-----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, BrMA8FxrVLeLOvSLWGHtbHTp2A9xU7nXEp5k9gBCdTXWlgP4JLf3dyx6YRgVjgZw Z6fIaldALeRNO5ilWWqFlQ== 0000930661-97-000777.txt : 19970402 0000930661-97-000777.hdr.sgml : 19970402 ACCESSION NUMBER: 0000930661-97-000777 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970331 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST CENTRAL INDEX KEY: 0000906547 STANDARD INDUSTRIAL CLASSIFICATION: OIL ROYALTY TRADERS [6792] IRS NUMBER: 766088828 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-12058 FILM NUMBER: 97572017 BUSINESS ADDRESS: STREET 1: NATIONSBANK OF TEXAS NA STREET 2: 700 LOUISIANA ST STE 3100 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7132477508 MAIL ADDRESS: STREET 1: NATIONSBANK OF TEXAS N A STREET 2: 901 MAIN STREET SUITE 1200 CITY: DALLAS STATE: TX ZIP: 75202 10-K405 1 FORM 10-K405 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ----------------------------- (Mark One) FORM 10-K [ [x] ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 ----------------------------- COMMISSION FILE NUMBER: 1-12058 BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) DELAWARE 76-6088828 (STATE OR OTHER JURISDICTION (I.R.S. EMPLOYER OF INCORPORATION OR ORGANIZATION) IDENTIFICATION NUMBER) NationsBank of Texas, N.A. NationsBank Plaza 901 Main Street, Suite 1700 Dallas, Texas 75202 (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (214) 508-2304 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 17, 1997, there were 8,800,000 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 $70,400,000. DOCUMENTS INCORPORATED BY REFERENCE Listed below are documents parts of which are incorporated herein by reference and the part of this report into which the document is incorporated: 1996 Annual Report to Unitholders - Part II. ================================================================================ TABLE OF CONTENTS PAGE ---- PART I Item 1. Business.......................................................... 1 GLOSSARY............................................................... 1 DESCRIPTION OF THE TRUST............................................... 5 Creation and Organization of the Trust............................ 5 Assets of the Trust............................................... 6 Liabilities of the Trust.......................................... 6 Duties and Limited Powers of the Trustee.......................... 6 Liabilities of the Delaware Trustee and the Trustee............... 7 Termination and Liquidation of the Trust.......................... 7 Arbitration and Derivative Actions................................ 8 DESCRIPTION OF UNITS................................................... 9 Distributions and Income Computations............................. 10 Conditional Right of Repurchase................................... 10 Possible Divestiture of Units..................................... 11 Periodic Reports to Unitholders................................... 12 Voting Rights of Unitholders...................................... 12 Liability of Unitholders.......................................... 13 Transfer Agent.................................................... 13 FEDERAL INCOME TAXATION................................................ 13 Summary of Certain Federal Income Tax Consequences................ 14 ERISA CONSIDERATIONS................................................... 18 STATE TAX CONSIDERATIONS............................................... 18 REGULATION AND PRICES.................................................. 18 Regulation of Natural Gas......................................... 18 Environmental Regulation.......................................... 19 Competition, Markets and Prices................................... 20 Item 2. Properties........................................................ 21 THE ROYALTY INTERESTS..................................... ............ 21 The Underlying Properties......................................... 21 The NPI........................................................... 23 Reserve Report.................................................... 24 Historical Gas Sales Prices and Production........................ 25 Possible NPI Percentage Reduction................................. 25 Gas Purchase Contract............................................. 26 Gas Gathering Contract............................................ 28 Federal Lands..................................................... 29 Sale and Abandonment of Underlying Properties..................... 30 The Infill NPI.................................................... 31 Burlington Resources' Performance Assurances...................... 31 Title to Properties............................................... 31 Item 3. Legal Proceedings................................................. 32 Item 4. Submission of Matters to a Vote of Security Holders............... 32 (i) PAGE ---- PART II Item 5. Market for Registrant's Common Equity and Related Unitholder Matters................................................ 32 Item 6. Selected Financial Data........................................... 32 Item 7. Trustee's Discussion and Analysis of Financial Condition and Results of Operations......................................... 33 Item 8. Financial Statements and Supplementary Data....................... 33 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.............................................. 33 PART III Item 10. Directors and Executive Officers of the Registrant................ 33 Item 11. Executive Compensation............................................ 33 Item 12. Security Ownership of Certain Beneficial Owners and Management.... 34 Item 13. Certain Relationships and Related Transactions.................... 34 Administrative Services Agreement............................... 34 Burlington Resources' Conditional Right of Repurchase........... 34 Potential Conflicts of Interest................................. 34 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K... 36 Financial Statements............................................ 36 Financial Statement Schedules................................... 36 Exhibits........................................................ 36 Reports on Form 8-K............................................. 38 (ii) PART I ITEM 1. BUSINESS. The following is a glossary of certain defined terms used in this Annual Report on Form 10-K. GLOSSARY "Administrative Services Agreement" means the Administrative Services Agreement, dated effective May 1, 1993, between Burlington Resources and the Trust, a copy of which is filed as an exhibit to this Form 10-K. "After-tax Cash Flow per Unit" means the sum of the following amounts that a hypothetical purchaser of a Unit in the Public Offering would have received or been allocated if such Unit were held through the date of such determination: (a) total cash distributions per Unit plus (b) total tax credits available per Unit under Section 29 of the IRC less (c) the total net taxes payable per Unit (assuming a 31 percent tax rate, the highest effective Federal income tax rate applicable to individuals at the time of the Public Offering). "Bcf" means billion cubic feet of natural gas. "Blanco Hub Spot Price" means for each month the posted index price (in dollars per MMBtu, on a dry basis) of spot gas delivered to pipelines as published in the first issue of such month during which gas is delivered or such determination is made, as the case may be, in Inside FERC's Gas Market Report for "El Paso Natural Gas Company, San Juan." Pursuant to the Gas Purchase Contract, MOTI has a one-time option to elect to substitute for the foregoing as the Blanco Hub Spot Price either (i) the average of the two posted index prices reported each month in Inside FERC's Gas Market Report for "El Paso Natural Gas Company, San Juan" or (ii) the Blanco Hub posted index price reported by Inside FERC's Gas Market Report, if either such price is then published in such publication. For purposes hereof, "average" prices refer to averages of the relevant monthly prices reported in Inside FERC's Gas Market Report. "Btu" means British Thermal Unit, the common unit of gross heating value measurement for natural gas. "Burlington Resources" means Burlington Resources Inc. "Central Gathering Point" means any one of four central delivery points in the unit gathering system of the Northeast Blanco Unit or any one of two wellhead delivery points. "Citibank's Base Rate" means a fluctuating interest rate per annum (compounded quarterly) as shall be in effect from time to time which rate per annum shall at all times be equal to the rate of interest announced publicly by Citibank, N.A. in New York, New York, from time to time, as its base rate. "Conveyance" means the Net Profits Interest Conveyance from MOPI to the Trust, a copy of which is filed as an exhibit to this Form 10-K. "December 31, 1993 Reserve Report" means the Reserve Report, dated March 25, 1994, on the estimated MOPI reserves, estimated future net revenues and the discounted estimated future net revenues distributable to the Royalty Interests and the Underlying Properties as of December 31, 1993, prepared by Netherland, Sewell & Associates, Inc., independenet petroleum engineers, a copy of which is filed as an exhibit to this Form 10-K. "December 31, 1994 Reserve Report" means the Reserve Report, dated March 15, 1995, on the estimated MOPI reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests and the Underlying Properties as of December 31, 1994, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers, a copy of which is filed as an exhibit to this Form 10-K. "December 31, 1994 Section 29 Tax Credit Report" means the report, dated March 16, 1995, on the estimated MOPI reserves and estimated Section 29 tax credits attributable to the Royalty Interests and the Underlying Properties as of December 31, 1994, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers, a copy of which is filed as an exhibit to this Form 10-K. 1 "December 31, 1995 Reserve Report" means the Reserve Report, dated March 18, 1996, on the estimated MOPI reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests and the Underlying Properties as of December 31, 1995, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers, a copy of which is filed as an exhibit to this Form 10-K. "December 31, 1995 Section 29 Tax Credit Report" means the report, dated March 19, 1996, on the estimated MOPI reserves and estimated Section 29 tax credits attributable to the Royalty Interests and the Underlying Properties as of December 31, 1995, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers, a copy of which is filed as an exhibit to this Form 10-K. "December 31, 1996 Reserve Report" means the Reserve Report, dated March 20, 1997, on the estimated MOPI reserves, estimated future net revenues and the discounted estimated future net revenues attributable to the Royalty Interests and the Underlying Properties as of December 31, 1996, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers, a copy of which is filed as an exhibit to this Form 10-K. "December 31, 1996 Section 29 Tax Credit Report" means the report, dated March 21, 1997, on the estimated MOPI reserves and estimated Section 29 tax credits attributable to the Royalty Interests and the Underlying Properties as of December 31, 1996, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers, a copy of which is filed as an exhibit to this Form 10-K. "Delaware Code" means the Delaware Business Trust Act, Title 12, Chapter 38 of the Delaware Code, Sections 3801 et seq. "Delaware Trustee" means Mellon Bank (DE) National Association, in its capacity as a trustee of the Trust. "Gas Gathering Contract" means the Gas Gathering, Dehydrating and Treating Agreement, dated as of May 3, 1990, between MOGI and MOTI, as amended, a copy of which is filed as an exhibit to this Form 10-K. "Gas Purchase Contract" means the Gas Purchase Contract, dated as of May 1, 1993, between MOPI and MOTI, a copy of which is filed as an exhibit to this Form 10-K. "Grantor trust" means a trust as to which the grantor, or his successor, has retained an interest in the income from the trust. "Gross acres" means the total number of surface acres of land. "Gross wells" means the total whole number of gas wells. "Index Price" means, for each month, 97 percent of the Blanco Hub Spot Price (such 3 percent deduction constituting a discount to compensate MOTI for marketing the gas). "Infill Net Proceeds" consists generally of the aggregate proceeds based on the price at the Central Gathering Point of gas attributable to MOPI's interest in any Infill Wells less (a) MOPI's working interest share of property, production and related taxes (including severance taxes) in respect of such Infill Wells; (b) MOPI's working interest share of lease operating expenses in respect of such Infill Wells; (c) MOPI's working interest share of capital costs in respect of such Infill Wells, including the costs of drilling and completing such Infill Wells and the costs of associated surface facilities; and (d) interest on the unrecovered portion, if any, of the foregoing costs at Citibank's Base Rate. In no event will any amounts relating to environmental liabilities related to activities occurring on or under, or in connection with, or conditions existing on or under, the Underlying Properties before June 17, 1993 (which liabilities will be borne by MOPI) be deducted in calculating Infill Net Proceeds. "Infill NPI" refers to one of the net profits interests conveyed to the Trust, entitling the Trust to receive a 20 percent interest in the Infill Net Proceeds. 2 "Infill Wells" means any additional wells drilled on the Underlying Properties after the date of the Conveyance pursuant to a change in spacing rules or a change allowing additional wells to be drilled on a spacing or proration unit, in either case made effective after such date. "IRC" means the Internal Revenue Code of 1986, as amended. "IRR" means the annual discount rate (compounded quarterly) that equates the present value of the After-tax Cash Flow per Unit to the $20.50 per Unit initial price to the public of the Units in the Public Offering. "Mcf" means thousand cubic feet of natural gas. Natural gas volumes are stated herein at the legal pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit. "Minimum Purchase Price" means $1.60 per MMBtu, subject to increase by 2 1/2 percent annually as of May 1 of each year commencing in 2003. "MMBtu" means million Btu. "MMcf" means million cubic feet of natural gas. "MOGI" means Burlington Resources Gathering Inc. (formerly named Meridian Oil Gathering Inc.), a wholly owned subsidiary of Burlington Resources. "MOPI" means Burlington Resources Oil & Gas Company (formerly named Meridian Oil Inc., which is the successor by merger to Meridian Oil Production Inc.) "MOPI Payment Obligations" has the meaning assigned to such term under "Item 2--The Royalty Interests--Burlington Resources' Performance Assurances." "MOTI" means Burlington Resources Trading Inc. (formerly named Meridian Oil Trading Inc.), a wholly owned subsidiary of Burlington Resources. "MOTI Payment Obligations" has the meaning assigned to such term under "Item 2--The Royalty Interests--Burlington Resources' Performance Assurances." "Net profits interest" generally refers to a real property interest entitling the owner to receive as a royalty a specified percentage of the net proceeds from the sale of production attributable to the properties burdened thereby, the amount of which is based on a revenue formula specified in such net profits interest. "Net revenue interest" means working interest or mineral interest less any applicable royalties, overriding royalties or similar burdens on production. "Net wells" and "net acres" are calculated by multiplying gross wells or gross acres by the working interest in such wells or acres. "Northeast Blanco Unit" means the unit area covered by that certain Unit Agreement For The Development And Operation of The Northeast Blanco Unit Area, dated July 16, 1951, and includes the rights attributable to such area in one communitized gross well with acreage in both the Northeast Blanco Unit and the adjoining San Juan 30-6 Unit (the "San Juan 30-6 Unit"). "NPI" refers to one of the net profits interests conveyed to the Trust, generally entitling the Trust to receive 95 percent of the NPI Net Proceeds. The NPI is subject to reduction as described under "Item 2--The Royalty Interests-- Possible NPI Percentage Reduction." 3 "NPI Net Proceeds" consists generally of the aggregate proceeds attributable to MOPI's net revenue interest in the Underlying Properties (other than its interest by virtue of Infill Wells) based on the sale at the Central Gathering Point of gas produced from the Underlying Properties, less (i) MOPI's working interest share of property, production and related taxes (including severance taxes) on the Underlying Properties; (ii) MOPI's working interest share of lease operating expenses on the Underlying Properties; (iii) MOPI's working interest share of capital costs on the Underlying Properties (other than capital costs incurred prior to January 1, 1994, which costs were borne by MOPI to the extent of its working interest share); (iv) royalties, if any, required to be paid that are based on the value of Section 29 tax credits attributable to such working interest share; and (v) interest on the unrecovered portion, if any, of the foregoing costs at Citibank's Base Rate. In no event will any amounts relating to environmental liabilities related to activities occurring on or under, or in connection with, or conditions existing on or under, the Underlying Properties before June 17, 1993 (which liabilities will be borne by MOPI) be deducted in calculating NPI Net Proceeds. "Price Credit" means the credit received by MOTI from MOPI for each MMBtu of natural gas purchased by MOTI after December 31, 1993 when the Index Price is less than the Minimum Purchase Price, equal to the difference between the Minimum Purchase Price and the Index Price. "Price Credit Account" means the account established by MOTI containing the accrued and unrecouped amount of any Price Credits. "Price Differential" means 50 percent of the excess of the Index Price over the Sharing Price. "Prior Reserve Reports" means, collectively, the December 31, 1993 Reserve Report, December 31, 1994 Reserve Report and December 31, 1995 Reserve Report. "Prior Tax Credit Reports" means, collectively, the December 31, 1994 Section 29 Tax Credit Report and December 31, 1995 Section 29 Tax Credit Report. "Public Offering" has the meaning assigned to such term under "--Description of the Trust--Creation and Organization of the Trust." "Public Offering Prospectus" has the meaning assigned to such term herein under "Item 1 - Federal Income Taxation." "Royalty" means an interest entitling the holder thereof to a certain percentage of the gas produced from the wells, which generally is free of all expenses of production, but may be subject to certain post-production costs. "Royalty Interests" means the NPI and the Infill NPI conveyed to the Trust. "Sharing Price" means $2.04 per MMBtu, subject to increase by 2 1/2 percent annually as of May 1 of each year commencing in 2003. "Trust" means Burlington Resources Coal Seam Gas Royalty Trust, a Delaware business trust formed pursuant to the Trust Agreement. "Trust Agreement" means the Trust Agreement, dated as of May 1, 1993, among Burlington Resources, MOPI, as grantor, Mellon Bank (DE) National Association, as the Delaware Trustee, and NationsBank of Texas, N.A., as the Trustee, a copy of which is filed as an exhibit to this Form 10-K. "Trustee" means NationsBank of Texas, N.A., in its capacity as a trustee of the Trust. "Underlying Properties" means the Fruitland coal formation underlying the Northeast Blanco Unit. "Units" means the 8,800,000 units of beneficial interest issued by, and evidencing the entire beneficial interest in, the Trust. 4 "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 requiring the owner of such working interest to bear a specified percentage of the costs to explore for, develop, produce and market such oil and gas. DESCRIPTION OF THE TRUST Burlington Resources Coal Seam Gas Royalty Trust (the "Trust") was formed as a Delaware business trust under the Delaware Business Trust Act, Title 12, Chapter 38 of the Delaware Code, Sections 3801 et seq. (the "Delaware Code"). The following information is subject to the detailed provisions of (i) the Trust Agreement of Burlington Resources Coal Seam Gas Royalty Trust (the "Trust Agreement"), dated as of May 1, 1993, among Burlington Resources Inc., a Delaware corporation ("Burlington Resources"), Meridian Oil Production Inc., a Delaware corporation ("MOPI"), as grantor, Mellon Bank (DE) National Association, a national banking association (the "Delaware Trustee"), and NationsBank of Texas, N.A., a national banking association (the "Trustee"), as trustees, and (ii) the Net Profits Interest Conveyance (the "Conveyance") dated effective as of May 1, 1993 from MOPI to the Trust. Effective January 1, 1996, MOPI was merged with and into Meridian Oil Inc. ("MOI"), a wholly owned subsidiary of Burlington Resources. Effective July 11, 1996, MOI changed its name to Burlington Resources Oil & Gas Company ("BROG") and Meridian Oil Trading Inc. ("MOTI") and Meridian Oil Gathering Inc. ("MOGI"), both affiliates of MOI, changed their names to Burlington Resources Trading Inc. ("BRTI") and Burlington Resources Gathering Inc. ("BRGI"), respectively. Accordingly, in this Form 10-K references to MOPI refer to BROG after the date of such merger, references to MOTI refer to BRTI and references to MOGI refer to BRGI. Copies of the Trust Agreement and of the Conveyance 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 a summary of the material terms of the Trust Agreement, and detailed provisions concerning the Trust may be found in the Trust Agreement. CREATION AND ORGANIZATION OF THE TRUST All of the authorized units of beneficial interest in the Trust ("Units") were issued to MOPI on June 17, 1993. On that date, MOPI transferred its Units to its parent, Burlington Resources, by dividend. Burlington Resources, in turn, sold, by means of a prospectus dated June 10, 1993, 7,700,000 Units on June 17, 1993, and an additional 1,100,000 Units on June 23, 1993, to the public through various underwriters (the "Public Offering"). The Trust has been formed under Delaware law pursuant to the terms of the Trust Agreement to acquire and hold certain net profits interests (the "Royalty Interests") in MOPI's interest in the Fruitland coal formation underlying the Northeast Blanco Unit (the "Underlying Properties"). The Royalty Interests were conveyed to the Trust on June 17, 1993 pursuant to the Conveyance for the benefit of the Unitholders. The Trustee has all powers to collect and distribute proceeds received by the Trust and to pay Trust liabilities and expenses. The Delaware Trustee has only such powers as are set forth in the Trust Agreement or are required by law and is not empowered to otherwise manage or take part in the business of the Trust. The Royalty Interests are passive in nature and neither the Delaware Trustee nor the Trustee has any control over or any responsibility relating to the operation of the Underlying Properties. Neither MOPI nor the operator of the Underlying Properties has any contractual commitments to the Trust to further develop the Underlying Properties, to remain as operator with respect to the Northeast Blanco Unit or to maintain its ownership interest in any of the properties. However, after the conveyance of the Royalty Interests, MOPI retained its interest in the Underlying Properties, which interest is burdened by the Royalty Interests. MOPI may sell its interest in the Underlying Properties subject to and burdened by the Royalty Interests. For a description of the Underlying Properties and other information relating to such properties, see "Item 2--The Royalty Interests." The Delaware Trustee and the Trustee may resign at any time upon 60 days' prior written notice or be removed with or without cause at any time by a vote of a majority of the outstanding Units, provided in each case that a successor trustee has been appointed and has accepted its appointment. Any successor trustee must be a bank or trust company meeting certain requirements including having combined capital, surplus and undivided profits of at least $20,000,000, in the case of the Delaware Trustee, and $100,000,000, in the case of the Trustee. 5 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 primarily of a net profits interest (the "NPI") in the Underlying Properties, generally entitling the Trust to receive 95 percent of the NPI Net Proceeds. "NPI Net Proceeds" consists generally of the aggregate proceeds attributable to MOPI's net revenue interest in the Underlying Properties (other than its interest by virtue of Infill Wells, as defined below) based on the sale at the Central Gathering Point (as defined) of gas produced from the Underlying Properties, less (i) MOPI's working interest share of property, production and related taxes (including severance taxes) on the Underlying Properties; (ii) MOPI's working interest share of lease operating expenses on the Underlying Properties; (iii) MOPI's working interest share of capital costs on the Underlying Properties (other than capital costs incurred prior to January 1, 1994, which costs were borne by MOPI to the extent of its working interest share); (iv) royalties, if any, required to be paid that are based on the value of Section 29 tax credits attributable to such working interest share; and (v) interest on the unrecovered portion, if any, of the foregoing costs at Citibank's Base Rate. The Royalty Interests also include a net profits interest (the "Infill NPI") entitling the Trust to receive a 20 percent interest in the Infill Net Proceeds, as defined below, from the sale of production from any additional wells drilled on the Underlying Properties after May 1, 1993 pursuant to a change in spacing rules or a change allowing additional wells to be drilled on a spacing or proration unit ("Infill Wells"). "Infill Net Proceeds" consists generally of the aggregate proceeds based on the price at the Central Gathering Point of gas attributable to MOPI's interest in any Infill Wells less MOPI's working interest share of taxes, lease operating expenses, capital costs, and interest on the unrecovered portion, if any, of the foregoing costs. See "Item 2--The Royalty Interests" for more information. LIABILITIES OF THE TRUST Because of the passive nature of the Trust assets and the restrictions on the activities of the Trustee, it is anticipated that the only liabilities the Trust will incur are those for routine administrative expenses, such as the trustees' fees and accounting, engineering, legal and other professional fees and the administrative services fee paid to Burlington Resources. However, as discussed under "--Federal Income Taxation," if a court were to hold that the Trust is taxable as a corporation, then the Trust would be subject to Federal income taxes. DUTIES AND LIMITED POWERS OF THE TRUSTEE Under the Trust Agreement, the Trustee receives the payments attributable to the Royalty Interests and pays all expenses, liabilities and obligations of the Trust. With respect to any liability that is contingent or uncertain in amount or that otherwise is not currently due and payable, the Trustee has the discretion to establish a cash reserve for the payment of such liability. The Trustee is entitled to cause the Trust to borrow money to pay expenses, liabilities and obligations that cannot be paid out of cash held by the Trust. Any such borrowing may be from any source, including from the entity serving as Trustee or Delaware Trustee, provided that the entity serving as Trustee or Delaware Trustee shall not be obligated to lend to the Trust. To secure payment of any such indebtedness (including any indebtedness to the entity serving as Trustee or Delaware Trustee), the Trustee is authorized to (i) mortgage and otherwise encumber the entire Trust estate or any portion thereof, including the Royalty Interests; (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 entity serving as Trustee or Delaware Trustee, must be similar to the terms which such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship, and such entity shall be entitled to enforce its rights with respect to any such indebtedness and security interest as if it were not then serving as trustee. The Trustee is authorized and directed to sell and convey the Royalty Interests without Unitholder approval in certain instances as described in the Trust Agreement, including upon termination of the Trust. The Trustee is empowered by the Trust Agreement to employ consultants and agents (including MOPI and Burlington Resources) 6 and to make payments of all fees for services or expenses out of the assets of the Trust. The Trust has no employees. The administrative functions of the Trust are performed by the Trustee. The Trust Agreement authorizes the Trustee to take such action as in its judgment is necessary or advisable to achieve the purposes of the Trust. The Trustee is authorized to agree to modifications of the terms of the Conveyance and to settle disputes with respect thereto, so long as such modifications or settlements do not result in treatment of the Trust for Federal income tax purposes as an association taxable as a corporation 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 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 initial cash deposit and the Royalty Interests 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 or Delaware Trustee provided the interest paid equals the amount paid by the Trustee or Delaware Trustee, as the case may be, on similar deposits. LIABILITIES OF THE DELAWARE TRUSTEE AND THE TRUSTEE Each of the Delaware Trustee and the Trustee may act in its discretion and shall be personally or individually liable only for fraud or acts or omissions in bad faith or which constitute gross negligence (and for taxes, fees and other charges based on 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 or retention of such agent or employee. Each of the Delaware Trustee and the Trustee (and their respective agents) is indemnified by Burlington Resources and MOPI 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 Delaware Trustee and the Trustee being indemnified from the Trust assets against its own negligence which does not constitute gross negligence), and will have a first lien against 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 Burlington Resources. Burlington Resources has also indemnified the Trustee and the Delaware Trustee against certain securities laws liabilities. Neither the Delaware Trustee nor the Trustee is entitled to indemnification from Unitholders (except in connection with lost or destroyed Unit certificates). TERMINATION AND LIQUIDATION OF THE TRUST The Trust will not terminate prior to January 1, 2003, except upon the affirmative vote of the holders of not less than 66-2/3% percent of the outstanding Units to liquidate the Trust. Thereafter, and subject to Burlington Resources' conditional right of repurchase (see "--Description of Units-- Conditional Right of Repurchase"), the Trust will terminate upon the first to occur (such date, the "Termination Date") of (i) an affirmative vote of the holders of not less than 66-2/3% percent of the outstanding Units to terminate the Trust; (ii) such time as the ratio of the cash amounts received by the Trust from the Royalty Interests (excluding deductions for capital expenditures) to administrative costs of the Trust is less than 1.2 to 1.0 for three consecutive quarters; (iii) such time as the Royalty Interests held by the Trust have been sold by the Trust; (iv) March 1 of any calendar year if, based on a reserve report as of December 31 of the prior year, it is determined that, as of such date, the net present value (discounted at 10 percent) of the estimated future net revenues (calculated in accordance with criteria established by the Securities and Exchange Commission (the "Commission") except that such calculation will utilize as the gas price in such calculation the average monthly gas price (before deduction of costs) paid under the Gas Purchase Contract for production attributable to MOPI's interest in the Underlying Properties during the 12 months ending on such December 31) of proved reserves attributable to the Royalty Interests is equal to or less than $30 million; and (v) December 31, 2012. Following termination, the Trustee and the Delaware Trustee will continue to act as trustees of the Trust until all remaining Trust assets have been sold and the net proceeds from such sales distributed to Unitholders. 7 Upon the termination of the Trust, the Trustee will use its best efforts (as defined in the Trust Agreement) to sell any remaining Royalty Interests for cash pursuant to the procedures described herein. The Trustee will retain an investment banking firm (the "Advisor") on behalf of the Trust who will assist the Trustee in selling the remaining Royalty Interests then owned by the Trust. MOPI has the right, but not the obligation, to purchase all remaining Royalty Interests following termination of the Trust as described in the following paragraph. MOPI may, within 60 days following the Termination Date, make a cash offer to purchase all of the remaining Royalty Interests then held by the Trust. In the event such an offer is made by MOPI, the Trustee will decide, based on the recommendation of the Advisor, to either (i) accept such offer (in which case no sale to MOPI 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 MOPI's offer, the offer will be deemed withdrawn and the Trustee will then use best efforts (as defined in the Trust Agreement), assisted by the Advisor, to locate other buyers for the Royalty Interests. At the end of a 120-day period following the Termination Date, the Trustee is required to notify MOPI of the highest of any other offers acceptable to the Trustee (which must be an all cash offer) received during such period (the "Highest Offer Price"). MOPI 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 Offer Price is more than 105 percent of MOPI's original offer (or if MOPI did not make an initial offer), the purchase price will be 105 percent of the Highest Offer Price, or (ii) if the Highest Offer Price is equal to or less than 105 percent of MOPI's original offer, the purchase price will be equal to the Highest Offer Price. If no other acceptable offers are received for all remaining Royalty Interests, the Trustee may request MOPI 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 MOPI 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 any 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 public auction, which sale may be to MOPI or any of its affiliates. MOPI's purchase rights, as described, may be exercised by MOPI and each of its successors in interest and assigns. MOPI's purchase rights are fully assignable by MOPI to any person or entity. The costs of liquidation, including the fees and expenses of the Advisor, and the Trustee's liquidation fee will be paid by the Trust. Unitholders are not entitled to any rights of appraisal or similar rights in connection with the termination of the Trust. ARBITRATION AND DERIVATIVE ACTIONS Pursuant to the Trust Agreement, any dispute, controversy or claim that may arise between or among (i) Burlington Resources or MOPI, on the one hand, and the Trustee, the Delaware Trustee and the Trust, on the other hand, in connection with or otherwise relating to the Trust Agreement or the application, implementation, validity or breach of the Trust Agreement or any provision thereof or (ii) MOPI, on the one hand, and the Trust, on the other hand, in connection with or otherwise relating to the Conveyance or the application, implementation, validity or breach of the Conveyance or any provision thereof, shall be finally, conclusively and exclusively settled by final and binding arbitration in Houston, 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 Gas Purchase Contract also includes a provision that will require MOPI and MOTI to submit any dispute regarding such contract to alternative dispute resolution before litigating such matter. 8 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 derivative action in the right of the Trust may be brought by a Unitholder in the Delaware Court of Chancery against Burlington Resources or MOPI (or any other person) to recover a judgment in favor of the Trust if the Trustee has refused to bring such action or if an effort to cause the Trustee to bring such action is not likely to succeed. Pursuant to Section 3816 of the Delaware Code, a plaintiff in a derivative action must be a beneficial owner at the time such action is brought and (a) at the time of the transaction subject to such complaint or (b) the plaintiff's status as a beneficial owner must have devolved upon it by operation of law or pursuant to the terms of the governing instrument of the trust from a person or entity who was a beneficial owner at the time of the transaction giving rise to the complaint. If a derivative action is successful, in whole or in part, or if anything is received by the trust as a result of a judgment, compromise or settlement of any such action, the Delaware Chancery Court may award the plaintiff reasonable expenses, including reasonable attorney's fees. If any award is so received by the plaintiff, the Delaware Chancery Court shall make such award of the plaintiff's expenses payable out of those proceeds and direct plaintiff to remit to the trust the remainder thereof. If the proceeds are insufficient to reimburse plaintiff's reasonable expenses in bringing the derivative action, the Delaware Chancery Court may direct that any such award of plaintiff's expenses or a portion thereof be paid by the trust. In addition, under Section 3816 a beneficial owner's right to bring a derivative action may be subject to such additional standards and restrictions, if any, as are set forth in the governing instrument of the trust, including, without limitation, the requirement that beneficial owners owning a specified beneficial interest in the trust join in the bringing of the derivative action. The rights of the Unitholders to bring a derivative action on behalf of the Trust provided pursuant to 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. Despite the latitude afforded pursuant to Section 3816, the Trust Agreement does not impose any such additional standards or restrictions on a Unitholder with respect to its right to bring a derivative action (other than as discussed below with respect to "MOPI Payment Obligations" and "MOTI Payment Obligations" (as such terms are defined herein)). 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 Burlington Resources or MOPI, then such Unitholder could, on behalf of the Trust, pursue such rights against Burlington Resources or MOPI, 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 Burlington Resources' obligation to cure any deficiency in MOPI Payment Obligations or MOTI Payment Obligations is subject to the restriction that such right may only be exercised by Unitholders owning of record not less than 25 percent of the Units then outstanding (treated as a single class) and then only absent action by the Trustee to enforce any such obligation within 10 days following receipt by the Trustee of a written request served upon the Trustee by such Unitholders to take such action. In such an event, Unitholders owning of record not less than 25 percent of the Units then outstanding may, acting as a single class and on behalf of the Trust, seek to enforce such obligations. 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 15, 1997, there were 8,800,000 Units outstanding. The Trust may not issue additional Units. 9 DISTRIBUTIONS AND INCOME COMPUTATIONS The Trustee determines for each 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, on or prior to the last business day before the 50th day following the end of each calendar quarter ending prior to the dissolution of the Trust from the Royalty Interests then held by the Trust attributable to production during such quarter, plus, with certain exceptions, any other cash receipts of the Trust during such quarter (which might include sales proceeds not sufficient in amount to qualify for special distribution (as described in the next paragraph) and interest), over the liabilities of the Trust paid during such quarter, 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. Based on the payment procedures relating to the Royalty Interests, cash received by the Trustee in a particular quarter from the Royalty Interests generally represents proceeds from the sale of gas produced during the preceding calendar quarter. The Quarterly Distribution Amount for each quarter is payable to Unitholders of record on the 63rd 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 distributes the Quarterly Distribution Amount on or prior to 75 days after the end of each calendar quarter to each person who was a Unitholder of record on the associated record date, together with interest estimated to be earned on such Quarterly Distribution Amount from the date of receipt thereof by the Trustee to the payment date. The Royalty Interests may be sold under certain circumstances and will be sold following termination of the Trust. Any proceeds from sales of the Royalty Interests, less liabilities and expenses of the Trust and amounts used for cash reserves, will be distributed, together with any interest expected to be earned thereon, to Unitholders of record on the record date established for such distribution. A special distribution will be made of undistributed sales proceeds and other amounts received by the Trust aggregating in excess of $10,000,000 (a "Special Distribution Amount"). The record date for 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 of 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. Distribution to Unitholders will be made no later than 15 days after the Special Distribution Amount record date. The terms of the Trust Agreement seek to assure to the extent practicable that gross income attributable to cash being distributed will be reported by the Unitholder who receives such distributions assuming that such Unitholder is the owner of record on the applicable record date. In certain circumstances, however, a Unitholder will not receive the cash giving rise to such income. For example, 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 any such borrowing 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 Unitholder's 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). CONDITIONAL RIGHT OF REPURCHASE Burlington Resources and any of its successors and affiliates retain in the Trust Agreement the right to repurchase all (but not less than all) outstanding Units at any time at which 15 percent or less of the outstanding Units is owned by persons or entities other than Burlington 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 Burlington 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 trading days prior to the date on which notice of such exercise is delivered to Unitholders and (ii) the average closing price of Units on the New York Stock Exchange for the 30 trading days immediately preceding the Determination Date. If Burlington Resources or any of its affiliates acquires Units (other than an acquisition from Burlington Resources or any affiliate) during the period that is three trading days after the Determination Date at a price per Unit greater than that at which an 10 acquisition was made during the 90-day period referred to in clause (i) of the preceding sentence, then for purposes of clause (i) of the preceding sentence the highest price used therein shall be such greater price. Any such repurchase would be conducted in accordance with applicable Federal and state securities laws. In the event that Burlington Resources elects to purchase all Units, Burlington 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 Burlington 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 Burlington Resources at the place designated in such notice and thereupon the purchase price of such Units shall be paid to or on the order of the person or entity whose name appears on such certificate or certificates as the owner thereof. In no event may fewer than all of the outstanding Units represented by the certificates be repurchased (except for any Units held by Burlington Resources and any of its affiliates). If Burlington Resources and the Trustee give a notice of repurchase and if, on or before the date fixed for repurchase, the funds necessary for such repurchase shall have been set aside by Burlington 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 Burlington Resources, MOPI, 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 the repurchase, upon surrender (and endorsement, if required by Burlington 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 Burlington Resources and unclaimed at the end of two years from the repurchase date shall revert to the general funds of Burlington Resources, after which reversion the holders of such Units so noticed for repurchase could look only to the general funds of Burlington Resources for the payment of the purchase price. Any interest accrued on funds so deposited would be paid to Burlington Resources from time to time as requested by Burlington Resources. In the event that Burlington 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 Burlington Resources' decision to terminate the Trust, the Trustee and the Delaware Trustee must cause all 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 Burlington Resources or its assignee (subject to the right of such trustees to create reasonable reserves in connection with the liquidation of the Trust). POSSIBLE DIVESTITURE OF UNITS The Trust Agreement imposes no restrictions based on nationality or other status of Unitholders. However, the Trust Agreement provides 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 within 90 days after expiration of the 30 day period, the Trustee shall cancel all outstanding certificates issued in the name of such Unitholder, transfer all Units held by such Unitholder to the Trustee and sell such Units (including by private sale). The proceeds of such sale (net of sales expenses), pending delivery of certificates representing the Units, will be held by the Trustee in a non- interest-bearing escrow account for the benefit of the Unitholder and will be paid to the Unitholder upon surrender of such certificates. Cash distributions payable to such Unitholder will also be held in a non-interest-bearing escrow account pending disposition by the Unitholder of the Units or cancellation of certificates representing the Units by the Trustee. 11 PERIODIC REPORTS TO UNITHOLDERS 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 quarterly record date for such quarter or (ii) on each Special Distribution Amount record date occurring during such quarter, a report which shows in reasonable detail the assets and liabilities and receipts and disbursements of the Trust and the revenues and direct operating expenses of MOPI's interest in the Underlying Properties for such quarter. Within 120 days following the end of each fiscal year or such shorter period of time as may be required by the rules of the New York Stock Exchange, the Trustee mails to Unitholders of record as of a date to be selected by the Trustee an annual report containing audited financial statements relating to the Trust and MOPI's interest in the Underlying Properties. The Trustee files such returns for Federal income tax purposes as it is required to comply with applicable law. The Trustee mails to each person or entity who was a Unitholder of record (i) on the quarterly record date for such quarter or (ii) on each Special Distribution Amount record date occurring during such quarter, a report which shows in reasonable detail the information necessary 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, the Trustee and the Delaware Trustee. 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 example, there is no requirement for annual meetings of Unitholders or for annual or other periodic re-election of the Trustee or the Delaware Trustee. Meetings of Unitholders may be called by the Trustee or by Unitholders owning not less than 10 percent in number of the outstanding Units. All such meetings shall be held in Houston, Texas and written notice of every such meeting setting forth the time and place of the meeting and the matters proposed to be acted upon shall be given not more than 60 nor less than 20 days before such meeting. The presence in person or by proxy of Unitholders representing a majority of the outstanding Units is necessary to constitute a quorum. Unitholders have the right to vote at all meetings of Unitholders and each Unitholder shall be entitled to one vote for each Unit owned by such Unitholder. The Trustee will call such meetings to consider amendments, waivers, consents and other changes relating to the Gas Purchase Contract, the Gas Gathering Contract or the Conveyance, if requested in writing by MOPI. No matter other than that stated in the notice of the Unitholder meeting shall be voted on and no action by the Unitholders may be taken without a meeting. Generally, amendments to the Trust Agreement require approval of a majority of the outstanding Units (except that amendment of required voting percentages requires approval of at least 80 percent of the outstanding Units), but no provision of the Trust Agreement may be amended that would (i) increase the power of the Delaware Trustee or the Trustee to engage in business or investment activities or (ii) alter the rights of the Unitholders as among themselves. Without the written consent of Burlington Resources and the approval of not less than 66-2/3% percent of the outstanding Units, no provision of the Trust Agreement may be amended with respect to (a) the sale or disposition of all or any part of the Trust estate, including the Royalty Interests, except as specifically provided in the Trust Agreement, (b) termination of the Trust and the disposition of Trust assets upon liquidation of the Trust or (c) MOPI's right of first refusal with respect to purchase of any remaining Royalty Interests upon termination of the Trust. Without the written consent of Burlington Resources and the approval of a majority of the outstanding Units, no amendment may be made to the Trust Agreement that would alter Burlington 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 Burlington Resources and its affiliates. Additionally, any amendment that increases the obligations, duties or liabilities of or affects the rights of the Delaware Trustee or the Trustee must be consented 12 to by such entity. The Trustee, the Delaware Trustee, Burlington Resources and MOPI 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, Burlington Resources may direct the Trustee to change the name of the Trust without approval of the Unitholders. Removal of the Trustee and the Delaware Trustee, approval of amendments, waivers, consents and other changes relating to the Gas Purchase Contract, the Gas Gathering Contract and 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 personal liability as is accorded under the laws of such state to stockholders of a corporation for profit. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation. TRANSFER AGENT The Trustee has appointed Boston Equiserve Shareholder Service transfer agent and registrar for the Units (the "Transfer Agent"). FEDERAL INCOME TAXATION 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-- Risks Associated With the Units--Tax Considerations" appearing in the Prospectus (the "Public Offering Prospectus") dated June 10, 1993, which constitutes a part of the Registration Statement on Form S-3 of Burlington Resources (Registration No. 33-61164) filed in connection with the registration of the Units under the Securities Act of 1933 for offer and sale in the Public Offering, set forth, respectively, a summary of Federal income tax matters of general application that addresses all material tax consequences of the ownership and sale of the Units acquired in the Public Offering and a discussion of certain risk factors associated with matters of Federal income taxation as applied to the Trust and such Unitholders. A copy of such sections of the Public Offering Prospectus is filed as an exhibit to this Form 10-K. In connection with the registration of the Units for offer and sale in the Public Offering, Burlington Resources and the underwriters of the Units received certain opinions of counsel to Burlington Resources (upon which the Trustee and the Delaware Trustee were entitled to rely), including, without limitation, opinions as to the material Federal income tax consequences of the ownership and sale of the Units acquired in the Public Offering. The opinions of counsel to Burlington Resources as to such Federal income tax consequences were based on provisions of the Internal Revenue Code of 1986, as amended (the "IRC"), as of June 17, 1993, the date of the closing of the Public Offering, existing and proposed regulations thereunder and administrative rulings and court decisions as of June 17, 1993, all of which are subject to changes that may or may not be retroactively applied. Some of the applicable provisions of the IRC have not been interpreted by the courts or the Internal Revenue Service ("IRS"). In addition, such opinions of counsel to Burlington Resources were based on various representations as to factual matters made by Burlington Resources and MOPI in connection with the Public Offering. As is typically the case, these opinions were limited in their application to certain investors purchasing Units in the Public Offering and, as a result, provide no assurance to investors purchasing Units following the Public Offering. 13 Neither counsel to the Trust, the Trustee nor the Delaware Trustee, respectively, has rendered any opinions with respect to any tax matters associated with the Trust or the Units. No ruling was requested by Burlington Resources, as the sponsor of the Trust, from the IRS with respect to any matter affecting the Trust or Unitholders. No assurance can be provided that the opinions of counsel to Burlington Resources (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 counsel to Burlington Resources on Federal income tax matters, which are set forth in the Public Offering Prospectus, and is qualified in its entirety by express reference to the sections of the Public Offering Prospectus identified in the first paragraph of this "Federal Income Taxation" section. Although the Trust believes that the following summary contains a description of all of the material matters discussed in the opinions referenced above, the summary is not exhaustive and many other provisions of the Federal tax laws may affect individual Unitholders. Furthermore, the summary does not purport to be complete or to address the tax issues potentially affecting Unitholders acquiring Units other than by purchase through the Public Offering. Each Unitholder should consult the Unitholder's tax advisor with respect to the effects of the Unitholder's ownership of Units on the Unitholder's personal tax situation. Classification and Taxation of the Trust.............. The Trust will be treated as a grantor trust and not as an association taxable as a corporation. As a grantor trust, the Trust will not be 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 could be materially different if the IRS were to successfully challenge this treatment. Taxation of Unitholders.... Each Unitholder will be taxed directly on his proportionate share of income, deductions, and credits of the Trust attributable to the Royalty Interests consistent with 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 1996, the Trust earned interest income on funds held for distribution and made adjustments to the cash reserve maintained for the payment of contingent or future obligations of the Trust. The deductions of the Trust consist of severance taxes and administrative expenses. In addition, each Unitholder is entitled to depletion deductions. See "Unitholder's Depletion Allowance" below. Limits on Deductions and Credits............... 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 14 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. At the time of the Public Offering, Burlington Resources, after consultation with its counsel, expressed its belief only in connection with the Public Offering that the purchaser of a Unit in the Public Offering, who did not borrow funds in order to purchase his Unit, had a reasonable possibility of deriving an economic profit in excess of a de minimis amount apart from tax benefits associated with ownership of the Unit. No assurance is given either by the Trustee or counsel to the Trustee to a purchaser of Units in or following the Public Offering as to whether (and to what extent) such purchaser will be entitled to claim deductions and the Section 29 tax credit generated with respect to such Units. Section 29 Tax Credit...... Unitholders will be entitled, provided certain requirements are met, to claim tax credits pursuant to Section 29 of the IRC with respect to sales of coal seam gas production attributable to the NPI, 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. The Section 29 tax credit applies to coal seam gas produced and sold prior to January 1, 2003 from qualifying wells. For a Unitholder who owned the same Units of record on all four quarterly record dates during 1996, the available Section 29 tax credit is approximately $1.116934 per Unit, based on the first estimate of the GNP implicit price deflator published by the Bureau of Economic Analysis. The availability of Section 29 tax credits is dependent upon meeting a number of requirements, many of which are factual in nature. Burlington Resources represented only in connection with the Public Offering that those factual requirements were met and Burlington Resources expressed its belief in connection with the Public Offering that substantially all of the production attributable to the NPI from the coal seam gas wells identified in the reserve estimate as of May 1, 1993, prepared by MOPI in connection with the Public Offering, qualified for Section 29 tax credits. At the time of the Public Offering, counsel to Burlington Resources 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. In addition, if the production units or participating areas are expanded to include additional production which does not qualify for the Section 29 tax credit, the amount of Section 29 tax credits available to a Unitholder will be reduced even though his share of production does not diminish. Neither MOPI nor the Trust can control whether a production unit or participating area is expanded. 15 No Section 29 tax credits will be available under current law to a Unitholder with respect to production attributable to the Infill NPI even if an Infill Well recovers a portion of the reserves that prior to the drilling and completion of an Infill Well were recoverable from a well burdened by the NPI that qualified for Section 29 tax credits. 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 IRC, 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 for a quarter, and the Section 29 tax credit allocable to such income, to Unitholders of record on the quarterly record date for such quarter. Such an allocation may be challenged by the IRS, but any challenge is likely to have a material adverse effect only 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. Unitholder's Depletion Allowance................. Each Unitholder is entitled to amortize the cost of the Units through cost depletion over the life of the NPI (or if greater, through percentage depletion equal to 15 percent of gross income). If any portion of the NPI 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. Non-Passive Activity Income, Credits and Loss.......... The income, credits and expenses of the Trust will not be taken into account in computing the passive activity losses and income under Section 469 of the IRC 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. 16 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. See the second paragraph under "Description of Units -- Periodic Reports to Unitholders." Tax Shelter Registration... The Trust is registered as a "tax shelter" and its tax shelter registration number is 93-147000231. 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 IRC 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 (a) 10 percent of the taxes required to be shown on the return and (b) $5,000 ($10,000 for most corporations). The penalty (which is not deductible) is 20 percent of the understatement. Except in the case of understatements attributable to "tax shelter" items, which are subject to special rules discussed below, an item of understatement will not give rise to the penalty if: (i) there is or was "substantial authority" for the taxpayer's treatment of the item or (ii) all the facts relevant to the tax treatment of the item are adequately disclosed on the return or on a statement attached to the return and there is a reasonable basis for the tax treatment of such item. In the case of Units, an individual Unitholder may make adequate disclosure with respect to particular tax items if certain conditions are met. Special rules enacted in December 1994 could affect the application of these provisions with regard to a corporation acquiring Units after December 8, 1994, to the extent such provisions were found to apply to the ownership of Units. In the case of understatements attributable to "tax shelter" items, the substantial understatement penalty may be avoided only if the taxpayer establishes that, in addition to having substantial authority for his position, he reasonably believed that the treatment claimed was more likely than not the proper treatment of the item. A "tax shelter" item is one that arises from a form of investment if its principal purpose was the avoidance or evasion of Federal income tax. Regulations promulgated by the IRS indicate that an entity or person has a principal purpose of avoidance or evasion of Federal income tax if that purpose "exceeds any other purpose." No assurance is given either by the Trustee or counsel to the Trustee as to the possible application of this penalty, in part because such application depends largely upon the individual circumstances under which the Units were acquired. As a result, purchasers of Units in and after the Public Offering should consult with their personal tax advisors. 17 ERISA CONSIDERATIONS The section entitled "ERISA Considerations" appearing in the Public Offering Prospectus sets forth certain information regarding the applicability of the Employee Retirement Income Security Act of 1974, as amended, and the IRC to pension, profit-sharing and other employee benefit plans, and is incorporated herein by reference. 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 IRC of their acquisition and ownership of Units. STATE TAX CONSIDERATIONS The following is intended as a brief summary of certain information regarding state income taxes and other state tax matters affecting individuals who are Unitholders. Unitholders are urged to consult their own legal and tax advisors with respect to these matters. Unitholders should consider state and local tax consequences of holding Units. The Trust owns Royalty Interests burdening gas properties located in New Mexico. New Mexico has an income tax applicable to individuals. In addition to any tax reporting and payment obligations of his state of residence, a Unitholder is generally required to file state income tax returns and/or pay taxes in New Mexico and may be subject to penalties for failure to comply with such requirements. In addition, New Mexico in the future may require the Trust to withhold tax from distributions to Unitholders. Unitholders should consult their own tax advisors to determine their income tax filing requirements in New Mexico with respect to their share of income of the Trust. The Trust has been structured to cause the Units to be treated for certain state law purposes, including state taxation other than income taxation, essentially the same as other securities, that is, as interests in intangible personal property rather than as interests in real property. If the Units are held to be real property or an interest in real property under the laws of New Mexico, a Unitholder, even if not a resident of such state, could be subject to devolution, probate and administration laws, and inheritance or estate and similar taxes, under the laws of such state. REGULATION AND PRICES REGULATION OF NATURAL GAS The production, transportation and sale of natural gas from the Underlying Properties are subject to Federal and state governmental regulation, including regulation of tariffs charged by pipelines, taxes, the prevention of waste, the conservation of gas, pollution controls and various other matters. The United States has governmental power to impose pollution control measures. Federal Regulation of Gas. The Underlying Properties are subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC") with respect to various aspects of gas operations including marketing and production of gas. 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 FERC under the Natural Gas Act ("NGA") and the NGPA. FERC has initiated a number of regulatory policy initiatives that may affect the transportation of natural gas from the wellhead to the market and thus may affect the marketing of natural gas. Such initiatives include regulations which are intended to further open access to interstate pipelines by requiring such pipelines to unbundle their transportation services from sales services and allow customers to choose 18 and pay for only the services they require, regardless of whether the customer purchases natural gas from such pipelines or from other suppliers. Although these regulations should generally facilitate the transportation of natural gas produced from the Underlying Properties to natural gas markets, the impact of these regulations on marketing production from the Underlying Properties cannot be predicted at this time, and such impacts could be significant. Legislative Proposals. In the past, Congress has been very active in the area of gas regulation. Legislation enacted in recent years repeals incremental pricing requirements and gas use restraints previously applicable. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on the Underlying Properties and the Trust. State Regulation. Many state jurisdictions have at times imposed limitations on the production of gas by restricting the rate of flow for gas wells below their actual capacity to produce and by imposing acreage limitations for the drilling of a well. States may also impose additional regulation of these matters. Most states regulate the production of gas, including requirements for obtaining drilling permits, the method of developing new fields, provisions for the unitization or pooling of gas properties, the spacing, operation, plugging and abandonment of wells and the prevention of waste of gas resources. The rate of production may be regulated and the maximum daily production allowable from gas wells may be established on a market demand or conservation basis or both. Several states have in recent years enacted or proposed regulations intended to revise significantly current systems of prorationing gas production. If modified in New Mexico, such modified rules may decrease the total amount of gas produced in New Mexico, and could result in an increase in market prices for gas. The foregoing developments have fostered debate regarding the purpose and effect of the new prorationing rules, with opponents of such rules arguing that the primary purpose thereof is to increase gas prices by withholding supplies from the market. The Trustee cannot predict what effect, if any, proration rules will have on the availability of or prices for the Underlying Properties' gas supplies. ENVIRONMENTAL REGULATION General. Activities on the Underlying Properties are subject to existing Federal, state and local laws (including case law), rules and regulations governing health, safety, environmental quality and pollution control. It is anticipated that, absent the occurrence of an extraordinary event, compliance with existing Federal, state and local laws, rules and regulations regulating health, safety, the release of materials into the environment or otherwise relating to the protection of the environment will not have a material adverse effect upon the Trust or Unitholders. The Trustee cannot predict what effect additional regulation or legislation, enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from operations on the Underlying Properties could have on the Trust or Unitholders. However, any costs or expenses incurred by MOPI 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 before June 17, 1993 will be borne by MOPI and not the Trust (and MOPI has indemnified the Trust with respect thereto) and such costs and expenses will not be deducted in calculating NPI Net Proceeds or Infill Net Proceeds. Any environmental costs or expenses that are attributable to MOPI's interest in the Underlying Properties that do not fall within the preceding sentence (including indemnification obligations payable to or on behalf of the Trustee or the Delaware Trustee relating to matters occurring on or after June 17, 1993) will be paid by MOPI but will be deducted in calculating NPI Net Proceeds or Infill Net Proceeds and will, therefore, reduce amounts payable to the Trust. Solid and Hazardous Waste. The Underlying Properties are carved out of leasehold interests in certain properties that have produced gas from other formations for many years. Burlington Resources and MOPI have advised the Trustee that to their knowledge the operator of the Underlying Properties has utilized operating and disposal practices that were standard in the industry at the time, although hydrocarbons or other solid or hazardous wastes may have been disposed or released on or under the Underlying Properties by the current or previous operators. Federal, state and local laws applicable to gas-related wastes and properties have become increasingly more stringent. Under these laws, the operator of the Underlying Properties or the working interest owners could be required to remove or remediate previously disposed wastes or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination. 19 The operations of the Underlying Properties may generate wastes that are subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The Environmental Protection Agency (the "EPA") has limited the disposal options for certain hazardous wastes and may adopt more stringent disposal standards for nonhazardous wastes. The operations of the Underlying Properties include the disposal of produced saltwater by reinjection into the subsurface. Such operations are subject to Federal and state regulations concerning Class II underground injection control disposal systems, which are used to dispose of fluids in connection with oil or natural gas production. To protect against contamination of drinking water, existing regulations contain stringent requirements relating to the construction, operation, monitoring, plugging and abandonment of underground injection wells. If the operator of the reinjection wells fails to maintain the mechanical integrity of the reinjection wells, the operator of the Underlying Properties or the working interest owners could be required to cease injection and perform additional construction, operation, monitoring or corrective action. Superfund. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "superfund" law, imposes liability, regardless of fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment. These persons include the current or previous owner and operator of a site and companies that disposed, or arranged for the disposal, of the hazardous substance found at a site. CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to the public health or the environment and to seek recovery from such responsible classes of persons of the costs of such action. In the course of its operations, the operator of the Underlying Properties has generated and will generate wastes that may fall within CERCLA's definition of "hazardous substances." The operator of the Underlying Properties or the working interest owners may be responsible under CERCLA for all or part of the costs to clean up sites at which such substances have been disposed. Any such CERCLA liabilities borne by MOPI may be passed on, proportionately, to the Trust (through deduction of such amounts in calculating NPI Net Proceeds) only to the extent that any such liability relates to activities occurring on or under, or in connection with, or conditions existing on or under, the Underlying Properties on or after June 17, 1993. All other CERCLA liabilities in connection with MOPI's interest in the Underlying Properties were retained by MOPI. Air Emissions. The operations of the Underlying Properties are subject to Federal, state and local regulations concerning the control of emissions from sources of air contaminants. Administrative enforcement actions for failure to comply strictly with air regulations or permits are generally resolved by payment of a monetary penalty and correction of any identified deficiencies. Regulatory agencies could require the operators to forego or modify construction or operation of certain air emission sources. OSHA. The operations of the Underlying Properties are subject to the requirements of the Federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and similar state statutes require that information be organized and maintained about hazardous materials used or produced in the operations. Certain of this information must be provided to employees, state and local government authorities and citizens. 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 gas industry is highly competitive in all of its phases. MOPI encounters competition from major oil and gas companies, independent oil and gas concerns, and individual producers and operators. Many of these competitors have greater financial and other resources than MOPI. Competition may also be presented by alternative fuel sources, including heating oil and other fossil fuels. The supply of natural gas capable of being produced in the United States has exceeded demand in recent years generally as a result of decreased demand for natural gas in response to economic factors, conservation, lower prices for alternative energy sources and other factors. As a result of this excess supply of natural gas, natural gas 20 producers have experienced increased competitive pressure and significantly lower prices. Due to the restructuring of the industry over the last nine years and the producers' method of marketing their gas production, caused mainly by FERC regulations, minimal gas is sold to pipelines under the past take-or-pay style long-term (15-20 year) contracts. Pipelines have either renegotiated their obligations to reflect more market responsive terms, or reduced or ceased altogether their purchase of gas. Demand for natural gas production has historically been seasonal in nature and prices for gas fluctuate accordingly. Due to unseasonably warm weather over the last several years and the ability of markets to access storage, lower prices have been received by producers than in prior years. Consequently, on an energy equivalent basis, gas has sold at a discount to oil for the past several years. However, during 1996 inventories were drawn down and severe weather created more demand for natural gas in the second half of the year. Such price fluctuations and the continuation of a depressed market for natural gas will directly impact Trust distributions, estimates of Trust reserves and estimated future net revenue from Trust reserves. 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 Burlington Resources. 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. In view of the many uncertainties affecting the supply and demand for natural gas, the Trust and Burlington Resources are unable to make reliable predictions of future gas prices and demand or the overall effect they will have on the Trust. ITEM 2. PROPERTIES. THE ROYALTY INTERESTS The Royalty Interests conveyed to the Trust entitle the Unitholders to receive 95 percent of the NPI Net Proceeds attributable to MOPI's interest in the Underlying Properties and 20 percent of MOPI's interest in the Infill Net Proceeds attributable to any Infill Wells that may be drilled after May 1, 1993. 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 San Juan and Rio Arriba counties in New Mexico so as to give notice of the Royalty Interests to creditors and any transferees, who would 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 New Mexico law. Burlington Resources, through MOPI, owns an interest in the Underlying Properties subject to and burdened by the Royalty Interests conveyed to the Trust pursuant to the Conveyance. MOPI receives all payments relating to its interest in the Underlying Properties and is required, pursuant to the Conveyance, to pay to the Trust the portion thereof attributable to the Royalty Interests. Under the Conveyance, the amounts payable by MOPI 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 to be paid to the Trust not later than the 50th day following the end of each calendar quarter. The amounts paid to the Trust will not include interest on any amounts payable with respect to the Royalty Interests which are held by MOPI prior to payment to the Trust. MOPI is entitled to retain all amounts attributable to its interest in the Underlying Properties which are not required to be paid to the Trust with respect to the Royalty Interests. The following description contains a summary of the material terms of the Conveyance and is subject to and qualified by the more detailed provisions of the Conveyance, a copy of which is filed as an exhibit to this 10-K. THE UNDERLYING PROPERTIES The Royalty Interests were conveyed by MOPI to the Trust out of its net revenue interest in the Underlying Properties. All of the production from the Underlying Properties is from the Northeast Blanco Unit in the Fruitland 21 coal formation in the San Juan Basin in San Juan and Rio Arriba counties in New Mexico. For the purpose of determining the extent of the Underlying Properties, as used in this Form 10-K the term "Northeast Blanco Unit" comprises the Northeast Blanco Unit, a 32,595 acre unit originally formed on July 16, 1951, as well as rights in one communitized gross well with acreage in both the Northeast Blanco Unit and the adjoining San Juan 30-6 Unit. The Underlying Properties do not include MOPI's interest in formations other than the Fruitland coal formation underlying the Northeast Blanco Unit. The Northeast Blanco Unit is located in the north-central portion of the San Juan Basin. The San Juan Basin has been an active area for coal seam gas development, and wells have been drilled on each of the 320 acre drill blocks within the Northeast Blanco Unit. The Royalty Interests transferred in the Conveyance to the Trust do not burden the mineral interests or overriding royalty interests owned by El Paso Production Company (a wholly owned subsidiary of Burlington Resources), the royalty and overriding royalty interests owned by Southland Royalty Company (a wholly owned subsidiary of Burlington Resources and the sponsor of the San Juan Basin Royalty Trust) or the interests owned by the San Juan Basin Royalty Trust, respectively, in the Northeast Blanco Unit. El Paso Production Company owns a .138 percent working interest and a .178 percent net revenue interest in the Northeast Blanco Unit attributable to its mineral interests and overriding royalty interests. Southland Royalty Company owns a .221 percent net revenue interest in the Northeast Blanco Unit attributable to its royalty interests and overriding royalty interests. Unitized Areas. Pursuant to the Federal Mineral Leasing Act of 1920, as amended, and applicable state regulations, owners of oil and gas leases in New Mexico created large unitized areas consisting of numerous contiguous sections for the orderly development and conservation of oil and gas reserves. All of the Fruitland coal seam gas wells on the Underlying Properties are located within such a unitized area. Operation and development of the Northeast Blanco Unit is governed by a unit agreement and a unit operating agreement (collectively, the "Unit Agreement"). Under the Unit Agreement and applicable government regulations, the unit operator requests regulatory approval from the New Mexico Commission of Public Lands, the New Mexico Oil Conservation Division and the Bureau of Land Management of the U.S. Department of Interior (the "Bureau of Land Management") to establish or expand participating areas which produce oil and gas in paying quantities from designated formations. The working interests of participants in a participating area are based on the surface acreage included in the participating area. Under the terms of the Unit Agreement, the operator, selected by a vote of the respective working interest owners, performs all operating functions. The Underlying Properties currently include 102 gross coal seam wells. One additional previously existing well in the Northeast Blanco Unit has ceased production, and no reserves have been attributed to such well in the December 31, 1996 Reserve Report. If subsequently deemed appropriate by the Northeast Blanco Unit working interest owners, such well could be redrilled and, if returned to production, MOPI's interest in that well would be burdened by the NPI. MOPI's working interest share of the capital costs of any such redrilling would be deducted in calculating NPI Net Proceeds and would, therefore, reduce amounts payable to the Trust. In addition, any production from that redrilled well would not entitle Unitholders to Section 29 tax credits. As of December 31, 1996, MOPI had a working interest of approximately 19.6 percent in the Underlying Properties and a net revenue interest of approximately 16.5 percent in the Underlying Properties. The operator of the Underlying Properties is Blackwood & Nichols Co. ("B&N"), an affiliate of Devon Energy Corporation ("Devon") (although the single communitized well included within the Underlying Properties is operated by MOPI). Adjacent Properties. In addition to the San Juan 30-6 Unit, MOPI and its affiliates own significant interests in five other Federal units and eleven non- unitized wells that are adjacent to the Northeast Blanco Unit. Three of the Federal units (the San Juan 30-6 Unit, the Allison Unit and the Rosa Unit) are operated by MOPI or its affiliates. It is possible that production from these properties could drain coal seam gas from the Underlying Properties and therefore reduce production from the wells burdened by the Royalty Interests. However, if drainage were to occur it should be insignificant because of the well spacing rules and well "set back" rules that have been established by the New Mexico Oil Conservation Division. These rules are designed to protect the correlative rights of each owner by limiting the number of wells that can be drilled and establishing a reasonable distance from adjoining lease or unit boundaries that each well can be drilled. Currently, the rules in effect for the Fruitland coal formation provide for one well to be drilled on a 320 acre drillblock and require each well to be drilled no closer than 790 feet from the adjacent lease boundary. 22 Working Interest Owners. The following is a list of working interest owners in the Underlying Properties owning at least a one percent working interest as of December 31, 1996.
WORKING INTEREST OWNERS WORKING INTEREST PERCENTAGE ----------------------- --------------------------- Amoco Production Co.................... 35.4 MOPI................................... 19.6 B&N.................................... 14.6 Devon Blanco Ltd....................... 13.9 EOG Inc................................ 5.6 Phillips - San Juan Partners L.P....... 3.8 Conoco, Inc............................ 2.5
Well Count and Acreage Summary. The following table shows as of December 31, 1994, 1995 and 1996 the gross and net wells and acreage for the Underlying Properties.
NUMBER OF WELLS ACRES --------------- ------------- DECEMBER 31, GROSS NET GROSS NET - ------------ -------- ----- ------ ----- 1994............................... 102 20 32,595 6,404 1995............................... 102 20 32,595 6,404 1996............................... 102 20 32,595 6,404
THE NPI The NPI generally entitles the Trust to receive 95 percent of the NPI Net Proceeds attributable to MOPI's interest in the Underlying Properties, subject to possible decrease as described under "--Possible NPI Percentage Reduction." MOPI will pay its working interest share of capital costs incurred on the Underlying Properties. Such capital costs will be equal to MOPI's working interest share of the amounts expended by the operator of the Northeast Blanco Unit and MOPI will be invoiced for its share of those costs by the operator. However, the operator and working interest owners of the wells could elect at any time to implement measures to increase the producible reserves. These measures, if implemented, could involve additional compression or enhanced or secondary recovery operations requiring substantial capital expenditures which would be proportionately borne by the NPI. During 1996 significant capital expenditures were made in conjunction with the installation of a looped gas gathering system. All cumulative lease operating expenses paid after May 1, 1993, and capital expenses paid on or after January 1, 1994, attributable to MOPI's working interest in the Underlying Properties (other than any environmental liabilities related to activities occurring on or under, or in connection with, or conditions existing on or under, the Underlying Properties before June 17, 1993, which liabilities will be borne by MOPI and for which MOPI has indemnified the Trust) will be deducted in calculating NPI Net Proceeds and, therefore, will reduce amounts payable to the Trust. If, during any calendar quarter, costs and expenses paid by MOPI and deducted in calculating the NPI Net Proceeds exceed gross proceeds (such excess referred to as a "Deficit"), neither the Trust nor Unitholders will be liable to pay such Deficit directly, but the Trust will receive no payments for distribution to Unitholders (although MOPI will pay to the Trust amounts sufficient to pay the administrative expenses of the Trust) until future gross proceeds exceed future costs and expenses plus the cumulative Deficit and interest on such cumulative Deficit at Citibank's Base Rate; provided, however, that in any calendar quarter in which the cumulative Deficit at the end of such quarter is less than $3,000,000, MOPI will pay to the Trust for distribution to Unitholders no less than 20 percent of such quarter's NPI Net Proceeds (calculated before deducting capital costs for such calendar quarter); and provided further, that if at the end of any calendar quarter, the cumulative Deficit is $3,000,000 or more, MOPI will not be obligated to make any payment to the Trust for distribution to Unitholders (although MOPI will pay to the Trust amounts sufficient to pay the administrative expenses of the Trust) until such cumulative Deficit is reduced to less than $3,000,000. As of December 31, 1996 no such deficit existed. 23 RESERVE REPORT The following table summarizes net proved reserves estimated as of December 31, 1996, and certain related information for the Royalty Interests and MOPI's interest in the Underlying Properties from the December 31, 1996 Reserve Report prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers. All of such reserves constitute proved developed reserves. Summaries of the December 31, 1996 Reserve Report, the Prior Reserve Reports and the Prior Tax Credit Reports are filed as exhibits to this Form 10-K and incorporated herein by reference. See Note 9 of the Notes to Financial Statements incorporated by reference in Item 8 hereof for additional information regarding the net proved reserves of the Trust. A net profits interest does not entitle the Trust to a specific quantity of gas but to a portion of gas sufficient to yield a specified portion of the net proceeds derived therefrom. Proved reserves attributable to a net profits interest are calculated by deducting an amount of gas sufficient, if sold at the prices used in preparing the reserve estimates for such net profits interest, to pay the future estimated costs and expenses deducted in the calculation of the net proceeds of such interest. Accordingly, the reserves presented for the Royalty Interests reflect quantities of gas that are free of future costs and expenses if the price and cost assumptions used in the December 31, 1996 Reserve Report occur. The December 31, 1996 Reserve Report was prepared in accordance with criteria established by the Securities and Exchange Commission. At December 31, 1996, the price the Trust was entitled to receive under the Gas Purchase Contract was $2.74 per MMBtu subject to accrued and unrecouped Price Credits in the Price Credit Account (see "-- The Royalty Interests -- Gas Purchase Contract"). For purposes of the preparation of the December 31, 1996 Reserve Report, however, pricing was held constant at the Minimum Purchase Price of $1.60 per MMBtu until the accrued Price Credits were recouped by MOTI, after which $2.74 per MMBtu was utilized for the remaining life of the Royalty Interests.
MOPI'S INTEREST ROYALTY IN THE INTERESTS UNDERLYING PROPERTIES --------------- --------------------- Net Proved Gas Reserves (Bcf)(a)(b)......................... 71.6 80.2 Estimated Future Net Revenues (in millions) (c)............. $116.3 $122.4 Discounted Estimated Future Net Revenues (in millions) (c).. $ 67.3 $ 70.8
- ---------------- (a) Although the prices utilized in preparing the estimates in this table are in accordance with criteria established by the Securities and Exchange Commission, those prices were influenced by seasonal demand for natural gas and other factors and may not be the most representative prices for estimating future net revenues or related reserve data. In addition, changes in gas prices have an effect on net reserve data for the NPI at any given level of costs assumed, because such changes in the cost of gas per MMBtu result in changes in the number of MMBtu required to pay a given level of costs. Since December 31, 1996, the Blanco Hub Spot Price has decreased substantially. (b) The gas reserves were estimated by Netherland, Sewell & Associates, Inc. by applying volumetric and decline curve analyses. (c) Estimated future net revenues are defined as the total revenues attributable to MOPI's interest in the Underlying Properties and to the Royalty Interests less the relevant share (MOPI's interest share, in the case of MOPI's interest in the Underlying Properties, and 95 percent thereof, in the case of the Royalty Interests) of royalties, production, property and related taxes (including severance taxes), lease operating expenses and future capital expenditures. Overhead costs (beyond the standard overhead charges for the nonoperated properties) have not been included, nor have the effects of depreciation, depletion and Federal income tax. Estimated future net revenues and discounted estimated future net revenues are not intended and should not be interpreted as representing the fair market value for the estimated reserves. Based upon the production estimates used in the December 31, 1996 Section 29 Tax Credit Report for the January 1, 1997 through December 31, 2002 period, and assuming constant future Section 29 tax credits at the estimated 1996 rate of $1.05 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 $36.1 million, having a discounted present value (assuming a 10 percent discount rate) of approximately $28.5 million. 24 There are many uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the timing of development expenditures. The reserve data set forth herein are estimates only, and actual quantities and values of natural gas are likely to differ from the estimated amounts set forth herein. In addition, the reserve estimates for the Royalty Interests will be affected by future changes in sales prices for natural gas produced and costs that are deducted in calculating NPI Net Proceeds and Infill Net Proceeds. Further, the discounted present values shown herein were prepared using guidelines established by the Securities and Exchange Commission for disclosure of reserves and should not be considered representative of the market value of such reserves or the Units. A market value determination would include many additional factors. HISTORICAL GAS SALES PRICES AND PRODUCTION The following table sets forth the actual net production volumes from MOPI's interest in the Underlying Properties, weighted average lifting costs and information regarding historical gas sales prices for each of the years ended December 31, 1994, 1995 and 1996:
YEAR ENDED DECEMBER 31, ----------------------- 1994 1995 1996 ----- ----- ----- Production from MOPI's interest in the Underlying Properties (Bcf)........ 16.8 14.7 12.2 Weighted average production costs (dollars per Mcf)....................... $0.15 $0.09 $0.12 Weighted average sales price of gas produced from MOPI's interest in the Underlying Properties (dollars per Mcf).................................. $1.17 $1.08 $1.04 Average Blanco Hub Spot Price (dollars per MMBtu)......................... $1.63 $1.18 $1.66
POSSIBLE NPI PERCENTAGE REDUCTION If there has been cumulative production after April 30, 1993 (other than production attributable to Infill Wells) of at least 161.8 Bcf of natural gas attributable to MOPI's interest in the Underlying Properties burdened by the NPI, the percentage of NPI Net Proceeds payable in respect of the NPI will be reduced with respect to any additional production from MOPI's interest in the Underlying Properties if the IRR of the "After-tax Cash Flow per Unit" (as defined below) exceeds 11 percent (or if, as set forth below, a greater amount of gas has been produced and certain other financial tests are met). For purposes hereof, "After-tax Cash Flow per Unit" is equal to the sum of the following amounts that a hypothetical purchaser of a Unit in the Public Offering would have received or been allocated if such Unit were held through the date of such determination: (a) total cash distributions per Unit plus (b) total tax credits available per Unit under Section 29 of the IRC less (c) the total net taxes payable per Unit (assuming a 31 percent tax rate, the highest effective Federal income tax rate applicable to individuals at the time of the Public Offering). IRR is the annual discount rate (compounded quarterly) that equates the present value of the After-tax Cash Flow per Unit to the $20.50 initial price to the public of the Units in the Public Offering. Set forth below is a table that reflects the cumulative production from MOPI's interest in the Underlying Properties after April 30, 1993 (other than production attributable to Infill Wells) and the corresponding percentage of NPI Net Proceeds represented by the NPI and the retained interest of MOPI in the NPI Net Proceeds:
PERCENTAGE OF NPI NET PROCEEDS ----------------- THE TRUST MOPI --------- ---- Cumulative Production: Less than 161.8 Bcf............................. 95 5 161.8 Bcf to 176.5 Bcf.......................... 75 25 More than 176.5 Bcf............................. 50 50
In addition to the foregoing, the percentage of NPI Net Proceeds payable to the Trust will be reduced to 25 percent and MOPI's retained percentage of NPI Net Proceeds will be increased to 75 percent (whether or not the IRR of the After-tax Cash Flow per Unit exceeds 11 percent) if (i)(a) after April 30, 1993 there has been total production (other than production attributable to Infill Wells) attributable to MOPI's interest in the Underlying Properties of more than 191.2 Bcf of natural gas, (b) a hypothetical purchaser of a Unit in the Public Offering would have received a cash return (equal to total cash distributions per Unit) of not less than the $20.50 initial 25 offering price in the Public Offering and (c) total capital expenditures (excluding capital expenditures in connection with any Infill Wells) incurred between May 1, 1993 and December 31, 2002 and attributable to MOPI's interest in the Underlying Properties do not exceed $20 million (adjusted for inflation between May 1, 1993 and December 31, 2002), or (ii)(a) after April 30, 1993 there has been total production (other than production attributable to Infill Wells) attributable to MOPI's interest in the Underlying Properties of more than 220.7 Bcf of natural gas and (b) a hypothetical purchaser of a Unit in the Public Offering would have received a cash return satisfying the criteria set forth in (i)(b) above. The percentage of NPI Net Proceeds payable in respect of the NPI will be reduced at any time and from time to time in the amounts set forth above if the criteria specified in the preceding paragraphs are met. If a reduction in the percentage of NPI Net Proceeds constituting the NPI occurs, that reduced percentage shall continue in effect thereafter unless and until a further reduction occurs. As of December 31, 1996 none of the criteria described above had been met. GAS PURCHASE CONTRACT Under the terms of the Gas Purchase Contract, MOTI is obligated to purchase the natural gas attributable to MOPI's interest in the Underlying Properties at the Central Gathering Point. The Gas Purchase Contract commenced as of May 1, 1993, and expires on the termination of the Trust. The monthly price to be paid by MOTI for natural gas purchased pursuant to the Gas Purchase Contract is, subject to applicable adjustment, (i) the $1.60 per MMBtu Minimum Purchase Price less (ii) all costs to be incurred in connection with gathering and/or transportation charges, taxes, treating and processing costs and other costs payable in connection with such services from the Central Gathering Point to main line delivery (collectively, "Deductible Costs"). Additionally, if MOTI's arrangements for gathering, treating, processing and transporting gas from the Central Gathering Point are altered by any governmental order, decree, legislation or regulation relating generally to gathering and transportation arrangements in the natural gas industry and such alterations materially increase MOTI's costs of performing its obligations under the Gas Purchase Contract, such increased costs shall be included in Deductible Costs to the extent that such increased costs are not recouped by MOTI from its gas purchaser. The monthly price is subject to adjustments under certain circumstances as described below: (a) If the Index Price in any month is greater than the $2.04 per MMBtu Sharing Price, then MOTI will pay MOPI an amount for each MMBtu of gas purchased equal to the Sharing Price for such month, less the Deductible Costs for such month, plus 50 percent of the excess of the Index Price for such month over the Sharing Price (the "Price Differential") for such month, provided MOTI has no accrued and unrecouped Price Credits (defined below) in the Price Credit Account (defined below). If MOTI has accrued and unrecouped Price Credits in the Price Credit Account, then MOTI will be entitled to reduce the amount in excess of the Minimum Purchase Price (before deducting the Deductible Costs) that otherwise would be payable for such month by the quotient of the balance of accrued and unrecouped Price Credits in the Price Credit Account as of the beginning of such month divided by the quantity of MOPI's gas purchased for such month under the Gas Purchase Contract. (b) If the Index Price in any month is greater than or equal to the Minimum Purchase Price but less than or equal to the Sharing Price for such month, then MOTI will pay MOPI an amount for each MMBtu of gas purchased during such month equal to the Index Price for such month less the Deductible Costs for such month provided MOTI has no accrued and unrecouped Price Credits in the Price Credit Account. If MOTI has accrued and unrecouped Price Credits in the Price Credit Account, then MOTI will be entitled to reduce the amount in excess of the Minimum Purchase Price (before deducting the Deductible Costs) that otherwise would be payable for such month by the quotient of the balance of accrued and unrecouped Price Credits in the Price Credit Account as of the beginning of such month divided by the quantity of MOPI's gas purchased for such month under the Gas Purchase Contract. (c) If the Index Price in any month commencing after December 31, 1993 is less than the Minimum Purchase Price, then MOTI will pay for each MMBtu of gas purchased the Minimum Purchase Price less the Deductible Costs for such month, and MOTI will receive a credit (a "Price Credit") from MOPI for each MMBtu of natural gas so purchased by MOTI equal to the difference between the Minimum Purchase Price 26 and the Index Price. MOTI is required to establish and maintain an account (the "Price Credit Account") containing the accrued and unrecouped amount of such Price Credits. The Index Price was below the Minimum Purchase Price from June 1994 through 1996, with the exception of the months of August, November and December of 1996. MOTI estimates that, as of December 31, 1996, MOTI had aggregate Price Credits in the Price Credit Account of approximately $8.9 million of which the Trust's 95 percent interest was approximately $8.5 million. This entitlement to recoup the Price Credits means that if and when the Index Price is above the Minimum Purchase Price, future royalty income paid to the Trust would be reduced until such time as such Price Credits have been fully recouped. Corresponding cash distributions to Unitholders would also be reduced. Each of the Minimum Purchase Price and the Sharing Price will increase by 2.5 percent per annum as of May 1 of each year commencing in 2003. The Central Gathering Point price in the Gas Purchase Contract is determined by utilizing a published price (which is before deduction of Deductible Costs), and then deducting Deductible Costs. As used herein, "Index Price" means for each month 97 percent of the Blanco Hub Spot Price (such 3 percent deduction constituting a discount to compensate MOTI for marketing the gas). The Blanco Hub Spot Price is a posted index price in dollars per MMBtu on a dry basis published in the first issue of such month in Inside FERC's Gas Market Report for "El Paso Natural Gas Company, San Juan." Pursuant to the Gas Purchase Contract, MOTI will have a one-time option to elect to substitute for the foregoing as the Blanco Hub Spot Price either (i) the average of the two posted index prices reported each month in Inside FERC's Gas Market Report for "El Paso Natural Gas Company, San Juan" or (ii) the Blanco Hub posted index price reported by Inside FERC's Gas Market Report, if either such price is then published in such publication. All prices used as index prices are delivered prices at the specified point of delivery and are, therefore, before deducting Deductible Costs. In any month in which MOTI recoups Price Credits under the Gas Purchase Contract, MOPI may be required to calculate royalty payments attributable to production from the Underlying Properties based on the higher price MOTI receives when it resells the gas production instead of the lower price payable by MOTI to MOPI under the Gas Purchase Contract (which price takes into account the Price Credits recouped by MOTI in such month). Royalties that are payable by MOPI in respect of such higher gas price will not reduce the NPI Net Proceeds payable to the Trust. However, the portion of the recouped Price Credits that is attributable to the royalty percentage of the gas sold in such month shall be returned to the Price Credit Account by MOTI and recouped by MOTI in future months. The Underlying Properties are subject to a gas balancing agreement which, under certain circumstances, allows any working interest owner (including MOPI) to take more or less than his working interest share of gas produced. NPI Net Proceeds and Infill Net Proceeds are calculated on an "entitlements basis," whereby the aggregate proceeds from the sale of gas are determined by MOPI as if MOPI had produced and sold its share of production from the Underlying Properties, even if the actual volumes delivered to and sold by MOPI are different from its entitled interest volumes. The effect of such an entitlements basis calculation is that NPI Net Proceeds or Infill Net Proceeds and, therefore, the amount thereof paid to the Trust, may include amounts in respect of production not taken by MOPI because of an imbalance (an imbalance is where an interest owner is delivered more or less than the actual share of production to which it is entitled). Likewise, in the event MOPI actually takes and sells more than its share of production but pays the NPI Net Proceeds or the Infill Net Proceeds on an entitlements basis, MOPI will receive revenues in excess of those distributed to the Trust. In the event the price of gas is lower when the other interest owners make-up the overproduction taken and sold by MOPI than the price received by MOPI, MOPI will retain the excess of such higher price over the lower price. MOPI bases such entitlements calculations upon production estimates furnished to MOPI by the operator of the Underlying Properties, which estimates may be subject to subsequent adjustment by the operator after the collection and evaluation of field data. Because the operator may not determine that such an adjustment is required until several months after the original estimates are furnished to MOPI, it is possible that an adjustment with respect to 27 a particular quarter will not be made until cash amounts have been distributed, and depletion and Section 29 tax credits have been allocated to Unitholders by the Trust. MOPI will take such an adjustment into account for the quarter in which MOPI is advised of such adjustment. The cash distributions made, and depletion deductions and Section 29 tax credits allocated, in respect of a future quarterly period on a Unit could be based in part upon such an adjustment, notwithstanding that the owner of such Unit did not own the Unit during the quarter in respect of which such adjustment is made. MOTI's obligation to purchase natural gas pursuant to the Gas Purchase Contract (as well as MOPI's obligation to sell such gas) may be suspended to the extent affected by the occurrence of any event that renders the affected party unable to perform its obligations under the Gas Purchase Contract if the event could not have been prevented with reasonable foresight, at reasonable cost and by the exercise of reasonable diligence including: (i) acts of God, lightning, fires, explosions and other casualties, (ii) strikes and other industrial disturbances, (iii) acts of the public enemy, wars, epidemics, restraints of government, civil disturbances, and acts, orders and regulations of governmental agencies, (iv) inability to acquire or delay in acquiring materials, equipment, rights-of-way and approvals of regulatory bodies, (v) physical constraint or restriction of, or accident or blockage of or to, equipment or lines of pipe and (vi) interruption of MOTI's gathering, treating, processing or transportation arrangements relating to production from the Underlying Properties, including such arrangements under the Gas Gathering Contract. Following any such event, the affected party's obligations under the Gas Purchase Contract will be suspended during the period of its inability to perform, and such party will use reasonable efforts to remedy the event and resume full performance as quickly as reasonably practical. Although MOTI will likely utilize the natural gas purchased from MOPI pursuant to the Gas Purchase Contract to satisfy its obligations under a number of resale agreements with third parties, none of the gas purchased by MOTI pursuant to any gas purchase agreement (including the Gas Purchase Contract) has been dedicated to any particular resale agreement, and the arrangements made by MOTI with respect to reselling any gas purchased by it vary from time to time. The prices to be paid by third party purchasers, therefore, may also be expected to vary from time to time, and may be either less than or greater than the price paid by MOTI pursuant to the Gas Purchase Contract. At times when the Minimum Purchase Price exceeds the Index Price, MOTI will be required to purchase gas at a price based on the Minimum Purchase Price. At times when the Index Price exceeds the Sharing Price, MOTI will receive a benefit from being able to resell gas at prices generally reflecting the full amount of the excess of the Index Price over the Sharing Price, while paying MOPI and, therefore, the Trust an amount generally reflecting only 50 percent of such excess. The Gas Purchase Contract may not be terminated without the consent of MOTI and MOPI. Further, it may not be amended in a manner that would materially adversely affect the revenues to the Trust without the approval of the holders of a majority of the Units then outstanding. The Gas Purchase Contract is filed as an exhibit to this Form 10-K. The foregoing summary of the material provisions of the Gas Purchase Contract is qualified in its entirety by reference to the terms of such agreement as set forth in such exhibit. GAS GATHERING CONTRACT The prices to be paid to MOPI pursuant to the Gas Purchase Contract are prices payable for the value of gas purchased for production at the Central Gathering Point. Title to the gas purchased pursuant to the Gas Purchase Contract, therefore, passes to MOTI at the Central Gathering Point. MOTI is responsible for gathering, treating, processing and marketing from the Central Gathering Point all gas purchased pursuant to the Gas Purchase Contract. The price paid by MOTI pursuant to the Gas Purchase Contract is after deducting Deductible Costs from the Central Gathering Point. Pursuant to the Gas Gathering Contract, MOGI gathers, treats and processes all of the production attributable to MOPI's interest in the Underlying Properties (excluding production attributable to five wells) from the Central Gathering Point. MOGI, under the Gas Gathering Contract, treats the gas gathered for MOTI to remove carbon dioxide and water and to otherwise bring the gas into compliance with the specifications of the Gas Gathering Contract. At December 31, 1996, MOGI's rates for performing its services under the Gas Gathering Contract varied from approximately $.30 to approximately $.43 per Mcf, depending upon the specific point of delivery to MOGI. MOTI reduces the price that it pays for the gas by the value of gas used by MOGI as fuel for compression and other facilities. These reductions can not exceed 6.5 percent of the value of volumes of gas gathered for MOTI. The rates payable to MOGI pursuant to the Gas Gathering Contract are subject to annual adjustment on January 1 of each year 28 on the basis of increases or decreases in a published index measuring consumer prices. Additionally, these rates may be increased by the amount of any additional costs incurred by MOGI as a direct result of any governmental action relating generally to gathering and/or treating agreements in the natural gas industry. The term of the Gas Gathering Contract will continue until December 31, 2012; thereafter, such contract will continue in effect on a month-to-month basis. All of the gas gathered pursuant to the Gas Gathering Contract must first be gathered from the wellhead to the Central Gathering Point by a unit gathering system owned by the working interest owners of the Northeast Blanco Unit. The costs of such initial gathering (including maintenance of the gathering system) are borne by such working interest owners (including MOPI) and deducted as lease operating expenses in calculating the NPI Net Proceeds or Infill Net Proceeds, as the case may be. MOPI does not anticipate any changes in the manner in which gas will be gathered at the wellhead and transported to the Central Gathering Point, or in the arrangements relating to use and maintenance of the Northeast Blanco Unit gathering system. The Gas Gathering Contract may not be amended in a manner that would materially adversely affect the revenues to the Trust without the approval of the holders of a majority of the Units then outstanding. The Gas Gathering Contract is filed as an exhibit to this Form 10-K. The foregoing summary of the material provisions of the Gas Gathering Contract is qualified in its entirety by reference to the terms of such agreement as set forth in such exhibit. FEDERAL LANDS Approximately 80 percent of the Underlying Properties are burdened by royalty interests held by the Federal government. Royalty payments due to the U.S. government for 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"), a subagency of the U.S. Department of the Interior that administers and receives revenues from Federal royalties on behalf of the U.S. government. The 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. Where gas is sold by a lessee to an affiliate such as MOTI, the MMS regulations (as well as state regulations with respect to severance taxes) may ignore the lessee-affiliate transaction and consider the arm's-length sale by the affiliate as the point of valuation for royalty purposes. Accordingly, MOPI may be required to calculate royalty payments and severance taxes based on the price MOTI receives when it markets the gas production (the "Resale Price"), notwithstanding the price payable by MOTI to MOPI pursuant to the Gas Purchase Contract. Although the NPI Net Proceeds, 95 percent of which is payable to the Trust, will reflect the deduction of all royalty and overriding royalty burdens and state severance taxes, to the extent that the Resale Price exceeds the price paid for production purchased under the Gas Purchase Contract, NPI Net Proceeds will not be reduced by the royalties, but will be reduced by the severance taxes, payable in respect of such excess. Royalties payable in respect of such excess will be borne by MOPI. The MMS regulations permit a lessee to deduct from its gross proceeds its reasonable actual costs of transportation and processing to transport the gas from the lease to the point of sale in calculating the market value of its production. Although MOPI will deduct (i) the Deductible Costs paid by MOTI pursuant to the Gas Gathering Contract and (ii) the gathering charges payable by MOPI as a working interest owner of the Northeast Blanco Unit gathering system in calculating the wellhead price of gas produced by MOPI, the MMS could disallow the deduction of some portion of such charges after review of such charges on audit of MOPI's royalty as discussed below. If some portion of such charges is disallowed, the MMS will likely demand additional royalties plus interest on the amount of the underpayment. The Trustee has been advised by MOPI that the MMS has from time to time considered the inclusion of the value of the Section 29 tax credits attributable to coal seam gas production in the calculation of gross proceeds for purposes of calculating the royalty that is payable to the MMS. On August 30, 1993, the U.S. Office of the Inspector General (the "OIG") issued an audit report stating the view that Section 29 tax credits should be included in the calculation of gross proceeds and recommending that the MMS pursue collection of additional royalties with 29 respect to past and future production. On December 8, 1993, however, the Office of the Solicitor of the U.S. Department of the Interior gave its opinion to the MMS that the report of the OIG was incorrect and that Section 29 tax credits are not part of gross proceeds for the purpose of federal royalty calculations. MOPI believes that any inclusion of the value of Section 29 tax credits for purposes of calculating royalty payments required to be made on Federal lands would be inappropriate since all mineral interest owners, including royalty owners, are entitled to Section 29 tax credits for their proportionate share of qualifying coal seam gas production. MOPI has advised the Trustee that it would vigorously oppose any attempt by the MMS to require the inclusion of the value of Section 29 tax credits in the calculation of gross proceeds. However, if regulations so to include such value were adopted and upheld, royalty payments would be increased which would decrease NPI Net Proceeds and, therefore, amounts payable to the Trust. The reduction in amounts payable to the Trust would cause a corresponding reduction in associated Section 29 tax credits available to Unitholders. The MMS generally audits royalty payments within a six-year period. Although MOPI calculates royalty payments in accordance with its interpretation of the then applicable MMS regulations, MOPI does not know whether the royalty payments made to the U.S. government are totally in conformity with MMS standards until the payments are audited. If an MMS audit, or any other audit by a Federal or state body, results in additional royalty charges, together with interest, relating to production from and after the consummation of the Public Offering in respect of MOPI's interest in the Underlying Properties, certain of such charges and interest will be deducted in calculating NPI Net Proceeds for the quarter in which the charges are paid and in each quarter thereafter until the full amount of the additional royalty charges and interest have been recovered. 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") may be limited. As a result, non-Eligible Citizens may be prohibited from owning Units. If any Units are acquired by persons or entities not constituting Eligible Citizens, such Unitholders may be required to sell such Units pursuant to a procedure set forth in the Trust Agreement. See "Item 1--Description of Units--Possible Divestiture of Units." SALE AND ABANDONMENT OF UNDERLYING PROPERTIES MOPI does not have the right to abandon its interest in any well on the Underlying Properties. However, MOPI does not have control over any decisions which may be made by the operator and other working interest owners of the Underlying Properties to abandon any well or property on the Underlying Properties (although MOPI does exercise influence over such decisions to the extent of its working interest). Since MOPI does not operate any of the wells on the Underlying Properties (although MOI operates a single communitized well), MOPI does not normally control the timing of plugging and abandoning wells. The Conveyance provides that MOPI's working interest share of the costs of plugging and abandoning uneconomic wells will be deducted in calculating NPI Net Proceeds or Infill Net Proceeds, as the case may be. MOPI 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. Any purchaser of such interest will be subject to the same standards, and will possess the same influence, set forth in the preceding paragraph. Under the Trust Agreement, MOPI has certain rights (but not the obligation) to purchase the Royalty Interests upon termination of the Trust. See "Item 1--Description of the Trust--Termination and Liquidation of the Trust." THE INFILL NPI The Royalty Interests include the Infill NPI, a net profits interest in any Infill Wells completed on the Underlying Properties. No Infill Wells have been drilled and none will be drilled unless, prior to any decision to drill any such wells by the working interest owners of the Underlying Properties, the well spacing limitations for coal seam wells in the San Juan Basin are reduced. If such changes occur and Infill Wells are drilled, the Infill NPI will entitle the Trust to receive 20 percent of the Infill Net Proceeds. No reserves have been attributed in the December 31, 1996 Reserve Report or the Prior Reserve Reports to any Infill Wells. The Trustee has been advised by Burlington Resources that it believes, although no assurances are given, that Infill Wells will be drilled on the Underlying Properties only if the owners of the working interests in such 30 properties believe that the expenditures required to drill and complete such Infill Wells will be justified by the expected increase in recoverable reserves therefrom. Infill Wells may recover a portion of the reserves producible from wells burdened by the NPI. Accordingly, the drilling of Infill Wells may reduce the proved reserves attributable to wells burdened by the NPI, although Burlington Resources has advised the Trustee that it believes that such reduction will be offset, at least in part, by the reserves then attributable to such Infill NPI. Because the NPI generally entitles the Trust to 95 percent of the NPI Net Proceeds and the Infill NPI entitles the Trust to only 20 percent of the Infill Net Proceeds, no assurance can be given that amounts payable to the Trust will not be reduced if Infill Wells are drilled. Further, under current law no Section 29 tax credits will be available with respect to production attributable to the Infill NPI even if an Infill Well recovers a portion of the reserves that qualified for Section 29 tax credits because prior to the drilling and completion of such Infill Well, they were recoverable from a well burdened by the NPI. MOPI's working interest share of capital expenditures and operating expenses relating to any Infill Wells will be deducted in calculating the Infill Net Proceeds. Such amounts bear no relation to capital and operating costs which will be deducted in calculating the NPI Net Proceeds. See "--The NPI." During the term of the Trust, MOPI will account for each of the NPI and the Infill NPI separately, with the result that no amounts deductible in calculating the NPI Net Proceeds will be deducted from the Infill NPI revenue stream, and vice versa. If, during any period, costs and expenses (including interest expenses) deductible in calculating the portion of the Infill Net Proceeds payable to the Trust exceed gross proceeds with respect to Infill Wells, neither the Trust nor Unitholders will be liable for such excess, but the Trust will receive no payments for distribution to Unitholders with respect to the Infill NPI until future gross proceeds with respect to such wells exceed future costs and expenses with respect thereto plus the cumulative excess of such costs and expenses plus interest thereon at Citibank's Base Rate. BURLINGTON RESOURCES' PERFORMANCE ASSURANCES Pursuant to the Trust Agreement, Burlington Resources has agreed to pay each of the following to the extent not paid by MOPI when due and payable: (i) all liabilities and capital and lease operating expenses which MOPI is required under the Conveyance to pay as a working interest owner of the Underlying Properties; (ii) all NPI Net Proceeds, Infill Net Proceeds and other amounts which MOPI is obligated to pay to the Trust under the Conveyance; (iii) any proceeds from a sale of any remaining Royalty Interests that MOPI may elect to purchase upon termination of the Trust; and (iv) certain indemnification obligations relating to environmental liabilities in connection with MOPI's interest in the Underlying Properties (collectively, "MOPI Payment Obligations"). Burlington Resources has also agreed to pay, to the extent not paid by MOTI when due and payable, all amounts which MOTI is required to pay to MOPI in respect of production attributable to the Royalty Interests pursuant to the terms of the Gas Purchase Contract ("MOTI Payment Obligations"). Burlington Resources may assign such performance assurance obligations, and may be relieved of such obligations, upon the occurrence of certain events and to an entity or entities meeting certain criteria. TITLE TO PROPERTIES Burlington Resources has advised the Trustee that it believes that MOPI's title to its interest in the Underlying Properties is, and the Trust's title to the Royalty Interests is, good and defensible in accordance with standards generally accepted in the gas industry, subject to such exceptions which, in the opinion of Burlington Resources, are not so material as to detract substantially from the use or value of MOPI's interest in the Underlying Properties or the Royalty Interests. The Underlying Properties are typically subject, in one degree or another, to one or more of the following: (i) royalties and other burdens and obligations, expressed and implied, under oil and gas leases; (ii) overriding royalties and other burdens created by MOPI or its predecessors in title; (iii) a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles; (iv) liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements; (v) pooling, unitization and communitization agreements, declarations and orders; (vi) irregularities or ambiguities in the instruments of title; and (vii) easements, restrictions, rights-of-way and other matters that commonly affect property. To the extent that such burdens and obligations affect MOPI's 31 rights to production and the value of production from the Underlying Properties, they have been taken into account in calculating the Trust's interests and in estimating the size and discounted net present value of the reserves attributable to the Royalty Interests. Except as noted below, Burlington Resources believes that the burdens and obligations affecting MOPI's interest in the Underlying Properties and Royalty Interests are conventional in the industry for similar properties, do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially and adversely affect the discounted net present value of the Royalty Interests. Although the matter is not entirely free from doubt, Burlington Resources has advised the Trustee that it believes (based upon the opinions of local counsel to Burlington Resources with respect to matters of New Mexico law) that the Royalty Interests should constitute property interests under applicable state law. Consistent therewith, the Conveyance states that the Royalty Interests constitute property interests and it was recorded in the appropriate real property records of San Juan and Rio Arriba counties, New Mexico, the counties in which the Underlying Properties are located, in accordance with local recordation provisions. If, during the term of the Trust, MOPI becomes involved as a debtor in bankruptcy proceedings under the Federal Bankruptcy Code, it is not entirely clear that all of the Royalty Interests would be treated as property interests under the laws of New Mexico. If in such a proceeding a determination were made that the Royalty Interests constitute property interests, the Royalty Interests should be unaffected in any material respect by such bankruptcy proceeding. If in such a proceeding a determination were made that the Royalty Interests constitute executory contracts (a term used, but not defined, in the Federal Bankruptcy Code to refer to a contract under which the obligations of both the debtor and the other party to such contract are so unsatisfied that the failure of either to complete performance would constitute a material breach excusing performance by the other) and not a property interest under applicable state law, and if such contract were not to be assumed in a bankruptcy proceeding involving MOPI, the Trust would be entitled to damages for breach of such contract covered by the termination of such contract in such bankruptcy proceeding and, with respect to such entitlement, the Trust would be treated as an unsecured creditor of MOPI in the pending bankruptcy. Although no assurance is given, Burlington Resources does not believe that the Royalty Interests should be subject to rejection in a bankruptcy proceeding as executory contracts. 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 UNITHOLDER MATTERS. Certain information with respect to the Units of the Trust and the market therefor is set forth on the inside front cover of the Trust's Annual Report to Unitholders for the year ended December 31, 1996 under the section entitled "Units of Beneficial Interest" and is incorporated herein by reference. ITEM 6. SELECTED FINANCIAL DATA. Selected financial data of the Trust is set forth on the inside front cover of the Trust's Annual Report to Unitholders for the year ended December 31, 1996 under "Selected Financial Data" and is incorporated herein by reference. 32 ITEM 7. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The "Trustee's Discussion and Analysis of Financial Condition and Results of Operations" appearing on pages 2 and 3 of the Trust's Annual Report to Unitholders for the year ended December 31, 1996 is incorporated herein by reference. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. The financial statements of the Trust and the notes thereto, together with the report thereon of Deloitte & Touche LLP, independent auditors, dated March 21, 1997, appearing on pages 4 through 11 of the Trust's Annual Report to Unitholders for the year ended December 31, 1996 are incorporated herein by reference. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. The Trust has no directors or executive officers. Each of the Trustee and the Delaware Trustee is a corporate trustee that may be removed as trustee under the Trust Agreement, with or without cause, at a meeting duly called and held by the affirmative vote of Unitholders of not less than a majority of all the Units then outstanding. Any such removal of the Delaware Trustee shall be effective only at such time as a successor Delaware Trustee fulfilling the requirements of Section 3807(a) of the Delaware Code has been appointed and has accepted such appointment, and any such removal of the Trustee shall be effective only at such time as a successor Trustee has been appointed and has accepted such appointment. 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 Burlington Resources, the Trustee, the Delaware Trustee, the Transfer Agent, or their affiliates. Ongoing Administrative Expenses. The Trust is responsible for paying all legal, accounting, engineering and stock exchange fees, printing costs and other administrative and out-of-pocket expenses incurred by or at the direction of the Trustee or Delaware Trustee and the out-of-pocket expenses of the Transfer Agent. Compensation of the Trustee, Delaware Trustee and Transfer Agent. The Trust Agreement provides for compensation to the Trustee and the Delaware Trustee for administrative services, out of the Trust assets. The Trustee was paid a 1996 base amount of $39,147, plus an hourly charge for services in excess of a combined total of 300 hours annually at the Trustee's then standard rate. The Trustee received total compensation for 1996 of $39,147. The Trustee's annual base fee escalates at the rate of 3 percent per year. The Delaware Trustee is paid a fixed annual amount of $10,000. The Trustee and the Delaware Trustee are each 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 a 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 fees payable to that trustee will increase significantly until a new trustee is appointed. The Transfer Agent receives a transfer agency fee of $5.30 annually per account (minimum of $15,000 annually), subject to increase or decrease each December, based upon the change in the Producers' Price Index as published by the Department of Labor, Bureau of Labor Statistics, plus $1.00 for each certificate issued in excess of 10,000 annually. The total of fees paid by the Trust to the Transfer Agent in 1996 was $12,472. 33 Fees to Burlington Resources. Burlington 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 as described below in "Item 13 --Administrative Services Agreement". ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. (a) Security Ownership of Certain Beneficial Owners. The Trustee knows of no Unitholder which is a beneficial owner of more than 5 percent of the outstanding Units. (b) Security Ownership of Management. The Trust has no directors or executive officers. As of March 15, 1997, NationsBank of Texas, N.A., the Trustee, did not beneficially own any Units. As of March 15, 1997, Mellon Bank (DE) National Association, the Delaware Trustee, did not beneficially own any Units. (c) 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 Trust. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. ADMINISTRATIVE SERVICES AGREEMENT Pursuant to the Trust Agreement, Burlington Resources and the Trust entered into an Administrative Services Agreement effective May 1, 1993. A copy of the Administrative Services Agreement is filed as an exhibit to this Form 10-K. The Administrative Services Agreement obligates the Trust to pay to Burlington 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 for 1996, payable in equal quarterly installments, was $313,157, and the fee will be adjusted annually, based upon the change in the Producers' Price Index. BURLINGTON RESOURCES' CONDITIONAL RIGHT OF REPURCHASE Burlington 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 Burlington Resources and its affiliates. Any such repurchase would generally be at a price equal to the greater of (i) the highest price at which Burlington 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 New York Stock Exchange for the 30 trading days immediately preceding the Determination Date. Any such repurchase would be conducted in accordance with applicable Federal and state securities laws. See "Item 1--Description of Units- - -Conditional Right of Repurchase." POTENTIAL CONFLICTS OF INTEREST The interests of Burlington Resources and its subsidiaries and the interests of the Trust and the Unitholders with respect to the Underlying Properties could at times be different. As an interest owner in the Underlying Properties, MOPI could have interests that conflict with the interests of the Trust and Unitholders. For example, such conflicts could be due to a number of factors including, but not limited to, future budgetary considerations and the absence of any contractual obligation on the part of MOPI to spend for development of the Underlying Properties, except as noted herein. Such decisions may have the effect of changing the amount or timing of future distributions to Unitholders. MOPI's interest may also conflict with those of the Trust and Unitholders in situations involving the sale or abandonment of Underlying Properties. MOPI has the right at any time, pursuant to the terms of the Conveyance, to sell any of its interest in the Underlying Properties subject to the Royalty Interests. Such sales may not be in the best interest of the Trust. Except for amendments to the Gas Purchase Contract, the Gas Gathering Contract or the Conveyance which must be approved by the vote of the holders of a majority of all Units then outstanding if such amendment would materially adversely affect Trust revenues, no mechanism or procedure has 34 been included to resolve potential conflicts of interest between the Trust and Burlington Resources, MOPI, MOTI or MOGI. To the extent that any matters are brought to a vote of Unitholders where the interests of Burlington Resources conflict, or potentially conflict, with the interests of the Trust or Unitholders, Burlington Resources can be expected to vote in its own self interest. See "Item 2--The Royalty Interests--Sale and Abandonment of Underlying Properties," "--Gas Purchase Contract" and "--Gas Gathering Contract." 35 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K. (a) The following documents are filed as a part of this report: 1. Financial Statements (incorporated by reference in Item 8. of this report) PAGE IN 1996 ANNUAL REPORT TO UNITHOLDERS (INCORPORATED BY REFERENCE) -------------- Independent Auditors' Report................................... 4 Statements of Assets, Liabilities and Trust Corpus as of December 31, 1996 and 1995....................... 5 Statements of Distributable Income for the years ended December 31, 1996, 1995 and 1994............................. 5 Statements of Changes in Trust Corpus for the years ended December 31, 1996, 1995 and 1994............................. 5 Notes to Financial Statements.................................. 6 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 -- Certificate of Trust of Burlington Resources Coal Seam Gas Royalty Trust (filed as Exhibit 3.1 to the Registrant's Form 10-K for the year ended December 31, 1993 and incorporated herein by reference). 3.2 -- Certificate of Amendment to the Certificate of Trust of Burlington Resources Coal Seam Gas Royalty Trust (filed as Exhibit 3.2 to the Registrant's Form 10-K for the year ended December 31, 1993 and incorporated herein by reference). 4.1 -- Trust Agreement of Burlington Resources Coal Seam Gas Royalty Trust effective as of May 1, 1993, by and among Meridian Oil Production Inc., Burlington Resources Inc. and Mellon Bank (DE) National Association and NationsBank of Texas, N.A., as trustees (filed as Exhibit 4.1 to the Registrant's Form 10-Q for the quarter ended June 30, 1993 and incorporated herein by reference). 36 EXHIBIT NUMBER EXHIBIT ------ ------- 10.1 -- Net Profits Interest Conveyance effective as of May 1, 1993, from Meridian Oil Production Inc. to Burlington Resources Coal Seam Gas Royalty Trust (filed as Exhibit 10.1 to the Registrant's Form 10-Q for the quarter ended June 30, 1993 and incorporated herein by reference). 10.2 -- Administrative Services Agreement effective May 1, 1993, by and between Burlington Resources Inc. and Burlington Resources Coal Seam Gas Royalty Trust (filed as Exhibit 10.2 to the Registrant's Form 10-Q for the quarter ended June 30, 1993 and incorporated herein by reference). 10.3 -- Gas Purchase Contract dated as of May 1, 1993, by and between Meridian Oil Production Inc. and Meridian Oil Trading Inc. (filed as Exhibit 10.3 to the Registrant's Form 10-Q for the quarter ended June 30, 1993 and incorporated herein by reference). 10.4 -- Gas Gathering, Dehydrating and Treating Agreement dated as of May 3, 1990 between Meridian Oil Gathering Inc. and Meridian Oil Trading Inc., as amended (filed as Exhibit 10.4 to the Registrant's Form 10- Q for the quarter ended June 30, 1993 and incorporated herein by reference). 13.1 -- 1996 Annual Report to Unitholders. 23.1 -- Consent of Netherland, Sewell & Associates, Inc. 27.1 -- Financial Data Schedule. 99.1 -- The information under the section captioned "Tax Considerations" on pages 26-27, the information under the section captioned "Federal Income Tax Consequences" on pages 57-64, the information under the section captioned "ERISA Considerations" on pages 64-65, and Exhibit A of the Prospectus dated June 10, 1993, which constitutes a part of the Registration Statement on Form S-3 of Burlington Resources Inc. (Registration No. 33-61164) is incorporated herein by reference to such Registration Statement. 99.2 -- Reserve Report, dated March 25, 1994, on the estimated reserves, estimated future net revenues and discounted estimated future net revenues attributable to the Royalty Interests and MOPI's interest in the Underlying Properties as of December 31, 1993, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers (filed as Exhibit 99.2 to the Registrant's Form 10-K for the year ended December 31, 1993 and incorporated herein by reference). 99.3 -- Reserve Report, dated March 15, 1995, on the estimated reserves, estimated future net revenues and discounted estimated future net revenues attributable to the Royalty Interests and MOPI's interest in the Underlying Properties as of December 31, 1994, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers (filed as Exhibit 99.3 to the Registrant's Form 10-K for the year ended December 31, 1994 and incorporated herein by reference). 99.4 -- Report, dated March 16, 1995, on the estimated Section 29 tax credits attributable to the Royalty Interests as of December 31, 1994, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers (filed as Exhibit 99.4 to the Registrant's Form 10-K for the year ended December 31, 1994 and incorporated herein by reference). 99.5 -- Reserve Report, dated March 18, 1996, on the estimated reserves, estimated future net revenues and discounted estimated future net revenues attributable to the Royalty Interests and MOPI's interest in the Underlying Properties as of December 31, 1995, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers (filed as Exhibit 99.5 to the Registrant's Form 10-K for the year ended December 31, 1995 and incorporated herein by reference). 37 EXHIBIT NUMBER EXHIBIT ------ ------- 99.6 -- Report, dated March 19, 1996, on the estimated Section 29 tax credits attributable to the Royalty Interests as of December 31, 1995, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers (filed as Exhibit 99.6 to the Registrant's Form 10-K for the year ended December 31, 1995 and incorporated herein by reference). 99.7 -- Reserve Report, dated March 20, 1997, on the estimated reserves, estimated future net revenues and discounted estimated future net revenues attributable to the Royalty Interests and MOPI's interest in the Underlying Properties as of December 31, 1996, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers. 99.8 -- Report, dated March 21, 1997, on the estimated Section 29 tax credits attributable to the Royalty Interests as of December 31, 1996, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers. (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. 38 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. BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST By: NATIONSBANK OF TEXAS, N.A., Trustee By: /s/ Ron E. Hooper ---------------------------------------- Ron E. Hooper Vice President and Administrator Date: March 31, 1997 (The Registrant has no directors or executive officers.) 39 EX-13 2 1996 ANNUAL REPORT EXHIBIT 13.1 BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST 1996 ANNUAL REPORT AND FORM 10-K THE TRUST Burlington Resources Coal Seam Gas Royalty Trust (the "Trust") was formed as a Delaware business trust pursuant to the Trust Agreement of Burlington Resources Coal Seam Gas Royalty Trust entered into effective as of May 1, 1993 by and among Meridian Oil Production Inc. ("MOPI"), as trustor, Burlington Resources Inc. ("Burlington Resources"), the parent company of MOPI, and NationsBank of Texas, N.A. (the "Trustee") and Mellon Bank (DE) National Association (the "Delaware Trustee"), as trustees. Effective January 1, 1996, MOPI was merged with and into Meridian Oil Inc. ("MOI"), a wholly owned subsidiary of Burlington Resources. Effective July 11, 1996, MOI changed its name to Burlington Resources Oil & Gas Company ("BROG") and Meridian Oil Trading Inc. ("MOTI") and Meridian Oil Gathering Inc. ("MOGI"), both affiliates of MOI, changed their names to Burlington Resources Trading Inc. ("BRTI") and Burlington Resources Gathering Inc. ("BRGI"), respectively. Accordingly, references in this Annual Report to MOPI refer to BROG, references to MOTI refer to BRTI and references to MOGI refer to BRGI. The Trust owns certain net profits interests (the" Royalty Interests") in MOPI's interest in the Fruitland coal formation underlying the Northeast Blanco Unit in the San Juan Basin of New Mexico (the "Underlying Properties"). The Royalty Interests are the only assets of the Trust, other than cash and temporary investments being held for the payment of expenses and liabilities and for distribution to Unitholders. The Trust makes quarterly cash distributions to Unitholders. The record date of the quarterly cash distribution of the Trust is the 63rd day following the end of the calendar quarter unless such day is not a business day in which case the record date will be the next business day. The quarterly cash distribution is payable on or before 75 days after the end of the calendar quarter. 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 MOPI'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.
1997 1998 Record Dates June 2 September 2 December 2 March 4 Distribution Dates June 13 September 12 December 12 March 16 UNITS OF BENEFICIAL INTEREST
The units of beneficial interest ("Units") in the Trust are listed and traded on the New York Stock Exchange under the symbol "BRU." The following table sets forth, for the periods indicated, the high and low sales prices per Unit on the New York Stock Exchange and the amount of quarterly cash distributions per Unit made by the Trust.
Price Distributions High Low per Unit 1996 First Quarter $ 13-5/8 $ 10-1/8 $ 0.332882 Second Quarter $ 11-3/4 $ 8-3/4 $ 0.298843 Third Quarter $ 10 $ 8-3/4 $ 0.255385 Fourth Quarter $ 10 $ 8-1/4 $ 0.250990 1995 First Quarter $ 17-5/8 $ 15-1/8 $ 0.364168 Second Quarter $ 17-1/8 $ 14-3/4 $ 0.399989 Third Quarter $ 16 $ 14-3/8 $ 0.385197 Fourth Quarter $ 15-3/8 $ 12-3/8 $ 0.375008
At March 18, 1997, there were 8,800,000 Units outstanding and approximately 1,188 Unitholders of record. SELECTED FINANCIAL DATA
FOR THE PERIOD FROM MAY 5, 1993 FOR THE YEAR ENDED DECEMBER 31, (DATE OF INCEPTION) ---------------------------------------------------- TO DECEMBER 31, 1996 1995 1994 1993 ------------ ------------ ------------ -------------------- ROYALTY INCOME................. $ 10,671,428 $ 14,076,780 $ 17,115,969 $ 6,900,747 DISTRIBUTABLE INCOME........... $ 10,040,541 $ 13,402,397 $ 16,423,579 $ 6,549,172 DISTRIBUTABLE INCOME PER UNIT.......................... $1.14 $1.52 $1.87 $0.74 DISTRIBUTIONS PER UNIT......... $1.14 $1.52 $1.88 $0.72 TOTAL ASSETS, DECEMBER 31...... $107,530,131 $123,634,960 $147,565,760 $172,184,435 TRUST CORPUS, DECEMBER 31...... $107,328,165 $123,534,740 $147,459,837 $172,153,000
TO UNITHOLDERS: We are pleased to present the 1996 Annual Report to Unitholders of Burlington Resources Coal Seam Gas Royalty Trust (the "Trust"). The report includes a copy of the Trust's annual report on Form 10-K for the year ended December 31, 1996. The Form 10-K contains important information concerning the creation and administration of the Trust, and the assets of the Trust, including coal seam gas reserves attributable to the net profits interests owned by the Trust estimated as of December 31, 1996. The Trust was formed as a Delaware business trust under the Delaware Business Trust Act pursuant to the Trust Agreement of Burlington Resources Coal Seam Gas Royalty Trust (the "Trust Agreement") entered into effective as of May 1, 1993 by and among Meridian Oil Production Inc. ("MOPI"), as trustor, Burlington Resources Inc. ("Burlington Resources"), the parent company of MOPI, and NationsBank of Texas, N.A. (the "Trustee") and Mellon Bank (DE) National Association, as trustees. The Trust was formed to acquire and hold certain net profits interests (the "Royalty Interests") in MOPI's interest in the Fruitland coal formation underlying the Northeast Blanco Unit in the San Juan Basin of New Mexico. The Royalty Interests are the only assets of the Trust, other than cash and temporary investments being held for the payment of expenses and liabilities and for distribution to Unitholders. 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 MOPI'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. For additional information concerning the reserves please refer to Note 9 "Supplemental Oil and Gas Information" to the financial statements. The year 1996 marked the Trust's third full year of operations. Distributable income for the year ended December 31, 1996 was $10,040,541 or $1.14 per Unit as compared to $13,402,397 or $1.52 per Unit for 1995. Royalty income for the year totaled $10,671,428 as compared to $14,076,780 for 1995. The Trust also earned interest of $28,339 from temporary investments of funds prior to quarterly distributions being made as compared to $37,576 for 1995. General and administrative expenses for the year were $659,226 as compared to $711,959 for 1995. Under the Trust Agreement, the Trustee has the responsibility to collect proceeds attributable to the Royalty Interests and to make quarterly cash distributions to Unitholders after deducting administrative expenses and any amounts necessary for cash reserves. The quarterly record date is the 63rd day following the end of the calendar quarter unless such day is not a business day in which case the record date will be the next business day. The quarterly distribution date is on or prior to 75 days after the end of the calendar quarter. Tax information for calendar year 1996 permitting each Unitholder to make all calculations reasonably necessary for tax purposes was distributed by the Trustee to Unitholders prior to March 15, 1997, in accordance with the Trust Agreement. Such income tax information will be provided annually to Unitholders by the Trustee not later than March 15th of each year. BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST BY: NATIONSBANK OF TEXAS, N.A., TRUSTEE BY:/SIG/RON E. HOOPER VICE PRESIDENT MARCH 31, 1997 TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The Trust 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 net revenue interest in the Underlying Properties which are owned by MOPI and not the Trust. Distributable income of the Trust consists of the excess of royalty income plus interest income over the general and administrative expenses of the Trust. Upon receipt by the Trust, royalty income is invested in short-term investments in accordance with the Trust Agreement until its subsequent distribution to Unitholders. The amount of distributable income of the Trust for any calendar year may differ from the amount of cash available for distribution to the Unitholders in such year due to differences in the treatment of the expenses of the Trust in 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 paid or reserves are established for them. Consequently, the reported distributable income of the Trust for any year is determined by deducting from the income received by the Trust the amount of expenses paid by the Trust during such year. The amount of cash available for distribution to Unitholders, however, is determined in accordance with the provisions of the Trust Agreement and reflects the deduction from the income actually received by the Trust of the amount of expenses actually paid by the Trust and adjustment for changes in reserves for unpaid liabilities. See Note 5 to the financial statements of the Trust appearing elsewhere in this Annual Report to Unitholders for additional information regarding the determination of the amount of cash available for distribution to Unitholders. 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 MOPI'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. For additional information concerning the reserves please refer to Note 9 "Supplemental Oil and Gas Information" of the financial statements. The year 1996 marked the third full year of operations for the Trust. Royalty income for 1996 was $10,671,428 as compared to $14,076,780 for 1995 and $17,115,969 for 1994. Production of 12,122,587 Mcf for 1996 declined from 14,212,659 Mcf for 1995 and 16,706,193 Mcf for 1994 due to the natural decline of production from the coal seam formation. Natural gas prices received for 1996 were $1.06 per Mcf compared to $1.08 per Mcf for 1995 and $1.22 per Mcf for 1994. Royalty income received by the Trust in a given calendar year will generally reflect the proceeds from the sale of gas produced from the Underlying Properties during the first three quarters of that year and the fourth quarter of the preceding calendar year less any operating and capital costs. Accordingly, the royalty income included in distributable income for the years ended December 31, 1996, 1995 and 1994 was based on production volumes and natural gas prices for the twelve months ended September 30, 1996, 1995 and 1994, respectively, in accordance with the terms of the conveyance of the Royalty Interests to the Trust, as shown in the table below. The production volumes included in the table are actual net production volumes attributable to MOPI's interest in the Underlying Properties, and not production attributable to the Royalty Interests owned by the Trust.
For the Twelve Months Ended September 30, ----------------------------------------- 1996 1995 1994 ------- ------- ------- Production (Bcf)(1)................... 12.761 14.961 17.585 Production (Trillion Btu)(2).......... 11.515 13.519 15.881 Average Inside FERC Price ($/MMBtu)(3)......................... $ 1.34 $ 1.22 $ 1.76 MOPI Average Entitled Price Received ($/MMBtu)(4)......................... $ 1.18 $ 1.20 $ 1.36
(1)Billion cubic feet of natural gas. (2)Trillion British Thermal Units. (3)The posted index price (Inside FERC) of spot gas delivered to pipelines. (4)Average Inside FERC price less allowable deductions. At December 31, 1995 and 1994, the Trust's net carrying value of its investment in royalty interests exceeded the sum of the future net cash flows plus the estimated future Section 29 tax credit benefits from the production of the Trust's reserves by $561,809 and $995,048, respectively. Accordingly, the Trust was required to record an impairment allowance in 1995 and 1994 to reduce its carrying value of royalty interests in gas reserves. The reduction in the carrying value of its investments was charged directly to trust corpus. For further discussion of impairment, please refer to Notes 2 and 10 in the financial statements. There was no impairment for 1996. Production attributable to MOPI's interest in the Underlying Properties is generally sold pursuant to a gas purchase contract between MOPI and Meridian Oil Trading Inc. ("MOTI"). The gas purchase contract provides certain protections for MOTI in the form of price credits and for Unitholders when the applicable Blanco Hub Spot Price falls below $1.65 per MMBtu and provides certain benefits for MOTI when the Blanco Hub Spot Price exceeds $2.10 per MMBtu. The gas purchase contract also provides that the price paid for gas by MOTI is reduced by the amount of gathering and/or transportation charges, taxes, treating and processing costs and all other costs in connection with such services from the central gathering point to main line delivery paid by MOTI. For more detailed information regarding the terms and conditions of the gas purchase contract, see "Item 2. Properties -- Gas Purchase Contract" in the Form 10-K of the Trust appearing elsewhere in this Annual Report to Unitholders. The Blanco Hub Spot Price was below $1.65 per MMBtu for all months during 1996 except August, November and December. The Blanco Hub Spot Price was below $1.65 per MMBtu in each month during 1995 and during the second, third and fourth quarters of 1994. However, pursuant to the terms of the gas purchase contract, MOTI continued to purchase gas attributable to MOPI's interest in the Underlying Properties at the $1.60 per MMBtu minimum purchase price, less deductible costs paid by MOTI, established by the gas purchase contract; and MOTI received a price credit from MOPI for each MMBtu of natural gas so purchased by MOTI equal to the difference between the $1.60 per MMBtu minimum purchase price and the applicable index price (which price is equal to 97 percent of the applicable Blanco Hub Spot Price). MOTI estimates that, as of December 31, 1996, MOTI had aggregate price credits of approximately $8.9 million of which the Trust's 95 percent interest was approximately $8.5 million. The Blanco Hub Spot Price was above $1.65 per MMBtu in January and February 1997 although there can be no assurance that it will not again fall below such price level. With the Blanco Hub Spot Price being above the minimum purchase price for several months of 1996, MOTI recouped price credits totaling $1.2 million. The entitlement of MOTI to recoup the price credits means that even though the applicable Blanco Hub Spot Price is above $1.65 per MMBtu, royalty income otherwise payable to the Trust will be reduced until such time as all accrued and unrecouped price credits have been recovered by MOTI. Reduced royalty income to the Trust correspondingly reduces cash distributions to Unitholders. The information in this Annual Report to Unitholders concerning production and prices relating to MOPI's interest in the Underlying Properties is based on information prepared and furnished by MOPI to the Trustee. The Trustee has no control over and no responsibility relating to the operation of the Underlying Properties. This Annual Report and the accompanying Form 10-K include "forward-looking statements" within the meaning of Section 21E of the Securities Exchange Act of 1934, which are intended to be covered by the safe harbors created thereby. All statements other than statements of historical fact included in this Annual Report and the accompanying Form 10-K are forward-looking statements. Such statements include, without limitation, the reserve information and other statements contained in Item 2, "Properties" of the accompanying Form 10-K. Although the Trust believes that the expectations reflected in such forward- looking statements are reasonable, such expectations are subject to numerous risks and uncertainties and the Trust can give no assurance that they will prove correct. There are many factors, none of which is within the Trust's control, that may cause such expectations not to be realized, including, among other things, factors identified in this Annual Report and the accompanying Form 10-K affecting oil and gas prices and the recoverability of reserves, and future economic, competitive and market conditions. FINANCIAL STATEMENTS Audited Statements of Assets, Liabilities and Trust Corpus of the Trust as of December 31, 1996 and 1995, and the related Statements of Distributable Income and Changes in Trust Corpus for the years ended December 31, 1996, 1995 and 1994 are included in this Annual Report to Unitholders immediately following the Independent Auditors' Report below. The Royalty Interests owned by the Trust burden the Underlying Properties, which are owned by MOPI and not the Trust. For the information of Unitholders, an audited Statement of Revenues and Direct Operating Expenses of the Underlying Properties for each of the three years in the period ended December 31, 1996 has been prepared and furnished by MOPI to the Trustee for inclusion in this Annual Report to Unitholders. The financial statements furnished by MOPI appear immediately preceding the Form 10-K of the Trust. INDEPENDENT AUDITORS' REPORT NATIONSBANK OF TEXAS, N.A., AS TRUSTEE OF BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST We have audited the accompanying statements of assets, liabilities and trust corpus of Burlington Resources Coal Seam Gas Royalty Trust as of December 31, 1996 and 1995, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 1996. 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 financial statements have been prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than generally accepted accounting principles. In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust corpus of the Burlington Resources Coal Seam Gas Royalty Trust at December 31, 1996, and 1995, and its distributable income and changes in trust corpus for each of the three years in the period ended December 31, 1996, on the basis of accounting described in Note 2. /SIG/DELOITTE & TOUCHE LLP Dallas, Texas March 21, 1997 FINANCIAL STATEMENTS BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
December 31, 1996 1995 ASSETS CASH AND CASH EQUIVALENTS.............................................................. $ 158,251 $ 31,260 Royalty interests in oil and gas properties (less accumulated amortization and......... 107,371,880 123,603,700 impairment of $73,028,120 and $56,796,300)(Note 10) TOTAL ASSETS..................................................................... $107,530,131 $123,634,960 LIABILITIES AND TRUST CORPUS Trust expenses payable................................................................. $ 201,966 $ 100,220 Trust corpus (8,800,000 units of beneficial interest authorized and outstanding)....... 107,328,165 123,534,740 TOTAL LIABILITIES AND TRUST CORPUS..................................................... $107,530,131 $123,634,960
STATEMENTS OF DISTRIBUTABLE INCOME
YEAR ENDED DECEMBER 31 1996 1995 1994 ROYALTY INCOME............................ $10,671,428 $ 14,076,780 $ 17,115,969 Interest income........................... 28,339 37,576 36,323 10,699,767 14,114,356 17,152,292 GENERAL AND ADMINISTRATIVE EXPENSES (NOTE 4)................................. (659,226) (711,959) (728,713) DISTRIBUTABLE INCOME...................... $10,040,541 $ 13,402,397 $ 16,423,579 DISTRIBUTABLE INCOME PER UNIT (8,800,000 UNITS)........................ $1.14 $1.52 $1.87 Distributions per unit.................... $1.14 $1.52 $1.88
STATEMENTS OF CHANGES IN TRUST CORPUS
YEAR ENDED DECEMBER 31 1996 1995 1994 TRUST CORPUS, BEGINNING OF PERIOD....... $123,534,740 $147,459,837 $172,153,000 Amortization and impairment of royalty interests.............................. (16,231,820) (23,913,096) (24,564,144) DISTRIBUTABLE INCOME.................... 10,040,541 13,402,397 16,423,579 DISTRIBUTIONS TO UNITHOLDERS............ (10,015,296) (13,414,398) (16,552,598) Trust corpus, end of period............. $107,328,165 $123,534,740 $147,459,837
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS. NOTES TO FINANCIAL STATEMENTS 1. TRUST ORGANIZATION AND PROVISIONS Burlington Resources Coal Seam Gas Royalty Trust (the "Trust") was formed as a Delaware business trust pursuant to the terms of the Trust Agreement of Burlington Resources Coal Seam Gas Royalty Trust (the "Trust Agreement") entered into effective as of May 1, 1993 by and among Meridian Oil Production Inc., a Delaware corporation ("MOPI"), as trustor, Burlington Resources Inc., a Delaware corporation ("Burlington Resources"), and NationsBank of Texas, N.A., a national banking association (the "Trustee"), and Mellon Bank (DE) National Association, a national banking association (the "Delaware Trustee"), as trustees. Effective January 1, 1996, MOPI was merged with and into Meridian Oil Inc. ("MOI"), a wholly owned subsidiary of Burlington Resources. Effective July 11, 1996, MOI changed its name to Burlington Resources Oil & Gas Company("BROG"), and Meridian Oil Trading Inc. ("MOTI") and Meridian Oil Gathering Inc.("MOGI"), both affiliates of MOI, changed their names to Burlington Resources Trading Inc. ("BRTI") and Burlington Resources Gathering Inc.("BRGI"), respectively. Accordingly, references in this Annual Report to MOPI refer to BROG, references to MOTI refer to BRTI and references to MOGI refer to BRGI. The trustees are independent financial institutions. The Trust is a grantor trust formed to acquire and hold certain net profits interests (the "Royalty Interests") in MOPI's interest in the Fruitland coal formation underlying the Northeast Blanco Unit in the San Juan Basin of New Mexico (the "Underlying Properties"). The Trust was initially created by the filing of a Certificate of Trust with the Secretary of State of Delaware on May 5, 1993. In accordance with the Trust Agreement, MOPI contributed $1,000 as the initial trust corpus of the Trust. On June 17, 1993, the Royalty Interests were conveyed to the Trust by MOPI pursuant to the Net Profits Interest Conveyance (the "Conveyance") dated effective as of May 1, 1993, in consideration for all 8,800,000 authorized units of beneficial interest ("Units") in the Trust. MOPI transferred its Units by dividend to its parent, Meridian Oil Holding Inc., which transferred such Units by dividend to its parent, Burlington Resources, which sold such Units to the public through various underwriters in June 1993 (the "Public Offering"). All of the production attributable to the Underlying Properties is from the Fruitland coal formation and currently constitutes "coal seam" gas that entitles the owners of such production, provided certain requirements are met, to tax credits pursuant to Section 29 of the Internal Revenue Code of 1986, as amended. Royalty income to the Trust is attributable to the sale of depleting assets. All of the Underlying Properties burdened by the NPI (as hereinafter defined) consist of producing properties. Accordingly, the proved reserves attributable to MOPI'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 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 business of the Trust. The Royalty Interests are passive in nature and neither the Delaware Trustee nor the Trustee has any control over or any responsibility relating to the operation of the Underlying Properties or MOPI's interest therein. The Trust will terminate no later than December 31, 2012, subject to earlier termination under certain circumstances described in the Trust Agreement (the "Termination Date"). Cancellation of the Trust will occur on or following the Termination Date when all Trust assets have been sold and the net proceeds thereof are distributed to the 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 consist primarily of a net profits interest (the "NPI") in MOPI's interest in the Underlying Properties. The NPI generally entitles the Trust to receive 95 percent of the NPI Net Proceeds, as defined below. The Royalty Interests also include a 20 percent interest in the Infill Net Proceeds, as defined below, from the sale of production if well spacing rules are effectively modified and additional wells are drilled on producing drilling blocks in the Northeast Blanco Unit ("Infill Wells") during the term of the Trust. With respect to the NPI, the term "NPI Net Proceeds" generally means the aggregate proceeds attributable to MOPI's net revenue interest in the Underlying Properties (excluding the proceeds, if any, from Infill Wells) calculated at the price paid by MOTI at any one of four central delivery points in the Northeast Blanco Unit gathering system or either of two wellhead delivery points (collectively, the "Central Gathering Point") for the entitled volume of gas produced and sold from MOPI's interest in the Underlying Properties less MOPI's working interest share of (i) property, production and related taxes (including severance taxes); (ii) lease operating expenses; (iii) capital costs (if paid after January 1, 1994); (iv) royalties, if any, required to be paid that are based on the value of Section 29 tax credits attributable to such working interest share; and (v) interest on the unrecovered portion, if any, of the foregoing costs at a rate equal to the base rate (compounded quarterly) as announced from time to time by Citibank, N.A. ("Citibank's Base Rate"). The term "Infill Net Proceeds" generally means the aggregate proceeds attributable to MOPI's net revenue interest calculated at the price paid by MOTI at the Central Gathering Point for the entitled volume of gas produced and sold from MOPI's interest in any Infill Wells less MOPI's working interest share of (a) property, production and related taxes (including severance taxes) on such Infill Wells; (b) lease operating expenses with respect to such Infill Wells; (c) capital costs with respect to such Infill Wells; and (d) interest on the unrecovered portion, if any, of the foregoing costs at Citibank's Base Rate. The complete definitions of NPI Net Proceeds and Infill Net Proceeds are set forth in the Conveyance. Because of the passive nature of the Trust and the restrictions and limitations on the powers and activities of the Trustee contained in the Trust Agreement, the Trustee does not consider any of the officers and employees of the Trustee to be "officers" or "executive officers" of the Trust as such terms are defined under the 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: .Royalty income and interest income are recorded in the period in which amounts are received by the Trust rather than in the months of production. .General and administrative expenses recorded are based on liabilities paid and cash reserves established out of cash received. .Amortization of the Royalty Interests is calculated on a unit-of-production basis and charged directly to trust corpus based upon when revenues are received. .Distributions to Unitholders are recorded when declared by the Trustee (see Note 5). The financial statements of the Trust differ from financial statements prepared in accordance with GAAP because royalty income is not accrued in the period of production, general and administrative expenses recorded are based on liabilities paid and cash reserves established rather than on an accrual basis, and amortization and impairment of the Royalty Interests is not charged against operating results. Burlington Resources sold an aggregate of 8,800,000 Units in the Public Offering. Accordingly, the carrying value of the Trust's Royalty interest in oil and gas properties at December 31, 1996 and 1995 reflect 8,800,000 Units at the public offering price of $20.50 per Unit, less accumulated amortization and impairment. 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 product prices plus the estimated future Section 29 credits for federal income tax purposes. If the net cost of royalty interests in gas properties exceeds this amount, 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. NEW ACCOUNTING STANDARDS Statements of Financial Accounting Standards ("SFAS") No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" establishes accounting standards for the impairment of long-lived assets, certain identifiable intangibles, and goodwill related to those assets to be held and used and for long-lived assets and certain identifiable intangibles to be disposed of. SFAS No. 121 requires the review of long-lived assets and certain identifiable intangibles for impairment. If an impairment event occurs and it is determined that the carrying value of the asset may not be recoverable, an impairment loss will be recognized as measured by the amount by which the carrying amount of the assets exceeds the fair value of the asset. The Trustee adopted SFAS No. 121 effective January 1, 1996 . Such implementation did not have any impact on the financial statements of the Trust (see Note 10). 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 without regard to the taxable year or accounting method employed by the Trust. Production from coal seam gas wells drilled after December 31, 1979 and prior to January 1, 1993, qualifies 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 the 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. Each Unitholder should consult his tax advisor regarding Trust tax compliance matters. 4. RELATED PARTY TRANSACTIONS Burlington Resources provides accounting, bookkeeping and informational services to the Trust in accordance with an Administrative Services Agreement effective May 1, 1993. The fee is $75,000 per quarter, adjusted annually, based upon the change in the Producer's Price Index each January 1 commencing January 1, 1994. Aggregate fees paid by the Trust to Burlington Resources in 1996, 1995 and 1994 were $313,157, $305,695 and $300,600, respectively. Aggregate fees paid by the Trust to the Trustee in 1996, 1995 and 1994 were $39,147, $38,192 and $37,080, respectively. The Delaware Trustee was paid a flat fee of $10,000 for each of the respective years. 5. DISTRIBUTIONS TO UNITHOLDERS The Trustee determines for each 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, on or before the last business day before the 50th day following the end of each calendar quarter from the Royalty Interests attributable to production during such quarter, plus, with certain exceptions, any other cash receipts of the Trust during such quarter, over the liabilities of the Trust paid during such quarter, 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. The Quarterly Distribution Amount for each quarter is payable to Unitholders of record on the 63rd 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 distributes the Quarterly Distribution Amount on or prior to the 75th day after the end of each calendar quarter to each person who was a Unitholder of record on the associated record date, together with interest estimated to be earned on such amount from the date of receipt thereof by the Trustee to the payment date. 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 $10,000,000 (a "Special Distribution Amount"). The record date for 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. Distribution to Unitholders of a Special Distribution Amount will be made no later than 15 days after the Special Distribution Amount record date. 6. CONTINGENCIES Under the terms of the gas purchase contract entered into between MOPI and an affiliate of MOPI (the "Gas Purchase Contract"), additional revenues may be paid to the Trust to meet the minimum purchase price provision of $1.60 per MMBtu (the "Minimum Purchase Price") (less applicable deductions). This additional revenue is subject to recoupment by MOPI from future revenues received from production when the applicable index price in such month exceeds the Minimum Purchase Price. The applicable index price was below the Minimum Purchase Price during 1996 except for the months of August, November and December, and in each month during 1995 and during the second, third and fourth quarters of 1994. Pursuant to the terms of the Gas Purchase Contract, MOTI established a price credit account. MOTI estimates that, as of December 31, 1996, MOTI had aggregate price credits in the price credit account of approximately $8.9 million of which the Trust's 95 percent interest was approximately $8.5 million. The applicable index price was above the Minimum Purchase Price in January and February 1997. The Trustee has been advised by MOPI that the Minerals Management Service ("MMS"), a subagency of the U.S. Department of the Interior, has from time to time considered the inclusion of the value of the Section 29 tax credits attributable to coal seam gas production in the calculation of gross proceeds for purposes of calculating the royalty that is payable to the MMS. On August 31, 1993, the U.S. Office of the Inspector General (the "OIG") issued an audit report stating the view that Section 29 tax credits should be included in the calculation of gross proceeds and recommended that the MMS pursue collection of additional royalties with respect to past and future production. On December 8, 1993, however, the Office of the Solicitor of the U.S. Department of the Interior gave its opinion to the MMS that the report of the OIG was incorrect and that Section 29 tax credits are not part of gross proceeds for the purpose of Federal royalty calculations. MOPI believes that any inclusion of the value of Section 29 tax credits for purposes of calculating royalty payments required to be made on Federal lands would be inappropriate since all mineral interest owners, including royalty owners, are entitled to Section 29 tax credits for their proportionate share of qualifying coal seam gas production. MOPI has advised the Trustee that it would vigorously oppose any attempt by the MMS to require the inclusion of the value of Section 29 tax credits in the calculation of gross proceeds. However, if such regulations were adopted and upheld, royalty payments would be increased which would decrease NPI Net Proceeds and, therefore, amounts payable to the Trust. The reduction in amounts payable to the Trust would cause a corresponding reduction in associated Section 29 tax credits available to Unitholders. Per the terms of the Gas Purchase Contract, all royalty income of the Trust was derived from MOPI. 7. SUBSEQUENT EVENT Subsequent to December 31, 1996, the Trust declared the following distribution: Quarterly Record Date Payment Date Distribution per Unit March 4, 1997 March 14, 1997 $.147801 The Trustee has estimated the Section 29 tax credit associated with the March 14, 1997 quarterly distribution to be $.18 per Unit (unaudited). 8. QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly financial data for the periods ended December 31, 1996 and 1995 are as follows (in thousands except per unit amount):
Calendar Quarter Royalty Income Distributable Distributable Income Income per Unit 1996 First $ 3,101 $ 2,920 $ .33 Second 2,852 2,638 .30 Third 2,423 2,309 .26 Fourth 2,295 2,174 .25 $10,671 $10,041 $1.14 1995 First $ 3,308 $ 3,174 $ .36 Second 3,812 3,517 .40 Third 3,528 3,398 .39 Fourth 3,429 3,313 .37 $14,077 $13,402 $1.52
Selected 1996 fourth quarter data are as follows (in thousands except per unit amounts): Royalty income......................................... $ 2,295 Interest income........................................ 6 General and administrative expenses.................... (127) ------- Distributable income................................... $ 2,174 ======= Distributable income per unit.......................... $ .25 ======= Distribution per unit.................................. $ .25 =======
Due to the significant upward revision in estimated reserve quantities (see Note 9), estimated amortization of royalty interests was adjusted downward by approximately $3.3 million during the fourth quarter of 1996. This adjustment did not have an impact on the Trust's distributable income. 9. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) The net proved reserves attributable to the Royalty Interests, all located within the United States, have been estimated as of December 31, 1996, 1995 and 1994 by independent petroleum engineers. In accordance with Statement of Financial Accounting Standards No. 69, estimates of future net revenues from proved reserves have been prepared either using end- of-period or contractual gas prices as appropriate and related costs. The standardized measure of future net revenues from the gas reserves is calculated based on discounting such future net revenues at an annual rate of 10 percent. At December 31, 1996, the price the Trust was entitled to receive under the Gas Purchase Contract was $2.74 per MMBtu subject to accrued and unrecouped price credits (see Note 6). For purposes of preparation of the reserve report as of December 31, 1996, however, pricing was held constant at the minimum purchase price ($1.60 per MMBtu) until the accrued price credits were recouped by MOTI, after which $2.74 per MMBtu was utilized for the remaining life of the Royalty Interests. Numerous uncertainties are inherent in estimating volumes and value of proved developed reserves and in projecting future production rates. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the original estimates. The reserve estimates for the Royalty Interests are based on a percentage share of NPI Net Proceeds payable to the Trust of 95 percent. A net profits interest does not entitle the Trust to a specific quantity of gas but to a portion of gas sufficient to yield a specified portion of the net proceeds derived therefrom. Proved reserves attributable to a net profits interest are calculated by deducting an amount of gas sufficient, if sold at the prices used in preparing the reserve estimates for such net profits interest, to pay the future estimated costs and expenses deducted in the calculation of the net proceeds of such interest. Accordingly, the reserves presented for the Royalty Interests reflect quantities of gas that are free of future costs and expenses if the price and cost assumptions used in the reserve report prepared as of December 31, 1996 occur.
Natural Gas (MMcf) Proved reserves at January 1, 1994...... 108,025 Revisions of previous estimates.......... (1,752) Production............................... (15,941) ------- Proved reserves at December 31, 1994..... 90,332 Revisions of previous estimates.......... 208 Production............................... (13,995) ------- Proved reserves at December 31, 1995..... 76,545 Revisions of previous estimates.......... 6,671 Production............................... (11,582) ------- Proved reserves at December 31,1996...... 71,634 =======
All proved reserve estimates presented above are proved developed. Proved reserves are estimated quantities of natural gas which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs 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. The following table sets forth the standardized measure of discounted future net revenues at December 31, 1996, 1995 and 1994 relating to proved reserves (in thousands):
1996 1995 1994 Future cash inflows................. $ 143,716 $ 94,079 $ 110,439 Future production taxes, operating costs, and capital expenditures...................... (27,410) 19,048 (24,470) --------- --------- --------- Future net cash flows............... 116,306 75,031 85,969 10% discount factor................. (49,001) (27,461) (30,286) --------- --------- --------- Standardized measure of discounted future net revenues.... $ 67,305 $ 47,570 $ 55,683 ========= ========= =========
The following table sets forth the changes in the aggregate standardized measure of discounted future net revenues from proved reserves during the years ended December 31, 1996, 1995 and 1994 (in thousands):
1996 1995 1994 Balance at January 1.............. $47,570 $ 55,683 $ 91,423 Increase (decrease) due to: Net sales of coal seam gas....... (9,042) (13,826) (15,906) Net changes in prices and costs.. 18,444 (80) (25,600) Changes in estimated volumes..... 5,576 225 (3,376) Accretion of discount............. 4,757 5,568 9,142 ------- -------- -------- Balance at December 31............ $67,305 $ 47,570 $ 55,683 ======= ======== ========
The above reserves do not include undiscounted Section 29 tax credits of approximately $36,055,600 as estimated by an independent petroleum engineer. The present discounted (10%) value of these tax credits is approximately $28,479,900. Subsequent to year end 1996, the price of gas decreased significantly. As of March 21,1997, published natural gas prices were approximately 1.53 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. 10. IMPAIRMENT OF ROYALTY INTERESTS At December 31, 1995 and 1994, the Trust's net carrying value of its investment in royalty interests exceeded the sum of the future net cash flows plus the estimated future Section 29 tax credit benefits from the production of the Trust's reserves by $561,809 and $995,048, respectively. Accordingly, the Trust was required to record an impairment allowance during 1995 and 1994 to reduce its carrying value of royalty interests in gas reserves. The reduction in the carrying value of its investments was charged directly to trust corpus. There was no impairment in 1996. For further discussion of impairment see Note 2. As more fully discussed in Note 2, beginning in 1996 the Trust was required to adopt SFAS No. 121. SFAS No. 121 requires that 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. SUPPLEMENTAL INFORMATION REGARDING THE UNDERLYING PROPERTIES The Royalty Interests owned by the Trust burden MOPI's interest in the Underlying Properties. The Royalty Interests are passive in nature and neither the Trustee nor the Delaware Trustee has any control over or responsibility relating to the operation of the Underlying Properties or MOPI's interest therein. For the information of Unitholders, the following Statement of Revenues and Direct Operating Expenses of MOPI's interest in the Underlying Properties for each of the three years in the period ended December 31, 1996, auditied by Coopers & Lybrand L.L.P., independent accountants, has been prepared and furnished by MOPI to the Trustee for inclusion herein. REPORT OF INDEPENDENT ACCOUNTANTS TO BOARD OF DIRECTORS OF BURLINGTON RESOURCES INC.: We have audited the accompanying Statement of Revenues and Direct Operating Expenses ("Statement") of certain coal seam gas producing properties of Burlington Resources Oil & Gas Company ("the Underlying Properties") for each of the three years in the period ended December 31, 1996. In 1996, Meridian Oil Inc., the successor by merger of Meridian Oil Production Inc., changed its name to Burlington Resources Oil & Gas Company (the "Company"). The financial statement is the responsibility of Company's management. Our responsibility is to express an opinion on this financial statement based upon 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 statement is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall statement presentation. We believe that our audits provide a reasonable basis for our opinion. The accompanying Statement reflects the revenue and direct operating expenses attributable to the Company's interest in the Underlying Properties as described in Note 2 and is not intended to be a complete presentation of the revenues and expenses of the Company's interest in the Underlying Properties. In our opinion, the Statement presents fairly, in all material respects, the revenues and direct operating expenses of the Company's interest in the Underlying Properties as described in Note 2 for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. /SIG/COOPERS & LYBRAND L.L.P. Fort Worth, Texas March 21, 1997 BURLINGTON RESOURCES OIL & GAS COMPANY'S INTEREST IN THE UNDERLYING PROPERTIES STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
(In thousands) Years Ended December 31, 1996 1995 1994 Revenues $12,682 $16,009 $19,573 ------- ------- ------- Direct operating expenses Taxes on production and property 1,228 1,111 1,871 Lease operating expenses 455 433 624 ------- ------- ------- 1,683 1,544 2,495 ------- ------- ------- Excess of revenues over direct operating expenses $10,999 $14,465 $17,078 ======= ======= =======
The accompanying notes are an integral part of this financial statement. BURLINGTON RESOURCES OIL & GAS COOMPANY'S INTEREST IN THE UNDERLYING PROPERTIES NOTES TO THE FINANCIAL STATEMENTS 1. BURLINGTON RESOURCES OIL & GAS COMPANY'S INTEREST IN THE UNDERLYING PROPERTIES The interest of Burlington Resources Oil & Gas Company in certain coal seam gas producing properties (the "Underlying Properties") consists of certain interests in the Fruitland Coal formation owned by Burlington Resources Inc. through the Company. The Underlying Properties, substantially all of which are located in the Northeast Blanco Unit in the San Juan Basin of New Mexico, are burdened by a Net Profits Interest Conveyance from Meridian Oil Production Inc. to the Burlington Resources Coal Seam Gas Royalty Trust ("Trust") dated May 1, 1993 ("Conveyance"). In 1996, Meridian Oil Inc., the successor by merger of Meridian Oil Production Inc., changed its name to Burlington Resources Oil & Gas Company (the "Company"). 2. BASIS OF PRESENTATION The accompanying financial statement does not include depreciation, depletion and amortization, interest, general and administrative expenses or income taxes as such information is either not readily available on an individual property basis or relevant for purposes of the Trust. During the periods presented, the Underlying Properties were not accounted for as a separate entity. Accordingly, the financial statement is not intended to represent the financial position, results of operations, or cash flows of the Underlying Properties in conformity with generally accepted accounting principles. Revenues are presented on an accrual basis using the production entitlement method as set forth in the Conveyance. The Company's revenues are recorded based upon its Net Revenue Interest Percentage (as defined in the Conveyance). Revenues are reflected net of existing royalties, overriding royalties and gathering, treating and processing expenses. The Company's actual cash receipts may vary from accrued revenues due to timing delays of receipt of cash from the operators of the Underlying Properties or purchasers, and due to wellhead and pipeline volume balancing agreements or practices. The Company produced and sold more gas than its entitled share based upon its working interest in the Underlying Properties, and thus is in an over-produced position of approximately 297 million cubic feet ("MMcf"), 258 MMcf and 1,100 MMcf as of December 31, 1996, 1995 and 1994, respectively. Expenses are presented on an accrual basis. The preparation of the financial statement requires the Company to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting periods. Actual results could differ from such estimates. 3. RELATED PARTY TRANSACTIONS Prior to May 1, 1993, the Company's production from the Underlying Properties was sold to Meridian Oil Trading Inc. ("MOTI"), an affiliate of the Company, based on MOTI's posted price. Beginning May 1, 1993, the Company's production from the Underlying Properties was sold to MOTI under the terms of the Gas Purchase Contract between the Company and MOTI dated May 1, 1993 ("Gas Purchase Contract"). In 1996, MOTI changed its name to Burlington Resources Trading Inc. ("BRTI"). The monthly price paid by BRTI for natural gas purchased pursuant to the Gas Purchase Contract is (i) the greater of (a) $1.60 per million British thermal units ("Minimum Purchase Price") and (b) the Index Price (as defined in the Gas Purchase Contract) up to the Sharing Price (as defined in the Gas Purchase Contract), less, in each case, (ii) gathering, treating and processing charges incurred in connection with such production, and plus (iii) a price differential, if any, when the Index Price exceeds the Sharing Price. After December 31, 1993, to the extent BRTI was required pursuant to the Gas Purchase Contract to pay a price based on the Minimum Purchase Price rather than the Index Price, BRTI is entitled to accrue certain price credits that will be used to reduce the purchase price of gas under the Gas Purchase Contract when the Index Price exceeds the Minimum Purchase Price. BRTI has the right to recover price credits of $8.9 million and $7.4 million as of December 31, 1996 and 1995, respectively. During 1996, BRTI accrued an additional $2.7 million in price credits and recovered price credits totaling $1.2 million. The Company's production from the Underlying Properties is gathered, treated and processed under the terms of the Gas Gathering, Dehydrating and Treating Agreement between the Company and Meridian Oil Gathering Inc. ("MOGI") dated May 3, 1990, as amended May 1, 1993 ("Gas Gathering , Dehydrating and Treating Agreement"). In 1996, MOGI changed its name to Burlington Resources Gathering Inc. ("BRGI"). The fees charged by BRGI totaled approximately $4.1 million, $4.8 million and $5.3 million for the years ended December 31, 1996, 1995 and 1994, respectively, and are in accordance with the rates defined in the Gas Gathering, Dehydrating and Treatment Agreement. TRUSTEE NationsBank of Texas, N.A. Dallas, Texas Delaware Trustee Mellon Bank(DE) National Association Wilmington, Delaware TRANSFER AGENT AND REGISTRAR Boston Equiserve Shareholder Service Boston, Massachusetts and New York, New York TRUST AUDITORS Deloitte & Touche LLP Dallas, Texas TRUST ENGINEERING CONSULTANTS Netherland, Sewell & Associates, Inc. Houston, Texas TRUSTEE COUNSEL Thompson & Knight, A Professional Corporation Dallas, Texas FORM 10-K A copy of the Form 10-K of the Trust for the year ended December 31, 1996 as filed with the Securities and Exchange Commission has been provided with this Annual Report to Unitholders. Additional copies of the Form 10-K will be provided, without charge, upon written request to: Burlington Resources Coal Seam Gas Royalty Trust NationsBank of Texas, N.A., Trustee NationsBank Plaza 901 Main Street, Suite 1700 Dallas, Texas 75283-0650 BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST NATIONSBANK OF TEXAS, N.A., TRUSTEE NATIONSBANK PLAZA 901 MAIN STREET, SUITE 1700 DALLAS, TEXAS 75283-0650 1-800-365-6547 EX-23.1 3 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEO EXHIBIT 23.1 [NETHERLAND, SEWELL & ASSOCIATES LETTERHEAD APPEARS HERE] CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS We hereby consent to the references to Netherland, Sewell & Associates, Inc. and to the use of its reports listed below regarding the Burlington Resources Coal Seam Gas Royalty Trust proved reserves and estimated Section 29 tax credits in the Annual Report on Form 10-K to be filed by the Burlington Resources Coal Seam Gas Royalty Trust with the Securities and Exchange Commission. 1. Report dated March 25, 1994 for reserves as of December 31, 1993. 2. Report dated March 15, 1995 for reserves as of December 31, 1994. 3. Report dated March 16, 1995 for estimated Section 29 tax credits as of December 31, 1994. 4. Report dated March 18, 1996 for reserves as of December 31, 1995. 5. Report dated March 19, 1996 for estimated Section 29 tax credits as of December 31, 1995. 6. Report date March 20, 1997 for reserves as of December 31, 1996. 7. Report dated March 21, 1997 for estimated Section 29 tax credits as of December 31, 1995. NETHERLAND, SEWELL & ASSOCIATES, INC. By: /s/ Danny D. Simmons ---------------------------------- Danny D. Simmons Senior Vice President Houston, Texas March 28, 1997 EX-27 4 FINANCIAL DATA SCHEDULE
5 12-MOS DEC-31-1996 JAN-01-1996 DEC-31-1995 158,251 0 0 0 0 158,251 180,400,000 73,028,120 107,530,131 201,966 0 0 0 0 107,328,165 107,530,131 10,671,428 10,699,767 0 659,226 0 0 0 10,040,541 0 0 0 0 0 10,040,541 1.14 0
EX-99.7 5 REPORT DATED MARCH 20, 1997 [NSA LETTERHEAD APPEARS HERE] EXHIBIT 99.7 March 20, 1997 Mr. Ron E. Hooper Burlington Resources Coal Seam Gas Royalty Trust NationsBank of Texas, N.A., Trustee NationsBank Plaza 901 Main Street, 17th Floor Dallas, Texas 75202 Dear Mr. Hooper: In accordance with your request, we have estimated, as of January 1, 1997, (1) the future net revenue to the Burlington Resources Coal Seam Gas Royalty Trust (Trust) net profits interest and (2) the proved reserves to the Burlington Resources Coal Seam Gas Royalty Trust (Burlington) interest in the Fruitland Coal Formation underlying the Northeast Blanco Unit, Rio Arriba and San Juan Counties, New Mexico, as listed in the accompanying tabulations. The Trust net profits interest is derived from the Burlington interest in such proved reserves. This report has been prepared using constant prices and costs and conforms to the guidelines of the Securities and Exchange Commission (SEC). The estimated net proved reserves in this report are defined as the portion of the gross reserves attributable to the Burlington interest to which the net profits interest is applied. As presented in the accompanying summary projection, Table I, we estimate the Burlington net reserves and the future net revenue to the Trust net profits interest, as of January 1, 1997, to be:
BURLINGTON NET RESERVES TRUST FUTURE NET REVENUE ----------------------- ------------------------- CONDENSATE GAS PRESENT WORTH CATEGORY (BARRELS) (MCF) TOTAL AT 10% - ---------------- ---------- ---------- ----------- ------------- Proved Developed 0 80,189,707 $116,306,100 $67,304,900
Gas volumes are expressed in thousands of standard cubic feet (MCF) at the contract temperature and pressure bases. These properties no longer produce commercial volumes of condensate. This report includes a summary projection of reserves and revenue along with one-line summaries of reserves, economics, and basic data by lease. For the purposes of this report, the term "lease" refers to a single economic projection. The estimated reserves and future revenue shown in this report are for proved developed reserves only. Our study indicates that there are no proved undeveloped reserves for these properties at this time. In accordance with SEC guidelines, our estimates do not include any value for probable or possible reserves which may exist for these properties. This report does not include any value which could be attributed to interests in undeveloped acreage. Future gross revenue in this report is to the Burlington interest prior to deducting state production taxes and ad valorem taxes. Future net revenue is the 95 percent net profits interest to the Trust after deducting the Burlington working interest share of these taxes and operating expenses, but before consideration of federal income taxes. Our estimates of future net revenue have not been adjusted to account for the Section 29 nonconventional fuels federal income tax credit. In accordance with SEC guidelines, the future net revenue has been discounted at an annual rate of 10 percent to determine its "present worth." The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the Trust net profits interests. For the purposes of this report, a field inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs which may be incurred due to such possible liability. Also, our estimates do not include any salvage value for the lease and well equipment nor the cost of abandoning the properties. The gas price used in this report is based on the December 1996 net price received; adjusted for BTU content, gathering fee, and shrinkage. The price is also adjusted as specified in the gas purchase contract under provisions related to the sharing price and price credit account and held constant in accordance with SEC guidelines. Lease and well operating costs are based on operating expense records provided by Burlington. These costs include the per-well overhead expenses allowed under joint operating agreements along with costs estimated to be incurred at and below the district and field levels. General and administrative overhead expenses of the Trustee are not included. Lease and well operating costs are held constant in accordance with SEC guidelines. Capital costs are included as required for workovers and production equipment. We have made no investigation of potential gas volume and value imbalances which may have resulted from overdelivery or underdelivery to the Burlington interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Burlington receiving its net revenue interest share of estimated future gross gas production. The reserves included in this report are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. The sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions included in this report due to governmental policies and uncertainties of supply and demand. Also, estimates of reserves may increase or decrease as a result of future operations. In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which legal or accounting, rather than engineering and geological, interpretation may be controlling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions necessarily represent only informed professional judgments. The titles to the properties have not been examined by Netherland, Sewell & Associates, Inc., nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were obtained from Burlington Resources Oil & Gas, Inc. and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. We are independent petroleum engineers, geologists and geophysicists; we do not own an interest in these properties and are not employed on a contingent basis. Basic geologic and field performance data together with our engineering work sheets are maintained on file in our office. Very truly yours, /s/ Frederic D. Sewell EX-99.8 6 REPORT DATED MARCH 21, 1997 [NSA LETTERHEAD APPEARS HERE] EXHIBIT 99.8 March 21, 1997 Mr. Ron E. Hooper Burlington Resources Coal Seam Gas Royalty Trust NationsBank of Texas, N.A., Trustee NationsBank Plaza 901 Main Street, 17th Floor Dallas, Texas 75202 Dear Mr. Hooper: In accordance with your request, we have estimated, as of January 1, 1997, the Section 29 nonconventional fuels federal income tax credit attributable to the Burlington Resources Coal Seam Gas Royalty Trust (Trust) net profits interest in the Fruitland Coal Formation underlying the Northeast Blanco Unit, Rio Arriba and San Juan Counties, New Mexico, as listed in the accompanying tabulations. The tax credit is derived from the Burlington Resources Oil & Gas, Inc. (Burlington) interest in the proved gas reserves as estimated in our report dated March 20, 1997. This report has been prepared using constant prices and costs and conforms to the guidelines of the Securities and Exchange Commission (SEC). The estimated net proved reserves in this report are defined as the portion of the gross reserves attributable to the Trust net profits interest. These reserves were reduced by the amount of gas reserves necessary to cover the lease operating costs at the current gas price. As presented in the accompanying summary projection, Table I, we estimate the Trust net reserves and the tax credit attributable to the Trust net profits interest, as of January 1, 1997, to be:
TRUST NET RESERVES FUTURE TAX CREDIT --------------------- ------------------------- CONDENSATE GAS PRESENT WORTH CATEGORY (BARRELS) (MCF) TOTAL AT 10% - ---------------- ---------- ---------- ----------- ------------- Proved Developed 0 38,197,677 $36,055,600 $28,479,900
Gas volumes are expressed in thousands of standard cubic feet (MCF) at the contract temperature and pressure bases. These properties no longer produce commercial volumes of condensate. This report includes a summary projection of reserves and future tax credit along with one-line summaries of reserves, economics, and basic data by lease. For the purposes of this report, the term "lease" refers to a single economic projection. The estimated reserves and future tax credit shown in this report are for proved developed reserves only. Our study indicates that there are no proved undeveloped reserves for these properties at this time. In accordance with SEC guidelines, our estimates do not include any value for probable or possible reserves which may exist for these properties. This report does not include any value which could be attributed to interests in undeveloped acreage. For the purposes of this report, a field inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs which may be incurred due to such possible liability. Also, our estimates do not include any salvage value for the lease and well equipment nor the cost of abandoning the properties. An estimated 1996 tax credit of $1.05 per MMBTU is held constant in accordance with SEC guidelines. Lease and well operating costs are based on operating expense records provided by Burlington. These costs include the per-well overhead expenses allowed under joint operating agreements along with costs estimated to be incurred at and below the district and field levels. General and administrative overhead expenses of the Trustee are not included. Lease and well operating costs are held constant in accordance with SEC guidelines. Capital costs are included as required for workovers and production equipment. We have made no investigation of potential gas volume and value imbalances which may have resulted from overdelivery or underdelivery to the Burlington interest. Therefore, our estimates of reserves and tax credit do not include adjustments for the settlement of any such imbalances; our projections are based on Burlington receiving its net revenue interest share of estimated future gross gas production. The reserves included in this report are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the tax credit therefrom and the costs related thereto could be more or less than the estimated amounts. The sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions included in this report due to governmental policies and uncertainties of supply and demand. Also, estimates of reserves may increase or decrease as a result of future operations. In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which legal or accounting, rather than engineering and geological, interpretation may be controlling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions necessarily represent only informed professional judgments. The titles to the properties have not been examined by Netherland, Sewell & Associates, Inc., nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were obtained from Burlington Resources Oil & Gas, Inc. and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. We are independent petroleum engineers, geologists and geophysicists; we do not own an interest in these properties and are not employed on a contingent basis. Basic geologic and field performance data together with our engineering work sheets are maintained on file in our office. Very truly yours, /s/ Frederic D. Sewell -----END PRIVACY-ENHANCED MESSAGE-----