement relating to such offering and, if
an underwriting syndicate is used, the managing underwriter or underwriters will
be set forth on the cover of such Prospectus Supplement. If any underwriter or
underwriters are utilized in the sale of the Units, the underwriting agreement
will provide that the obligations of the underwriters are subject to certain
conditions precedent and that the underwriters with respect to a sale of Units
will be obligated to purchase all such Units if any are purchased. In connection
with the sale of Units, underwriters may be deemed to have received compensation
from the Company in the form of underwriting discounts or commissions and may
also receive commissions from purchasers of Units for whom they may act as
agent. Underwriters may sell Units to or through dealers, and such dealers may
receive compensation in the form of discounts, concessions or commissions from
the underwriters and/or commissions from the purchasers for whom they may act as
agent. Under such underwriting agreements, underwriters, dealers and agents who
participate in the distribution of the Units, may be entitled to indemnification
by Dominion Resources against certain civil liabilities, including liabilities
under the Securities Act or contribution with respect to payments which the
underwriters, dealers or agents may be required to make in respect thereof.
Certain of the underwriters or agents and their associates may be customers
of, engage in transactions with and perform services for, Dominion Resources and
its subsidiaries in the ordinary course of business and for which they receive
customary compensation.
VALIDITY OF THE UNITS
The validity of the Units are being passed upon by Hunton & Williams,
Richmond, Virginia, as counsel for the Trust, the Company and Dominion
Resources, and certain matters described under the caption "Federal Income Tax
Consequences" are being passed upon by Baker & Botts, L.L.P., Houston, Texas, as
special counsel for the Trust, the Company and Dominion Resources, and certain
matters described under the caption "State Tax Considerations" are being passed
upon by Tanner & Guin, P.C., Tuscaloosa, Alabama, as special Alabama tax counsel
to the Company and Dominion Resources. Certain legal matters will be passed upon
for the Underwriters by McGuire, Woods, Battle & Boothe, L.L.P., Richmond,
Virginia, who also perform certain legal services for Dominion Resources and its
affiliates on other matters.
EXPERTS
Certain information appearing in this Prospectus regarding the estimated
quantities of reserves of the Company Interests and the Royalty Interests, the
pre-tax future net revenues from such reserves and the present value thereof is
based on
51
<PAGE>
estimates of such reserves and present values prepared by or derived from
estimates prepared by Ryder Scott Company Petroleum Engineers, independent
petroleum engineers.
The statements of revenues and direct operating expenses of Dominion Black
Warrior Basin, Inc.'s Interests in the Underlying Properties for the years ended
December 31, 1994, 1993, and 1992 and the statement of assets, liabilities and
trust corpus of the Dominion Resources Black Warrior Trust as of December 31,
1994 and the related statements of distributable income and changes in trust
corpus for period May 31, 1994 (date of inception) to December 31, 1994 included
in this Prospectus have been audited by Deloitte & Touche LLP, independent
auditors, as stated in their reports appearing herein and are included in
reliance upon the reports of such firm given upon their authority as experts in
accounting and auditing.
The financial statements and related financial statement schedules
incorporated in this Prospectus by reference from Dominion Resources, Inc.'s
Annual Report on Form 10-K for the year ended December 31, 1994 and from the
Trust's Annual Report on Form 10-K for the year ended December 31, 1994 have
each been audited by Deloitte & Touche LLP, independent auditors, as stated in
their reports, which are incorporated herein by reference, and have been so
incorporated in reliance upon the reports of such firm given upon their
authority as experts in accounting and auditing.
52
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL POSITION AND RESULTS OF OPERATIONS
THE COMPANY INTERESTS IN THE UNDERLYING PROPERTIES
THREE MONTHS ENDED MARCH 31, 1994 COMPARED WITH THREE MONTHS ENDED MARCH 31,
1995
The excess of revenues over direct operating expenses in 1994 was
$7,872,000 compared to $5,446,000 in 1995. This decrease can be primarily
attributed to decreased revenues due to lower natural gas prices and lower
production partially offset by lower lease operating expenses. Production
decreased by 5 percent which decreased revenues by $533,000. Natural gas prices
decreased by 21 percent from $2.28 per Mcf in 1994 to $1.81 per Mcf in 1995
which decreased revenues by $2,248,000.
Direct operating expenses and taxes were $3,562,000 in 1994 compared to
$3,207,000 in 1995. The $355,000 decrease was primarily due to lower costs
associated with the purchase of previously leased compression and the lower cost
of compressor fuel gas. Direct operating expenses per Mcf decreased by six
percent from $0.71 per Mcf in 1994 to $0.67 per Mcf in 1995.
YEAR ENDED DECEMBER 31, 1993 COMPARED WITH YEAR ENDED DECEMBER 31, 1994
The excess of revenues over direct operating expenses in 1993 was
$30,396,000 compared to $24,553,000 in 1994. This decrease can be primarily
attributed to decreased revenues due to lower production and natural gas prices
and by higher lease operating expenses. Production decreased by 5 percent which
decreased revenues by $2,135,000. Natural gas prices decreased by 7 percent from
$2.09 per Mcf in 1993 to $1.95 per Mcf in 1994 which decreased revenues by
$2,824,000.
Direct operating expenses and taxes were $13,964,000 in 1993 compared to
$14,848,000 in 1994. The $884,000 increase was primarily due to higher
production taxes and compressor fuel. Direct operating expenses per Mcf
increased by 11 percent from $0.66 per Mcf in 1993 to $0.73 per Mcf in 1994.
YEAR ENDED DECEMBER 31, 1992 COMPARED WITH YEAR ENDED DECEMBER 31, 1993
The excess of revenues over direct operating expenses in 1992 was
$23,665,000 compared to $30,396,000 in 1993. This increase can be primarily
attributed to increased revenues due to higher natural gas prices and production
partially offset by higher lease operating expenses. Production increased by
five percent which increased revenues by $1,980,000. Natural gas prices
increased by over 16 percent from $1.80 per Mcf in 1992 to $2.09 per Mcf in 1993
which increased revenues by $6,235,000.
Direct operating expenses and taxes were $12,480,000 in 1992 compared to
$13,964,000 in 1993. The $1,484,000 increase was primarily due to higher costs
associated with the increase in production (I.E. production taxes, compression,
fuel, etc.). Direct operating expenses per Mcf increased by six percent from
$0.62 per Mcf in 1992 to $0.66 per Mcf in 1993.
THE TRUST'S ROYALTY INTERESTS
THREE MONTHS ENDED MARCH 31, 1995
The Trust was initially created by the filing of a Certificate of Trust
with the Secretary of State of Delaware on May 31, 1994. Accordingly, there are
no financial results of the Trust for the three months ended March 31, 1994.
The Trust received royalty income amounting to $5,608,705 during the first
quarter of 1995. This revenue was derived from the receipt of cash on production
of 3,261 MMcf at an average price received of $1.81 per Mcf after deducting
production taxes of $294,563. Administrative expenses during the period amounted
to $105,780. These expenses are primarily related to administrative services
provided by Dominion Resources and the Trustee and the Delaware Trustee during
the period. These transactions resulted in distributable income for the first
quarter of 1995 of $5,517,607, or $0.70 per Unit. The Trust made a distribution
on March 10, 1995 of $5,433,121, or $0.69 per Unit.
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 Interests' allocable share of
property,
53
<PAGE>
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 the Delaware Trustee 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 $0.93 per Unit. The Trust
made two distributions during the period aggregating $7,116,317, or $0.91 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 $135,000 for the payment
of expenses and liabilities of the Trust. The quarterly distribution made in the
third quarter of 1994 was reduced by the amount of this reserve in accordance
with the provisions of the Trust Agreement. The Trust anticipates that it will
maintain for the foreseeable future a cash reserve to enable it to pay
administrative expenses as they become due. The amount of the cash reserve from
time to time will fluctuate as expenses are paid and royalty income is received.
Royalty income received by the Trust in a given calendar year will
generally reflect the proceeds from the sale of gas produced from the Underlying
Properties during the first three quarters of that year and the fourth quarter
of the preceding calendar year due to the timing of the receipt of these
revenues. The conveyance of the Royalty Interests to the Trust was effective
June 1, 1994. Accordingly, the royalty income included in distributable income
for the period ended December 31, 1994, was based on production volumes and
natural gas prices for the period from June 1, 1994 to September 30, 1994, in
accordance with the terms of the conveyance of the Royalty Interests to the
Trust.
The following table sets forth the production volumes attributable to the
Trust's Royalty Interests and the average sales price and Index Price for such
production for the period indicated.
<TABLE>
<CAPTION>
FOR THE PERIOD
FROM
JUNE 1, 1994 TO
SEPTEMBER 30, 1994
<S> <C>
Production (Bcf).................................................................. 4.382
Production (Trillion British Thermal Units)....................................... 4.332
Average Contract Price Received ($/MMBtu)......................................... $ 1.86
Average Index Price ($/MMBtu)..................................................... $ 1.69
</TABLE>
54
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
<S> <C>
The Company Interests in the Underlying Properties
Independent Auditors' Report................................................................................. F- 2
Statements of Revenues and Direct Operating Expenses for
the Years Ended December 31, 1992, 1993 and 1994
and the Three Months Ended March 31, 1994 and 1995........................................................ F- 3
Notes to Financial Statements................................................................................ F- 4
Supplementary Financial Information.......................................................................... F- 5
Pro Forma Financial Statements of Dominion Resources Black Warrior Trust
Pro Forma Statement of Assets, Liabilities and Trust Corpus as of
December 31, 1994......................................................................................... F- 7
Pro Forma Statements of Distributable Cash for the Year
Ended December 31, 1994 and the Three Months Ended
March 31, 1994 and 1995................................................................................... F- 8
Notes to Pro Forma Statements of Distributable Cash.......................................................... F- 8
Pro Forma Supplementary Financial Information................................................................ F- 9
Dominion Resources Black Warrior Trust
Independent Auditors' Report................................................................................. F-11
Statement of Assets, Liabilities and Trust Corpus at December 31, 1994 and March 31, 1995.................... F-12
Statement of Distributable Income for the Period from May 31, 1994 (date of inception) to December 31, 1994
and for the Three Months Ended March 31, 1995............................................................. F-12
Statement of Changes in Trust Corpus for the Period from May 31, 1994 (date of inception) to December 31,
1994 and for the Three Months Ended March 31, 1995........................................................ F-12
Notes to Financial Statements................................................................................ F-13
</TABLE>
F-1
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Board of Directors of
Dominion Resources, Inc.
We have audited the accompanying statements of revenues and direct
operating expenses of Dominion Black Warrior Basin, Inc.'s interests in the
Underlying Properties (the Company Interests) for each of the three years in the
period ended December 31, 1994. These financial statements are the
responsibility of the management of Dominion Resources, Inc. Our responsibility
is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
The accompanying statements of revenues and direct operating expenses
reflect the revenues and direct operating expenses attributable to the Company
Interests as described in Note 2 and are not intended to be a complete
presentation of the revenues and expenses of the Company Interests.
In our opinion, such statements present fairly, in all material respects,
the revenues and direct operating expenses of the Company Interests as described
in Note 2 for each of the three years in the period ended December 31, 1994, in
conformity with generally accepted accounting principles.
Deloitte & Touche LLP
Richmond, Virginia
May 5, 1995
F-2
<PAGE>
DOMINION BLACK WARRIOR BASIN, INC.'S INTERESTS IN THE UNDERLYING PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
(IN THOUSANDS)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
1992 1993 1994 1994 1995
<S> <C> <C> <C> <C> <C>
(UNAUDITED)
Revenues $36,145 $44,360 $39,401 $11,434 $8,653
Taxes on production 1,332 1,759 1,851 407 353
Net revenues 34,813 42,601 37,550 11,027 8,300
Direct operating expenses 11,148 12,205 12,997 3,155 2,854
Excess of revenues over direct operating expenses $23,665 $30,396 $24,553 $ 7,872 $5,446
</TABLE>
See Notes to Financial Statements.
F-3
<PAGE>
DOMINION BLACK WARRIOR BASIN, INC.'S INTERESTS IN THE UNDERLYING PROPERTIES
NOTES TO FINANCIAL STATEMENTS
1. THE COMPANY INTERESTS IN THE UNDERLYING PROPERTIES
Dominion Black Warrior Basin, Inc.'s (the Company) interests in the
Underlying Properties (the Company Interests) consist of certain coal seam
gas interests currently owned by the Company, a wholly-owned subsidiary of
Dominion Energy, Inc. (Dominion Energy), a wholly-owned subsidiary of
Dominion Resources, Inc. (Dominion Resources). The Underlying Properties, all
of which are located in the Black Warrior Basin of Alabama, are burdened by
an overriding royalty interest conveyed to Dominion Resources Black Warrior
Trust (the Trust).
2. BASIS OF PRESENTATION
The Statements of Revenues and Direct Operating Expenses of the Company
Interests were developed from the historical accounting records of the
Company and do not give effect to the conveyance of the overriding royalty
interests in these properties to the Trust. The statements do not include
depreciation, depletion and amortization, general and administrative
expenses, interest expense or income taxes and are not intended to be
complete statements of income in conformity with generally accepted
accounting principles. The revenues are reflected net of existing royalties
and overriding royalties, except for the royalties applicable to the Trust.
Revenues are presented on an accrual basis using the production entitlement
method wherein the Company's revenue interest is applied to the volumes of
natural gas produced. Expenses are presented on an accrual basis.
3. UNAUDITED INTERIM PERIODS
The Statements of Revenue and Direct Operating Expenses for the three
months ended March 31, 1994 and 1995 are unaudited. The statements were
derived from the historical accounting records of the Company and, in the
opinion of the management of Dominion Resources, include all adjustments
necessary to present fairly the results of operations on a basis consistent
with that described in Note 2 above.
F-4
<PAGE>
DOMINION BLACK WARRIOR BASIN, INC.'S INTERESTS IN THE UNDERLYING PROPERTIES
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTAL GAS DISCLOSURES
(UNAUDITED)
Proved natural gas reserves of the Company Interests have been estimated
as of January 1, 1992, October 1, 1992, January 1, 1994, and January 1, 1995
by Ryder Scott Company Petroleum Engineers (Ryder Scott), an independent
petroleum engineering firm. Reserves as of December 31, 1992 have been
determined by management by excluding reserves attributable to the period
October 1 through December 31, 1992 from Ryder Scott's October 1, 1992
estimate. The natural gas reserve estimates provided for the Company
Interests have been reduced for royalty interests owned by others and
excludes the effect of the conveyance of the overriding royalty interest to
the Trust.
<TABLE>
<CAPTION>
1992 1993 1994
<S> <C> <C> <C>
(BCF)
Proved Developed Gas Reserves
January 1 122.5 106.9 107.8
Revision of previous estimates 4.5 22.1 9.6
Production (20.1) (21.2) (20.2)
December 31 106.9 107.8 97.2
</TABLE>
Proved developed reserves for the Company Interests are estimated
quantities of coal seam gas which geological and engineering data indicate with
reasonable certainty to be recoverable in future years from the coal formation
under existing economic and operating conditions.
Numerous uncertainties are inherent in estimating volumes and value of
proved reserves and in projecting future production rates and timing of any
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.
In accordance with Statement of Financial Accounting Standards No. 69,
estimates of future net cash flows from proved reserves have been prepared using
end-of-year natural gas prices adjusted for the effect of the gas purchase
agreement between the Company and Sonat Marketing Company (the Gas Purchase
Agreement) and related costs. As of December 31, 1992, costs reflect those
provided by management at the time future cash flows were determined and include
normal inflationary adjustments. Such normal inflationary adjustments have not
been eliminated from 1992 estimates due to the unavailability of information
necessary to reflect current costs as of these dates. The standardized measure
of future net cash flows from the natural gas reserves was calculated based on
discounting such future net cash flows at an annual rate of 10 percent. The
price for gas from the Company Interests, including the effect of the Gas
Purchase Agreement, was $2.24, $2.35 and $1.83 per Mcf for December 1992, 1993
and 1994, respectively.
Future cash flows were developed by management based on reserves estimated
by Ryder Scott as of January 1, 1992, October 1, 1992, January 1, 1994 and
January 1, 1995. Management has determined future cash flows as of December 31,
1992 by excluding 1992 reserves attributable to the period October 1 through
December 31, 1992 from Ryder Scott's October 1, 1992 estimate.
Future cash inflows do not include the discounted value of the Section 29
tax credit associated with the sale of future production. The value of the
credit associated with the sale of future production discounted at 10 percent
would be $71.2, $73.6 and $68.6 million, based on a constant future rate for the
credit per Mcf of $0.94, $0.97 and $0.98 for the years ended December 31, 1992,
1993 and 1994, respectively.
The following table sets forth the standardized measure of discounted
future net cash flows relating to proved natural gas reserves from the Company
Interests.
F-5
<PAGE>
DOMINION BLACK WARRIOR BASIN, INC.'S INTERESTS IN THE UNDERLYING PROPERTIES
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTAL GAS DISCLOSURES
(UNAUDITED) -- CONTINUED
<TABLE>
<CAPTION>
DECEMBER 31,
1992 1993 1994
<S> <C> <C> <C>
(IN THOUSANDS)
Future cash inflows $239,500 $253,000 $172,900
Future production costs (95,100) (120,900) (96,600)
Future development costs (5,200) (8,200) (5,400)
Future net cash flows 139,200 123,900 70,900
10% annual discount factor (32,400) (28,400) (16,100)
Standardized measure of discounted
future net cash flows $106,800 $ 95,500 $ 54,800
</TABLE>
A summary of the changes in the standardized measure of discounted future
net cash flows applicable to proved natural gas reserves is as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
1992 1993 1994
<S> <C> <C> <C>
(IN THOUSANDS)
January 1 $ 98,000 $106,800 $ 95,500
Revisions of previous estimates:
Changes in prices and costs 16,800 (6,400) (33,300)
Changes in quantities 3,700 16,800 9,000
Sales, net of production costs (23,700) (30,400) (24,600)
Accretion of discount 9,800 10,700 9,600
Other 2,200 (2,000) (1,400)
8,800 (11,300) (40,700)
December 31 $106,800 $ 95,500 $ 54,800
</TABLE>
The information presented with respect to estimated future net cash flows
and the present value thereof is not intended to represent the fair value of
coal seam gas reserves. Actual future sales prices and production costs may vary
significantly from those as of December 31, 1994 and actual future production
may not occur in the periods or amounts projected. This information is presented
to allow a reasonable comparison of reserve values prepared using standardized
measurement criteria and should be used only for that purpose.
F-6
<PAGE>
DOMINION RESOURCES BLACK WARRIOR TRUST
PRO FORMA STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS
DECEMBER 31, 1994
(UNAUDITED)
STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
7.85 MILLION
UNITS SOLD
IN PUBLIC
OFFERING
DECEMBER 31, 1994
<S> <C>
(IN THOUSANDS)
ASSETS
Proved developed coal
seam gas properties................................................................................ $ 146,396
Cash and cash equivalents............................................................................ 2
Total Assets $ 146,398
LIABILITIES AND TRUST CORPUS
Trust administration expenses payable................................................................ $ 170
Trust corpus (7,850,000 units of beneficial interest authorized, issued and outstanding)............. 146,228
Total Liabilities and Trust Corpus............................................................ $ 146,398
</TABLE>
BASIS OF PRESENTATION
The Pro Forma Statement of Assets, Liabilities and Trust Corpus for
Dominion Resources Black Warrior Trust (the Trust) is presented on the basis of
the assumption that the Trust has been in existence since May 31, 1994 (date of
inception) and reflects the sale of 6,904,000 Units at the June 1994 public
offering price of $20.00 per unit (less accumulated amortization of $9,184,572
at December 31, 1994), and the sale of the remaining 946,000 units at $18.50 per
unit as of December 31, 1994, and gives effect to the operation of the Trust
from inception to December 31, 1994.
F-7
<PAGE>
DOMINION RESOURCES BLACK WARRIOR TRUST
PRO FORMA STATEMENTS OF DISTRIBUTABLE CASH
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
YEAR ENDED THREE MONTHS ENDED
DECEMBER 31, MARCH 31,
1994 1994 1995
<S> <C> <C> <C>
Revenues (Note 1.B.) $ 39,401 $11,434 $ 8,653
Pro Forma Adjustment:
Revenue increase (decrease) under the Gas Purchase Agreement
(Note 1.A.) 114 (146) --
39,515 11,288 8,653
Taxes 1,851 407 353
Pro Forma Adjustment:
Tax increase (decrease) due to adjustment in revenue 5 (5) --
1,856 402 353
Pro Forma Gross Proceeds 37,659 10,886 8,300
Overriding Royalty Interests Percentage 65% 65% 65%
24,478 7,076 5,395
Pro Forma General and Administrative Expenses (515) (129) (133)
Pro Forma Distributable Cash (Note 1.B.) $ 23,963 $ 6,947 $ 5,262
Pro Forma Distributable Cash Per Unit (Note 1.B.)
(7.85 million Units issued and outstanding) $ 3.05 $ 0.88 $ 0.67
</TABLE>
See Notes to Pro Forma Statements of Distributable Cash
DOMINION RESOURCES BLACK WARRIOR TRUST
NOTES TO PRO FORMA STATEMENTS OF DISTRIBUTABLE CASH
(UNAUDITED)
1. BASIS OF PRESENTATION
The Pro Forma Statements of Distributable Cash for Dominion Resources Black
Warrior Trust (the Trust) are based on the actual operating results, developed
from historical accounting records of Dominion Black Warrior Basin, Inc. (the
Company). (See Note 1 of Notes to Financial Statements on page F-4 for a
discussion of the Company Interests in the Underlying Properties.) The
assumptions used to develop this statement are as follows.
A. The Company's production is assumed to be sold subject to a gas
purchase agreement between the Company and Sonat Marketing Company (the
Gas Purchase Agreement). Based on the terms of the Gas Purchase
Agreement, the pro forma average gas price would have been $1.96 per
Mcf for the year ended December 31, 1994, and $2.25 and $1.81 per Mcf
for the three months ended March 31, 1994 and 1995, respectively.
B. Revenues were assumed to be paid to the Trust in the month of
production. Actual distributable cash may vary from pro forma
distributable cash since the Pro Forma Statements of Distributable Cash
are presented on an accrual basis. The Trust will receive cash payments
on or before the last business day before the 45th day following the
end of each quarter.
2. TAXES
As a grantor trust, it is assumed that the Trust will not be required to
pay federal or state income taxes. Accordingly, no provision for income taxes
has been reflected.
The pro forma Section 29 tax credit per Unit arising from the sale of
production from the Royalty Interests for the year ended December 31, 1994 was
$1.64.
F-8
<PAGE>
DOMINION RESOURCES BLACK WARRIOR TRUST
PRO FORMA SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTAL GAS DISCLOSURES
(UNAUDITED)
The reserve quantities attributable to the Trust's overriding royalty
interests have been estimated as of January 1, 1995 by Ryder Scott Company
Petroleum Engineers, an independent petroleum engineering firm. The reserve
estimates provided for the Trust give effect to the conveyance of the overriding
royalty interests to the Trust.
<TABLE>
<CAPTION>
BCF
<S> <C>
Proved Developed Reserves
January 1, 1994 70.1
Revisions of previous estimates 6.1
Production (13.1)
December 31, 1994 63.1
</TABLE>
The pro forma proved natural gas reserves at December 31, 1994, set forth
in the table above, are less than the proved reserves for the Company Interests
as of December 31, 1994 due to the fact that the pro forma reserves attributable
to the overriding royalty interests are determined on the basis of the Trust
being entitled to receive 65 percent of natural gas produced from the Company
Interests.
Proved developed reserves for the Company Interests are estimated
quantities of coal seam gas which geological and engineering data indicate with
reasonable certainty to be recoverable in future years from the coal formation
under existing economic and operating conditions. Estimated economic quantities
have been determined considering the Section 29 tax credit.
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.
In accordance with Statement of Financial Accounting Standards No. 69,
estimates of future net cash flows from proved reserves have been prepared using
end-of-year natural gas prices, adjusted for the effect of the Gas Purchase
Agreement and related costs. The standardized measure of future net cash flows
from the gas reserves was calculated based on discounting such future net cash
flows at an annual rate of 10 percent. The price for December 1994 was $1.83 per
Mcf, including the effect of the Gas Purchase Agreement.
Future cash inflows do not include Section 29 tax credits.
F-9
<PAGE>
DOMINION RESOURCES BLACK WARRIOR TRUST
PRO FORMA SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTAL GAS DISCLOSURES
(UNAUDITED)
The following table sets forth the standardized measure of discounted pro
forma estimated future net cash flows relating to the Trust's Royalty Interests
as of December 31, 1994.
<TABLE>
<CAPTION>
(IN THOUSANDS)
<S> <C>
Future cash inflows $112,400
Future taxes (6,500)
Future net cash flows 105,900
10% annual discount for estimated timing of cash flows (27,600)
Standardized measure of discounted future net cash flows $ 78,300
</TABLE>
The following table sets forth the changes in the present value of pro
forma estimated future net cash flows from proved gas reserves for the year
ended December 31, 1994.
<TABLE>
<CAPTION>
(IN THOUSANDS)
<S> <C>
January 1, 1994 $113,400
Revisions of previous estimates:
Changes in prices (26,200)
Changes in quantities 10,600
Sales, net of taxes (24,400)
Accretion of discount 11,300
Other (6,400)
(35,100)
December 31, 1994 $ 78,300
</TABLE>
The information presented with respect to pro forma estimated future net
cash flows and the present value thereof is not intended to represent the fair
value of coal seam gas reserves. Actual future sales prices may vary
significantly from those as of December 31, 1994 and actual future production
may not occur in the periods or amounts projected. This information is presented
to allow a reasonable comparison of reserve values prepared using standardized
measurement criteria and should be used only for that purpose.
F-10
<PAGE>
DOMINION RESOURCES BLACK WARRIOR TRUST
INDEPENDENT AUDITORS' REPORT
To the Board of Directors of Dominion Resources, Inc.
and the Trustees 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 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 includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our 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 presents fairly, in all
material respects, the assets, liabilities and trust corpus of Dominion
Resources Black Warrior Trust as of 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.
Deloitte & Touche LLP
Dallas, Texas
March 10, 1995
F-11
<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 and $16,401,710 at March 31, 1995)....................... 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
FOR THE PERIOD FROM
MAY 31, 1994
(DATE OF INCEPTION) TO
DECEMBER 31, 1994
STATEMENT OF DISTRIBUTABLE INCOME
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)................................. $ 0.927252
Distributions per unit.......................................................... $ 0.906537
FOR THE PERIOD FROM
MAY 31, 1994
(DATE OF INCEPTION) TO
DECEMBER 31, 1994
STATEMENT OF CHANGES IN TRUST CORPUS
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
<CAPTION>
MARCH 31, 1995
<S> <C>
(UNAUDITED)
ASSETS
Cash and cash equivalents....................................................... $ 11,272
Royalty interests in gas properties (less accumulated amortization of $9,184,572
at December 31, 1994 and $16,401,710 at March 31, 1995)....................... 132,422,577
Total Assets............................................................. $132,433,849
LIABILITIES AND TRUST CORPUS
Trust administration expenses payable........................................... $ 94,828
Trust corpus (7,850,000 units of beneficial interest authorized, issued and
outstanding).................................................................. 132,339,021
Total Liabilities and Trust Corpus....................................... $132,433,849
THREE MONTHS
ENDED
MARCH 31,
1995
(UNAUDITED)
STATEMENT OF DISTRIBUTABLE INCOME
Royalty income.................................................................. $ 5,608,705
Interest income................................................................. 14,682
5,623,387
General and administrative expenses............................................. (105,780)
Distributable income............................................................ $ 5,517,607
Distributable income per unit (7,850,000 units)................................. $ 0.702880
Distributions per unit.......................................................... $ 0.692117
THREE MONTHS
ENDED
MARCH 31,
1995
(UNAUDITED)
STATEMENT OF CHANGES IN TRUST CORPUS
Trust corpus, beginning of period............................................... $139,471,673
Conveyance of royalty interests by Dominion Black Warrior Basin, Inc. .......... --
Amortization of royalty interests............................................... (7,217,138)
Distributable income............................................................ 5,517,607
Trust formation costs........................................................... --
Distributions to unitholders.................................................... (5,433,121)
Trust corpus, end of period..................................................... $132,339,021
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
F-12
<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.
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:
(Bullet) 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.
F-13
<PAGE>
(Bullet) General and administrative expenses are recorded based on
liabilities paid and cash reserves established out of cash
received.
(Bullet) Amortization of the Royalty Interests is calculated on a
unit-of-production basis and charged directly to trust corpus when
revenues are received.
(Bullet) 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 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.
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
F-14
<PAGE>
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.
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:
<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 0.22 0.71
</TABLE>
F-15
<PAGE>
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......... $ 0.709139
Distributions per Unit................ $ 0.726389
</TABLE>
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 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.
F-16
<PAGE>
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>
GAS PURCHASE AGREEMENT
Sonat Marketing Company ("Sonat Marketing") is required under a gas
purchase agreement (the "Gas Purchase Agreement") to purchase the natural gas
produced and sold from the Underlying Properties ("Gas") for as long as reserves
on the Underlying Properties produce natural gas. Under 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 $.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. During 1994, Sonat Marketing purchased
all the gas production attributable to the Royalty Interests.
F-17
<PAGE>
EXHIBIT A
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
FAX (713) 651-0849
1100 LOUISIANA SUITE 3800 HOUSTON, TEXAS 77002-5218 TELEPHONE (713) 651-9191
May 4, 1995
Dominion Resources Black Warrior Trust
NationsBank Center
Main Street, 12th Floor
Dallas, Texas 75202
Dominion Black Warrior Basin, Inc.
Riverfront Plaza - West Tower
901 E. Byrd Street
Richmond, Virginia 23219-4072
Gentlemen:
At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain leasehold and royalty interests
of Dominion Resources Black Warrior Trust (the Trust) and Dominion Black Warrior
Basin, Inc. (The Underlying Properties) 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 results 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
Discounted FNI @ 10%
(Excluding Tax Credits) $ 68,258,848 $10,048,147 $ 78,306,995
</TABLE>
A-1
<PAGE>
UNESCALATED PARAMETERS
ESTIMATED NET RESERVE AND INCOME DATA
CERTAIN LEASEHOLD INTERESTS OF
DOMINION BLACK WARRIOR BASIN, INC.
AS OF JANUARY 1, 1995
<TABLE>
<CAPTION>
PROVED
DEVELOPED TOTAL
PRODUCING NON-PRODUCING PROVED
<S> <C> <C> <C>
NET REMAINING RESERVES
Gas -- MMCF 84,804 12,347 97,151
INCOME DATA
Future Gross Revenue $142,065,882 $20,794,992 $162,860,874
Tax Credits 78,442,780 12,295,019 90,737,799
Deductions 82,359,180 9,537,914 91,897,094
Future Net Income (FNI) $138,149,482 $23,552,097 $161,701,579
Discounted FNI @ 10% $106,871,312 $16,573,398 $123,444,710
Discounted FNI @ 10%
(Excluding Tax Credits) $ 47,366,849 $ 7,456,937 $ 54,823,786
</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 in the attached "Reserve
Definitions and Pricing Assumptions" in this report.
A Staff Accounting Bulletin (S.A.B.) issued September 18, 1989 allows for
oil and gas producing companies to include coalbed methane gas in their estimate
of proved reserves under SEC guidelines. In accordance with the S.A.B. dated
November 30, 1989 these reserves should be included provided they comply in all
other respects with the definition of proved oil and gas reserves. Included is
the requirement that methane production be economical at current prices, costs
(net of the tax credit) and existing operating conditions. At the request of
Dominion 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 in the attached "Reserve Definitions
and Pricing Assumptions" in this report.
The future gross revenue is after the deduction of production taxes and
before the addition of Dominion's estimate of Section 29 Tax Credit (presented
as "other income"). The deductions are comprised of normal direct costs of
operating the wells (including general administrative overhead) and recompletion
costs. 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 in the attached "Reserve Definitions and Pricing
Assumptions"in this report.
ESTIMATES OF RESERVES
In general, the reserves included herein were estimated by performance
methods or the volumetric method; however, other methods were used in certain
cases where characteristics of the data indicated such other methods were more
appropriate in our opinion. The reserves estimated by the performance method
utilized extrapolations of various historical data in those cases where such
data were definitive. Reserves were estimated by the volumetric method in those
cases where there
A-2
<PAGE>
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 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 were then projected to decline at their decreasing
delivery capacity rate. Our general policy on estimates of future gas production
rates is adjusted when necessary to reflect actual gas market conditions in
specific cases.
The future production rates from wells now on production may be more or
less than estimated because of changes in 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 in the attached "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 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.
A-3
<PAGE>
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 and Dominion.
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
Larry P. Connor, P.E.
Petroleum Engineer
LPC/sw
Approved:
Kent A. Williamson, P.E.
Group Vice President
A-4
<PAGE>
RESERVE DEFINITIONS AND PRICING ASSUMPTIONS
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 productibility 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.
A-5
<PAGE>
RESERVE DEFINITIONS AND PRICING ASSUMPTIONS
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.
A-6
<PAGE>
RESERVE DEFINITIONS AND PRICING ASSUMPTIONS
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 968 .239 .239
</TABLE>
*Behind pipe "Lease Operating Expense" carried with the proved producing
lease until depletion.
ESTIMATED SECTION 29 TAX CREDIT
<TABLE>
<CAPTION>
YEAR $/MMBTU
<S> <C>
1995 .995788
1996 .995788
1997 .995788
1998 .995788
1999 .995788
2000 .995788
2001 .995788
2002 .995788
</TABLE>
A-7
<PAGE>
EXHIBIT B
GLOSSARY
"After-Tax Cash Return per Unit" means the sum of the following amounts
that a hypothetical purchaser of a Unit in the offering made hereby would have
received or been allocated if such Unit were held through the date of such
determination: (a) total cash distributions per Unit plus (b) total Section 29
tax credits available per Unit less (c) the total net taxes payable or total net
tax savings per Unit (assuming a 36 percent marginal federal income tax rate).
"Bcf" means billion cubic feet of natural gas.
"Btu" means British Thermal Unit, the common unit of gross heating value
measurement for natural gas.
"Central Gathering Point" means the central delivery points in the
gathering system for the Underlying Properties.
"Company" means Dominion Black Warrior Basin, Inc., a Virginia 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 Gathering Point. 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 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 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 of the Royalty
Interests from the Company to the Trust, as amended by the Conveyance Amendment,
copies of which are filed as exhibits to the Registration Statement of which
this Prospectus is a part.
"Conveyance Amendment" means the Amendment to and Ratification of
Overriding Royalty Conveyance, dated as of November 20, 1994 among the Trust,
the Trustee and the Delaware Trustee.
"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, a copy of which is filed as an
exhibit to the Registration Statement of which this Prospectus is a part.
"Grantor trust" means a trust as to which the grantor, or his successor,
has retained an interest in the income from the trust.
"Gross Proceeds" means the aggregate amounts received by the Company
Interests Owner attributable to the Company Interests from the sale, at the
Central Gathering Point, of Subject Gas.
"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 price 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.
B-1
<PAGE>
"Maximum Price" means $2.63 per MMBtu, the maximum price payable pursuant
to the Gas Purchase Agreement from June 1, 1994 through December 31, 1998.
"Minimum Price" means $1.85 per MMBtu, the minimum price payable pursuant
to the Gas Purchase Agreement from June 1, 1994 through December 31, 1998.
"MMcf" means million cubic feet of natural gas. As used herein, 1 MMcf is
assumed to have a Btu content of 990 MMBtu.
"MMBtu" means million Btu. As used herein, 990 MMBtu is deemed to be the
Btu content of 1 MMcf.
"Monthly Base Quantity" means the volumes of natural gas designated as such
in the Gas Purchase Agreement.
"Net revenue interest" means working interest or mineral interest less any
applicable royalties, overriding royalties or similar burdens on production
prior to the Royalty Intersts.
"Net wells" and "net acres" are calculated by multiplying gross wells or
gross acres by the working interest in such wells or acres.
"Original Reserve Estimate" means the estimated net proved reserves,
estimated future net revenues and the discounted net revenues attributable to
the Royalty Interests and the Company Interests prepared by Ryder Scott as of
June 1, 1994.
"Premium" means the premium per MMbtu on a wet basis pursuant to the Gas
Purchase Agreement from June 1, 1994 through December 31, 1998 as follows:
<TABLE>
<CAPTION>
INDEX PRICE PREMIUM
($/MMBTU) ($/MMBTU)
<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>
"Reserve Estimate" means the estimated net proved reserves, estimated
future net revenues and the discounted net revenues attributable to the Royalty
Interests and the Company Interests prepared by Ryder Scott summaries of which,
as of January 1, 1995, are included as Exhibit A to this Prospectus.
"River Gas" means The River Gas Corporation, an Alabama corporation.
"Royalty" means an interest entitling the holder thereof to a certain
percentage of the natural gas produced from the wells, which generally is free
of all expenses of production except its proportionate share of production
taxes, but may be subject to certain post-production costs.
"Royalty Interests" means the overriding royalty interests conveyed to the
Trust 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 the Trust Agreement Amendment, copies of which are filed
as an exhibit to the Registration Statement of which this Prospectus is a part.
"Trust Agreement Amendment" means the First Amendment of Trust Agreement,
dated as of June 27, 1994, among the Company, Dominion Resources, the Trustee
and the Delaware Trustee.
"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 located in the
Black Warrior Basin, Tuscaloosa County, Alabama insofar as such properties
include the Pottsville Formation and in which the Company has an interest.
"Units" means the 7,850,000 units of beneficial interest issued by, and
evidencing the entire beneficial interest in, the Trust.
B-2
<PAGE>
No dealer, salesman or any other person has been authorized to give any
information or to make any representations not contained in this Prospectus and,
if given or made, such information or representations must not be relied upon as
having been authorized by Dominion Resources or any of the Underwriters. This
Prospectus does not constitute an offer of any securities other than those to
which it relates or an offer to sell, or a solicitation of an offer to buy, to
any person in any jurisdiction where such an offer or solicitation would be
unlawful. Neither the delivery of this Prospectus nor any sale made hereunder
shall, under any circumstances, create any implication that the information
contained herein is correct as of any time subsequent to the date hereof.
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
<S> <C>
Prospectus Supplement
Prospectus Supplement Summary.................. S-3
Selected Financial Data........................ S-4
Distributions and Market Prices................ S-4
Recent Developments............................ S-4
Underwriting................................... S-5
Prospectus
Available Information.......................... 2
Incorporation of Certain Documents by
Reference.................................... 2
Prospectus Summary............................. 3
Risk Factors................................... 12
Use of Proceeds................................ 18
Hypothetical 1996 Cash Distributions and
After-Tax Returns............................ 18
The Royalty Interests.......................... 26
Federal Income Tax Consequences................ 34
State Tax Considerations....................... 40
ERISA Considerations........................... 41
Description of the Trust Agreement............. 41
Plan of Distribution........................... 50
Validity of the Units.......................... 51
Experts........................................ 51
Management's Discussion and Analysis of
Financial Position and Results
of Operations................................ 53
Index to Financial Statements.................. F-1
Independent Petroleum Engineer's Letter........ A-1
Glossary....................................... B-1
</TABLE>
946,000 Trust Units
Dominion Resources
Black Warrior Trust
(Dominion Resources logo)
PROSPECTUS SUPPLEMENT
, 1995
LEHMAN BROTHERS
WHEAT FIRST BUTCHER SINGER
