-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, PCU1Cws6dgnjupfPFYsAduiySUMVjd6N8P2BAsz9FEnAuvCdQQXbAH9AzHQWqBQm 0Da1gitH3u5VzZa61m0Sgw== 0000950134-00-002709.txt : 20000331 0000950134-00-002709.hdr.sgml : 20000331 ACCESSION NUMBER: 0000950134-00-002709 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000329 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DOMINION RESOURCES BLACK WARRIOR TRUST CENTRAL INDEX KEY: 0000923680 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-11335 FILM NUMBER: 584716 BUSINESS ADDRESS: STREET 1: 901 MAIN ST - 12TH FLR STREET 2: C/O NATIONSBANK OF TEXAS NA CITY: DALLAS STATE: TX ZIP: 75283-0308 BUSINESS PHONE: 2145082444 MAIL ADDRESS: STREET 1: 901 MAINST - 12TH FLR STREET 2: C/O NATIONSBANK OF TEXAS NA CITY: DALLAS STATE: TX ZIP: 75283-0308 10-K405 1 FORM 10-K FOR FISCAL YEAR END DECEMBER 31, 1999 1 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------- FORM 10-K (MARK ONE) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 ---------- COMMISSION FILE NUMBER: 001-11335 DOMINION RESOURCES BLACK WARRIOR TRUST (Exact name of registrant as specified in its charter) Delaware 75-6461716 (State or other jurisdiction of (I.R.S. employer incorporation or organization) identification number) Trust Division Royalty Trust Group Bank of America, N.A. 901 Main Street 17th Floor Dallas, Texas 75202 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (214) 209-2400 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NAME OF EACH EXCHANGE ON TITLE OF EACH CLASS WHICH REGISTERED ------------------- ---------------- Units of Beneficial Interest New York Stock Exchange, Inc. SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X --- At March 10, 2000, there were 7,850,000 units of beneficial interest outstanding and the aggregate market value of such units (based on the closing sale price on the New York Stock Exchange) held by non-affiliates of the registrant was approximately $95,181,250. DOCUMENTS INCORPORATED BY REFERENCE None. 2 TABLE OF CONTENTS
PAGE ---- PART I ..................................................................................................................1 Item 1. Business........................................................................................................1 GLOSSARY........................................................................................................1 DESCRIPTION OF THE TRUST........................................................................................4 Creation and Organization of the Trust................................................................4 Assets of the Trust...................................................................................4 Duties and Limited Powers of the Trustee and the Delaware Trustee.....................................4 Resignation of Trustees...............................................................................5 Transfer of Royalty Interests.........................................................................5 Liabilities of the Trust..............................................................................5 Liabilities of the Trustee and the Delaware Trustee...................................................6 Termination and Liquidation of the Trust..............................................................6 Arbitration and Actions by Unitholders................................................................7 DESCRIPTION OF UNITS............................................................................................9 Distributions and Income Computations.................................................................9 Conditional Right of Repurchase......................................................................10 Possible Divestiture of Units........................................................................11 Periodic Reports.....................................................................................11 Voting Rights of Unitholders.........................................................................12 Liability of Unitholders.............................................................................12 Transfer Agent.......................................................................................13 FEDERAL INCOME TAX CONSIDERATIONS..............................................................................13 Summary of Certain Federal Income Tax Consequences...................................................13 ERISA CONSIDERATIONS...........................................................................................17 STATE TAX CONSIDERATIONS.......................................................................................17 Alabama Income Tax...................................................................................17 Alabama Franchise Tax................................................................................18 Alabama Severance Taxes..............................................................................18 Other Alabama Taxes..................................................................................18 REGULATION AND PRICES..........................................................................................19 Regulation of Natural Gas............................................................................19 Environmental Regulation.............................................................................19 Competition, Markets and Prices......................................................................20 Item 2. Properties....................................................................................................21 THE ROYALTY INTERESTS..........................................................................................21 The Underlying Properties............................................................................21 The Royalty Interests................................................................................23 Reserve Estimate.....................................................................................24 Natural Gas Sales Prices and Production..............................................................25 Gas Purchase Agreement...............................................................................25 Operation of Properties..............................................................................26 Sale and Abandonment of Underlying Properties........................................................27 Dominion Resources' Assurances.......................................................................27 Title to Properties..................................................................................28 Item 3. Legal Proceedings.............................................................................................28 Item 4. Submission of Matters to a Vote of Security Holders...........................................................28 PART II .................................................................................................................28 Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.........................................28 Item 6. Selected Financial Data.......................................................................................29 Item 7. Trustee's Discussion and Analysis of Financial Condition and Results of Operations............................29 Year 2000............................................................................................31 Item 7A. Quantitative and Qualitative Disclosures About Market Risk....................................................32 Item 8. Financial Statements and Supplementary Data...................................................................33 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..........................42
i 3 PART III .................................................................................................................42 Item 10. Directors and Executive Officers of the Registrant...........................................................42 Item 11. Executive Compensation.......................................................................................42 Item 12. Security Ownership of Certain Beneficial Owners and Management...............................................42 Item 13. Certain Relationships and Related Transactions...............................................................43 Administrative Services Agreement ...................................................................43 Dominion Resources' Conditional Right of Repurchase..................................................43 Potential Conflicts of Interest......................................................................43 PART IV .................................................................................................................44 Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K..............................................44 Financial Statements................................................................................44 Financial Statement Schedules.......................................................................44 Exhibits............................................................................................44 Reports on Form 8-K.................................................................................45
ii 4 PART I Item 1. Business. GLOSSARY The following is a glossary of certain defined terms used in this Annual Report on Form 10-K. "Administrative Services Agreement" means the Administrative Services Agreement dated as of June 28, 1994, between Dominion Resources and the Trust, a copy of which is filed as an exhibit to this Form 10-K. "Bcf" means billion cubic feet of natural gas. "Btu" means British Thermal Unit, the common unit of gross heating value measurement for natural gas. "Code" means the Internal Revenue Code of 1986, as amended. "Company" means Dominion Black Warrior Basin, Inc., an Alabama corporation and a wholly-owned indirect subsidiary of Dominion Resources. "Company Interests" means the Company's interest in the Underlying Properties, as of June 1, 1994, not burdened by the Royalty Interests. "Company Interests Owner" means the Company while it owns all or part of the Company Interests and any other person or persons who acquire all or any part of the Company Interests or any operating rights therein other than a royalty, overriding royalty, production payment or net profits interest. "Contract Price" means the price at which, pursuant to the Gas Purchase Agreement, Sonat Marketing is obligated to purchase the Subject Gas at the central delivery points in the gathering system for the Underlying Properties. From June 1, 1994 through April 1, 1996, the Contract Price for each month equaled (a) for quantities of Gas equal to or less than the Monthly Base Quantity, the sum of the Index Price and the Premium, provided that such price would in no event be below the Minimum Price or above the Maximum Price, and (b) for quantities of Gas in excess of the Monthly Base Quantity, the Index Price. From April 1, 1996 to December 31, 1998, the Contract Price for each month equaled (a) for quantities of Gas equal to or less than the Monthly Base Quantity, the sum of the Index Price and the Premium, provided that such price would not be below the Minimum Price or above the Maximum Price, and (b) for quantities of Gas in excess of the Monthly Base Quantity, the sum of the Index Price and $.02 per MMBtu. From January 1, 1999 through December 31, 1999, the Contract Price for each month equaled (a) for quantities of Gas equal to or less than the Monthly Base Quantity, the Monthly Base Contract Price, provided that such price will in no event be below the Minimum Price or above the Maximum Price, (b) for quantities of Gas in excess of the Monthly Base Quantity but equal to or less than the Monthly Fixed Price Quantity, the sum of the Index Price and $.02 per MMBtu, provided that such price will not be below $2.12 per MMBtu or above $3.02 per MMBtu, and (c) for quantities of Gas in excess of the Monthly Fixed Price Quantity, the sum of the Index Price and $.02 per MMBtu. Pursuant to an amendment effective January 1, 2000 through December 31, 2000, the Monthly Base Quantity shall be divided into two categories, a Fixed Price Quantity and an Index Price Quantity. The price for each Fixed Price Quantity shall be $2.45 per MMBtu. The price for each Index Price Quantity shall be the sum of the Index Price and the Premium, provided that such price would in no event be less than the Minimum Price nor more than the Maximum price. During the period from January 1, 2000 through December 31, 2000, the Contract Price for quantities of Gas in excess of the Monthly Fixed Price Quantity shall equal the sum of the Index Price and $.02 per MMBtu. "Conveyance" means the Overriding Royalty Conveyance dated effective as of June 1, 1994, from the Company to the Trust, as amended by instrument dated as of November 20, 1994, copies of which are filed as exhibits to this Form 10-K. 1 5 "Delaware Trustee" means Mellon Bank (DE) National Association. "Dominion Resources" means Dominion Resources, Inc., a Virginia corporation. "Existing Wells" means the wells producing on the Underlying Properties as of June 1, 1994. "Fixed Price Quantity" means the volume of natural gas designated as such in the Gas Purchase Agreement. "Gas" means natural gas produced and sold from the Underlying Properties. "Gas Purchase Agreement" means the Gas Purchase Agreement dated as of May 3, 1994, between the Company and Sonat Marketing, as amended by instruments effective as of April 1, 1996, January 1, 1999 and January 1, 2000. "Gross Proceeds" means the aggregate amounts received by the Company Interests Owner attributable to the Company Interests from the sale of Subject Gas at the central delivery points in the gathering system for the Underlying Properties. "Gross Wells" means the total whole number of gas wells without regard to ownership interest. "Index Price" means the price published by Inside Ferc's Gas Market Report in its first issue of the month which posts prices for the beginning of such month for "Prices of Spot Gas Delivered to Pipelines -- Southern Natural Gas Co. -- Louisiana -- Index," for such month. "Index Price Quantity" means the volume of natural gas designated as such in the Gas Purchase Agreement. "Mcf" means thousand cubic feet of natural gas. Natural gas volumes are stated herein at the legal pressure base of 14.65 or 14.73 pounds per square inch absolute, as the case may be, at 60 degrees Fahrenheit. "Maximum Price" means, for the periods from June 1, 1994 through December 31, 1998, January 1, 1999 through December 31, 1999 and January 1, 2000 through December 31, 2000, $2.63 per MMBtu, $3.07 per MMBtu and $2.82 per MMBtu, respectively. "Minimum Price" means, for the periods from June 1, 1994 through December 31, 1998, January 1, 1999 through December 31, 1999 and January 1, 2000 through December 31, 2000, $1.85 per MMBtu, $2.16 per MMBtu and $2.20 per MMBtu, respectively. "MMcf" means million cubic feet of natural gas. As used herein, 1 MMcf is assumed to have a Btu content of 990 MMBtu. "MMBtu" means million Btu. As used herein, 990 MMBtu is deemed to be the Btu content of 1 MMcf. "Monthly Base Quantity" means the volumes of natural gas designated as such in the Gas Purchase Agreement. "Monthly Fixed Price Quantity" means the volumes of natural gas designated as such from time to time in the Gas Purchase Agreement. "Net revenue interest" means working interest or mineral interest less any applicable royalties, overriding royalties or similar burdens on production prior to the Royalty Interests. "Net wells" and "net acres" are calculated by multiplying gross wells or gross acres by the ownership interest in such wells or acres. "Premium" means the premium per MMbtu on a wet basis pursuant to the Gas Purchase Agreement from June 1, 1994 through December 31, 2001 as follows: 2 6
INDEX PRICE PREMIUM ($/MMBTU) ($/MMBTU) ------------ ---------- Below $2.00 .................................$ 0.050 $2.01-2.25 ..................................$ 0.060 $2.26-2.50 ..................................$ 0.065 Above $2.50 .................................$ 0.070
"Prospectus" means the prospectus dated June 21, 1994, as supplemented by the final prospectus supplement dated June 1, 1995, relating to the offer and sale of the Units, and forming a part of Dominion Resources' Registration Statement on Form S-3 (No. 33-53513). "Reserve Estimate" means the estimated net proved reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests as of January 1, 2000, prepared by Ryder Scott. "River Gas" means The River Gas Corporation, an Alabama corporation. "Royalty Interests" means the overriding royalty interests conveyed to the Trust pursuant to the Conveyance entitling the holder thereof to 65 percent of the Gross Proceeds derived from the Company Interests. "Ryder Scott" means Ryder Scott Company Petroleum Engineers, independent petroleum engineers. "Section 29 tax credit" means the tax credits for federal income tax purposes pursuant to Section 29 of the Code to an owner of coal seam gas production, which tax credits are generated upon the sale of such production. "Sonat" means Sonat, Inc., a Delaware corporation. "Sonat Marketing" means Sonat Marketing Company, a Delaware Corporation. "Subject Gas" means Gas attributable to the Company Interests. "Trust" means Dominion Resources Black Warrior Trust, a Delaware business trust formed pursuant to the Trust Agreement. "Trust Agreement" means the Trust Agreement dated as of May 31, 1994, among the Company, as grantor, Dominion Resources, the Delaware Trustee and the Trustee, as amended by instrument dated as of June 27, 1994, copies of which are filed as exhibits to this Form 10-K. "Trustee" means Bank of America, N.A., as successor to NationsBank of Texas, N.A. "Working interest" generally refers to the lessee's interest in an oil, gas or mineral lease which entitles the owner to receive a specified percentage of oil and gas production, but requires the owner of such working interest to bear such specified percentage of the costs to explore for, develop, produce and market such oil and gas. "Underlying Properties" means the natural gas properties in which the Company has an interest located in the Black Warrior Basin, Tuscaloosa County, Alabama insofar as such properties include the Pottsville Formation. "Units" means the 7,850,000 units of beneficial interest issued by, and evidencing the entire beneficial interest in, the Trust. 3 7 DESCRIPTION OF THE TRUST Dominion Resources Black Warrior Trust is a Delaware business trust formed under the Delaware Business Trust Act, Title 12, Chapter 38 of the Delaware Code, Section 3801 et seq. (the "Delaware Code"). The following information is subject to the detailed provisions of the Trust Agreement and the Conveyance, copies of which are filed as exhibits to this Form 10-K. The provisions governing the Trust are complex and extensive and no attempt has been made below to describe or reference all of such provisions. The following is a general description of the basic framework of the Trust and the material provisions of the Trust Agreement. CREATION AND ORGANIZATION OF THE TRUST The Trust was initially created by the filing of its Certificate of Trust with the Delaware Secretary of State on May 31, 1994. In accordance with the Trust Agreement, the Company contributed $1,000 as the initial corpus of the Trust. On June 28, 1994, the Royalty Interests were conveyed to the Trust by the Company pursuant to the Conveyance, in consideration for the issuance to the Company of all 7,850,000 of the authorized Units in the Trust. The Company transferred all the Units to its parent, Dominion Energy, Inc., which in turn transferred all the Units to its parent, Dominion Resources. Dominion Resources sold an aggregate of 6,904,000 Units to the public through various underwriters (the "Underwriters") in June and August 1994 in the initial public offering of the Units (the "Initial Public Offering") and sold the remaining 946,000 Units to the public through certain of the Underwriters in June 1995 pursuant to Post-Effective Amendment No. 1 to the Form S-3 Registration Statement relating to the Units (the "Secondary Public Offering" and, collectively with the Initial Public Offering, the "Public Offerings"). ASSETS OF THE TRUST The only assets of the Trust, other than cash and temporary investments being held for the payment of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests. The Royalty Interests consist of overriding royalty interests burdening the Company's interest in the Underlying Properties. The Royalty Interests generally entitle the Trust to receive 65 percent of the Company's Gross Proceeds (as defined below). The Royalty Interests are non-operating interests and bear only expenses related to property, production and related taxes (including severance taxes). See "Properties--The Royalty Interests." The Company has advised the Trustee that all the production attributable to the Underlying Properties is from the Pottsville coal formation and currently constitutes coal seam gas that entitles the owners of such production, provided certain requirements are met, to tax credits pursuant to Section 29 of the Code, upon the production and sale of such gas. See "--Federal Income Taxation." DUTIES AND LIMITED POWERS OF THE TRUSTEE AND THE DELAWARE TRUSTEE Under the Trust Agreement, the Trustee has all powers to collect the payments attributable to the Royalty Interests and to pay all expenses, liabilities and obligations of the Trust. The Trustee has the discretion to establish a cash reserve for the payment of any liability that is contingent or uncertain in amount or that otherwise is not currently due and payable. The Trustee is entitled to cause the Trust to borrow money from any source, including from the entity serving as Trustee (provided that the entity serving as Trustee shall not be obligated to lend to the Trust), to pay expenses, liabilities and obligations that cannot be paid out of cash held by the Trust. To secure payment of any such indebtedness (including any indebtedness to the Trustee), the Trustee is authorized to (i) mortgage and otherwise encumber the entire Trust estate or any portion thereof; (ii) carve out and convey production payments; (iii) include all terms, powers, remedies, covenants and provisions it deems necessary or advisable, including confession of judgment and the power of sale with or without judicial proceedings; and (iv) provide for the exercise of those and other remedies available to a secured lender in the event of a default on such loan. The terms of such indebtedness and security interest, if funds were loaned by the Trustee, must be similar to the terms which the Trustee would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship, and the Trustee shall be entitled to enforce its rights with respect to any such indebtedness and security interest as if it were not then serving as trustee. 4 8 The Delaware Trustee has only such powers as are set forth in the Trust Agreement or are required by law and is not empowered to take part in the management of the Trust. The Royalty Interests are passive in nature and neither the Trustee nor the Delaware Trustee has any control over or any responsibility relating to the operation of the Underlying Properties. The Company does not have any contractual commitment to the Trust to develop further the Underlying Properties or to maintain its ownership interest in any of the Underlying Properties. The Company may sell the Company Interests subject to and burdened by the Royalty Interests and, absent certain conditions having been met, with the continuing benefit of Dominion Resources' assurances and the Gas Purchase Agreement. For a description of the Underlying Properties, the Royalty Interests and other information relating to such properties, see "Properties--The Royalty Interests." The Trust Agreement authorizes the Trustee to take such action as in its judgment is necessary, desirable or advisable to best achieve the purposes of the Trust. The Trustee is empowered by the Trust Agreement to employ consultants and agents (including the Company, Dominion Energy and Dominion Resources) and to make payments of all fees for services or expenses out of the assets of the Trust. The Trustee is authorized to agree to modifications of the terms of the Conveyance and to settle disputes with respect thereto, so long as such modifications or settlements do not result in treatment of the Trust as an association, taxable as a corporation, for federal income tax purposes and such modifications or settlements do not alter the nature of the Royalty Interests as a right to receive a share of production or the proceeds of production from the Underlying Properties which, with respect to the Trust, are free of any operating rights, expenses or obligations. The Trust Agreement provides that cash being held by the Trustee as a reserve for liabilities or for distribution at the next distribution date will be placed in demand deposit accounts, U.S. government obligations, repurchase agreements secured by such obligations or certificates of deposit, but the Trustee is otherwise prohibited from acquiring any asset other than the Royalty Interests and cash proceeds therefrom or engaging in any business or investment activity of any kind whatsoever. The Trustee may deposit funds awaiting distribution in an account with the Trustee provided the interest rate paid equals the interest rate paid by the Trustee on similar deposits. The Trust has no employees. Administrative functions are performed by the Trustee. RESIGNATION OF TRUSTEES The Trustee and the Delaware Trustee may resign at any time upon 60 days' prior written notice or be removed, with or without cause, by a vote of not less than a majority of the outstanding Units, provided in each case that a successor trustee has been appointed and has accepted its appointment. Any successor must be a bank or trust company meeting certain requirements, including having capital, surplus and undivided profits of at least $100,000,000, in the case of the Trustee, and $20,000,000, in the case of the Delaware Trustee. TRANSFER OF ROYALTY INTERESTS Prior to the termination of the Trust, the Trustee is not authorized to sell or otherwise dispose of all or any part of the Royalty Interests. The Trustee is authorized and directed to sell and convey the Royalty Interests without Unitholder approval upon termination of the Trust. No Unitholder approval for sales or dispositions upon termination is required even though they may constitute a disposition of all or substantially all the assets of the Trust. Any sales upon termination may be made to Dominion Resources or its affiliates. See "--Termination and Liquidation of the Trust." LIABILITIES OF THE TRUST Because of the passive nature of the Trust assets and the restrictions on the activities of the Trustee, the only liabilities the Trust has incurred are those for routine administrative expenses, such as trusteeship fees and accounting, engineering, legal and other professional fees and the administrative services fee paid to Dominion Resources. If a court 5 9 were to hold that the Trust is taxable as a corporation, then the Trust would incur substantial federal income tax liabilities. See also "--State Tax Considerations--Alabama Franchise Tax." LIABILITIES OF THE TRUSTEE AND THE DELAWARE TRUSTEE Each of the Trustee and the Delaware Trustee may act in its discretion and is personally or individually liable only for fraud or acts or omissions in bad faith or which constitute gross negligence (and for taxes, fees and other charges on, based on or measured by any fees, commissions or compensation received pursuant to the Trust Agreement) and will not be otherwise liable for any act or omission of any agent or employee unless such trustee has acted in bad faith or with gross negligence in the selection and retention of such agent or employee. Each of the Trustee and the Delaware Trustee (and their respective agents) is indemnified by Dominion Resources and from the Trust assets for certain environmental liabilities, and for any other liability, expense, claim, damage or other loss incurred in performing its duties, unless resulting from gross negligence, fraud or bad faith (each of the Trustee and the Delaware Trustee is indemnified from the Trust assets against its own negligence which does not constitute gross negligence), and will have a first lien upon the assets of the Trust as security for such indemnification and for reimbursements and compensation to which it is entitled; provided that the Trustee and the Delaware Trustee are generally required to first be indemnified from Trust assets before seeking indemnification from Dominion Resources. Dominion Resources also has agreed to indemnify the Trustee and the Delaware Trustee against certain securities laws' liabilities. Neither the Trustee nor the Delaware Trustee is entitled to indemnification from Unitholders (except in connection with lost or destroyed Unit certificates). Insofar as indemnification for liabilities arising under the Securities Act of 1933, as amended (the "Securities Act"), is permitted to the Trustee pursuant to the foregoing provisions, the Trustee has been informed that in the opinion of the Securities and Exchange Commission (the "Commission") such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. TERMINATION AND LIQUIDATION OF THE TRUST The Trust will terminate upon the occurrence of: (i) an affirmative vote of the holders of not less than 66 percent of the outstanding Units to terminate the Trust; (ii) such time as the ratio of the cash amounts received by the Trust attributable to the Royalty Interests in any calendar quarter to administrative costs of the Trust for such calendar quarter is less than 1.2 to 1.0 for two consecutive calendar quarters; or (iii) March 1 of any year if it is determined, based on a reserve report as of December 31 of the prior year prepared by a firm of independent petroleum engineers mutually selected by the Trustee and the Company, that the net present value (discounted at 10 percent) of (a) estimated future net revenues from proved reserves attributable to the Royalty Interests plus (b) the amount of all remaining Section 29 tax credits attributable to the Royalty Interests, is equal to or less than $5 million (as applicable, the "Termination Date"). Upon such occurrence, the remaining assets of the Trust will be sold, the net proceeds of the sale will be distributed to the Unitholders and the Trust will be wound up and a certificate of cancellation filed. Upon the termination of the Trust, the Trustee will use its best efforts to sell any remaining Royalty Interests then owned by the Trust for cash pursuant to the procedures described in the Trust Agreement. The Trustee will retain a nationally recognized investment banking firm (the "Advisor") on behalf of the Trust who will assist the Trustee in selling the remaining Royalty Interests. The Company has the right, but not the obligation, within 60 days following the Termination Date, to make a cash offer to purchase all of the remaining Royalty Interests then held by the Trust. In the event such an offer is made by the Company, the Trustee will decide, based on the recommendation of the Advisor, to either (i) accept such offer (in which case no sale to the Company will be made unless a fairness opinion is given by the Advisor that the purchase price is fair to the Unitholders) or (ii) defer action on the offer for approximately 60 days and seek to locate other buyers for the remaining Royalty Interests. If the Trustee defers action on the Company's offer, the offer will be deemed withdrawn and the Trustee will then use its best efforts, assisted by the Advisor, to locate other buyers for the Royalty Interests. At the end of the 120-day period following the Termination Date, the Trustee is required to notify the Company of the highest of any other offers acceptable to the Trustee (which must be an all cash offer) received during such period (such price, net of any commissions or other fees payable by the Trust, the "Highest Acceptable Offer"). The Company then has the right (whether or not it made an initial offer), but not the obligation, to purchase all remaining Royalty Interests for a cash purchase price computed as follows: (i) if the Highest Acceptable Offer is more than 105 percent of the Company's original offer (or if the Company did not make an initial offer), the purchase price will be 105 percent of the Highest Acceptable Offer, or (ii) if the Highest Acceptable 6 10 Offer is equal to or less than 105 percent of the Company's original offer, the purchase price will be equal to the Highest Acceptable Offer. If no other acceptable offers are received for all remaining Royalty Interests, the Trustee may request the Company to submit another offer for consideration by the Trustee and may accept or reject such offer. If a sale of the Royalty Interests is made or a definitive contract for sale of the Royalty Interests is entered into within a 150-day period following the Termination Date, the buyer of the Royalty Interests, and not the Trust or Unitholders, will be entitled to all proceeds of production attributable to the Royalty Interests following the Termination Date. In the event that the Company does not purchase the Royalty Interests, the Trustee may accept any offer for all or any part of the Royalty Interests as it deems to be in the best interests of the Trust and Unitholders and may continue, for up to one calendar year after the Termination Date, to attempt to locate a buyer or buyers of the remaining Royalty Interests in order to sell such interests in an orderly fashion. If the Royalty Interests have not been sold or a definitive agreement for sale has not been entered into by the end of such calendar year, the Trustee is required to sell the remaining Royalty Interests at a public auction, which sale may be to the Company or any of its affiliates. The Company's purchase rights, as described above, may be exercised by the Company and each of its successors in interest and assigns. The Company's purchase rights are fully assignable by the Company to any person or entity. The costs of liquidation, including the fees and expenses of the Advisor and the Trustee's liquidation fee will be paid by the Trust. The Trust may terminate without Unitholder approval. Unitholders are not entitled to any rights of appraisal or similar rights in connection with the termination of the Trust. ARBITRATION AND ACTIONS BY UNITHOLDERS Pursuant to the Trust Agreement, any dispute, controversy or claim that may arise between or among Dominion Resources or the Company, on the one hand, and the Trustee, the Delaware Trustee or the Trust, on the other hand, in connection with or otherwise relating to the Trust Agreement or the Conveyance or the application, implementation, validity or breach thereof or any provision thereof, shall be settled by final and binding arbitration in Dallas, Texas in accordance with the Rules of Practice and Procedure for the arbitration of commercial disputes of Judicial Arbitration & Mediation Services, Inc. (or any successor thereto) then in effect. The Administrative Services Agreement also includes a provision that will require Dominion Resources and the Trustee and the Trust to submit any dispute regarding such contract to alternative dispute resolution before litigating such matter. The Trust Agreement requires under certain circumstances that the Trustee and the Trust pursue any claims against Dominion Resources and the Company with respect to any breach by Dominion Resources and the Company of the terms of the Conveyance or the Trust Agreement (and requires that any such claims be brought in arbitration), without the joinder of any Unitholder. The Trust Agreement does not provide for any procedure allowing Unitholders to bring an action on their own behalf to enforce the rights of the Trust under the Conveyance and, except in the case of the failure of the Trustee to enforce certain performance obligations of Dominion Resources to the Trust, does not provide for any procedure allowing Unitholders to direct the Trustee to bring an action on behalf of the Trust to enforce the Trust's rights under the Conveyance. Each Unitholder has a statutory right, however, under Section 3816 of the Delaware Code to bring a derivative action in the Delaware Court of Chancery on behalf of the Trust to enforce the rights of the Trust if the Trustee has refused to bring the action or if an effort to cause the Trustee to bring the action is not likely to succeed. The procedures for the arbitration of disputes enumerated in the Trust Agreement neither bar nor restrict the statutory right of any Unitholder under Section 3816 of the Delaware Code to bring a derivative action. Pursuant to Section 3816 of the Delaware Code, a plaintiff in a derivative action must be a beneficial owner at the time such action is brought and (i) at the time of the transaction subject to such complaint or (ii) the Unitholder's status as a beneficial owner must have devolved upon it by operation of law or pursuant to the terms of the governing instrument of the Trust from a person or entity who was a beneficial owner at the time of the transaction giving rise to the complaint. If a derivative action is successful, in whole or in part, or if anything is received by the Trust as a result of a judgment, compromise or settlement of any such action, the Delaware Chancery Court may award the plaintiff 7 11 reasonable expenses, including reasonable attorney's fees. If any award is so received by the plaintiff, the Delaware Chancery Court will make such award of the plaintiff's expenses payable out of those proceeds and direct the plaintiff to remit to the Trust the remainder thereof. If the proceeds are insufficient to reimburse the plaintiff's reasonable expenses in bringing the derivative action, the Delaware Chancery Court may direct that any such award of the plaintiff's expenses or a portion thereof be paid by the Trust. The rights of the Unitholders to bring a derivative action on behalf of the Trust provided pursuant to the Trust Agreement and Section 3816 of the Delaware Code are substantially similar to the derivative rights afforded stockholders under Section 327 of Chapter 8 of the Delaware General Corporation Law and applicable Delaware case law. In the event that any Unitholder was successful in bringing a derivative action on behalf of the Trust to enforce rights on behalf of the Trust against Dominion Resources or the Company, then such Unitholder could, on behalf of the Trust, pursue such rights against Dominion Resources or the Company, as the case may be, in the Delaware Chancery Court. The Trust Agreement does not require, and expressly provides that it shall not be construed to require, arbitration of a claim or dispute solely between the Trustee and the Delaware Trustee or of any claim or dispute brought by any person or entity, including, without limitation, any Unitholder (whether in its own right or through a derivative action in the right of the Trust), who is not a party to the Trust Agreement. The right of a Unitholder to bring a derivative action on behalf of the Trust with respect to Dominion Resources' obligation to cure certain deficiencies under the Trust Agreement is subject to the restriction that such right may only be exercised by Unitholders owning of record not less than 25 percent of the Units then outstanding (treated as a single class) and then only absent action by the Trustee to enforce any such obligation within 10 days following receipt by the Trustee of a written request served upon the Trustee by such Unitholders to take such action. In such an event, Unitholders owning of record not less than 25 percent of the Units then outstanding may, acting as a single class and on behalf of the Trust, seek to enforce such obligations. See "Properties--The Royalty Interests--Dominion Resources' Assurances." 8 12 DESCRIPTION OF UNITS Each Unit represents an equal undivided share of beneficial interest in the Trust and is evidenced by a transferable certificate issued by the Trustee. Each Unit entitles its holder to the same rights as the holder of any other Unit, and the Trust has no other authorized or outstanding class of equity security. At March 10, 2000, there were 7,850,000 Units outstanding. The Trust may not issue additional Units. DISTRIBUTIONS AND INCOME COMPUTATIONS The Trustee determines for each calendar quarter the amount of cash available for distribution to Unitholders. Such amount (the "Quarterly Distribution Amount") is equal to the excess, if any, of the cash received by the Trust attributable to production from the Royalty Interests during such calendar quarter, provided that such cash is received by the Trust on or before the last business day prior to the 45th day following the end of such calendar quarter, plus the amount of interest expected by the Trustee to be earned on such cash proceeds during the period between the date of receipt by the Trust of such cash proceeds and the date of payment to the Unitholders of such Quarterly Distribution Amount, plus all other cash receipts of the Trust during such calendar quarter (to the extent not distributed or held for future distribution as a Special Distribution Amount or included in the previous Quarterly Distribution Amount) (which might include sales proceeds not sufficient in amount to qualify for a special distribution, as described in the next paragraph, and interest), over the liabilities of the Trust paid during such calendar quarter and not taken into account in determining a prior Quarterly Distribution Amount, subject to adjustments for changes made by the Trustee during such calendar quarter in any cash reserves established for the payment of contingent or future obligations of the Trust. An amount which is not included in the Quarterly Distribution Amount for a calendar quarter because such amount is received by the Trust after the last business day prior to the 45th day following the end of such calendar quarter shall be included in the Quarterly Distribution Amount for the next calendar quarter. The Quarterly Distribution Amount for each calendar quarter will be payable to Unitholders of record on the 60th day following the end of such calendar quarter unless such day is not a business day in which case the record date will be the next business day thereafter. The Trustee will distribute the Quarterly Distribution Amount for each calendar quarter on or prior to 70 days after the end of such calendar quarter to each person who was a Unitholder of record on the record date for such calendar quarter. The Royalty Interests will be sold in whole or in part upon termination of the Trust. Any proceeds from sales of the Royalty Interests, plus any interest expected by the Trustee to be earned thereon, less liabilities and expenses of the Trust and amounts used for cash reserves, will be distributed to Unitholders of record on the record date established for such distribution. A special distribution will be made of undistributed cash proceeds and other amounts received by the Trust aggregating in excess of $10,000,000, plus the amount of interest expected by the Trustee to be earned on such cash proceeds during the period between the date of receipt by the Trust of such cash proceeds and the date of payment to the Unitholders of such special distribution (a "Special Distribution Amount"). The record date for distribution of a Special Distribution Amount will be the 15th day following receipt of amounts aggregating a Special Distribution Amount by the Trust (unless such day is not a business day in which case the record date will be the next business day thereafter) unless such day is within 10 days prior to the record date for a Quarterly Distribution Amount in which case the record date will be the date as is established for the next Quarterly Distribution Amount. Distributions to Unitholders will be no later than 15 days after the Special Distribution Amount record date. Gross income attributable to cash being distributed in most cases will be reported for federal income tax purposes by the Unitholder who receives such distributions assuming that such Unitholder is the owner of record on the applicable record date. In certain circumstances, however, a Unitholder will not receive the cash giving rise to such income. For example, the Trustee maintains a cash reserve, and is authorized to borrow money under certain conditions, in order to pay or provide for the payment of Trust liabilities. Income associated with the cash used to increase that reserve or to repay that loan must be reported by the Unitholder, even though that cash is not distributed to him. Likewise, if a portion of a cash distribution is attributable to a reduction in the cash reserve maintained by the Trustee, such cash is treated as a reduction to the Unitholders' basis in his Units and is not treated as taxable income to such Unitholder (assuming such Unitholder's basis exceeds the amount of the distribution of cash reserve). 9 13 CONDITIONAL RIGHT OF REPURCHASE Dominion Resources (and any of its successor and affiliates) has the right to repurchase all (but not less than all) outstanding Units at any time at which 15 percent or less of the outstanding Units are owned by persons or entities other than Dominion Resources and its affiliates. Subject to the following sentence, any such repurchase would be at a price equal to the greater of (i) the highest price at which Dominion Resources or any of its affiliates acquired Units during the 90 days immediately preceding the date (the "Determination Date") which is three New York Stock Exchange ("NYSE") trading days prior to the date on which notice of such exercise is delivered to the Unitholders and (ii) the average closing price of Units on the NYSE for the 30 trading days immediately preceding the Determination Date. If Dominion Resources or any of its affiliates acquires Units (other than an acquisition from Dominion Resources or any affiliate) during the period that is three NYSE trading days after the Determination Date at a price per Unit greater than that at which an acquisition was made during the 90-day period referred to in clause (i) of the preceding sentence, then for purposes of clause (i) of the preceding sentence the highest price used therein will be such greater price. Any such repurchase would be conducted in accordance with applicable federal and state securities laws. In the event that Dominion Resources elects to purchase all Units, Dominion Resources and the Trustee will, prior to the date fixed for purchase, give all Unitholders of record not less than 15 days' nor more than 60 days' written notice specifying the time and place of such repurchase, calling upon each such Unitholder to surrender to Dominion Resources on the repurchase date at the place designated in such notice its certificate or certificates representing the number of Units specified in such notice of repurchase. On or after the repurchase date, each holder of Units to be repurchased must present and surrender its certificates for such Units to Dominion Resources at the place designated in such notice and thereupon the purchase price of such Units will be paid to or on the order of the person or entity whose name appears on such certificate or certificates as the owner thereof. In no event may fewer than all of the outstanding Units represented by the certificates be repurchased (except for any Units held by Dominion Resources and any of its affiliates). If Dominion Resources and the Trustee give a notice of repurchase and if, on or before the date fixed for repurchase, the funds necessary for such repurchase are set aside by Dominion Resources, separate and apart from its other funds in trust for the pro rata benefit of the holders of the Units so noticed for repurchase, then, notwithstanding that any certificate for such Units has not been surrendered, at the close of business on the repurchase date the holders of such Units shall cease to be Unitholders and shall have no interest in or claims against Dominion Resources, the Company, the Trust, the Delaware Trustee or the Trustee by virtue thereof and shall have no voting or other rights with respect to such Units, except the right to receive the purchase price payable upon such repurchase, without interest thereon and without any other distributions for record dates after the date of notice of repurchase, upon surrender (and endorsement, if required by Dominion Resources) of their certificates, and the Units evidenced thereby shall no longer be held of record in the names of such Unitholders. Subject to applicable escheat laws, any monies so set aside by Dominion Resources and unclaimed at the end of two years from the repurchase date shall revert to the general funds of Dominion Resources, after which reversion the holders of such Units so noticed for repurchase could look only to the general funds of Dominion Resources for the payment of the purchase price. Any interest accrued on funds so deposited would be paid to Dominion Resources from time to time as requested by Dominion Resources. In the event that Dominion Resources exercises and consummates its right of repurchase, then at its option it may cause the Trust to be terminated by providing written notice thereof to the Trustee and the Delaware Trustee. Within 30 days following written notice of Dominion Resources' decision to terminate the Trust, the Trustee must cause any remaining Royalty Interests (and, subject to the rights of Unitholders with respect to the receipt of distributions for which a record date has been determined, all proceeds of production attributable to the Royalty Interests) and any other assets of the Trust to be conveyed to Dominion Resources or its assignee (subject to the right of such trustees to create reasonable reserves in connection with the liquidation of the Trust). 10 14 POSSIBLE DIVESTITURE OF UNITS The Trust Agreement imposes no restrictions based on nationality or other status of Unitholders. The Trust Agreement provides, however, that in the event of certain judicial or administrative proceedings seeking the cancellation or forfeiture of any property in which the Trust has an interest, or asserting the invalidity of, or otherwise challenging any portion of the Royalty Interests because of the nationality, citizenship or any other status of any one or more Unitholders, the Trustee will give written notice thereof to each Unitholder whose nationality, citizenship or other status is an issue in the proceeding, which notice will constitute a demand that such Unitholder dispose of his Units within 30 days. If any Unitholder fails to dispose of his Units in accordance with such notice, the Trustee will cancel all outstanding certificates issued in the name of such Unitholder, transfer all Units held by such Unitholder to the Trustee and sell such Units (including by private sale). The proceeds of such sale (net of sales expenses), pending delivery of certificates representing the Units, will be held by the Trustee in a non-interest bearing account for the benefit of the Unitholder and paid to the Unitholder upon surrender of such certificates. Cash distributions payable to such Unitholder will also be held in a non-interest bearing account pending disposition by the Unitholder of the Units or cancellation of certificates representing the Units by the Trustee, subject to a maximum retention period of two years or such shorter period as shall be permitted by applicable laws. PERIODIC REPORTS The Trustee causes a reserve report to be prepared for the Trust (by a firm of independent petroleum engineers mutually selected by the Trustee and the Company) each year showing estimated proved natural gas reserves and other reserve information attributable to the Royalty Interests as of December 31 of such year. Such reserve reports show estimated future net revenues and the net present value (discounted at 10 percent) of the estimated future net revenues (using the year-end Contract Price as of December 31) from proved reserves attributable to the Royalty Interests and the amount of the estimated net present value (discounted at 10 percent) of the remaining Section 29 tax credits attributable to the Royalty Interests. The costs of the reserve reports are paid by the Trust and constitute an administrative expense. The Trustee also provides to Dominion Resources and the Company, within 15 days after the end of each calendar quarter, a written itemized report showing all administrative costs of the Trust paid during such quarter. Within 75 days following the end of each of the first three calendar quarters of each calendar year, the Trustee mails to each person or entity who was a Unitholder of record (i) on the record date for each such calendar quarter and (ii) on a Special Distribution Amount record date occurring during such quarter, if any, a report which shows in reasonable detail the assets and liabilities and receipts and disbursements of the Trust for such calendar quarter. Within 120 days following the end of each fiscal year, the Trustee mails to Unitholders of record as of a date to be selected by the Trustee an annual report containing audited financial statements which includes reserve information relating to the Trust and the Royalty Interests. The Trustee files such returns for federal income tax purposes as it is advised are required to comply with applicable law. The Trustee mails to each person or entity who was a Unitholder of record (i) on the record date for each such calendar quarter and (ii) on a Special Distribution Amount record date occurring during such quarter, if any, a report which shows in reasonable detail information to permit each Unitholder to make all calculations reasonably necessary for tax purposes. The Trustee treats all income, credits and deductions recognized during each calendar quarter during the term of the Trust as having been recognized by holders of record on the quarterly record date established for the distribution unless otherwise advised by counsel. Available year-end tax information permitting each Unitholder to make all calculations reasonably necessary for tax purposes is distributed by the Trustee to Unitholders no later than March 15 of the following year. Each Unitholder and his duly authorized agents and attorneys have the right during reasonable business hours upon reasonable prior notice to examine and inspect records of the Trust and the Trustee and the Delaware Trustee. 11 15 VOTING RIGHTS OF UNITHOLDERS While Unitholders have certain voting rights as provided in the Trust Agreement, such rights differ from and are more limited than those of stockholders of a corporation for profit. For example, there is no requirement for annual meetings of Unitholders or for annual or other periodic reelection of the Trustee. Meetings of Unitholders may be called by the Trustee or by Unitholders owning not less than 10 percent of the outstanding Units. In addition, the Delaware Trustee may call such a meeting but only for the purpose of appointing a successor to it upon its resignation. All meetings of Unitholders will be held in Dallas, Texas. Written notice of every such meeting setting forth the time and place of the meeting and the matters proposed to be acted upon will be given not more than 60 nor less than 20 days before such meeting is to be held to all of the Unitholders of record at the close of business on a record date selected by the Trustee, which record date will not be more than 60 days before the date of such meeting. The presence in person or by proxy of Unitholders representing a majority of the outstanding Units is necessary to constitute a quorum. Each Unitholder is entitled to one vote for each Unit owned by such Unitholder. The Trustee will call such meetings to consider amendments, waivers, consents and other changes relating to the Conveyance, if requested in writing by the Company or Dominion Resources. No matter other than that stated in the notice of the Unitholder meeting will be voted on and no action by the Unitholders may be taken without a meeting. Generally, amendments to the Trust Agreement require approval of a majority of the outstanding Units (except that amendments of required voting percentages requires approval of at least 80 percent of the outstanding Units), but no provision of the Trust Agreement may be amended that would (i) increase the power of the Trustee or the Delaware Trustee to engage in business or investment activities or (ii) alter the rights of the Unitholders as among themselves. Without the written consent of Dominion Resources and the approval of not less than 66 percent of the outstanding Units, no provision of the Trust Agreement may be amended with respect to (a) the sale or disposition of all or any part of the Trust estate, including the Royalty Interests, except as specifically provided in the Trust Agreement, (b) termination of the Trust and the disposition of Trust assets upon liquidation of the Trust or (c) the Company's right of first refusal with respect to the purchase of any remaining Royalty Interests upon termination of the Trust. Without the written consent of Dominion Resources and the approval of a majority of the outstanding Units, no amendment may be made to the Trust Agreement that would alter Dominion Resources' conditional right to repurchase all outstanding Units at any time at which 15 percent or less of the outstanding Units is owned by persons or entities other than Dominion Resources or its affiliates. Additionally, any amendment that increases the obligations, duties or liabilities of or affects the rights of the Trustee or the Delaware Trustee must be consented to by such entity. The Trustee, the Delaware Trustee, Dominion Resources and the Company may, without approval of the Unitholders, from time to time supplement or amend the Trust Agreement in order to cure any ambiguity or to correct or supplement any defective or inconsistent provisions, provided such supplement or amendment is not adverse to the interests of the Unitholders. In addition, (i) Dominion Resources may direct the Trustee to change the name of the Trust without approval of the Unitholders and (ii) in the event that a business purpose of the Trust is found or deemed to exist by any taxing or other authority on which finding any taxation authority might rely, the Trustee is authorized to amend or delete and, subject to the receipt of an opinion of counsel reasonably satisfactory to the Trustee, the Trustee, the Delaware Trustee, Dominion Resources and the Company will amend or delete any provision of the Trust Agreement or take such other action as may be necessary to eliminate such business purpose, without approval of the Unitholders. Removal of the Trustee and the Delaware Trustee, approval of amendments, waivers, consents and other changes relating to the Conveyance and the approval of the merger or consolidation of the Trust into one or more entities require approval of a majority of the outstanding Units. Except as set forth under "Description of the Trust--Termination and Liquidation of the Trust," all other actions may be approved by a majority vote of the Units represented at a meeting at which a quorum is present or represented. LIABILITY OF UNITHOLDERS Consistent with Delaware law, the Trust Agreement provides that the Unitholders will have the same limitation on liability as is accorded under Delaware law to stockholders of a corporation for profit. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation. 12 16 TRANSFER AGENT Chase Mellon Shareholder Services serves as transfer agent and registrar for the Units. FEDERAL INCOME TAX CONSIDERATIONS THE TAX CONSEQUENCES TO A UNITHOLDER OF THE OWNERSHIP AND SALE OF UNITS WILL DEPEND IN PART ON THE UNITHOLDER'S TAX CIRCUMSTANCES. EACH UNITHOLDER SHOULD THEREFORE CONSULT THE UNITHOLDER'S TAX ADVISOR ABOUT THE FEDERAL, STATE AND LOCAL TAX CONSEQUENCES TO THE UNITHOLDER OF THE OWNERSHIP OF UNITS. The sections entitled "Federal Income Tax Consequences" and "Risk Factors--Tax Considerations" appearing in the Prospectus set forth, respectively, a discussion of the material federal income tax matters of general application of the acquisition, ownership and sale of the Units acquired in the Public Offerings and a discussion of certain risk factors associated with matters of federal income taxation as applied to the Trust and such Unitholders. In connection with the registration of the Units for offer and sale in the Public Offerings, Dominion Resources and the Underwriters received certain opinions of special counsel ("Special Counsel") to Dominion Resources (upon which the Trustee and the Delaware Trustee were entitled to rely), including, without limitation, opinions as to the material federal income tax consequences of the ownership and sale of the Units acquired in either of the Public Offerings. Each of these opinions was based on provisions of the Code existing as of June 28, 1994 with respect to the opinions given in connection with the Initial Public Offering and as of June 8, 1995 with respect to the opinions given in connection with the Secondary Public Offering, and existing and proposed regulations thereunder, administrative rulings and court decisions as of such dates, all of which are subject to changes that may or may not be retroactively applied. Some of the applicable provisions of the Code have not been interpreted by the courts or the IRS. In addition, such opinions were based on various representations as to factual matters made by the Company and Dominion Resources in connection with the Public Offerings. In addition, such opinions were expressly limited in their application to investors purchasing Units in each of such Public Offerings and, as a result, provide no assurance to investors not purchasing Units in one of the Public Offerings. Neither the Trustee, the Delaware Trustee, nor counsel to the Trustee, respectively, has rendered any opinions with respect to any tax matters associated with the Trust or the Units. No ruling was requested by Dominion Resources, as the sponsor of the Trust, the Trustee or the Delaware Trustee from the IRS with respect to any matter affecting the Trust or Unitholders. No assurance can be provided that the opinions of Special Counsel (which do not bind the IRS) will not be challenged by the IRS or will be sustained by a court if so challenged. SUMMARY OF CERTAIN FEDERAL INCOME TAX CONSEQUENCES The following summary of certain federal income tax consequences of acquiring, owning and disposing of Units is based on the opinions of Special Counsel to Dominion Resources on oil and gas and federal income tax matters, which are set forth in the Prospectus. The summary is not exhaustive and many other provisions of the federal tax laws may affect individual Unitholders, and the summary is not intended to address the tax issues potentially affecting Unitholders acquiring Units other than by purchase through either of the Public Offerings. Each Unitholder should consult the Unitholder's tax advisor with respect to the effects of the Unitholder's ownership of Units on the Unitholder's personal tax situation. Classification and Taxation of the Trust .................................... The Trust is a grantor trust and not an association taxable as a corporation. As a grantor trust, the Trust is not subject to federal income tax. There can be no assurance that the IRS will not challenge this treatment. The tax treatment of the Trust and Unitholders would be
13 17 materially different if the IRS were to successfully challenge this treatment. Economic Substance of Ownership of Units ................................. Generally, a taxpayer is entitled to claim deductions and tax credits generated by an investment only if the investment has economic substance. The application of this principle in the context of the production and sale of nonconventional fuels (like coal seam gas) which generate the Section 29 tax credit is uncertain because such application has not been addressed either by a court or the IRS. An investment has economic substance if the investor can demonstrate that there is a reasonable possibility of deriving an economic profit from the investment in excess of a de minimis amount, apart from tax benefits. In many cases, economic profit has been computed by comparing the taxpayer's total cash investment to the total cash reasonably expected to be received by the taxpayer as a result of the investment (a "Pre-Tax Profit Objective"). At the time of the Public Offerings, Special Counsel to Dominion Resources expressed the opinion (only in connection with the Public Offerings) that the ownership of Units purchased in either of the Public Offerings, whose ownership of Units is not subject to puts, calls or other risk allocation devices, has economic substance even if the owner has no Pre-Tax Profit Objective. No assurance is given either by the Trustee or counsel to the Trustee to a purchaser of Units in or following the Public Offerings as to whether (and to what extent) such purchaser is or will be entitled to claim deductions and the Section 29 tax credit generated with respect to such Units. Taxation of Unitholders ...................... Each Unitholder is taxed directly on his proportionate share of income, deductions and credits of the Trust attributable to the Royalty Interests consistent with each such Unitholder's taxable year and method of accounting and without regard to the taxable year or method of accounting employed by the Trust. Income and Deductions ........................ The income of the Trust consists primarily of a specified share of the proceeds from the sale of coal seam gas produced from the Underlying Properties. During 1999, the Trust earned interest income on funds held for distribution and made adjustments to the cash reserve maintained for the payment of contingent and future obligations of the Trust. The deductions of the Trust consist of property, production and related taxes and administrative expenses. In addition, each Unitholder is entitled to depletion deductions. See "Unitholder's Depletion Allowance" below. Section 29 Tax Credits ...................... Unitholders are entitled, provided certain requirements are met, to claim tax credits pursuant to Section 29 of the Code with respect to sales of coal seam gas production attributable to the Royalty Interests that is produced from the Existing Wells, the gross income from which is included in their taxable income. The Section 29 tax credit provides to a taxpayer a dollar-for-dollar reduction in his regular federal income tax liability and, therefore, generally provides to him a greater benefit than a deduction, which merely reduces the amount of his taxable income. Such credits may be earned each year until the year beginning January 1, 2003. For a Unitholder who owned the same Units of record on all four quarterly record dates during 1999, the available Section 29 tax credit is approximately $1.224738 per Unit, based on the first estimate of the GNP implicit price deflator published by the Bureau of Economic Analysis.
14 18 The availability of Section 29 tax credits is dependent upon meeting a number of requirements, many of which are factual in nature. The Company and Dominion Resources represented in connection with the Public Offerings only that those factual requirements were met. At the time of each of the Public Offerings, Special Counsel opined as to those requirements which are statutory or legal in nature. If any of the factual requirements are not met, or the opinion not followed, some or all of the expected Section 29 tax credits may not be available. Limits on Unitholder's Use of Credits .................................. In any year, a Unitholder is permitted to reduce his regular federal income tax liability by the Section 29 tax credits allocated to such Unitholder for such year on a dollar-for- dollar basis, but only to the extent such Unitholder's regular tax liability exceeds his alternative minimum tax liability (with certain adjustments). Any amount of Section 29 tax credit in excess of a Unitholder's total regular federal income tax liability for a year is permanently lost. Section 29 tax credits cannot be used to reduce a Unitholder's liability for any alternative minimum tax for any taxable year but can be carried forward to reduce his regular tax liability in a subsequent year (subject to the applicable rules governing such carryforward(s)). Quarterly Allocations ........................ Under the Code, a Unitholder is entitled to Section 29 tax credits only to the extent that he is an owner of the economic interest at the time the coal seam gas is produced. The Trustee allocates the income received by the Trust during a quarter, and the Section 29 tax credit allocable to such income, to Unitholders of record on the quarterly record date for such quarter. Such an allocation may be challenged by the IRS, but any challenge is likely to have a material adverse impact only if successful and only for Unitholders who do not own Units for a full quarter for each record date, particularly Unitholders who acquire Units shortly before a record date and sell shortly after a record date. At the time of each of the Public Offerings, Special Counsel declined to express an opinion as to whether the IRS would accept quarterly allocations or would require income, credits and deductions of the Trust to be determined and allocated daily based on ownership at the time of production or on some other basis. Treatment of the Royalty Interests ................................ Each Royalty Interest is a nonoperating economic interest in an Underlying Property because it is a right to a fixed percentage of the gross proceeds from the sale of gas as, if and when produced from such properties, the right endures for the economic life of the burdened reserves and the right is not required to bear any cost in developing or producing such gas. Unitholder's Depletion Allowance ................................ Each Unitholder is entitled to amortize the cost of the Units through cost depletion over the life of the Royalty Interests (or, if greater, through percentage depletion equal to 15 percent of gross income). If any portion of the Royalty Interests is treated as a production payment or is not treated as an economic interest, however, a Unitholder will not be entitled to depletion in respect of such portion. No depletion allowances were available to Unitholders in respect of production from the Royalty Interests prior to June 28, 1994.
15 19 Non-Passive Activity Income, Credits and Loss ......................... The income, credits and expenses of the Trust are not taken into account in computing the passive activity losses and income under Section 469 of the Code for a Unitholder who acquires and holds Units as an investment and did not acquire them in the ordinary course of a trade or business. Section 29 tax credits generated by an investment in Units, therefore, can be utilized to offset regular tax liability on income from any source whether active or passive, subject to other limitations discussed herein or arising from the individual tax circumstances of each Unitholder. See "Limits on Unitholder's Use of Credits" above. Tax Shelter Registration ..................... The Trust is registered as a "tax shelter" and its tax shelter registration number is 94-277000355. Issuance of a tax shelter registration number does not indicate that the investment in Units or the claimed tax benefits have been reviewed, examined or approved by the IRS. Substantial Understatement Penalty .................................. Section 6662 of the Code imposes a penalty in certain circumstances for a substantial understatement of taxes if a taxpayer's tax liability is understated by more than the greater of (i) 10 percent of the taxes required to be shown on the return and (ii) $5,000 ($10,000 for most corporations). The penalty (which is not deductible) is 20 percent of the understatement. Except in the case of understatements attributable to "tax shelter" items, which are subject to special rules discussed below, an item of understatement will not give rise to the penalty if: (i) there is or was "substantial authority" for the taxpayer's treatment of the item or (ii) all the facts relevant to the tax treatment of the item are adequately disclosed on the return or on a statement attached to the return and there is a reasonable basis for the tax treatment of such item. In the case of Units, an individual Unitholder may make adequate disclosure with respect to particular tax items if certain conditions are met. Special rules enacted in December 1994 could affect the application of these provisions with regard to a corporation acquiring Units after December 8, 1994, to the extent such provisions were found to apply to the ownership of Units. In the case of understatements attributable to "tax shelter" items, the substantial understatement penalty may be avoided only if the taxpayer establishes that, in addition to having substantial authority for his position, he reasonably believed that the treatment claimed was more likely than not the proper treatment of the item. A "tax shelter" item is one that arises from a form of investment if its principal purpose was the avoidance or evasion of Federal income tax. Regulations promulgated by the IRS indicate that an entity or person has a principal purpose of avoidance or evasion of Federal income tax if that purpose "exceeds any other purpose." No assurance is given either by the Trustee or counsel to the Trustee as to the possible application of this penalty, in part because such application depends largely upon the individual circumstances under which the Units were acquired. As a result, purchasers of Units in and after the Public Offerings should consult with their personal tax advisors.
16 20 Unitholder Reporting Information .............................. The Trustee furnishes to Unitholders tax information concerning royalty income, depletion and the Section 29 tax credits on an annual basis. Year-end tax information is furnished to Unitholders no later than March 15 of the following year. Unless the final information issued by the U.S. Treasury Department at the end of March regarding the amount of the section 29 credit for 1999 differs materially from the Trustee's estimate, the final information will be contained in the next quarterly report. However, to the extent the final information issued by the U.S. Treasury Department causes the tax credit amounts for 1999 to materially differ from the Trustee's estimates contained in the 1999 Tax Information booklet, the Trustee will promptly mail final tax credit information to each affected Unitholder.
ERISA CONSIDERATIONS The section entitled "ERISA Considerations" appearing in the Prospectus sets forth certain information regarding the applicability of the Employee Retirement Income Security Act of 1974, as amended, and the Code to pension, profit-sharing and other employee benefit plans and to individual retirement accounts (collectively, "Qualified Plans"). Due to the complexity of the prohibited transaction rules and the penalties imposed upon persons involved in prohibited transactions, it is important that potential Qualified Plan investors consult with their counsel regarding the consequences under ERISA and the Code of their acquisition and ownership of Units. STATE TAX CONSIDERATIONS The following is intended as a brief discussion of certain state tax matters affecting individuals who are Unitholders. Unitholders are urged to consult their own legal and tax advisors with respect to these matters. ALABAMA INCOME TAX All revenues attributable to the Royalty Interests are derived from sources within the State of Alabama. Alabama imposes an income tax on individuals, corporations and certain other entities that are residents of, conduct business in, or derive income from sources within, Alabama. Under general rules of application, both resident and nonresident Unitholders would be required to file annual Alabama income tax returns and pay Alabama income taxes with respect to any income received from the Trust and would be subject to penalties for failure to comply with those rules. Alabama tax counsel has advised the Trust that the Alabama Department of Revenue (the "DOR") will permit the Trust to file a "composite income tax return" on behalf of all Unitholders who are not residents of Alabama, and that the filing of the composite income tax return and acceptance of the return by DOR will relieve those nonresident Unitholders of any obligation to file Alabama state income tax returns. The Trust filed for 1995, 1996, 1997 and 1998 composite income tax returns with the DOR on behalf of all Nonresident Unitholders (defined below), and intends to file a composite return for 1999 and each year thereafter for so long as the composite return will not report any taxable income for Alabama state income tax purposes. Based on certain assumptions, the composite income tax return to be filed by the Trust on behalf of Nonresident Unitholders will show a net taxable loss for 1999. Accordingly, no Alabama state income tax is due under the 1999 return. No assurance can be given, however, that the DOR will accept the assumptions used by the Trust in preparing and filing the composite income tax return for any year and determining the composite taxable income or loss thereunder for Alabama state income tax purposes. If all or a portion of those assumptions are not acceptable to the DOR, the DOR may require the Trust to recompute and refile one or more composite income tax returns based on different assumptions acceptable to the DOR. If the composite income tax return for 1999 (or any other tax year) as initially filed by the Trust is not accepted as filed by the DOR, the Trust may decide not to refile a composite income tax return either (i) because the Trust would have net Alabama taxable income for that 17 21 year as a result of the assumptions required by the DOR or (ii) because the refiling of the composite income tax return imposes an unreasonable burden on the Trust in the judgment of the Trustee (based on its sole discretion). In that event, each Nonresident Unitholder would be required to file a separate Alabama state income tax return and pay any Alabama state income tax due as well as any penalties and interest due thereon. For purposes of the filing of the composite income tax return for any taxable year, "Nonresident Unitholders" will consist of those Unitholders to whom the Trust has provided an individualized tax information letter (together with its tax information booklet) for such tax year which shows a mailing address outside the State of Alabama. All other Unitholders will be treated by the Trust for purposes of the filing of the composite income tax return as "Resident Unitholders." The filing of the composite income tax return by the Trust does not relieve any resident of the State of Alabama or any Resident Unitholder from the obligation to file an Alabama state income tax return individually (and pay Alabama state income tax thereon, if any) with respect to the revenues and expenses attributable to the Royalty Interests. In light of the foregoing, each Unitholder should consult his tax adviser regarding the requirements for filing state income tax returns for his state of residence and Alabama. ALABAMA FRANCHISE TAX Alabama imposes a franchise tax on domestic corporations and foreign corporations doing business in Alabama, under a broad definition of "corporation" in the state constitution, based on the amount of a corporation's "capital employed" in the state. In reliance upon the representations and assumptions set forth in the Prospectus and on a private letter ruling issued June 10, 1994 by the DOR as to the offering of the Units, special Alabama tax counsel to the Company opined in connection with each of the Public Offerings that the Trust is not subject to Alabama franchise tax. Although the Alabama Commissioner of Revenue has the authority to revoke retroactively DOR rulings under certain limited circumstances, special Alabama tax counsel did not believe, based on the above representations and assumptions, that those circumstances exist with respect to the Company's private letter ruling. Dominion Resources has agreed to indemnify the Trust against any resulting Alabama franchise tax imposed on the Trust. ALABAMA SEVERANCE TAXES The DOR has proposed a set of regulations that indicate the DOR is considering changing the way it computes the amount of severance taxes due by disallowing certain deductions previously allowed on audit. Such a change could result in an increase in the amount of severance taxes due for natural gas production. Since the Trust, as owner of the Royalty Interests, bears its proportionate share of severance taxes, any increase in the amount of severance taxes will decrease the amount of cash distributions payable to Unitholders. The Company has informed the Trust that it has been advised by Alabama counsel that it is impossible to predict whether this change will be implemented (by regulations or otherwise) and, if so, whether and in what amount severance taxes may be increased. OTHER ALABAMA TAXES The Trust has been structured to cause the Units to be treated as interests in intangible personal property rather than as interests in real property for certain Alabama state law purposes, other than income and franchise taxation. If the Units are held to be real property or as interests in real property under the laws of Alabama, Unitholders could be subject to Alabama probate laws, and estate and similar taxes, whether or not they are residents of Alabama. 18 22 REGULATION AND PRICES REGULATION OF NATURAL GAS Certain aspects of production, transportation and sale of natural gas from the Underlying Properties may be subject to federal and state governmental regulation, including regulation of transportation tariffs charged by pipelines, taxes, the prevention of waste, the conservation of natural gas, pollution controls and various other matters. As a result of the Natural Gas Policy Act of 1978 ("NGPA") and the Natural Gas Wellhead Decontrol Act of 1989 ("NGWDA"), as of January 1, 1993, the wellhead price for natural gas is no longer subject to federal regulation. All sales of natural gas produced from the Underlying Properties are considered under NGPA and NGWDA to be sold at the wellhead (as opposed to downstream sales or resales) for purposes of pricing and, therefore, are not subject to federal regulation. The transportation of natural gas in interstate commerce is subject to federal regulation by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act ("NGA") and the NGPA. FERC has initiated a number of regulatory policy initiatives that may affect the transportation of natural gas from the wellhead to the market and thus may affect the marketing of natural gas. Such initiatives include regulations intended to further open access to interstate pipelines by requiring such pipelines to unbundle their transportation services from sales services and allow customers to choose and pay for only the services they require, regardless of whether the customer purchases natural gas from such pipelines or from other suppliers. Although these regulations should generally facilitate the transportation of natural gas produced from the Underlying Properties to natural gas markets, the impact of these regulations on marketing production from the Underlying Properties cannot be predicted at this time and could be significant. In the past, Congress has been very active in the area of natural gas regulation. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on the Underlying Properties and the Trust. The State Oil and Gas Board of Alabama regulates the production of natural gas, including requirements for obtaining drilling permits, the method of developing new fields, provisions for the unitization or pooling of natural gas properties, the spacing, operation, plugging and abandonment of wells and the prevention of waste of natural gas resources. The rate of production may be regulated and the maximum daily production allowable from natural gas wells may be established on a market demand or conservation basis or both. Reductions in allowable production may extend the timing of recovery of reserves. Although the Trust is not aware of any pending or contemplated proceedings to change allowable rates of production from the Underlying Properties, there can be no assurances made that such changes will not be made. The Unitholders and the Trust will not have any control over such changes. Reductions in the allowable production from the Underlying Properties could affect the timing or amount of distributions to Unitholders. ENVIRONMENTAL REGULATION Operations on the Underlying Properties associated with the production of natural gas are subject to numerous federal and state laws, rules and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment. Such laws, rules and regulations require the acquisition of certain permits, impose substantial liabilities for pollution resulting from exploration and production operations and may also restrict air or other pollution resulting from operations. It is possible that federal and state environmental laws and regulations will become more stringent in the future. For instance, legislation has been proposed in Congress in connection with the pending reauthorization of the Federal Resource Conservation and Recovery Act ("RCRA") that would amend RCRA to reclassify certain oil and gas production wastes as "hazardous waste." If adopted, this amendment would result in more rigorous and expensive disposal requirements. It is impossible to predict what the precise effect additional regulation or legislation, or enforcement policies thereunder, could have on the operation of the Underlying Properties. However, any costs or expenses incurred by the Company in connection with environmental liabilities arising out of or relating to activities occurring on, in or in connection with, or conditions existing on or under, the Underlying Properties, will be borne by the Company and not the Trust and such costs and expenses will not be deducted in calculating Gross Proceeds. Such costs and expenses may, however, be taken into account by the Company 19 23 in exercising its rights to abandon a well and may accelerate the termination of the Trust. See "Properties--The Royalty Interests--Sale and Abandonment of Underlying Properties" and "Properties--Description of the Trust--Termination and Liquidation of the Trust." Water from the operations on the Underlying Properties is discharged into the Black Warrior River pursuant to a National Pollutant Discharge Elimination System permit issued by the Alabama Department of Environmental Management ("ADEM"). ADEM initially issued five permits in connection with the Underlying Properties which were consolidated into one permit in February 1994. The ADEM permit was renewed in 1999 and will expire in July 2004. It generally authorizes water disposal based upon the Black Warrior River's minimum flow rate and maximum chloride level. The Company has advised the Trust that since 1987 water disposal from the Underlying Properties has not been disrupted. While the Company has informed the Trust that it believes the Underlying Properties are in material compliance with all environmental laws and regulations, such regulations have generally become more stringent and costly over time. As a royalty holder the Trust may not be directly subject to increased costs; however, such costs may be taken into account by the Company in exercising its rights to abandon a well, which may accelerate the termination of the Trust. The Company has informed the Trust that it estimates that it plans to expend approximately $92,000 during 2000 for anticipated expenditures related to compliance with environmental laws. COMPETITION, MARKETS AND PRICES The revenues of the Trust and the amount of cash distributions to Unitholders depend upon, among other things, the effect of competition and other factors in the market for natural gas. The natural gas industry is highly competitive in all of its phases. The Company encounters competition from major oil and gas companies, independent oil and gas concerns and individual oil and gas producers and operators. Many of these competitors have greater financial and other resources than the Company. Competition may also be presented by alternative fuel sources, including heating oil and other fossil fuels. Demand for natural gas production has historically been seasonal in nature and prices for natural gas fluctuate accordingly. Unseasonably warm weather and the ability of markets to access storage can cause the demand for natural gas to decrease, resulting in lower prices received by producers than when demand is higher due to seasonal weather factors. Such price fluctuations and any continuation of a depressed market for natural gas will directly impact Trust distributions, estimates of reserves attributable to the Royalty Interests and estimated future net revenue from reserves attributable to the Royalty Interests. Prices for natural gas are subject to wide fluctuations in response to relatively minor changes in supply, market uncertainty and a variety of additional factors that are beyond the control of the Trust and the Company. These factors include political conditions in the Middle East, the price and quantity of imported oil and gas, the level of consumer product demand, the severity of weather conditions, government regulations, the price and availability of alternative fuels and overall economic conditions. Additionally, lower natural gas prices may reduce the amount of gas that is economic to produce from the Underlying Properties. The Trust's revenues and distributions to Unitholders will be primarily dependent on the sales prices for Gas produced from the Underlying Properties and the quantities of Gas sold. Natural gas prices have historically been volatile and are likely to continue to be volatile. Price volatility and the risk of production curtailment make it difficult to estimate the future levels of cash distributions to Unitholders or the value of the Units. While the Minimum Price will mitigate to some extent the negative effects of such volatility, the Maximum Price may limit the benefits Unitholders realize from future price increases. See "Properties--The Royalty Interests--Gas Purchase Agreement." 20 24 ITEM 2. PROPERTIES. THE ROYALTY INTERESTS The Royalty Interests held by the Trust generally entitle the Trust to receive 65 percent of Gross Proceeds. The Royalty Interests were conveyed to the Trust by means of a single instrument of conveyance. The Conveyance was recorded in the appropriate real property records in Alabama, so as to give notice of the Royalty Interests to creditors, and any transferees will take an interest in the Underlying Properties subject to the Royalty Interests. The Conveyance was intended to convey the Royalty Interests as real property interests under Alabama law. The following description of the material provisions of the Conveyance and the Trust Agreement is subject to and qualified by the more detailed provisions of the Conveyance and the Trust Agreement included as exhibits to this Form 10-K. THE UNDERLYING PROPERTIES Black Warrior Basin. The Black Warrior Basin covers 6,000 square miles in west central Alabama and contains seven Pennsylvania age multi-seam coal groups in the Pottsville formation: the Black Creek, Mary Lee, Pratt, Cobb, Gwin, Utley and Brookwood coal groups. The Pottsville coal formation ranges from the surface to a depth of 4,100 feet. Wells in the Black Warrior Basin produce natural gas from coal seam formations that have production characteristics materially different from conventional natural gas wells. The primary factor affecting recovery of gas reserves from coal seams in the Black Warrior Basin is the lowering of reservoir pressure through "dewatering" operations. In a typical coal seam gas well on the Underlying Properties, average daily natural gas production generally will increase as wells are "dewatered" until natural gas production reaches a "peak" at which time natural gas production will decline. The amount of time necessary to "dewater" a well and cause it to reach its peak production, and the ultimate level of a well's peak production, are difficult to estimate. Since all of the 532 wells included in the Underlying Properties were producing by mid- 1991, the Company believes that production from such wells is currently past its peak and will decline over the term of the Trust. The Royalty Interests were conveyed by the Company to the Trust out of the Company Interests. The Existing Wells are operated by River Gas in accordance with the Operating Agreement. See "--Operation of Properties." The Underlying Properties comprise 34,212 gross acres of land in an area approximately five miles wide and 23 miles long located on the Tuscaloosa to Bankhead Lake portion of the Black Warrior Basin. Initial production began in December 1988 and consisted of eight wells. The Company acquired its interest in the Underlying Properties in December 1992. As of December 31, 1999, the Underlying Properties contained 532 wells that were producing gas, all of which were drilled prior to 1993. Well Count and Acreage Summary. The following table shows as of December 31, 1999, the gross and net producing wells and acreage for the Company Interests. The net wells and acreage are determined by multiplying the gross wells or acres by the Company Interests Owner's working interest in the wells or acreage.
NUMBER OF WELLS ACRES --------------- ------------------ GROSS NET GROSS NET ----- --- ------ ------ Company Interests 532 519 34,212 33,391
Royalty Interests, Company Interests and Retained Interests. On June 1, 1994, the effective date of the Conveyance, the Company had an average aggregate working interest in the Existing Wells of approximately 98 percent, and an average aggregate net revenue interest of approximately 80 percent in the Existing Wells. The Company has not sold or otherwise disposed of any of its interest in the Company Interests since June 1, 1994. The Royalty Interests are entitled to approximately 52 percent of the net revenue from natural gas produced and sold from the Underlying 21 25 Properties and the interests (the "Retained Interests") of the Company in the Underlying Properties (after giving effect to the Royalty Interests) entitle the Company to receive approximately 28 percent of the net revenue from the natural gas produced and sold from the Underlying Properties. As a working interest owner in the Underlying Properties, the Company is responsible for an average of approximately 98 percent of the operating costs of the Existing Wells. The Royalty Interests do not burden (i) royalties and other obligations, expressed or implied, under oil or natural gas leases, (ii) the overriding royalties and other burdens created by the Company's predecessors in title or (iii) the working interests owned by other individual working interest owners. Water Removal and Disposal. Water from the wells located on the Underlying Properties is pumped from the wellhead to one of five water disposal systems, each with two ponds, where the water is analyzed and chemically treated to remove impurities, if necessary, prior to discharge into the Black Warrior River. Water from the operations on the Underlying Properties is discharged into the Black Warrior River pursuant to a National Pollutant Discharge Elimination System permit issued by ADEM that will expire in July 2004. The ADEM permit generally authorizes water disposal based upon the Black Warrior River's minimum flow rate and maximum chloride level. The Company has advised the Trust that since 1987 water disposal from the Underlying Properties has not been disrupted. Although the facilities of the Company have the capacity to store several days of water production, if water disposal into the Black Warrior River is disrupted, natural gas production from the wells on the Underlying Properties would be curtailed during the period of such disruption. See "Business--Regulation and Prices--Environmental Regulation." Curtailments. The Company has advised the Trust that, during 1999, production from the Underlying Properties was not curtailed for any reason other than for routine maintenance. Federal Lands. Approximately one percent (360 acres) of the Underlying Properties are leases on land held by the federal government. Royalty payments due to the U.S. government for natural gas produced from federal lands included in the Underlying Properties must be calculated in conformance with a working interest owner's interpretation of regulations issued by the Minerals Management Service ("MMS"). MMS regulations cover both valuation standards, which establish the basis for placing a value on production, and cost allowances, which define those post-production costs that are deductible by the lessee. The Trust is subject to certain rules of the Bureau of Land Management under which the holding of interests in leases by persons other than citizens, nationals and legal resident aliens of the United States ("Eligible Citizens") are limited. As a result, non-Eligible Citizens are prohibited from owning Units. If any Units are acquired by persons or entities not constituting Eligible Citizens, such Unitholders may be required to sell such Units pursuant to a procedure set forth in the Trust Agreement. See "Business--Description of the Trust--Possible Divestiture of Units." Additional Wells. Well spacing rules, which are in effect in Alabama, generally govern the space between wells drilled to the same productive formation and are promulgated in order to prevent waste and confiscation of property. Pursuant to such rules, the Existing Wells are located on 40 to 80 acre spacing units. Exceptions or changes to these rules may be granted by the applicable regulatory agency upon application of an interested party following notice to other interested parties if, in the agency's opinion, good reasons exist therefor after consideration of evidence presented by the applicant and any opponents. The Company has informed the Trust that it is not aware of any plans to change spacing regulations with respect to the Underlying Properties in Alabama. No assurances can be made, however, that exceptions or changes will not be made in the future. The Company and its affiliates or unrelated third parties may acquire interests in properties adjoining the Underlying Properties. It is possible that wells drilled on adjoining properties would drain reserves attributable to the Underlying Properties. The Company has agreed for the term of the Trust not to consent to, cooperate with, assist in or conduct infill drilling (except as required by law) on any of the Underlying Properties in which the Company owned an interest as of June 1, 1994. Although the Company believes that it is unlikely that any additional wells will be drilled, if the Operating Agreement is terminated, the Company cannot prevent one of the other owners of an interest in the Underlying Properties from drilling additional wells on the Underlying Properties. Additional wells, if drilled, could recover a portion of the reserves otherwise producible from wells burdened by the Company Interests, thereby reducing the Gross 22 26 Proceeds attributable to the Royalty Interests. The Company has advised the Trust that it is not aware of any wells that have been drilled by others on spacing units adjacent to the Company Interests since the date of the Conveyance. THE ROYALTY INTERESTS Summary of Conveyance. The Conveyance has been filed as an exhibit to this Form 10-K. The following summary of the material terms of the Conveyance is qualified in its entirety by reference to the terms thereof as set forth in such exhibit. Expenses Borne by Royalty Interests. The Royalty Interests are non-operating, non-expense bearing interests except for their share of property, production and related taxes, including severance taxes. Accordingly, owners of the Royalty Interests are not liable or responsible for costs or liabilities incurred by the working interest owners in connection with the production of Gas from the Underlying Properties. Operating Standard. The Company Interests Owner is obligated to conduct and carry on, as would a reasonably prudent operator, or cause to be so conducted or carried on, the development, maintenance and operation of the Company Interests. Infill Drilling. The Company Interests Owner has agreed not to consent to, cooperate with, assist in or conduct any infill drilling on the Underlying Properties, except as required by law. Pratt Recompletions. To recover behind pipe reserves, the Company Interests Owner recompleted certain of the Existing Wells to the Pratt coal seam prior to March 31, 1997. Right to Take in Kind. The owner of the Royalty Interests has no right to take production in-kind. Pooling and Unitization. The Company Interests Owner has certain pooling and unitization rights. Right to Assign Company Interests. The Company Interests Owner has the right to assign all or any part of the Company Interests, subject to the Royalty Interests and the terms and provisions of the Conveyance. If any such assignment is made of part, but not all, of such interests, then effective as of the date of such assignment the assignee will be required to make a separate computation of Gross Proceeds attributable to the assigned interests. Sale or Assignment of Royalty Interests. In certain situations, the Trust may sell or dispose of all or a part of the Royalty Interests, in which case the Trust would receive the proceeds therefrom and distribute such proceeds to the Unitholders, net of any amounts held as a reserve. See "Business--Description of the Trust--Transfer of Royalty Interests" and "Business--Description of the Trust--Duties and Limited Powers of the Trustee." Books and Records. The Company Interests Owner is required to maintain books and records sufficient to determine the amounts payable with respect to the Royalty Interests. Computation and Payment. The Royalty Interests entitle the Trust to receive 65 percent of the Gross Proceeds. The Royalty Interests bear their proportionate share of property, production and related taxes (including severance taxes). The definitions, formulas and accounting procedures and other terms governing the computation of the Royalty Interests are set forth in the Conveyance. The Company Interests Owner is required, pursuant to the Conveyance, to pay to the Trust amounts received by the Company Interests Owner from the sale of Subject Gas attributable to the Royalty Interests. Under the Conveyance, the amounts payable by the Company Interests Owner with respect to the Royalty Interests are computed with respect to each calendar quarter ending prior to termination of the Trust, and such amounts are paid to the Trust not later than the last business day before the 45th day following the end of each calendar quarter. The amounts paid to the Trust do not include interest on any amounts payable with respect to the Royalty Interests which are held by the Company Interests Owner prior to payment to the Trust. The Company Interests Owner is entitled to retain all amounts attributable to the Retained Interests. The Company Interests Owner deducts from the payment to the Trust the Royalty Interests' share of property, production and related taxes (including severance taxes) and pays the same on behalf of the Trust. 23 27 RESERVE ESTIMATE Reserve Estimate. The following table summarizes net proved reserves estimated as of January 1, 2000, and certain related information for the Royalty Interests from the Reserve Estimate prepared by Ryder Scott. The natural gas reserves were estimated by Ryder Scott by applying volumetric and decline curve analyses. All of such reserves constitute proved developed gas reserves. The Reserve Estimate was prepared in accordance with criteria established by the Commission.
AS OF ROYALTY INTERESTS JANUARY 1, 2000 ----------------- --------------- Net Proved Natural Gas Reserves (MMcF)(a)(b): Developed Producing .............................................. 69,180 ========= Estimated Future Net Revenues (in thousands) (a)(c): 2000 ............................................................. $ 26,203 2001 ............................................................. 23,326 2002 ............................................................. 20,789 2003 ............................................................. 11,732 2004 ............................................................. 10,496 Thereafter ....................................................... 72,185 -------- Total ......................................................... $ 164,731 ========= Total Discounted at 10 Percent ................................ $ 102,854 =========
- ---------- (a) The estimates of reserves and future net revenues summarized in this table are based upon an unescalated price of $2.16 per MCF, which was the price being received by the Company under the Gas Purchase Agreement as of December 31, 1999. This price may not be the most representative price for estimating reserves or related future net revenues data. See "--Gas Purchase Agreement." (b) The estimated economic life of the wells comprising the Royalty Interests has been determined taking into account the Section 29 tax credits. (c) Estimated future net revenues are defined as the total revenues attributable to the Royalty Interests for gas production less the relevant share of production, property and related taxes (including severance taxes). Overhead costs have not been included, nor have the effects of depreciation, depletion and federal income tax. Estimated future net revenues do not include any Section 29 tax credits, although, as discussed in footnote (b) above, Section 29 tax credits have been taken into account in determining the estimated economic life of the wells comprising the Royalty Interests. Estimated future net revenues and discounted estimated future net revenues are not intended and should not be interpreted as representing the fair market value for the estimated reserves. The reserve data set forth herein, which was prepared by Ryder Scott in a manner customary in the industry, is an estimate only, and actual quantities, rates of production and sales prices for natural gas are likely to differ from the estimated amounts set forth herein, and such differences could be significant. There are many uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production. Reserve engineering is a subjective process of estimating underground accumulations of natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of the geological and engineering evaluation of that data. Results of testing and production subsequent to the date of an estimate may justify revision of such estimate. Further, reserve estimates for any given property may vary from engineer to engineer even though each engineer bases his estimate on common data and utilizes techniques and principles customary in the industry. For properties with short production histories, reserve estimates in many instances are based upon volumetric calculations and upon analogy to similar types of production or producing fields. Relative to many conventional natural 24 28 gas producing properties, coal seam gas producing properties in general, and the Underlying Properties in particular, have short production histories. In addition, there are no significant coal seam reservoirs which have been produced to depletion that can be used as analogies to the Underlying Properties. The discounted estimated future net revenues shown herein were prepared using guidelines established by the Commission and may not be representative of the market value for the estimated reserves. The reserves attributable to the Royalty Interests are expected to decline substantially during the term of the Trust and a portion of each cash distribution made by the Trust will, therefore, be analogous to a return of capital. As a result, cash distributions will decrease materially over time. For example, based upon the production estimates set forth in the Reserve Estimate, annual production attributable to the Royalty Interests is estimated to decline from 8.4 Bcf in 2000 to 5.2 Bcf in 2004. Tax Credits Based on Reserves. Based upon the production estimates used in the Reserve Estimate for the January 1, 2000 through December 31, 2002 period, and assuming constant future Section 29 tax credits at the estimated 2000 rate of $1.08 per MMBtu, the estimated total future tax credits available from the production and sale of the net proved reserves from the Royalty Interests would be approximately $24.3 million, having a discounted present value (assuming a 10 percent discount rate) of approximately $20.3 million. Miscellaneous. Ryder Scott has delivered to the Trust the Reserve Estimate, a summary of which is included as an exhibit to this Form 10-K. Information concerning historical changes in net proved developed reserves attributable to the Royalty Interests, and the calculation of the standardized measure of discounted future net revenues related thereto, is contained in Note 8 of the Notes to the Financial Statements incorporated by reference in Item 8 hereof. Dominion Resources has not filed reserve estimates covering the Royalty Interests with any other federal authority or agency. NATURAL GAS SALES PRICES AND PRODUCTION The following table sets forth the actual net production volumes attributable to the Royalty Interests, weighted average property, production and related taxes and information regarding natural gas sales prices for the years ended December 31, 1999, December 31, 1998 and December 31, 1997.
YEAR ENDED Year ended Year ended DECEMBER 31, 1999 December 31, 1998 December 31, 1997 ----------------- ----------------- ----------------- Production attributable to the Royalty Interests (Bcf) .................................. 9.2 10.6 11.3 Weighted average property, production and related taxes (per Mcf) .......................... $ .13 $ .12 $ .13 Average Contract Price (per Mcf) .................... $ 2.37 $ 2.14 $ 2.40
GAS PURCHASE AGREEMENT Sonat Marketing Company ("Sonat Marketing") is required under a gas purchase agreement to purchase the gas produced from the Underlying Properties for as long as reserves on the Underlying Properties produce natural gas. Under the agreement, Sonat Marketing is obligated to purchase up to a specified monthly base quantity of gas for a contract price which provides for a specified premium (between $.05 and $.07 per MMBtu) over the Index Price (as defined below). Until December 31, 1998, the contract price paid was subject to a minimum price of $1.85 per MMBtu and a maximum price of $2.63 per MMBtu. From January 1, 1999 through December 31, 1999, the Contract Price paid was subject to a minimum price of $2.16 per MMBtu and a maximum price of $3.07 per MMBtu. Beginning effective January 1, 2000 and through December 31, 2000, the price paid on Index Price Quantities is subject to a minimum price of $2.20 and a maximum price of $2.82. Prior to April 1, 1996, Sonat Marketing was obligated to purchase gas production in 25 29 excess of the specified monthly base quantities at the Index Price. Effective April 1, 1996 through December 31, 1998, the price payable for such excess gas production equaled the Index Price plus $.02. Effective January 1, 1999, the price payable for such excess gas production equaled the Index Price plus $.02. Effective January 1, 2000, the price payable for such excess gas production shall equal the Index Price plus $.02. The "Index Price," which is determined on a monthly basis, is Southern Natural Gas Company's posted index price for deliveries of gas in Louisiana. Sonat Marketing's obligation to purchase gas pursuant to the Gas Purchase Agreement (as well as the Company's obligation to sell such natural gas) may be suspended to the extent affected by the occurrence of any event not within the control of the affected party that renders the affected party unable to perform its obligations under the Gas Purchase Agreement if the event could not have been prevented by the exercise of reasonable diligence including: acts of God, strikes, lockouts or other industrial disturbances, acts of the public enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, storms, floods, washouts, arrests and restraints of governments and people, civil disturbances, explosions, breakage or accident to machinery or lines of pipe, the necessity for maintenance of or making repairs or alterations to machinery or lines of pipe, freezing of wells or lines of pipe, partial or entire failure of wells, curtailment, interruption or other unavailability of transportation, inability to acquire or delay in acquiring at reasonable cost and by the exercise of reasonable diligence, servitudes, rights of way, grants, permits, permissions, licenses, materials or supplies that are required to enable the affected party to perform its obligations. Following any such event, the affected party's obligations under the Gas Purchase Agreement will be suspended during the period of its inability to perform, and such party will as far as possible remedy the event with reasonable dispatch. During the pendency of any such suspension, the cash available for distribution, and the depletion deductions and Section 29 tax credits available for allocation, by the Trust to Unitholders could be reduced materially or eliminated entirely. Sonat Marketing has entered into a put and call agreement with a nationally recognized commodities brokerage firm intended to limit its losses in the event that the Index Price falls below the Minimum Price. Pursuant to the Gas Purchase Agreement Amendment, Sonat Marketing's obligation to enter into such a put and call agreement terminated on January 1, 1999. The Gas Purchase Agreement is filed as an exhibit to this Form 10-K, and the foregoing summary of the material terms of such agreement is qualified in its entirety by reference to the terms of such agreement as set forth in such exhibit. OPERATION OF PROPERTIES No Control by Trust. Under the terms of the Conveyance, neither the Trustee nor the Unitholders will be able to influence or control the operation or future development of the Underlying Properties. Unitholders will therefore be reliant on the Company and the other working interest owners to make all decisions regarding operations on the Underlying Properties. The Trust will not be able to appoint or control the appointment of operators. The Conveyance does not prohibit the transfer of the Underlying Properties by the Company, subject to and burdened by the Royalty Interests. The Company and the other working interest owners of the Underlying Properties will have the right, subject to certain restrictions, to abandon any well or lease on the Underlying Properties under certain circumstances. Upon abandonment of any such well or lease, that portion of the Royalty Interests relating thereto will be extinguished. See "--Sale and Abandonment of the Underlying Properties." Operating Agreement. Pursuant to the Operating Agreement, River Gas operates and maintains the Underlying Properties for the Company and the other working interest owners. The Operating Agreement has a one-year term and will be automatically renewed for additional one-year periods unless either party provides written notice to the other party of its desire to terminate the Operating Agreement at least six months prior to the date on which the agreement is to terminate. Upon not less than 30 days' notice either River Gas or the Company may terminate the Operating Agreement if: (i) the other party has committed a material breach of the Operating Agreement, unless such breach is cured in the manner specified in the Operating Agreement; (ii) the other party files a petition for relief under federal or state bankruptcy laws, the other party's insolvency is determined by a final court proceeding, the other party's filing of a petition or application to accomplish such a result or for the appointment of a receiver or trustee for such party or 26 30 for a substantial part of its assets or commencement of any proceedings relating to the other party under any other reorganization, arrangement, insolvency, adjustment of debt or liquidation law of any jurisdiction; provided, however, that if such proceeding is not commenced, the proceeding will not give rise to a right to terminate the Operating Agreement unless such party consents or such proceeding has not been finally dismissed within 90 days after its commencement; or (iii) after good faith negotiations River Gas and the Company and the other working interest owners cannot agree on an annual operating plan or budget for any year. While the Operating Agreement is in effect, all of the production attributable to the Company Interests will be gathered, treated and processed by River Gas pursuant to the Operating Agreement. Such production will be gathered at the wellhead and transported to the central delivery points in the gathering system for the Underlying Properties, which is owned by the Company and the other working interest owners. Under the terms of the Operating Agreement, River Gas owes a duty to the Company and the other working interest owners to conduct the operations on the Underlying Properties in a good and workmanlike manner and following practices that (i) are engaged in or accepted by a significant portion of the natural gas production industry at the time the decision was made or (ii) in the exercise of reasonable judgment in light of the facts known at the time the decision was made would have been expected to accomplish the desired result at a reasonable cost consistent with reliability, safety, expeditiousness and protection of the environment. River Gas has no direct contractual or fiduciary duty to protect the interests of the Trust or the Unitholders. SALE AND ABANDONMENT OF UNDERLYING PROPERTIES The Company has the right to abandon any well or lease included in the Underlying Properties if, in its opinion, acting as would a reasonably prudent operator, such well or lease is not capable of producing Gas in commercial quantities (determined before giving effect to the Royalty Interests). Neither the Trust nor the Unitholders will control the timing of the plugging and abandoning of any wells. Through December 31, 1999, none of the wells included in the Underlying Properties had been plugged and abandoned. The Company may sell its interest in the Underlying Properties, subject to and burdened by the Royalty Interests, without the consent of the Trust or the Unitholders. Under the Trust Agreement, the Company has certain rights (but not the obligation) to purchase the Royalty Interests upon termination of the Trust. See "Business--Description of the Trust Agreement--Termination and Liquidation of the Trust." DOMINION RESOURCES' ASSURANCES Pursuant to the Trust Agreement, Dominion Resources has agreed to cause each of the following obligations to be paid in full when due: (i) all liabilities and operating and capital expenses that any Company Interests Owner becomes obligated to pay as a result of such Company Interests Owner's obligations under the Conveyance and (ii) the obligations of the Company to indemnify the Trust, the Trustee and the Delaware Trustee for certain environmental liabilities under the Trust Agreement (collectively, the "Payment Obligations"). The Trustee may, at any time after the 10th day following receipt by Dominion Resources of written notice from the Trustee that a Payment Obligation has not been paid when due, make demand of Dominion Resources for payment stating the amount due. Dominion Resources is obligated to cure any failure to pay the obligation within 10 days following receipt of the foregoing demand. After written request of the Unitholders owning of record not less than 25 percent of the Units then outstanding served upon the Trustee, and absent action by the Trustee within 10 days following receipt by the Trustee of such written request to enforce such obligations for the benefit of the Trust, such Unitholders may, acting as a single class and on behalf of the Trust, seek to enforce Dominion Resources' performance obligations. All of Dominion Resources' obligations will terminate upon: (i) the termination and cancellation of the Trust, (ii) the sale or other transfer by the Company of all or substantially all of the Company's interest in the Underlying Properties subject to the terms of the Trust Agreement and (iii) the sale or other transfer of a majority of Dominion 27 31 Resources' direct or indirect equity ownership interest in the Company; provided that, with respect to clauses (ii) and (iii) above, Dominion Resources' obligations will terminate only if: (a) the transferee has a specified credit rating or the transferee together with an affiliate which guarantees the transferee's obligations has not less than a specified net worth or (b) the transferee is approved by the holders of a majority of the outstanding Units; and provided further, that in the case of clauses (ii) or (iii) above the transferee also unconditionally agrees in writing, in form and substance reasonably satisfactory to the Trustee, to assume Dominion Resources' remaining obligations under the Trust Agreement with respect to the assets transferred and under the Administrative Services Agreement. TITLE TO PROPERTIES Alabama counsel to Dominion Resources and the Company has opined that the Company's title to its interest in the Underlying Properties, and the Trust's title to the Royalty Interests, are good and defensible in accordance with standards generally accepted in the natural gas industry, subject to such exceptions which, in the opinion of Alabama counsel, are not so material as to detract substantially from the use or value of the Company Interests or the Royalty Interests. Although the matter is not entirely free from doubt, Alabama counsel has opined that the Royalty Interests constitute interests in real property under Alabama law. Consistent therewith, the Conveyance states that the Royalty Interests constitute real property interests. The Company has recorded the Conveyance in the appropriate real property records of Alabama in accordance with local recordation provisions. If, during the term of the Trust, the Company or any Company Interests Owner becomes involved as a debtor in bankruptcy proceedings under the Federal Bankruptcy Code, it is not entirely clear that the Royalty Interests would be treated as real property interests under the laws of Alabama. ITEM 3. LEGAL PROCEEDINGS. There are no material pending legal proceedings to which the Trust is a party or of which any of its property is the subject. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. Not applicable. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. The units of beneficial interest ("Units") in the Trust are listed and traded on the New York Stock Exchange under the symbol "DOM". The following table sets forth, for the periods indicated, the high and low sales prices per Unit on the New York Stock Exchange and the amount of quarterly cash distributions per Unit paid by the Trust. 28 32
PRICE ---------------------------- DISTRIBUTION HIGH LOW PER UNIT ---------- ---------- ------------ 1999 First Quarter ........... $ 16.000 $ 14.25 $ .600258 Second Quarter .......... 15.875 14.6875 .567476 Third Quarter ........... 15.75 14.50 .600583 Fourth Quarter .......... 14.8125 10.3125 .694369 1998 First Quarter ........... $ 21.25 $ 18.375 $ .874821 Second Quarter .......... 22.75 19.8750 .670386 Third Quarter ........... 21.6875 16.8750 .672017 Fourth Quarter .......... 20.125 12.8750 .614702
At March 10, 2000, there were 7,850,000 Units outstanding and approximately 1,408 Unitholders of record. ITEM 6. SELECTED FINANCIAL DATA.
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------------------ 1999 1998 1997 1996 1995 ------------ ------------ ------------ ------------ ------------ Royalty Income $ 20,031,958 $ 22,849,760 $ 24,977,563 $ 26,013,428 $ 21,603,550 Distributable Income $ 19,385,356 $ 22,226,804 $ 24,338,026 $ 25,423,282 $ 20,947,426 Distributable Income per Unit $ 2.47 $ 2.83 $ 3.10 $ 3.24 $ 2.67 Distributions per Unit $ 2.46 $ 2.83 $ 3.10 $ 3.24 $ 2.66 Total Assets, December 31 $ 75,397,111 $ 85,645,529 $ 97,774,353 $109,761,403 $125,641,485 Total corpus, December 31 $ 75,273,180 $ 85,533,029 $ 97,670,701 $109,562,077 $125,545,839
ITEM 7. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The Trust collects the proceeds attributable to the Royalty Interests and makes quarterly cash distributions to Unitholders. The only assets of the Trust, other than cash and cash equivalents being held for the payment of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests. The Royalty Interests owned by the Trust burden the interest in the Underlying Properties that is owned by the Company. The Royalty Interests consist of overriding royalty interests burdening the Company's interest in the Underlying Properties. The Royalty Interests generally entitle the Trust to receive 65 percent of the Gross Proceeds (as defined below) during the preceding calendar quarter. The Royalty Interests are non-operating interests and bear only expenses related to property, production and related taxes (including severance taxes). "Gross Proceeds" consist generally of the aggregate amounts received by the Company attributable to the interests of the Company in the Underlying Properties from the sale of coal seam gas at the central delivery points in the gathering system for the Underlying Properties. Production from coal seam gas wells drilled after December 31, 1979 and prior to January 1, 1993, is believed to qualify for the Federal income tax credit for producing nonconventional fuels under Section 29 of the Internal Revenue Code. This tax credit is calculated annually based on each year's qualified production through the year 2002. Such credit, based on a Unitholder's pro rata share of qualifying production, may not reduce his regular tax liability (after the foreign tax credit and certain other non-refundable credits) below his alternative minimum tax. Any part of the Section 29 credit not allowed for the tax year solely because of this limitation is subject to certain carryover provisions. The Trustee is provided Section 29 tax credit information related to Trust Properties by Dominion Resources, which is then passed along to the Unitholders. In 1997, the Tax Court upheld the Internal Revenue Service ("IRS") position that nonconventional fuel such as coal seam gas does not qualify for the Section 29 credit unless the producer received a formal certification from the Federal Energy Regulatory Commission ("FERC"). The FERC's certification authority expired effective January 1, 1993. During March 1999, the U.S. Court of Appeals for the 10th Circuit affirmed that decision. The appeal (which is not binding as precedent) suggests that lack of a certification from FERC may render Section 29 credits unavailable in respect of production from wells recompleted in a qualified formation after January 1, 1993, the date that the FERC's certification authority expired (so that obtaining the requisite determination for any such well was impossible). Many producers believe that wells meeting the certification requirements are eligible for the Section 29 credits regardless of FERC certification. However, this position is not in accordance with the IRS position, the decision of the Tax Court or the decision of the U.S. Court of Appeals. The ability of the Trust to realize the carrying value of its reserves and the ability of the Unitholders to utilize allocated Section 29 credits could be in question with respect to any uncertificated wells. In some cases the extent to which production from the various coal seam gas wells in which the Trust holds an interest would qualify for the Section 29 credit under the standards applied in the appealed case is unclear, and the Trustee has requested that Dominion Resources provide clarification and an assessment of the effects of the foregoing, if any, on the Trust and its Unitholders. Pending such clarification and assessment, or further developments, or both, however, the availability of Section 29 credits to Unitholders in respect of some portion of the Trust's coal seam gas production could be subject to debate and challenge. Distributable income of the Trust consists of the excess of royalty income plus interest income over the administrative expenses of the Trust. Upon receipt by the Trust, royalty income is invested in short-term investments in accordance with the Trust Agreement until its subsequent distribution to Unitholders. 29 33 The amount of distributable income of the Trust for any calendar year may differ from the amount of cash available for distribution to the Unitholders in such year due to differences in the treatment of the expenses of the Trust and the determination of those amounts. The financial statements of the Trust are prepared on a modified cash basis pursuant to which the expenses of the Trust are recognized when they are paid or reserves are established. Consequently, the reported distributable income of the Trust for any year is determined by deducting from the income received by the Trust the amount of expenses paid by the Trust during such year. The amount of cash available for distribution to Unitholders is determined after adjustment for changes in reserves for unpaid liabilities in accordance with the provisions of the Trust Agreement. (See Note 5 to the financial statements of the Trust appearing elsewhere in this Form 10-K for additional information regarding the determination of the amount of cash available for distribution to Unitholders.) The year 1999 marked the fifth full year of the existence of the Trust. The Trust received royalty income amounting to $20,031,958 during the year ended December 31, 1999 compared to $22,849,760 for 1998 and $24,977,563 for 1997. The royalty income received by the Trust was net of the Royalty Interest's allocable share of property, production and related taxes. Administrative expenses during the year ended December 31, 1999 remained relatively stable at $703,308 compared to $699,832 for 1998 and $713,380 for 1997. Distributable income for the year ended December 31, 1999 was $19,385,356 or $2.47 per Unit compared to $22,226,804 or $2.83 per Unit for 1998 and $24,338,026 or $3.10 per Unit for 1997. Royalty income to the Trust is attributable to the sale of depleting assets. All of the Underlying Properties burdened by the Royalty Interests consist of producing properties. Accordingly, the proved reserves attributable to the Company's interest in the Underlying Properties are expected to decline substantially during the term of the Trust and a portion of each cash distribution made by the Trust will, therefore, be analogous to a return of capital. Accordingly, cash yields attributable to the Units are expected to decline over the term of the Trust. The decreases in royalty income and distributable income noted in the preceding paragraph were due primarily to this depletion of reserves and to a decrease in the average prices received for gas attributable to the Royalty Interests. Royalty Income received by the Trust in a given calendar year will generally reflect the proceeds from the sale of gas produced from the Underlying Properties during the first three quarters of that year and the fourth quarter of the preceding calendar year due to the timing of the receipt of these revenues. Accordingly, the royalty income included in distributable income for the years ended December 31, 1999, 1998 and 1997, was based on production volumes and natural gas prices for the periods from October 1, 1998 to September 30, 1999, October 1, 1997 through September 30, 1998 and October 1, 1996 to September 30, 1997, respectively. 30 34 The following table sets forth the production volumes attributable to the Trust's Royalty Interests and the average sales Price and Index Price for such production for the periods indicated.
FOR 12 MONTHS ENDED SEPTEMBER 30, ---------------------------------------- 1999 1998 1997 -------- -------- -------- Production (Bcf)(1) 9.482 10.588 11.515 Production (MMBtu)(2) 9.391 10.494 11.404 Average Contract Price Received ($/MMBtu) $ 2.24 $ 2.29 $ 2.32 Average Index Price ($/MMBtu) $ 2.25 $ 2.35 $ 2.48
(1) Billion cubic feet of natural gas (2) Trillion British Thermal Units. - ---------- The information in this Form 10-K concerning production and prices relating to the Royalty Interests is based on information prepared and furnished by the Company to the Trustee. The Trustee has no control over and no responsibility relating to the operation of or accounting for the Underlying Properties. Sonat Marketing Company ("Sonat Marketing") is required under a gas purchase agreement to purchase the gas produced from the Underlying Properties for as long as reserves on the Underlying Properties produce natural gas. Under the agreement, Sonat Marketing is obligated to purchase up to a specified monthly base quantity of gas for a contract price which provides for a specified premium (between $.05 and $.07 per MMBtu) over the Index Price (as defined below). Until December 31, 1998, the contract price paid was subject to a minimum price of $1.85 per MMBtu and a maximum price of $2.63 per MMBtu. Beginning effective January 1, 1999, the Contract Price paid was subject to a minimum price of $2.16 per MMBtu and a maximum price of $3.07 per MMBtu. Beginning effective January 1, 2000 and through December 31, 2000, the price paid on Index Price Quantities is subject to a minimum price of $2.20 and a maximum price of $2.82. Prior to April 1, 1996, Sonat Marketing was obligated to purchase gas production in excess of the specified monthly base quantities at the Index Price. Effective April 1, 1996 through December 31, 1998, the price payable for such excess gas production equaled the Index Price plus $.02 per MMBtu. Effective January 1, 1999, the price payable for such excess gas production equaled the Index Price plus $.02 per MMBtu. Effective January 1, 2000, the price payable for such excess gas production shall equal The Index Price plus $.02 per MMBtu. The "Index Price," which is determined on a monthly basis, is Southern Natural Gas Company's posted index price for deliveries of gas in Louisiana. The net proved reserves attributable to the Royalty Interests have been estimated as of December 31, 1999, 1998, 1997 and 1996, by independent petroleum engineers. The reserve quantities of 69.2 Bcf for 1999 compared to 74.7 Bcf for 1998, 94.5 Bcf for 1997 and 82.4 Bcf for 1996 reflect a decline in reserves between 1998 and 1999 as a result of production. See "Financial Statements and Supplementary Data --Notes to Financial Statements-- Note 8." YEAR 2000 Many existing computer programs use only two digits to identify a year in the date field. These programs were designed and developed without considering the impact of the recent change in the century. If not corrected, it was believed that many computer applications could fail or create erroneous results by or at the Year 2000. The Year 2000 issue potentially affected virtually all companies and organizations, and it was believed that material adverse consequences could result if a company or organization did not successfully address its Year 2000 issues. The Trustee took various steps to identify, assess and remediate its potential Year 2000 problems that might have affected the Trust. The total cost of the Trustee's Year 2000 efforts was approximately $10,000, all of which was incurred and paid during the last quarter of 1998 and during 1999. Of this amount, the Trustee has paid $9,000 for identification, assessment and remediation of affected systems. The expenditures made in connection with the Year 2000 efforts described above represent substantially all of the Trustee's information technology-related expenditures 31 35 on behalf of the Trust during 1999. These expenditures have been treated as Trust expenses on the financial statements of the Trust. The Trustee identified and contacted those vendors it believed could have an impact on its day-to-day operations if their operations were interrupted as a result of Year 2000 problems. Substantially all essential vendors reported to the Trustee that they had addressed and resolved their internal Year 2000 issues prior to January 1, 2000. Neither the Trustee, nor to the Trustee's knowledge any of the Trustee's important vendors experienced any material Year 2000 system failures. To the Trustee's knowledge, Year 2000 issues have had no material adverse impact on the Trust or on the Trust's ability to make timely Trust distributions to Unitholders. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. The Trust invests in no derivative financial instruments, and has no foreign operations or long-term debt instruments. The Trust is a passive entity and other than the Trust's ability to periodically borrow money as necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited from engaging in borrowing transactions. The amount of any such borrowings is unlikely to be material to the Trust. The Trust periodically holds short term investments acquired with funds held by the Trust pending distribution to Unitholders and funds held in reserve for the payment of Trust expenses and liabilities. Because of the short-term nature of these borrowings and investments and certain limitations upon the types of such investments which may be held by the Trust, the Trustee believes that the Trust is not subject to any material interest rate risk. The Trust does not engage in transactions in foreign currencies which could expose the Trust or Unitholders to any foreign currency related market risk. 32 36 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. INDEPENDENT AUDITORS' REPORT Unitholders of Dominion Resources Black Warrior Trust and Bank of America, N.A., Trustee We have audited the accompanying statements of assets, liabilities and trust corpus of Dominion Resources Black Warrior Trust (the "Trust") as of December 31, 1999 and 1998, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As described in Note 2 to the financial statements, these statements were prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than generally accepted accounting principles. In our opinion, such financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of the Trust at December 31, 1999 and 1998, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 1999, on the basis of accounting described in Note 2. /s/ DELOITTE & TOUCHE LLP Dallas, Texas March 9, 2000 33 37 DOMINION RESOURCES BLACK WARRIOR TRUST FINANCIAL STATEMENTS STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
December 31, -------------------------------- 1999 1998 ------------ ------------ ASSETS Cash and cash equivalents ......................................... $ 124,159 $ 59,455 Royalty interests in gas properties (less accumulated amortization of $80,544,548 and $70,231,426, respectively) ..... 75,272,952 85,586,074 ------------ ------------ Total Assets ............................................... $ 75,397,111 $ 85,645,529 ============ ============ LIABILITIES AND TRUST CORPUS Trust expenses payable ............................................. $ 123,931 $ 112,500 Trust corpus (7,850,000 units of beneficial interest authorized, issued and outstanding) ............................ 75,273,180 85,533,029 ------------ ------------ Total Liabilities and Trust Corpus ......................... $ 75,397,111 $ 85,645,529 ============ ============
STATEMENTS OF DISTRIBUTABLE INCOME
Year Ended --------------------------------------------------------- December 31, 1999 December 31, 1998 December 31, 1997 ----------------- ----------------- ----------------- Royalty income ...................................... $ 20,031,958 $ 22,849,760 $ 24,977,563 Interest income ..................................... 56,706 76,876 73,843 ------------ ------------ ------------ 20,088,664 22,926,636 25,051,406 General and administrative expenses ................. 703,308 699,832 713,380 ------------ ------------ ------------ Distributable income ................................ $ 19,385,356 $ 22,226,804 $ 24,338,026 ============ ============ ============ Distributable income per unit (7,850,000 units) ..... $ 2.47 $ 2.83 $ 3.10 ============ ============ ============ Distributions per unit .............................. $ 2.46 $ 2.83 $ 3.10 ============ ============ ============
STATEMENTS OF CHANGES IN TRUST CORPUS
Year Ended --------------------------------------------------------- December 31, 1999 December 31, 1998 December 31, 1997 ----------------- ----------------- ----------------- Trust corpus, beginning of period ................ $ 85,533,029 $ 97,670,701 $ 109,562,077 Amortization of royalty interests ................ (10,313,122) (12,133,848) (11,891,773) Distributable income ............................. 19,385,356 22,226,804 24,338,026 Distributions to Unitholders ..................... (19,332,083) (22,230,628) (24,337,629) ------------- ------------- ------------- Trust corpus, end of period ...................... $ 75,273,180 $ 85,533,029 $ 97,670,701 ============= ============= =============
The accompanying notes are an integral part of these financial statements. 34 38 NOTES TO FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997 1. TRUST ORGANIZATION AND PROVISIONS Dominion Resources Black Warrior Trust (the "Trust") was formed as a Delaware business trust pursuant to the terms of the Trust Agreement of Dominion Resources Black Warrior Trust (as amended, the "Trust Agreement"), entered into effective as of May 31, 1994, among Dominion Black Warrior Basin, Inc., an Alabama corporation (the "Company"), as trustor, Dominion Resources, Inc., a Virginia corporation ("Dominion Resources"), and Bank of America, N.A. (as successor to NationsBank of Texas, N.A.), a national banking association (the "Trustee"), and Mellon Bank (DE) National Association, a national banking association (the "Delaware Trustee"), as trustees. The trustees are independent financial institutions. The Trust is a grantor trust formed to acquire and hold certain overriding royalty interests (the "Royalty Interests") burdening proved natural gas properties located in the Pottsville coal formation of the Black Warrior Basin, Tuscaloosa County, Alabama (the "Underlying Properties") owned by the Company. The Trust was initially created by the filing of its Certificate of Trust with the Delaware Secretary of State on May 31, 1994. In accordance with the Trust Agreement, the Company contributed $1,000 as the initial corpus of the Trust. On June 28, 1994, the Royalty Interests were conveyed to the Trust by the Company pursuant to the Overriding Royalty Conveyance (the "Conveyance") effective as of June 1, 1994, from the Company to the Trust, in consideration for all the 7,850,000 authorized units of beneficial interest ("Units") in the Trust. The Company transferred all the Units to its parent, Dominion Energy, Inc., a Virginia corporation, which in turn transferred all the Units to its parent, Dominion Resources, Inc., which sold an aggregate of 6,904,000 Units to the public through various underwriters (the "Underwriters") in June and August 1994 and the remaining 946,000 Units were sold to the public through certain of the Underwriters in June 1995. All of the production attributable to the Underlying Properties is from the Pottsville coal formation and currently constitutes coal seam gas that entitles the owners of such production, provided certain requirements are met, tax credits pursuant to Section 29 of the Internal Revenue Code of 1986, as amended, upon the production and sale of such gas. The Trustee has all powers to collect and distribute proceeds received by the Trust and to pay Trust liabilities and expenses. The Delaware Trustee has only such powers as are set forth in the Trust Agreement or are required by law and is not empowered to otherwise manage or take part in the management of the Trust. The Royalty Interests are passive in nature and neither the Trustee nor the Delaware Trustee has any control over, or any responsibility relating to, the operation of the Underlying Properties or the Company's interest therein. The Trust is subject to termination under certain circumstances described in the Trust Agreement. Upon the termination of the Trust, all Trust assets will be sold and the net proceeds therefrom distributed to Unitholders. The only assets of the Trust, other than cash and temporary investments being held for the payment of expenses and liabilities and for distribution to Unitholders, are the Royalty Interests. The Royalty Interests consist of overriding royalty interests burdening the Company's interest in the Underlying Properties. The Royalty Interests generally entitle the Trust to receive 65 percent of the Company's Gross Proceeds (as defined below). The Royalty Interests are non- operating interests and bear only expenses related to property, production and related taxes (including severance taxes). "Gross Proceeds" consist generally of the aggregate amounts received by the Company attributable to the interests of the Company in the Underlying Properties from the sale of coal seam gas at the central delivery points in the gathering system for the Underlying Properties. The definitions, formulas and accounting procedures and other terms governing the computation of the Royalty Interests are set forth in the Conveyance. 35 39 Because of the passive nature of the Trust and the restrictions and limitations on the powers and activities of the Trustee contained in the Trust Agreement, the Trustee does not consider any of the officers and employees of the Trustee to be "officers" or "executive officers" of the Trust as such terms are defined under applicable rules and regulations adopted under the Securities Exchange Act of 1934. 2. BASIS OF ACCOUNTING The financial statements of the Trust are prepared on a modified cash basis and are not intended to present financial position and results of operations in conformity with generally accepted accounting principles ("GAAP"). Preparation of the Trust's financial statements on such basis includes the following: o Royalty income and interest income are recorded in the period in which amounts are received by the Trust rather than in the month of production or when earned. o General and administrative expenses are recorded based on liabilities paid and cash reserves established out of cash received. o Amortization of the Royalty Interests is calculated on a unit-of-production basis and charged directly to trust corpus based upon when revenue is received. o Distributions to Unitholders are recorded when declared by the Trustee (see Note 5). The financial statements of the Trust differ from financial statements prepared in accordance with GAAP because royalty income is not accrued in the period of production, general and administrative expenses recorded are based on liabilities paid and cash reserves established rather than on an accrual basis, and amortization of the Royalty Interests is not charged against operating results. Dominion Resources sold an aggregate of 6,904,000 Units in the Public Offering during 1994 at a price of $20.00 per Unit and sold the remaining 946,000 Units to the public during 1995 through certain of the Underwriters at a price of $18.75 per Unit. Accordingly, the statements of assets, liabilities and trust corpus reflects 6,940,000 Units at the Public Offering price of $20.00 per Unit and 946,000 Units at the price of $18.75 per Unit. The net amount of royalty interests in gas properties is limited to the sum of the future net cash flows attributable to the Trust's gas reserves at year end using current unescalated product prices plus the estimated Section 29 credits for federal income tax purposes. If the net cost of royalty interests in gas properties exceeds the aggregate of these amounts, an impairment provision is recorded and charged to the Trust Corpus. Use of Estimates The preparation of financial statements in conformity with the basis of accounting described above requires management to make estimates and assumptions that affect reported amounts of certain assets, liabilities, revenues and expenses as of and for the reporting periods. Actual results may differ from such estimates. Impairment Trust management routinely reviews its royalty interests in oil and gas properties for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If an impairment event occurs and it is determined that the carrying value of the Trust's royalty interests may not be recoverable, an impairment will be recognized as measured by the amount by which the carrying amount of the royalty interests exceeds the fair value of these assets, which would likely be measured by discounting projected cash flows. Should the aggregate dollar amount of the Trust's reserves and Section 29 credits decline, an additional impairment provision, which could be material, will be required. There can be no assurance such a writedown will not occur. 36 40 Distributable Income Per Unit Basic earnings per share is computed by dividing net income by the weighted average shares outstanding. Earnings per share assuming dilution is computed by dividing net income by the weighted average number of shares and equivalent shares outstanding. The Trust had no equivalent shares outstanding for any period presented. As a result basic diluted earnings per unit and distributable income per unit are the same. New Accounting Standards The Financial Accounting Standards Board ("FASB") issued in June 1998 Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," which establishes accounting and reporting standards for derivative instruments. SFAS No. 133 is effective for the Trust January 1, 2001. The Trust has evaluated the impact and determined that none will result from adopting this SFAS. 3. FEDERAL INCOME TAXES The Trust is a grantor trust for Federal income tax purposes. As a grantor trust, the Trust will not be required to pay Federal or state income taxes. Accordingly, no provision for income taxes has been made in these financial statements. Because the Trust will be treated as a grantor trust, and because a Unitholder will be treated as directly owning an interest in the Royalty Interests, each Unitholder will be taxed directly on his per Unit share of income attributable to the Royalty Interests consistent with the Unitholder's method of accounting and without regard to the taxable year or accounting method employed by the Trust. Production from coal seam gas wells drilled after December 31, 1979 and prior to January 1, 1993, is believed to qualify for the Federal income tax credit for producing nonconventional fuels under Section 29 of the Internal Revenue Code. This tax credit is calculated annually based on each year's qualified production through the year 2002. Such credit, based on a Unitholder's pro rata share of qualifying production, may not reduce his regular tax liability (after the foreign tax credit and certain other non-refundable credits) below his alternative minimum tax. Any part of the Section 29 credit not allowed for the tax year solely because of this limitation is subject to certain carryover provisions. The Trustee is provided Section 29 tax credit information related to Trust Properties by Dominion Resources, which is then passed along to the Unitholders. In 1997, the Tax Court upheld the Internal Revenue Service ("IRS") position that nonconventional fuel such as coal seam gas does not qualify for the Section 29 credit unless the producer received a formal certification from the Federal Energy Regulatory Commission ("FERC"). The FERC's certification authority expired effective January 1, 1993,. During March 1999, the U.S. Court of Appeals for the 10th Circuit affirmed that decision. The appeal (which is not binding as precedent) suggests that lack of a certification from FERC may render the Section 29 credit unavailable in respect of production from wells recompleted in a qualified formation after January 1, 1993, the date that FERC's certification authority expired (so that obtaining the requisite determination of any such well was impossible). Many producers believe that wells meeting the certification requirements are eligible for the Section 29 credits regardless of FERC certification. However, this position is not in accordance with the IRS position, the decision of the Tax Court or the decision of the U.S. Court of Appeals. The ability of the Trust to realize the carrying value of its reserves and the ability of the Unitholders to utilize allocated Section 29 credits could be in question with respect to any uncertificated wells. In some cases the extent to which production from the various coal seam gas wells in which the Trust holds an interest would qualify for the Section 29 credit under the standards applied in the appealed case is unclear, and the Trustee has requested that Dominion Resources provide clarification and an assessment of the effects of the foregoing, if any, on the Trust and its Unitholders. Pending such clarification and assessment, or further developments, or both, however, the availability of Section 29 credits to Unitholders in respect of some portion of the Trust's coal seam gas production could be subject to debate and challenge. 4. RELATED PARTY TRANSACTIONS Dominion Resources provides accounting, bookkeeping and informational services to the Trust in accordance with an Administrative Services Agreement effective June 1, 1994. During 1999 this fee was $352,817 and will increase 37 41 annually by three percent. Aggregate fees paid by the Trust to Dominion Resources in 1999, 1998 and 1997 were $352,817, $342,515 and $327,561, respectively. Aggregate fees and expense reimbursements paid by the Trust to the trustees in 1999, 1998 and 1997 were $34,778, $33,765 and $32,756, respectively. 5. DISTRIBUTIONS TO UNITHOLDERS The Trustee determines for each calendar quarter the amount of cash available for distribution to Unitholders. Such amount (the "Quarterly Distribution Amount") is an amount equal to the excess, if any, of the cash received by the Trust attributable to production from the Royalty Interests during such quarter, provided that such cash is received by the Trust on or before the last business day prior to the 45th day following the end of such calendar quarter, plus the amount of interest expected by the Trustee to be earned on such cash proceeds during the period between the date of receipt by the Trust of such cash proceeds and the date of payment to the Unitholders of such Quarterly Distribution Amount, plus all other cash receipts of the Trust during such quarter (to the extent not distributed or held for future distribution as a Special Distribution Amount (as defined below) or included in the previous Quarterly Distribution Amount)(which might include sales proceeds not sufficient in amount to qualify for a special distribution as described in the next paragraph), over the liabilities of the Trust paid during such quarter and not taken into account in determining a prior Quarterly Distribution Amount, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for the payment of contingent or future obligations of the Trust. An amount which is not included in the Quarterly Distribution Amount for a calendar quarter because such amount is received by the Trust after the last business day prior to the 45th day following the end of such calendar quarter will be included in the Quarterly Distribution Amount for the next calendar quarter. The Quarterly Distribution Amount for each quarter will be payable to Unitholders of record on the 60th day following the end of such calendar quarter unless such day is not a business day in which case the record date is the next business day thereafter. The Trustee will distribute the Quarterly Distribution Amount for each quarter on or prior to 70 days after the end of such calendar quarter to each person who was a Unitholder of record on the record date for such calendar quarter. The Royalty Interests may be sold under certain circumstances and will be sold following termination of the Trust. A special distribution will be made of undistributed net sales proceeds and other amounts received by the Trust aggregating in excess of $10 million (a "Special Distribution Amount"). The record date for a Special Distribution Amount will be the 15th day following the receipt by the Trust of amounts aggregating a Special Distribution Amount (unless such day is not a business day, in which case the record date will be the next business day thereafter) unless such day is within 10 days or less prior to the record date for a Quarterly Distribution Amount, in which case the record date for the Special Distribution Amount will be the same as the record date for the Quarterly Distribution Amount. Distribution to Unitholders of a Special Distribution Amount will be made no later than 15 days after the Special Distribution Amount record date. 6. SUBSEQUENT EVENTS Subsequent to December 31, 1999, the Trust declared and paid the following distribution:
QUARTERLY DISTRIBUTION RECORD DATE PAYMENT DATE PER UNIT - ----------------------- ---------------------- -------------------- February 29, 2000 March 10, 2000 $.674578
The trustee has estimated the Section 29 tax credit associated with the March 10, 2000 quarterly distribution to be $.28 per unit (unaudited). 38 42 7. QUARTERLY FINANCIAL DATA (UNAUDITED) The following table sets forth the royalty income, distributable income and distributable income per Unit of the Trust for each quarter in the years ended December 31, 1999 and 1998 (in thousands, except per Unit amounts):
ROYALTY DISTRIBUTABLE DISTRIBUTABLE CALENDAR QUARTER INCOME INCOME INCOME PER UNIT - ---------------- -------- ------------- ---------------- 1999 First .............. $ 4,859 $ 4,672 $ .60 Second ............. 4,660 4,446 .57 Third .............. 4,901 4,782 .60 Fourth ............. 5,612 5,485 .70 -------- -------- -------- $ 20,032 $ 19,385 $ 2.47 ======== ======== ======== 1998 First .............. $ 6,917 $ 6,749 $ .86 Second ............. 5,524 5,311 .68 Third .............. 5,451 5,344 .68 Fourth ............. 4,958 4,823 .61 -------- -------- -------- $ 22,850 $ 22,227 $ 2.83 ======== ======== ========
Selected 1999 fourth quarter data are as follows (in thousands, except per Unit amounts): Royalty income............................... $ 5,612,344 Interest income.............................. 17,856 General and administrative expenses.......... (144,713) -------------- Distributable income......................... $ 5,485,487 ============== Distributable income per Unit................ $ .70 ============== Distributions per Unit....................... $ .70 ==============
Due to significant revisions in estimate of reserve quantities (see Note 8), estimated amortization of royalty interests was increased by approximately $2 million and $1.2 million and decreased approximately $3.4 million during the fourth quarters of 1999, 1998 and 1997, respectively. These adjustments did not have an impact on the Trust's distributable income. 8. SUPPLEMENTAL GAS DISCLOSURE (UNAUDITED) The net proved reserves attributable to the Royalty Interests have been estimated as of December 31, 1999, 1998 and 1997 and January 1, 1997 by independent petroleum engineers. In accordance with SFAS No. 69, estimates of proved reserves and future net cash flows from proved reserves have been prepared using contractually guaranteed prices and end-of-period natural gas prices, and related costs. The standardized measure of future net cash flows from the gas reserves is calculated based on discounting such future net cash flows at an annual rate of 10 percent. The prices for December 31, 1999, 1998 and 1997 and January 1, 1997 were $2.16, $2.12, $2.55 and $2.81 per Mcf, respectively, including the effect of the Gas Purchase Agreement (see Note 9). Numerous uncertainties are inherent in estimating volumes and value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the original estimates. 39 43 The reserve estimates for the Royalty Interests are based on a percentage share of the Company's Gross Proceeds payable to the Trust of 65 percent.
Mmcf ------------ Proved developed reserves at January 1, 1997.............. 82,388 Revisions of previous estimates.................. 23,380 Production....................................... (11,302) ------------ Proved developed reserves at December 31, 1997............ 94,466 Revisions of previous estimates.................. ( 9,458) Production....................................... (10,329) ------------ Proved developed reserves at December 31, 1998............ 74,679 Revisions of previous estimates.................. 3,687 Production....................................... (9,186) ------------ Proved developed reserves at December 31, 1999............ 69,180 ===========
All proved reserve estimates presented above at December 31, 1999, 1998 and 1997 and January 1, 1997 are proved developed. Proved developed reserves, all located in the United States, for the Trust's Interests are estimated quantities of coal seam gas which geological and engineering data indicate with reasonable certainty to be recoverable in future years from the coal formation under existing economic and operating conditions. Proved developed reserves are proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Estimated economic quantities have been determined considering the Section 29 tax credits. The following table sets forth the standardized measure of discounted estimated future net cash flows from proved reserves at December 31, 1999, 1998 and 1997 relating to the Trust's Royalty Interests (thousands of dollars):
1999 1998 1997 ---------- ---------- ---------- Future cash inflows .............................. $ 149,364 $ 158,122 $ 241,346 Future taxes ..................................... (8,962) (9,487) (14,481) ---------- ---------- ---------- Future net cash flows ............................ 140,402 148,635 226,865 10% annual discount for estimated timing of cash flow ............................... (57,863) (59,703) (97,941) ---------- ---------- ---------- Standardized measure of discounted future net cash flows ...................... $ 82,539 $ 88,932 $ 128,924 ========== ========== ==========
Future cash flows do not include Section 29 tax credits which in the aggregate are estimated to be approximately $ 24,328,162 having a discounted present value (assuming a 10% discounted rate) of approximately $20,315,000 at December 31, 1999. The following table sets forth the changes in the present value of estimated future net cash flows from proved reserves during the period ended December 31, 1999, 1998 and 1997 (thousands of dollars):
1999 1998 1997 ---------- ---------- ---------- Balance at beginning of period.......................... $ 88,932 $ 128,924 $ 134,675 Increase (decrease) due to: Royalty income, net of taxes....................... (21,493) (21,722) (25,096) Changes in prices.................................. 1,534 (16,723) (21,421) Changes in estimated volumes....................... 4,673 (14,439) 27,298 Accretion of discount.............................. 8,893 12,892 13,468 ---------- ---------- ---------- Balance at December 31.................................. $ 82,539 $ 88,932 $ 128,924 ========== ========== ==========
40 44 As of March 24, 2000, published natural gas prices were approximately $2.23 per MMBtu as compared to prices utilized in the Trust's calculation of its year end standardized measure of discounted future net cash flow. The use of prices currently being received would result in a lower standardized measure of discounted future net cash flows. 9. GAS PURCHASE AGREEMENT Sonat Marketing Company ("Sonat Marketing") is required under a gas purchase agreement to purchase the gas produced from the Underlying Properties for as long as reserves on the Underlying Properties produce natural gas. Under the agreement, Sonat Marketing is obligated to purchase up to a specified monthly base quantity of gas for a contract price which provides for a specified premium (between $.05 and $.07 per MMBtu) over the Index Price (as defined below). Until December 31, 1998, the contract price paid was subject to a minimum price of $1.85 per MMBtu and a maximum price of $2.63 per MMBtu. Beginning effective January 1, 1999, the Contract Price paid was subject to a minimum price of $2.16 per MMBtu and a maximum price of $3.07 per MMBtu. Beginning effective January 1, 2000 and through December 31, 2000 the price paid on Index Price Quantities is subject to a minimum price of $2.20 and a maximum price of $2.82. Prior to April 1, 1996, Sonat Marketing was obligated to purchase the Subject Gas in excess of the Monthly Base Quantity at the Index Price. From April 1, 1996 through December 31, 1998, the price payable for Subject Gas in excess of the Monthly Base Quantity equaled the Index Price plus $.02. Beginning effective January 1, 1999 through December 31, 1999, the price payable for Subject Gas in excess of the Monthly Base Quantity but less than or equal to the Monthly Fixed Price Quantity equaled the Index Price plus $.02 subject to a minimum price of $2.12 per MMBtu and a maximum price of $3.02 per MMBtu. Also during the period, the price payable for Subject Gas in excess of the Monthly Fixed Price Quantity equaled the sum of the Index Price and $.02. Effective January 1, 2000 through December 31, 2000, the price payable for Subject Gas in excess of the Monthly Fixed Price Quantity shall equal the sum of the Index Price and $.02 per MMBtu. The Company has advised the Trust that at the end of the primary term or any extensions thereof, Sonat Marketing will be obligated to purchase the Subject Gas at the Index Price until such time as the Company and Sonat Marketing negotiate a different price, and that the Company will have the ability to obtain an offer to purchase the Subject Gas from another purchaser and terminate the Gas Purchase Agreement if Sonat Marketing does not match such offer. 41 45 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. The Trust has no directors or executive officers. Each of the Trustee and the Delaware Trustee is a corporate trustee that may be removed as trustee under the Trust Agreement, with or without cause, at a meeting duly called and held by the affirmative vote of Unitholders of not less than a majority of all the Units then outstanding. Any such removal of the Delaware Trustee shall be effective only at such time as a successor Delaware Trustee fulfilling the requirements of Section 3807(a) of the Delaware Code has been appointed and has accepted such appointment, and any such removal of the Trustee shall be effective only at such time as a successor Trustee has been appointed and has accepted such appointment. ITEM 11. EXECUTIVE COMPENSATION. The following is a description of certain fees and expenses anticipated to be paid or borne by the Trust, including fees expected to be paid to Dominion Resources, the Trustee, the Delaware Trustee, the Transfer Agent, or their respective affiliates. Ongoing Administrative Expenses. The Trust is responsible for paying all fees, charges, expenses, disbursements and other costs incurred by the Trustee in connection with the discharge of its duties pursuant to the Trust Agreement, including, without limitation, trustee fees, engineering, audit, accounting and legal fees and expenses, printing and mailing costs, amounts reimbursed or paid to the Company or Dominion Resources pursuant to the Trust Agreement or the Administrative Services Agreement and the out-of-pocket expenses of the Transfer Agent. Compensation of the Trustee. The Trust Agreement provides that the Trustee is to be compensated for its administrative services and preparation of quarterly and annual statements, out of the Trust assets, in an annual amount of $30,900, plus an hourly charge for services in excess of a combined total of 350 hours annually at its standard rate which is currently $120 per hour. These service fees escalate by three percent annually. The Delaware Trustee is compensated for its administrative services, in an annual amount of $5,000 which will be paid by the Trustee. Each of the Trustee and the Delaware Trustee is entitled to reimbursement for out-of-pocket expenses. Upon termination of the Trust, the Trustee will receive, in addition to its out-of-pocket expenses, a termination fee in the amount of $10,000. If the Trustee resigns and a successor has not been appointed in accordance with the terms of the Trust Agreement within 210 days after the notice of resignation is received, the fee payable to the Trustee will increase significantly until a new trustee is appointed. During 1999, the Trustee and the Delaware Trustee received total compensation of $34,778 and $3,750, respectively. Compensation of the Transfer Agent. The Transfer Agent receives a transfer agency fee of $3.25 annually per account, plus $1.50 for each certificate issued and $.40 for each check issued (subject to an annual minimum of $7,200). Fees to Dominion Resources. Dominion Resources will receive throughout the term of the Trust an administrative services fee for accounting, bookkeeping and other administrative services relating to the Royalty Interests and the Underlying Properties as described in Item 13 under "Administrative Services Agreement." ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. Security Ownership of Certain Beneficial Owners. The Trustee knows of no Unitholder that is a beneficial owner of more than five percent of the outstanding Units. 42 46 Security Ownership of Management. The Trust has no directors or executive officers. As of March 10, 2000, neither Bank of America, N.A., the Trustee, nor Mellon Bank (DE) National Association, the Delaware Trustee, beneficially owned any Units. Changes in Control. The Trustee knows of no arrangements the operation of which may at a subsequent date result in a change in control of the Registrant. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. ADMINISTRATIVE SERVICES AGREEMENT Pursuant to the Trust Agreement, Dominion Resources and the Trust entered into the Administrative Services Agreement, pursuant to which the Trust is obligated, throughout the term of the Trust, to pay to Dominion Resources each quarter an administrative services fee for accounting, bookkeeping and other administrative services relating to the Royalty Interests and the Underlying Properties. The annual fee, payable in equal quarterly installments, is currently $352,817 and will increase annually by three percent. A copy of the Administrative Services Agreement is filed as an exhibit to this Form 10-K. The foregoing summary of the material provisions of the Administrative Services Agreement does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all the provisions of the Administrative Services Agreement. DOMINION RESOURCES' CONDITIONAL RIGHT OF REPURCHASE Dominion Resources retains in the Trust Agreement the right to repurchase all (but not less than all) outstanding Units at any time at which 15 percent or less of the outstanding Units is owned by persons or entities other than Dominion Resources and its affiliates. Any such repurchase would generally be at a price equal to the greater of (i) the highest price at which Dominion Resources or any of its affiliates acquired Units during the 90 days immediately preceding the Determination Date and (ii) the average closing price of Units on the NYSE for the 30 trading days immediately preceding the Determination Date. Any such repurchase would be conducted in accordance with applicable Federal and state securities laws. See "Business--Description of the Trust--Conditional Right of Repurchase." POTENTIAL CONFLICTS OF INTEREST The interests of Dominion Resources and its affiliates and the interests of the Trust and the Unitholders with respect to the Underlying Properties could at times be different. The following is a summary of certain conflicts of interest: Obligations of Company Interests Owner may exceed its share of distributions and tax credits. As a working interest owner in the Underlying Properties, the Company Interests Owner is responsible for an average of approximately 98 percent of the operating costs of the Existing Wells but only entitled to approximately 28 percent of the revenues therefrom, after giving effect to the Royalty Interests. Based on the Reserve Estimate, beginning in the year 2000, the projected operating costs to be borne by the Company Interests Owner will exceed its projected share of Gross Proceeds and Section 29 tax credits. The terms of the Conveyance provide, however, that the Company Interests Owner will make decisions with respect to the Company Interests pursuant to the standard of a reasonably prudent operator. Sale or abandonment of Underlying Properties may terminate assurances. The Company Interests Owner's interests may conflict with those of the Trust and Unitholders in situations involving the sale or abandonment of Underlying Properties. The Company Interests Owner has the right at any time to sell any of the Underlying Properties subject to the Royalty Interests and may abandon a well or lease included in the Underlying Properties if such well or lease is not capable of producing in commercial quantities, determined before giving effect to the Royalty Interests. Under certain circumstances, a sale or abandonment will effectively terminate Dominion Resources' assurances of the 43 47 Company Interests Owner's obligation to the Trust with respect to the Underlying Properties sold or abandoned. Such sales or abandonment may not be in the best interest of the Trust or the Unitholders. Dominion Resources may profit from contracts with the Trust. The amount that Dominion Resources may charge for services it renders under the Administrative Services Agreement is established in such contract at rates that do not necessarily take into account the actual cost of rendering such services by Dominion Resources. Accordingly, Dominion Resources may profit or suffer losses in connection with the performance of such contract. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K. (a) The following documents are filed as a part of this report: 1. Financial Statements (included in Item 8. of this report) Independent Auditors' Report Statements of Assets, Liabilities and Trust Corpus as of December 31, 1999 and 1998 Statements of Distributable Income for the years ended December 31, 1999, 1998 and 1997 Statements of Changes in Trust Corpus for the years ended December 31, 1999, 1998 and 1997 Notes to Financial Statements 2. Financial Statement Schedules Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the financial statements and notes thereto. 3. Exhibits Exhibit Number Exhibit 3.1 --Trust Agreement of Dominion Resources Black Warrior Trust dated as of May 31, 1994, by and among Dominion Black Warrior Basin, Inc., Dominion Resources, Inc., Mellon Bank (DE) National Association and NationsBank, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 3.1 to Dominion Resources, Inc.'s Registration Statement* on Form S-3 (No. 33-53513), and incorporated herein by reference). 3.2 --First Amendment of Trust Agreement of Dominion Resources Black Warrior Trust dated as of June 27, 1994, by and among Dominion Black Warrior Basin, Inc., Dominion Resources, Inc., Mellon Bank (DE) National Association and NationsBank, N.A. (as successor to NationsBank of Texas, N.A.) (filed as Exhibit 3.2 to the Registrant's Form 10-Q for the quarter ended June 30, 1994 and incorporated herein by reference). 10.1 --Overriding Royalty Conveyance dated as of June 28, 1994, from Dominion Black Warrior Basin, Inc. to Dominion Resources Black Warrior Trust (filed as Exhibit 10.1 to the Registrant's Form 10-Q for the quarter ended June 30, 1994 and incorporated herein by reference). 10.2 --Administrative Services Agreement dated as of June 1, 1994, by and between Dominion Resources, Inc. and Dominion Resources Black Warrior Trust (filed as Exhibit 10.2 to the Registrant's Form 10-Q for the quarter ended June 30, 1994 and incorporated herein by reference). 10.3 --Amendment to and Ratification of Overriding Royalty Conveyance dated as of November 20, 1994, among Dominion Back Warrior Basin, Inc., NationsBank, N.A. (as successor to NationsBank of Texas, N.A.), and Mellon Bank (DE) National Association (filed as Exhibit 10.3 to the Registrant's Form 10-K for the year ended December 31, 1994 and incorporated herein by reference). 44 48 10.4 --Gas Purchase Agreement, dated as of May 3, 1994, between Sonat Marketing and the Company (filed as Exhibit 10.2 to Dominion Resources, Inc.'s Registration Statement* on Form S-3 (No. 33-53513), and incorporated herein by reference). 10.5 --Amendment to Gas Purchase Agreement dated May 16, 1996, between Sonat Marketing and the Company (filed as Exhibit 10.1 to the Registrant's Form 10-Q for the quarter ended June 30, 1996 and incorporated herein by reference). 10.6 --Amendment to Gas Purchase Agreement dated April 9, 1998, between Sonat Marketing and the Company (filed as Exhibit 10.6 to the Registrant's Form 10-K for the year ended December 31, 1998 and incorporated herein by reference). 10.7 --Amendment to Gas Purchase Agreement dated July 1, 1999, between Sonat Marketing and the Company. 23.1 --Consent of Ryder Scott Company Petroleum Engineers, independent petroleum engineers. 27.1 --Financial Data Schedule. 99.1 --Summary of Reserve Report, dated February 23, 2000, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests as of January 1, 2000, prepared by Ryder Scott Company Petroleum Engineers, independent petroleum engineers. - ---------- * On its own behalf and as sponsor of the Dominion Resources Black Warrior Trust (b) Reports on Form 8-K. No report on Form 8-K was filed by the Registrant during the last quarter of the period covered by this report. 45 49 SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. DOMINION RESOURCES BLACK WARRIOR TRUST By: BANK OF AMERICA, N.A., TRUSTEE By: /s/ RON E. HOOPER ------------------------------------- RON E. HOOPER VICE PRESIDENT AND ADMINISTRATOR Date: March 30, 2000 (THE REGISTRANT HAS NO DIRECTORS OR EXECUTIVE OFFICERS.) 46 50 INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION - ------- ----------- 10.7 --Amendment to Gas Purchase Agreement dated July 1, 1999, between Sonat Marketing and the Company. 23.1 --Consent of Ryder Scott Company Petroleum Engineers, independent petroleum engineers. 27.1 --Financial Data Schedule. 99.1 --Summary of Reserve Report, dated February 23, 2000, on the estimated reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests as of January 1, 2000, prepared by Ryder Scott Company Petroleum Engineers, independent petroleum engineers.
EX-10.7 2 AMENDMENT TO THE GAS PURCHASE AGREEMENT 1 EXHIBIT 10.7 AMENDMENT TO THE GAS PURCHASE AGREEMENT DATED MAY 3, 1994 THIS AMENDMENT (the "July 1999 Amendment"), made and entered into as of the 1st day of July 1999, between Dominion Black Warrior Basin, Inc. ("Seller") and Sonat Marketing Company L.P. ("Buyer"). WITNESSETH WHEREAS, Buyer and Seller entered into a Gas Purchase Agreement dated May 3, 1994, as amended by Amendments dated April 1, 1996, May 16, 1996, and April 9, 1998 ("the 1994 Agreement"); and WHEREAS, Buyer and Seller desire to further amend the 1994 Agreement to establish Floor and Ceiling Prices for a given quantity and a fixed price for an equal quantity and related procedures to be effective during the calendar year 2000; NOW THEREFORE, in consideration of the premises and mutual covenants contained herein, the parties hereby mutually understand and agree as follows: 1. Section 2.1 of the 1994 Agreement shall be deleted in its entirety and the following Section 2.1 substituted therefor: 2.1 Subject to the terms and conditions hereinafter set forth, commencing on the Effective Date, Seller agrees to sell and deliver, and Buyer agrees to purchase and receive one hundred percent (100%) of the gas produced in the Field attributable to Seller's interest therein as described on Exhibit A hereto. On Revised Exhibit B attached hereto, Seller has designated for each month of the primary term hereof commencing on the Effective Date, the projected production for such month (the "Monthly Base Quantity"). Any gas produced during a month in excess of the Monthly Base Quantity shall be deemed the "Excess Quantity". 1 2 2. Effective January 1, 2000 through December 31, 2000, Sections 4.1, 4.2 and 4.3 of the 1994 Agreement shall be deleted in its entirety and the following Sections 4.1, 4.2 and 4.3 shall be substituted therefor: 4.1 The price payable by Buyer for each MMBtu of Monthly Base quantity purchased hereunder during each month of the primary term hereof commencing on January 1, 2000 shall be divided into two categories, a Fixed Price Quantity and an Index Price Quantity, as described in Revised Exhibit D hereto. The price for each MMBtu of Fixed Price Quantity shall be $2.45 per MMBtu (the "Monthly Fixed Contract Price"). The price for each MMBtu of Index Price Quantity shall be the sum of (a) the price published in the price table dated the first (1st) day of the applicable month by Inside F.E.R.C.'s Gas Market Report for "Prices of Spot Gas Delivered to Pipelines" "Southern Natural Gas Co." "Louisiana" "Index" (the "Index Price") and (b) a Premium per MMBtu as described below (the "Monthly Index Contract Price"):
Index Price Premium ($/MMBtu) ($/MMBtu) --------- --------- Below 2.00 0.050 2.00 - 2.25 0.060 2.26 - 2.50 0.065 Above 2.50 0.070
4.2 The above Section 4.1 notwithstanding, the Index Price component of the Monthly Index Contract Price payable during each month shall, in no event, be less than $2.20 per MMBtu (the "Floor Price"), nor more than $2.82 per MMBtu (the "Ceiling Price"); provided, however, that the Premium shall be based on the actual Index Price regardless whether such Index Price falls below the Floor Price. 4.3 The price payable by Buyer for each MMBtu of Excess Quantity during the primary term hereof commencing on January 1, 2000 shall be the sum of the Index Price and $.02 per MMBtu (the "Excess Quantity Contract Price"). 3. Exhibit B is deleted in its entirety and the attached Revised Exhibit B is substituted therefor. 4. Exhibit D is deleted in its entirety and the attached Revised Exhibit D is substituted therefor and is effective during the calendar year 2000 only. 2 3 IN WITNESS WHEREOF, the parties hereto have executed this July 1999 Amendment in duplicate originals as of date hereinabove first written. Witness: SONAT MARKETING COMPANY L.P. By /s/ Edward J. Crenshaw -------------------------- ------------------------------- Edward J. Crenshaw -------------------------- Vice President - Marketing Witness: DOMINION BLACK WARRIOR BASIN, INC. /s/ G.E. Lake, Jr. ------------------------------- G.E. Lake, Jr. 3 4 REVISED EXHIBIT B DATED JULY 1, 1999 TO THE GAS PURCHASE AGREEMENT BETWEEN DOMINION BLACK WARRIOR BASIN, INC. AND SONAT MARKETING COMPANY L.P., SUCCESSOR-IN-INTEREST TO SONAT MARKETING COMPANY DATED MAY 3, 1994
Month/Year Monthly Base Quantity ---------- --------------------- Jun-94 2,049,266 Jul-94 2,024,890 Aug-94 1,997,383 Sep-94 1,973,850 Oct-94 1,951,089 Nov-94 1,927,251 Dec-94 1,906,933 Jan-95 1,885,876 Feb-95 1,863,385 Mar-95 1,843,489 Apr-95 1,823,962 May-95 1,805,450 Jun-95 1,787,173 Jul-95 1,771,348 Aug-95 1,756,032 Sep-95 1,740,875 Oct-95 1,726,083 Nov-95 1,711,675 Dec-95 1,698,140 Jan-96 1,685,535 Feb-96 1,673,928 Mar-96 1,663,482 Apr-96 1,652,832 May-96 1,643,705 Jun-96 1,633,814 Jul-96 1,625,079 Aug-96 1,614,930 Sep-96 1,604,315 Oct-96 1,593,147 Nov-96 1,581,881 Dec-96 1,571,915 Jan-97 1,562,875
4 5
Month/Year Monthly Base Quantity ---------- --------------------- Feb-97 1,554,163 Mar-97 1,540,578 Apr-97 1,525,042 May-97 1,510,269 Jun-97 1,494,454 Jul-97 1,477,976 Aug-97 1,461,398 Sep-97 1,444,593 Oct-97 1,427,214 Nov-97 1,408,676 Dec-97 1,389,533 Jan-97 1,368,701 Feb-98 1,342,469 Mar-98 1,319,441 Apr-98 1,296,269 May-98 1,272,573 Jun-98 1,249,204 Jul-98 1,225,774 Aug-98 1,201,433 Sep-98 1,178,126 Oct-98 1,154,755 Nov-98 1,131,388 Dec-98 1,109,349 Jan-99 1,198,000 Feb-99 1,171,000 Mar-99 1,136,000 Apr-99 1,140,000 May-99 1,106,000 Jun-99 1,094,000 Jul-99 1,096,000 Aug-99 1,071,000 Sep-99 1,053,000 Oct-99 1,045,000 Nov-99 1,007,000 Dec-99 1,008,000 Jan-00 1,200,000 Feb-00 1,200,000 Mar-00 1,200,000 Apr-00 1,200,000 May-00 1,150,000 Jun-00 1,150,000 Jul-00 1,150,000 Aug-00 1,150,000
5 6
Month/Year Monthly Base Quantity ---------- --------------------- Sep-00 1,100,000 Oct-00 1,100,000 Nov-00 1,100,000 Dec-00 1,100,000 Jan-01 1,050,000 Feb-01 1,050,000 Mar-01 1,050,000 Apr-01 1,050,000 May-01 1,000,000 Jun-01 1,000,000 Jul-01 1,000,000 Aug-01 1,000,000 Sep-01 950,000 Oct-01 950,000 Nov-01 950,000 Dec-01 950,000
6 7 REVISED EXHIBIT D DATED JULY 1, 1999 TO THE GAS PURCHASE AGREEMENT BETWEEN DOMINION BLACK WARRIOR BASIN, INC. AND SONAT MARKETING COMPANY L.P., SUCCESSOR-IN-INTEREST TO SONAT MARKETING COMPANY DATED MAY 3, 1994
Fixed Price Quantities Index Quantities Month/Year (MMBtu) (MMBtu) ---------- ---------------------- ---------------- Jan-00 600,000 600,000 Feb-00 600,000 600,000 Mar-00 600,000 600,000 Apr-00 600,000 600,000 May-00 575,000 575,000 Jun-00 575,000 575,000 Jul-00 575,000 575,000 Aug-00 575,000 575,000 Sep-00 550,000 550,000 Oct-00 550,000 550,000 Nov-00 550,000 550,000 Dec-00 550,000 550,000
7 EX-23.1 3 CONSENT OF RYDER SCOTT COMPANY PETROLEUM ENGINRS. 1 EXHIBIT 23.1 March 28, 2000 Dominion Resources Black Warrior Trust NationsBank of Texas, N.A. NationsBank Plaza - 17th Floor 901 Main Street Dallas, Texas 75202 Gentlemen: We hereby consent to the inclusion of our report dated February 23, 2000, concerning the reserves and revenue, as of January 1, 2000, of certain royalty interests owned by Dominion Resources Black Warrior Trust in the Form 10-K for the year ended December 31, 1999, of the Dominion Resources Black Warrior Trust to be filed with the Securities and Exchange Commission. Very truly yours, RYDER SCOTT COMPANY, L.P. CPM/sw EX-27.1 4 FINANCIAL DATA SCHEDULE
5 12-MOS DEC-31-1999 JAN-01-1999 DEC-31-1999 124,159 0 0 0 0 124,159 155,817,500 80,544,548 75,397,111 123,931 0 0 0 0 75,273,180 75,397,111 20,031,958 20,088,664 0 703,308 0 0 0 19,385,356 0 0 0 0 0 19,385,356 2.47 2.46
EX-99.1 5 PRESS RELEASE 1 Ryder Scott Company Petroleum Consultants 1100 Louisiana, Suite 3800 Houston, TX 77002-5218 February 23, 2000 Dominion Black Warrior Basin, Inc. Riverfront Plaza - West Tower 901 E. Byrd Street Richmond, VA 23219-4072 Gentlemen: At your request, we have prepared an estimate of the reserves, future production, and income attributable to certain royalty interests of Dominion Resources Royalty Trust 1994-1 (Dominion) as of January 1, 2000. The subject properties are located in the Black Warrior Basin, Tuscaloosa County, Alabama. Two cases of reserve estimates based on different pricing parameters provided by Dominion are presented herein. The income data for Case 1 was estimated using escalated cost and price parameters. It should be noted that due to a combination of economic and political forces, there is significant uncertainty regarding the forecasting of future hydrocarbon prices. The recoverable reserves and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. A summary of the results of this study is shown below. CASE 1 ESCALATED PARAMETERS - YEAR END PRICING Estimated Net Reserve and Income Data Certain Royalty Interests of DOMINION RESOURCES ROYALTY TRUST 1994-1 65% OVERRIDING ROYALTY INTEREST As of January 1, 2000 -----------------------------------------------------------
Total Proved ------------ NET REMAINING RESERVES Gas - MMCF 70,235 INCOME DATA Future Gross Revenue $182,805,658 Tax Credits $ 24,858,955 ------------ Future Net Income (FNI) $207,663,955 Discounted FNI @ 5% $149,458,540
2 Dominion Black Warrior Basin, Inc. February 23, 2000 Page 2 CASE 2 UNESCALATED PARAMETERS - YEAR-END PRICING Estimated Net Reserve and Income Data Certain Royalty Interest of DOMINION RESOURCES TRUST 1994-1 65% OVERRIDING ROYALTY INTEREST As of January 1, 2000 ----------------------------------------------------------------
Total Proved ------------ NET REMAINING RESERVES - ---------------------- Gas - MMCF 69,180 INCOME DATA Future Gross Revenue $140,402,560 Tax Credits $ 24,328,162 ------------ Future Net Income (FNI) $164,730,722 Discounted FNI @ 5% $126,467,437
All gas volumes are sales gas expressed in millions of cubic feet (MMCF) at the official temperature and pressure base of the area in which the gas reserves are located. All of the reserves included herein are comprised of the proved producing category. The various producing status categories are defined under the tab "Reserve Definitions and Pricing Assumptions" in this report. A Staff Accounting Bulletin (S.A.B.) issued September 18, 1989 allows for oil and gas producing companies to include coalbed methane gas in their estimate of proved reserves under SEC guidelines. In accordance with the S.A.B. dated November 30, 1989 these reserves should be included provided they comply in all other respects with the definition of proved oil and gas reserves. Included is the requirement that methane production be economical at current prices, costs (net of the tax credit) and existing operating conditions. At your request, the coalbed methane gas reserves presented herein are based on economic parameters which include your estimates of the future Section 29 Tax Credit. Your estimates of the future tax credits are presented in detail under the tab "Reserve Definition and Pricing Assumptions" in this report. The future gross revenue is after the deduction of production taxes and before the addition of Dominion`s estimate of the Section 29 Tax Credit (presented as "Other Income"). The future net income is before the deduction of state and federal income taxes and general administrative 3 Dominion Black Warrior Basin, Inc. February 23, 2000 Page 3 overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. Gas reserves account for 100 percent of total future gross revenue from proved reserves. The discounted future net income shown above was calculated using a discount rate of 5 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown on each estimated projection of future production and income presented in a later section of this report and in summary form below. Year End Pricing DOMINION RESOURCES ROYALTY TRUST 1994-1 65% OVERRIDING ROYALTY INTEREST Discounted Future Net Income As of January 1, 2000 Total Proved -------------------------------------------------------
Discount Rate Escalated Unescalated Percent Case Case ---------------- ------------- ------------- 10 $ 116,638,533 $ 102,854,098 15 $ 95,964,656 $ 86,958,053 20 $ 81,813,050 $ 75,533,178 25 $ 71,505,369 $ 66,904,940
The results shown above are presented for your information and should not be construed as our estimate of fair market value. RESERVES INCLUDED IN THIS REPORT Escalated Parameters The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as clarified by subsequent Commission Staff Bulletins, except that they are based on cost and price parameters which allow for future changes in current economic conditions as discussed in other sections of this report; whereas, the definition approved by the Securities and Exchange Commission assumes no change in current economic conditions will occur in the future. 4 Dominion Black Warrior Basin, Inc. February 23, 2000 Page 4 It should be noted that the estimated quantities of reserves presented in this report, which were based on escalated cost and price parameters, differ from the quantities of reserves which were estimated using constant current cost and price parameters. Unescalated Parameters The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulation S-X 210.4-10(a) as clarified by subsequent Commission Staff Accounting. Our definition of proved reserves is included under the tab "Reserve Definitions and Pricing Assumptions" in this report. ESTIMATES OF RESERVES The reserves included herein were estimated by the performance method. The reserves estimated by the performance method utilized extrapolations of various historical data. The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations. FUTURE PRODUCTION RATES Initial production rates are based on the current producing rates for those wells now on production. Test data on other related information were used to estimate the anticipated peak production rates for those wells which are not currently producing at peak rates. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of dewatering where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. In general, we estimate that future gas production rates will continue to be the same as the average rate for the latest available 12 months of actual production until such time that the well or wells are incapable of producing at this rate. The well or wells were then projected to decline at their decreasing delivery capacity rate. Our general policy on estimates of future gas production rates is adjusted when necessary to reflect actual gas market conditions in specific cases. The future production rates from wells now on production may be more or less than estimated because of changes in marketing conditions or allowables set by regulatory bodies. Wells or locations which are not currently producing may start producing earlier or later than anticipated in our estimates of their future production rates. 5 Dominion Black Warrior Basin, Inc. February 23, 2000 Page 5 HYDROCARBON PRICES Escalated Parameters The future hydrocarbon price parameters used in the escalated pricing scenario reflect Dominion's current estimates. Estimates of future price parameters have been revised in the past because of changes in governmental policies, changes in hydrocarbon supply and demand, and variations in general economic conditions. There is a possibility that the price parameters used in this report may be revised in the future for similar reasons. Unescalated Parameters Dominion furnished us with gas prices in effect at January 1, 2000 and these prices were held constant to depletion of the reserves in the unescalated pricing scenario. Dominion's estimates of future price parameters for gas are presented in detail under the tab "Reserve Definitions and Pricing Assumptions" in this report. COSTS The income attributable to Dominion Resources Royalty Trust 1994-1 is based on a 65 percent overriding royalty interest, and has no associated deductions or costs. The costs utilized in the evaluation of the leasehold interest are presented below. Escalated Parameters The escalated case utilized the same operating and cost parameters as the unescalated except they are escalated according to a scenario provided by Dominion. Future costs parameters are presented in detail under the tab "Reserve Definitions and Pricing Assumptions" in this report. Unescalated Parameters Operating costs for the leases and wells in the unescalated case are based on the operating expense reports of Dominion and include only those costs directly applicable to the leases or wells. When applicable, the operating costs include a portion of general and administrative costs allocated directly to the leases and wells under terms of operating agreements. The current operating costs were held constant throughout the life of the properties. At the request of Dominion, their estimate of zero net abandonment costs after salvage value for properties was used in this report. We have not performed a detailed study of the abandonment costs nor the salvage value and make no warranty for Dominion's estimate. No deduction was made for indirect costs such as general administration and overhead expenses, 6 Dominion Black Warrior Basin, Inc. February 23, 2000 Page 6 loan repayments, interest expenses, and exploration and development prepayments that are not charged directly to the leases or wells. GENERAL Table A presents a one line summary of gross and net reserves and income data for each of the subject properties. The grand summaries of our estimated projection of production and income by years beginning January 1, 2000 are presented under the tab "Grand Summary Projections". The estimates of reserves presented herein are based upon a detailed study of the properties in which Dominion owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities which may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. Dominion has informed us that they have furnished us all of the accounts, records, geological and engineering data, and reports and other data required for this investigation. The ownership interests, prices, and other factual data furnished by Dominion were accepted without independent verification. The estimates presented in this report are based on data available through November 1999. Neither we nor any of our employees have any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future income of the subject properties. This report was prepared for the exclusive use of Dominion Black Warrior Basin, Inc., The data, work papers, and maps used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service. Very truly yours, RYDER SCOTT COMPANY, L.P. C. Patrick McInturff, P.E. Petroleum Engineer Approved: - ---------------------------------- John R. Warner, P.E. Senior Vice President -----END PRIVACY-ENHANCED MESSAGE-----