-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, XJrzlYmfdFeoVS9fRq3ibLyJXku3BkWU320ALFrdwuOr4vOVUhlkqDIAacgidZKa pInpee1JKFqfrfirdhLXuw== 0000916641-95-000170.txt : 19950530 0000916641-95-000170.hdr.sgml : 19950530 ACCESSION NUMBER: 0000916641-95-000170 CONFORMED SUBMISSION TYPE: 424B3 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19950518 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: DOMINION RESOURCES INC /VA/ CENTRAL INDEX KEY: 0000715957 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 541229715 STATE OF INCORPORATION: VA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B3 SEC ACT: 1933 Act SEC FILE NUMBER: 033-53513 FILM NUMBER: 95540842 BUSINESS ADDRESS: STREET 1: 901 E BYRD ST STREET 2: P O BOX 26532 CITY: RICHMOND STATE: VA ZIP: 23219 BUSINESS PHONE: 8047755700 424B3 1 DOMINION RESOURCES BLACK WARRIOR 424B3 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] Underwriting Proceeds to Price to Discounts and Dominion Public Commissions (1) Resources(2) Per Unit.............................................. $ $ $ Total................................................. $ $ $
(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. (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 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.
PRODUCTION PERIOD JANUARY 1--MARCH 31, 1995 APRIL 1--JUNE 30, 1995 JULY 1--SEPTEMBER 30, 1995 OCTOBER 1--DECEMBER 31, 1995 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
THE OFFERING 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."
S-3 SELECTED FINANCIAL DATA DOMINION RESOURCES BLACK WARRIOR TRUST
FOR THE PERIOD FROM MAY 31, 1994 (DATE OF INCEPTION) TO THREE MONTHS ENDED DECEMBER 31, 1994 MARCH 31, 1995 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
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.
PRICE DISTRIBUTION 1994 HIGH LOW PER UNIT (1) 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 1995 First Quarter............................................ 19 5/8 17 1/4 0.692117 Second Quarter (through May 16, 1995).................... 20 1/8 18 3/4 --
(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 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.
NUMBER OF FIRM UNDERWRITER UNITS Lehman Brothers Inc. ....................................... Wheat, First Securities, Inc................................ Total................................................ 946,000
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 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 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 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 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 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.
ESTIMATED ESTIMATED FUTURE NET NET PROVED REVENUES NATURAL GAS RESERVES (DOLLARS IN MILLIONS) (BCF) UNDISCOUNTED DISCOUNTED 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
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 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
5 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.
6 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").
7 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."
8 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 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." 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).
10 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.
11 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 12 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." 13 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 14 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. 15 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: 16 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." 17 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 18 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 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 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 $2.26 per Mcf for their allocated share of production from the Underlying Properties. Depletion deductions will reduce the tax basis of a Unitholder in his Units, which will increase the gain (or reduce the loss) realized upon the disposition of such Units. In order for the Unitholders to utilize percentage depletion, the price for natural gas sales would have to be substantially in excess of the prices shown in the above tables. See "Federal Income Tax Consequences -- The Royalty Interests -- Cost Depletion," " -- The Royalty Interests -- Percentage Depletion" and " -- Sale of Units." 21 THE AMOUNTS SET FORTH IN THE TABLES BELOW ARE NOT NECESSARILY INDICATIVE OF FUTURE RESULTS HYPOTHETICAL ANNUAL CASH DISTRIBUTIONS PER UNIT FOR ESTIMATED 1996 PRODUCTION (A)(F)
AVERAGE CONTRACT PRICE(B) ($ PER MMBTU) $1.85 $2.00 $2.25 $2.50 $2.63 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 $3.72
HYPOTHETICAL PRE-TAX CASH RETURNS FOR ESTIMATED 1996 PRODUCTION(A)(C)(D)(F)
AVERAGE CONTRACT PRICE(B) ($ PER MMBTU) $1.85 $2.00 $2.25 $2.50 $2.63 PRODUCTION REALIZATION (% OF RESERVE REPORT ESTIMATE FOR 1996) 90% 11.4 % 12.4 % 14.0 % 15.6 % 16.4 % 95% 12.1 % 13.1 % 14.8 % 16.4 % 17.3 % 100% 12.7 % 13.8 % 15.6 % 17.3 % 18.2 % 105% 13.4 % 14.5 % 16.3 % 18.2 % 19.2 % 110% 14.0 % 15.2 % 17.1 % 19.1 % 20.1 %
HYPOTHETICAL AFTER-TAX TOTAL RETURNS FOR ESTIMATED 1996 PRODUCTION(A)(D)(E)(F)
AVERAGE CONTRACT PRICE(B) ($ PER MMBTU) $1.85 $2.00 $2.25 $2.50 $2.63 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 %
(FOOTNOTES ON NEXT PAGE) 22 (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) $18.50 (the assumed purchase price per Unit utilized in such hypothetical calculations). (f) A portion of the cash distributions and returns is analogous to a return of capital. As used herein, "return of capital" means the return of a Unitholder's original investment in a Unit, such return determined by the sum of (a) cash distributions received from the Trust in respect of such Unit plus (b) the effective reduction or increase in federal income taxes realizable in respect of such Unit by reason of tax losses or taxable income and Section 29 tax credits plus (c) the net cash proceeds, if any, received in respect of such Unit upon liquidation of the Trust or, if the Unit is sold prior to liquidation, the net cash proceeds received by such Unitholder upon the sale of such Unit. A portion of each cash distribution and of the allocations of tax losses or taxable income and Section 29 tax credits made per Unit will effectively constitute a return of capital, and the remaining portion of such cash distribution and allocations will effectively constitute a return on capital (that is, a return on such Unitholder's original investment). Such portions may be accurately determined only after termination of a Unitholder's investment in a Unit (either upon sale of such Unit or upon liquidation of the Trust). 23 HYPOTHETICAL 1996 AFTER-TAX RETURN CALCULATIONS (DOLLARS IN THOUSANDS, UNLESS INDICATED OTHERWISE) The hypothetical returns set forth below are for 1996 only and actual returns may differ materially from those set forth below. Additionally, cash returns attributable to the Units are expected to decline over the term of the Trust and, therefore, in subsequent years may be substantially lower than those set forth below. HYPOTHETICAL CASH DISTRIBUTIONS Contract price ($/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%
(FOOTNOTES ON NEXT PAGE) 24 (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:
PRICE $17.50 $18.00 $18.50 $19.00 $19.50 After-Tax Return 23.5% 22.8% 22.2% 21.6% 21.1%
25 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 NET MONTHLY PRODUCTION OF THE COMPANY INTERESTS JANUARY 1993 TO MARCH 1995
MCF 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
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.
NUMBER OF WELLS ACRES GROSS NET GROSS NET 532 519 34,212 33,391
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 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." 28 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.
ROYALTY INTERESTS COMPANY INTERESTS 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)
(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. 29 (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):
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, 1992 1993 1994 1994 1995 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
(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. 30 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." 31 (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 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 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. 34 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. 35 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 36 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). 37 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 38 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. 39 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 40 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. 41 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 42 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. 43 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. 44 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 45 946,000 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, 46 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 47 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. 48 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 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 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 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 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 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 $135,000 for the payment of expenses and liabilities of the Trust. The quarterly distribution made in the third quarter of 1994 was reduced by the amount of this reserve in accordance with the provisions of the Trust Agreement. The Trust anticipates that it will maintain for the foreseeable future a cash reserve to enable it to pay administrative expenses as they become due. The amount of the cash reserve from time to time will fluctuate as expenses are paid and royalty income is received. Royalty income received by the Trust in a given calendar year will generally reflect the proceeds from the sale of gas produced from the Underlying Properties during the first three quarters of that year and the fourth quarter of the preceding calendar year due to the timing of the receipt of these revenues. The conveyance of the Royalty Interests to the Trust was effective June 1, 1994. Accordingly, the royalty income included in distributable income for the period ended December 31, 1994, was based on production volumes and natural gas prices for the period from June 1, 1994 to September 30, 1994, in accordance with the terms of the conveyance of the Royalty Interests to the Trust. The following table sets forth the production volumes attributable to the Trust's Royalty Interests and the average sales price and Index Price for such production for the period indicated.
FOR THE PERIOD FROM JUNE 1, 1994 TO SEPTEMBER 30, 1994 Production (Bcf).................................................................. 4.382 Production (Trillion British Thermal Units)....................................... 4.332 Average Contract Price Received ($/MMBtu)......................................... $ 1.86 Average Index Price ($/MMBtu)..................................................... $ 1.69
54 INDEX TO FINANCIAL STATEMENTS
PAGE 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
F-1 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 DOMINION BLACK WARRIOR BASIN, INC.'S INTERESTS IN THE UNDERLYING PROPERTIES STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES (IN THOUSANDS)
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, 1992 1993 1994 1994 1995 (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
See Notes to Financial Statements. F-3 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 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.
1992 1993 1994 (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
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 DOMINION BLACK WARRIOR BASIN, INC.'S INTERESTS IN THE UNDERLYING PROPERTIES SUPPLEMENTARY FINANCIAL INFORMATION SUPPLEMENTAL GAS DISCLOSURES (UNAUDITED) -- CONTINUED
DECEMBER 31, 1992 1993 1994 (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
A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved natural gas reserves is as follows:
DECEMBER 31, 1992 1993 1994 (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
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 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
7.85 MILLION UNITS SOLD IN PUBLIC OFFERING DECEMBER 31, 1994 (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
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 DOMINION RESOURCES BLACK WARRIOR TRUST PRO FORMA STATEMENTS OF DISTRIBUTABLE CASH (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS) (UNAUDITED)
YEAR ENDED THREE MONTHS ENDED DECEMBER 31, MARCH 31, 1994 1994 1995 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
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 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.
BCF Proved Developed Reserves January 1, 1994 70.1 Revisions of previous estimates 6.1 Production (13.1) December 31, 1994 63.1
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 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.
(IN THOUSANDS) 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
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.
(IN THOUSANDS) 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
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 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 DOMINION RESOURCES BLACK WARRIOR TRUST FINANCIAL STATEMENTS STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS
DECEMBER 31, 1994 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 MARCH 31, 1995 (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
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS. F-12 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 (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 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:
DISTRIBUTION QUARTERLY RECORD DATE PAYMENT DATE PER UNIT March 1, 1995.......................... March 10, 1995 $ 0.692117
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:
SECOND THIRD FOURTH QUARTER QUARTER QUARTER 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
F-15 Selected 1994 fourth quarter data are as follows: 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
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.
BCF 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
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):
1994 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
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 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): 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
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 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
PROVED DEVELOPED TOTAL PRODUCING NON-PRODUCING PROVED 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
A-1 UNESCALATED PARAMETERS ESTIMATED NET RESERVE AND INCOME DATA CERTAIN LEASEHOLD INTERESTS OF DOMINION BLACK WARRIOR BASIN, INC. AS OF JANUARY 1, 1995
PROVED DEVELOPED TOTAL PRODUCING NON-PRODUCING PROVED 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
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 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 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 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 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 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.
YEAR $/MMBTU 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
BEHIND PIPE LEASE OPERATING COMPRESSION COMPRESSION EXPENSE COSTS COSTS YEAR $/WELL/MONTH $/MCF $/MCF* 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
*Behind pipe "Lease Operating Expense" carried with the proved producing lease until depletion. ESTIMATED SECTION 29 TAX CREDIT
YEAR $/MMBTU 1995 .995788 1996 .995788 1997 .995788 1998 .995788 1999 .995788 2000 .995788 2001 .995788 2002 .995788
A-7 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 "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 $1.85 per MMBtu, the minimum price payable pursuant to the Gas Purchase Agreement from June 1, 1994 through December 31, 1998. "MMcf" means million cubic feet of natural gas. As used herein, 1 MMcf is assumed to have a Btu content of 990 MMBtu. "MMBtu" means million Btu. As used herein, 990 MMBtu is deemed to be the Btu content of 1 MMcf. "Monthly Base Quantity" means the volumes of natural gas designated as such in the Gas Purchase Agreement. "Net revenue interest" means working interest or mineral interest less any applicable royalties, overriding royalties or similar burdens on production prior to the Royalty Intersts. "Net wells" and "net acres" are calculated by multiplying gross wells or gross acres by the working interest in such wells or acres. "Original Reserve Estimate" means the estimated net proved reserves, estimated future net revenues and the discounted net revenues attributable to the Royalty Interests and the Company Interests prepared by Ryder Scott as of June 1, 1994. "Premium" means the premium per MMbtu on a wet basis pursuant to the Gas Purchase Agreement from June 1, 1994 through December 31, 1998 as follows:
INDEX PRICE PREMIUM ($/MMBTU) ($/MMBTU) Below $2.00 $ 0.050 $2.01-2.25 $ 0.060 $2.26-2.50 $ 0.065 Above $2.50 $ 0.070
"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 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
Page 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
946,000 Trust Units Dominion Resources Black Warrior Trust (Dominion Resources logo) PROSPECTUS SUPPLEMENT , 1995 LEHMAN BROTHERS WHEAT FIRST BUTCHER SINGER -----END PRIVACY-ENHANCED MESSAGE-----