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, BRTI 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.
"BRGI" means Burlington Resources Gathering Inc., a wholly owned subsidiary of Burlington Resources.
"BROG" means Burlington Resources Oil & Gas Company.
"BROG Payment Obligations" has the meaning assigned to such term under "Item 2
ITEM 2. PROPERTIES.
THE ROYALTY INTERESTS
Prior to the Termination Date, the Royalty Interests conveyed to the Trust entitled the Unitholders to receive 95 percent of the NPI Net Proceeds attributable to San Juan's interest in the Underlying Properties and 20 percent of San Juan's interest in the Infill Net Proceeds attributable to any Infill Wells that may be drilled after May 1, 1993. Pursuant to the Trust Agreement, because the Liquidation was consummated within the 150-day period following the Termination Date ending on May 27, 1999, San Juan, as the buyer of the Royalty Interests, and not the Trust or Unitholders, was entitled to all proceeds of production attributable to the Royalty Interests following the Termination Date. 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.
San Juan owns an interest in the Underlying Properties subject to and burdened by the Royalty Interests conveyed to the Trust pursuant to the Conveyance. San Juan receives all payments relating to its interest in the Underlying Properties and for production prior to the Termination Date was 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 San Juan with respect to the Royalty Interests were computed with respect to each calendar quarter ending prior to termination of the Trust, and such amounts were 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 did not include interest on any amounts payable with respect to the Royalty Interests which were held by San Juan prior to payment to the Trust. San Juan was entitled to retain all amounts attributable to its interest in the Underlying Properties which were 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 BROG to the Trust out of its net revenue interest in the Underlying Properties. As described above, BROG conveyed its retained interest in the Underlying Properties to San Juan on December 31, 1998 effective as of July 1, 1998. All of the production from the Underlying Properties is from the Northeast Blanco Unit in the Fruitland 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 BROG's or San Juan's interests 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. Both entities were merged into BROG in 1996.
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 101 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, 1998 Reserve Report. If subsequently deemed appropriate by the Northeast Blanco Unit working interest owners, such well could be redrilled and, if returned to production, San Juan's interest in that well would be burdened by the NPI. San Juan'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, 1998, San Juan had a working interest of approximately 19.8 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 BROG).
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, 1998.
Well Count and Acreage Summary. The following table shows as of December 31, 1996, 1997 and 1998 the gross and net wells and acreage for the Underlying Properties.
THE NPI
With respect to production from the Underlying Properties prior to the Termination Date, the NPI generally entitled the Trust to receive 95 percent of the NPI Net Proceeds attributable to San Juan's interest in the Underlying Properties.
However, as described elsewhere herein, as a result of the sale of the Royalty Interests in the Liquidation, neither the Trust nor the Unitholders are expected to receive any further payments from the NPI Net Proceeds.
San Juan pays its working interest share of capital costs incurred on the Underlying Properties. Such capital costs are equal to San Juan's working interest share of the amounts expended by the operator of the Northeast Blanco Unit and San Juan is 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 1997 and 1998 significant capital expenditures were made in conjunction with the installation of a looped gas gathering system. Due to the Liquidation, the Trust and Unitholders will not be affected by the level of capital expenditures on the Underlying Properties after December 28, 1998.
All cumulative lease operating expenses paid after May 1, 1993, and capital expenses paid on or after January 1, 1994, attributable to San Juan'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 were borne by BROG and for which BROG has indemnified the Trust) were deducted in calculating NPI Net Proceeds and, therefore, reduced amounts payable to the Trust.
RESERVE REPORT
The following table summarizes net proved reserves estimated as of December 31, 1998, and certain related information for the Royalty Interests and San Juan's interest in the Underlying Properties from the December 31, 1998 Reserve Report prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers. All of such reserves constitute proved developed reserves. Summaries of the December 31, 1998 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 included in Item 8 hereof for additional information regarding the net proved reserves of the Trust.
The net profits interest did 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, 1998 Reserve Report occur. The December 31, 1998 Reserve Report was prepared in accordance with criteria established by the Securities and Exchange Commission.
At December 31, 1998, the price the Trust was entitled to receive under the Gas Purchase Contract was $1.90 per MMBtu. As part of the proposal to terminate the Trust approved by Unitholders on December 28, 1998, the Gas Purchase Contract was terminated and the remaining balance in the Price Credit Account was cancelled on December 31, 1998. For purposes of the preparation of the December 31, 1998 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 BRTI, after which $1.90 per MMBtu was utilized for the remaining life of the Royalty Interests.
- ---------------- (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, 1998, the Blanco Hub Spot Price has remained above the minimum price. (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 the Royalty Interests less the relevant share 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, 1998 Section 29 Tax Credit Report for the January 1, 1999 through December 31, 2002 period, and assuming constant future Section 29 tax credits at the estimated 1998 rate of $1.07 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 $22.3 million, having a discounted present value (assuming a 10 percent discount rate) of approximately $18.8 million. As described above under "Federal Income Tax Consequences", the Section 29 tax credits attributable to production from the Royalty Interests continued to accrue to the benefit of Unitholders until the March 26, 1999 consummation date of the Liquidation regardless of the fact that San Juan, as purchaser of the Royalty Interests was entitled to the proceeds from such production since the Termination Date.
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 San Juan'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, 1996, 1997 and 1998:
GAS PURCHASE CONTRACT
The following is a description of the Gas Purchase Contract that was in effect through December 31, 1998.
Under the terms of the Gas Purchase Contract, BRTI was obligated to purchase the natural gas attributable to San Juan's interest in the Underlying Properties at the Central Gathering Point. The Gas Purchase Contract commenced as of May 1, 1993, was terminated on December 31, 1998. The monthly price paid by BRTI for natural gas purchased pursuant to the Gas Purchase Contract was, 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 BRTI's arrangements for gathering, treating, processing and transporting gas from the Central Gathering Point were altered by any governmental order, decree, legislation or regulation relating generally to gathering and transportation arrangements in the natural gas industry and such alterations were to materially increase BRTI's costs of performing its obligations under the Gas Purchase Contract, such increased costs would be included in Deductible Costs to the extent that such increased costs were not recouped by BRTI from its gas purchaser. The monthly price was subject to adjustments under certain circumstances as described below:
(a) In any month in which the Index Price was greater than the $2.04 per MMBtu Sharing Price, BRTI paid San Juan 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 BRTI had no accrued and unrecouped Price Credits (defined below) in the Price Credit Account (defined below). When BRTI had accrued and unrecouped Price Credits in the Price Credit Account, then BRTI was entitled to reduce the amount in excess of the Minimum Purchase Price (before deducting the Deductible Costs) that otherwise would have been 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 San Juan's gas purchased for such month under the Gas Purchase Contract.
(b) In any month in which the Index Price was greater than or equal to the Minimum Purchase Price but less than or equal to the Sharing Price for such month, then BRTI paid San Juan 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 BRTI had no accrued and unrecouped Price Credits in the Price Credit Account. If BRTI had accrued and unrecouped Price Credits in the Price Credit Account, then BRTI was entitled to reduce the amount in excess of the Minimum Purchase Price (before deducting the Deductible Costs) that otherwise would have been 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 San Juan's gas purchased for such month under the Gas Purchase Contract.
(c) In any month in which the Index Price was less than the Minimum Purchase Price, then BRTI paid for each MMBtu of gas purchased the Minimum Purchase Price less the Deductible Costs for such month, and BRTI received a credit (a "Price Credit") from San Juan for each MMBtu of natural gas so purchased by BRTI equal to the difference between the Minimum Purchase Price and the Index Price. BRTI 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 1995 through 1996, with the exception of the months of August, November and December of 1996. The Index Price was above the Minimum Purchase Price during 1997 except for March and April of 1997, resulting in a net reduction of the Price Credit Account of $3.3 million. The Index Price was above the Minimum Purchase Price during 1998 except for the month of September, resulting in a net reduction of the Price Credit Account of $2.0 million. BRTI estimates that, as of December 31, 1998, BRTI had aggregate Price Credits in the Price Credit Account of approximately $3.6 million, of which the Trust's 95 percent interest potentially subject to recoupment by BRTI against future revenues to the Trust was approximately $3.4 million. As described above, the Price Credit Account was terminated as of December 31, 1998 in connection with the termination of the Gas Purchase Contract.
The Central Gathering Point price in the Gas Purchase Contract was 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 BRTI 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." All prices used as index prices are delivered prices at the specified point of delivery and are, therefore, before deducting Deductible Costs.
The termination of the Gas Purchase Contract required the consent of BRTI and BROG and the approval of the holders of a majority of the Units then outstanding, and was approved by Unitholders at the December 28, 1998 meeting in connection with the approval of the termination the Trust. 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 paid to San Juan pursuant to the Gas Purchase Contract prior to its termination were 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, passed to BRTI at the Central Gathering Point. BRTI was 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 BRTI pursuant to the Gas Purchase Contract was after deducting Deductible Costs from the Central Gathering Point. Pursuant to the Gas Gathering Contract, BRGI gathered, treated and processed all of the production attributable to San Juan's interest in the Underlying Properties (excluding production attributable to five wells) from the Central Gathering Point. BRGI, under the Gas Gathering Contract, treats the gas gathered for BRTI 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, 1998, BRGI's rates for performing its services under the Gas Gathering Contract varied from approximately $.34 to approximately $.45 per Mcf, depending upon the specific point of delivery to BRGI. BRTI reduced the price that it paid for the gas by the value of gas used by BRGI as fuel for compression and other facilities. These reductions could not exceed 6.5 percent of the value of volumes of gas gathered for BRTI. The rates payable to BRGI pursuant to the Gas Gathering Contract were subject to annual adjustment on January 1 of each year on the basis of increases or decreases in a published index measuring consumer prices. Additionally, these rates could be increased by the amount of any additional costs incurred by BRGI as a direct result of any governmental action relating generally to gathering and/or treating agreements in the natural gas industry.
All of the gas gathered pursuant to the Gas Gathering Contract was 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) were borne by such working interest owners (including San Juan) and deducted as lease operating expenses in calculating the NPI Net Proceeds or Infill Net Proceeds, as the case may be.
The Gas Gathering Contract was amended with the approval of the Unitholders on December 31, 1998. The amendment to the Gas Gathering Contract was approved by Unitholders at the December 28, 1998 meeting in connection with the approval of the termination of the Trust. As a result of the Liquidation, such amendment to the Gas Gathering Contract will not affect the Trust or Unitholders.
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 the sales by BROG to BRTI made in the past, 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, BROG would have been required to calculate royalty payments and severance taxes based on the price BRTI received when it marketed the gas production (the "Resale Price"), notwithstanding the price payable by BRTI to BROG pursuant to the Gas Purchase Contract. Although the NPI Net Proceeds, 95 percent of which were payable to the Trust, reflected the deduction of all royalty and overriding royalty burdens and state severance taxes, to the extent that the Resale Price exceeded the price paid for production purchased under the Gas Purchase Contract, NPI Net Proceeds were not reduced by the royalties, but were reduced by the severance taxes, payable in respect of such excess. Royalties payable in respect of such excess were borne by BROG.
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. Had the Royalty Interests not been sold, if such changes were to occur and Infill Wells were drilled, the Infill NPI would have entitled the Trust to receive 20 percent of the Infill Net Proceeds. No reserves have been attributed in the December 31, 1998 Reserve Report or the Prior Reserve Reports to any Infill Wells.
TITLE TO PROPERTIES
Burlington Resources advised the Trustee that it believed that BROG's title to its interest in the Underlying Properties (prior to the sale of such interests to San Juan) was, and the Trust's title to the Royalty Interests (prior to the Liquidation) was, good and defensible in accordance with standards generally accepted in the gas industry, subject to such exceptions which, in the opinion of Burlington Resources, were not so material as to have detracted substantially from the use or value of BROG's interest (prior to the sale of such interests to San Juan) in the Underlying Properties or the Royalty Interests. The Trust transferred the Royalty Interests to San Juan in the Liquidation without warranty as to title.
ITEM 3.
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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
San Juan, as a holder of more than 10 percent in number of the outstanding Units, called a meeting of Unitholders of the Trust to be held December 28, 1998 in Houston, Texas, for the purpose of considering and voting upon a proposal by San Juan that included the termination of the Trust and certain related matters. Written notice of the meeting of Unitholders and an information statement describing the proposal were mailed to Unitholders on December 8, 1998.
A quorum was present at the meeting and the proposal to terminate the Trust was approved by a vote of the holders of more than 66-2/3% of the total outstanding Units as required by the Trust Agreement. The vote at the meeting was 5,867,968 Units in favor of the proposal and zero Units against the proposal, with 2,932,032 Units unrepresented at the meeting. All Units voted in favor of the proposal were directly or indirectly controlled by San Juan.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED UNITHOLDER MATTERS.
The Units were, through April 12, 1999 (the Special Distribution Record Date), 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.
At March 31, 1999, there were 8,800,000 Units outstanding and approximately 628 Unitholders of record.
ITEM 6.
ITEM 6. Selected Financial Data.
ITEM 7.
ITEM 7. TRUSTEE'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The Trust makes quarterly cash distributions to Unitholders. Following the Liquidation and the sale of the Royalty Interests, the only assets of the Trust are cash and cash equivalents being held for the payment of expenses and liabilities and for distribution to Unitholders, including the proceeds from the Liquidation, the net amount of which will be distributed on or before April 27, 1999 in a special distribution to Unitholders as of record on April 12, 1999.
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 Form 10-K 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 San Juan'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 prior to the Liquidation was therefore analogous to a return of capital. Accordingly, cash yields attributable to the Units were 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 1998 marked the fifth full year of existence for the Trust. Royalty income for 1998 was $7,440,433 as compared to $6,270,303 for 1997 and $10,671,428 for 1996. Production of 12,327,927 Mcf for 1998 increased from 10,389,400 Mcf for 1997 and 12,122,587 Mcf for 1996 due to enhanced production from the coal seam formation resulting from the installation of a looped gas gathering system. Natural gas prices received for 1998 were $.97 per Mcf compared to $1.00 per Mcf for 1997 and $1.06 per Mcf for 1996. During 1998, 1997 and 1996, the Trust was charged $1,964,793, $2,108,110 and $1,037,445, respectively, of capital costs related to various capital projects such as installation of gas gathering loop systems on specific units and recavitation of wells. The Royalty income presented for those years is net of these capital expenditures. While future capital expenditures are expected, these costs are expected to be at lower levels in future years.
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, 1998, 1997 and 1996 was based on production volumes and natural gas prices for the twelve months ended September 30, 1998, 1997 and 1996, 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 San Juan's interest in the Underlying Properties, and not production attributable to the Royalty Interests owned by the Trust.
(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, 1998 the net amount of royalty interests in gas properties was reduced to the aggregate of the net proceeds from the sale of the royalty interests and the March 1999 distribution to Unitholders. The reduction in the net carrying value of royalty interests in gas properties was charged directly to trust corpus. For a further discussion of impairment, please refer to Note 10 in the financial statements. There was no impairment writedown required to be recorded in 1996 or 1997.
Prior to December 29, 1998, production attributable to San Juan's interest in the Underlying Properties was generally sold pursuant to a gas purchase contract between BROG and Burlington Resources Trading Inc. ("BRTI"). The gas purchase contract provided certain protections in the form of price credits for Unitholders when the applicable Blanco Hub Spot Price was below $1.65 per MMBtu and provided certain benefits for BRTI when the Blanco Hub Spot Price exceeded $2.10 per MMBtu. The gas purchase contract also provided that the price paid for gas by BRTI would be 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 BRTI. For more detailed information regarding the terms and conditions of the gas purchase contract, see "Item 2. Properties - Gas Purchase Contract."
The Blanco Hub Spot Price was above $1.65 per MMBtu for all months of 1998 except September resulting in a net reduction of the Price Credit Account of approximately $2 million. The Blanco Hub Spot Price was above $1.65 per MMBtu for all months of 1997 except March and April 1997, but was below $1.65 per MMBtu for all months during 1996 except August, November and December. However, pursuant to the terms of the gas purchase contract, during periods when the Blanco Hub Spot price was below $1.65 per MMBtu, BRTI continued to purchase gas attributable to San Juan's interest in the Underlying Properties at the $1.60 per MMBtu minimum purchase price, less deductible costs paid by BRTI, established by the gas purchase contract; and BRTI received a Price Credit from San Juan for each MMBtu of natural gas so purchased by BRTI 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). BRTI estimates that, as of December 31, 1998, BRTI had aggregate Price Credits of approximately $3.6 million of which the Trust's 95 percent interest, which would have been subject to potential recoupment had the Price Credit Account not been terminated, was approximately $3.4 million. As described above, with the termination of the gas purchase contract on December 31, 1998, the remaining balance in the Price Credit Account was terminated. With the Blanco Hub Spot Price being above the minimum purchase price for several months of 1998, BRTI recouped price credits totaling $2 million. The recoupment of price credits by BRTI when the applicable Blanco Hub Spot Price has been above $1.65 per MMBtu, as was the case in 1998, has resulted in corresponding reductions of royalty income otherwise payable to the Trust and cash distributions to Unitholders.
General and Administrative Expenses increased for 1998 compared to 1997 and 1996. For the years ended December 31, 1998, 1997 and 1996, General and Administrative Expenses totaled $804,770, $664,555 and $659,226 respectively. This increase in 1998 was largely the result of increased legal and accounting expenses incurred in connection with two unsolicited tender offers for Units in early 1998, the Unitholder meeting held on December 28, 1998 and the termination of the Trust.
YEAR 2000
Many existing computer programs use only two digits to identify a year in the date field. These programs were designed and developed without considering the impact of the upcoming change in the century. If not corrected, many computer applications could fail or create erroneous results by or at the Year 2000. The Year 2000 issue affects virtually all companies and organizations. If a company or organization does not successfully address its Year 2000 issues, it may face material adverse consequences.
As described throughout this Report, on March 26, 1999, effective as of the Termination Date, all of the assets of the Trust, including the remaining Royalty Interests, were sold to San Juan. The net proceeds from such sale will be distributed to Unitholders as a Special Distribution on or before April 27, 1999. Following such distribution, the Trust will have no assets other than a reserve account to be held by the Trustee to pay certain fees, expenses, liabilities or obligations of the Trust as may be incurred in connection with the final administration, winding up and dissolution of the Trust. The Trustee expects that dissolution of the Trust will occur prior to January 1, 2000, and the Year 2000 issue is therefore expected to be inapplicable to the Trust.
FORWARD-LOOKING STATEMENTS
This Form 10-K includes "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 harbor created thereby. All statements other than statements of historical fact included in this Form 10K are forward-looking statements. Such statements include, without limitation, certain reserve information and other statements contained in this Item 2, "Properties", and certain statements regarding the Trust's financial position, industry conditions and other matters contained in "Trustee's Discussion and Analysis" in Item 7. Although the Trustee believes that the expectations reflected in such forward-looking statements are reasonable, such expectations are subject to numerous risks and uncertainties and the Trustee can give no assurance that they will prove correct. There are many factors, none of which is within the Trustee's control, that may cause such expectations not to be realized, including, among other things, factors identified in this Form 10-K affecting oil and gas prices and the recoverability of reserves, general economic conditions, actions and policies of petroleum-producing nations and other changes in the domestic and international energy markets.
The information in this report concerning production and prices relating to San Juan's interest in the Underlying Properties is based on information prepared and furnished by San Juan to the Trustee. The Trustee has no control over and no responsibility relating to the operation of the Underlying Properties.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
As a result of the Liquidation, the Trust no longer holds and will not acquire any assets other than the proceeds of the Liquidation and other funds held in cash accounts or temporary investments pending payment of expenses and liabilities of the Trust or distribution to Unitholders. After payment of the Special Distribution Amount to Unitholders, the remaining assets of the Trust will consist solely of a small reserve fund retained by the Trustee for payment of the final expenses and fees anticipated to be incurred in connection with the winding down and dissolution of the Trust. To the extent any portion of the reserve fund is held in temporary investments, because of the short-term nature of these investments and certain limitations upon the types of such investments permitted, the Trustee believes that the Trust is not subject to any material interest rate risk. As a result of the sale of the Royalty Interests in the Liquidation, the Trust is no longer subject to any form of commodity price risk. The Trust does not engage in transactions in foreign currencies which could expose the Trust or Unitholders to any foreign currency related market risk.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEPENDENT AUDITORS' REPORT
NATIONSBANK, 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, 1998 and 1997, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 1998. 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 Burlington Resources Coal Seam Gas Royalty Trust at December 31, 1998, and 1997, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 1998, on the basis of accounting described in Note 2.
As described in Notes 1 and 5 to the financial statements, the Unitholders of the Trust voted on December 28, 1998 to terminate the Trust and on March 26, 1999 the Trust entered into an Agreement of Sale and Purchase with San Juan Partners, L.L.C. to sell all of the Trust's royalty interests to San Juan Partners, L.L.C.
DELOITTE & TOUCHE LLP
Dallas, Texas April 12, 1999
FINANCIAL STATEMENTS BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
STATEMENTS OF DISTRIBUTABLE INCOME
STATEMENTS OF CHANGES IN TRUST CORPUS
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 Burlington Resources Oil & Gas Company, a Delaware corporation ("BROG"), as trustor, Burlington Resources Inc., a Delaware corporation ("Burlington Resources"), and NationsBank, N.A., a national banking association (as successor to NationsBank of Texas, N.A., the "Trustee"), and Mellon Bank (DE) National Association, a national banking association (the "Delaware Trustee"), as trustees. The trustees are independent financial institutions.
The Trust is a grantor trust formed to acquire and hold certain net profits interests (the "Royalty Interests") in the Fruitland coal formation underlying the Northeast Blanco Unit in the San Juan Basin of New Mexico formerly held by BROG and conveyed to San Juan Partners, L.L.C., a Texas limited liability company ("San Juan") effective as of July 1, 1998 pursuant to a transaction consummated by such parties on December 29, 1998 (such properties, 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, BROG contributed $1,000 as the initial trust corpus of the Trust. On June 17, 1993, the Royalty Interests were conveyed to the Trust by BROG 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. BROG transferred its Units by dividend to its parent, Burlington Resources, 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 San Juan'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 is therefore analogous to a return of capital. Accordingly, cash yields attributable to the Units were 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 ever had control over or any responsibility relating to the operation of the Underlying Properties or San Juan's interest therein.
Pursuant to the Trust Agreement the Trust was terminated by a vote of the holders of greater than 66-2/3% of the outstanding Units on December 28, 1998 (the "Termination Date"). The remaining assets of the Trust, including the Royalty Interests, were sold to San Juan on March 26, 1999 in a transaction effective as of the Termination Date. Cancellation of the Trust will occur as soon as practicable after all net proceeds from the sale of the Trust's Assets are distributed to the Unitholders and all necessary administrative duties of the Trust have been fulfilled.
The only assets of the Trust are cash and cash equivalents being held for the payment of expenses and liabilities and for distribution to Unitholders, including the proceeds from the Liquidation, the net amount of which will be distributed in a special distribution to Unitholders on or before April 27, 1999. Prior to the Liquidation, the primary asset of the Trust was the Royalty Interests. The Royalty Interests consisted primarily of a net profits interest (the "NPI") in San Juan's interest in the Underlying Properties. The NPI generally entitled 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 were 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 San Juan's net revenue interest in the Underlying Properties (excluding the proceeds, if any, from Infill Wells) previously calculated prior to December 29, 1998 at the price paid by Burlington Resources Trading Inc. ("BRTI"), 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 San Juan's interest in the Underlying Properties less San Juan'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 San Juan's net revenue interest previously calculated prior to December 29, 1998 at the price paid by BRTI at the Central Gathering Point for the entitled volume of gas produced and sold from San Juan's interest in any Infill Wells less San Juan' 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:
o 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. o General and administrative expenses recorded are based on liabilities paid and cash reserves established out of cash received. o Amortization of the Royalty Interests is calculated on a unit-of-production basis and charged directly to trust corpus based upon when revenues are received. o Distributions to Unitholders are recorded when declared by the Trustee (see Note 5).
The financial statements of the Trust differ from financial statements prepared in accordance with GAAP because royalty income is not accrued in the period of production, general and administrative expenses recorded are based on liabilities paid and cash reserves established rather than on an accrual basis, and amortization 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, 1998 and 1997 reflect 8,800,000 Units at the public offering price of $20.50 per Unit, less accumulated amortization and impairment allowance.
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. At December 31, 1998, the net amount of royalty interests in gas properties was reduced to the aggregate of the net proceeds from the sale of the royalty interests and the March 1999 distribution to unitholders. If the net cost of royalty interests in gas properties exceeded this amount, an impairment provision was 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.
DISTRIBUTABLE INCOME PER UNIT
Basic earnings per share is computed by dividing distributable income by the weighted average shares outstanding. Earnings per share assuming dilution is computed by dividing distributable income by the weighted average number of shares and equivalent shares outstanding. The Trust had no equivalent shares outstanding for any period presented. As a result, basic and diluted distributable income per unit are the same.
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board ("FASB") issued, in June 1997, Statement of Financial Accounting Standard ("SFAS") No. 131, "Disclosures about Segments of an Enterprise and Related Information," which establishes standards for the way public companies disclose information about operating segments, products and services, geographic areas and major customers. SFAS No. 131 is effective for financial statements for periods beginning after December 15, 1997. SFAS No. 131 has no effect on the Trust's reporting since it operates in only one business segment and its assets are located solely in the United States.
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
During 1998, Burlington Resources provided accounting, bookkeeping and informational services to the Trust in accordance with an Administrative Services Agreement effective May 1, 1993. The fee was $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 1998, 1997 and 1996 were $329,118, $322,877 and $313,157, respectively.
Aggregate fees paid by the Trust to the Trustee in 1998, 1997 and 1996 were $39,206, $39,699 and $39,147, respectively. The Delaware Trustee was paid a flat fee of $10,000 for each of the respective years.
5. DISTRIBUTIONS TO UNITHOLDERS
Ending, as a result of the Trust termination, with the quarterly distribution made in the first quarter of 1999, the Trustee determined for each quarter the amount of cash available for distribution to Unitholders. Such amount (the "Quarterly Distribution Amount") was 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 such 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 was payable to Unitholders of record on the 63rd day following the end of such calendar quarter unless such day was not a business day in which case the record date was the next business day thereafter. The Trustee distributed 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.
As a result of the unitholder vote to terminate the Trust on December 28, 1998, the Royalty Interests were sold by the Trustee to San Juan for an all cash purchase price of $73 million in a transaction consummated on March 26, 1999. Pursuant to the Trust Agreement, all proceeds of production attributable to the Royalty Interests after the Termination Date will be paid to San Juan, as purchaser of the royalty interests. A special distribution will be made to unitholders of record as of April 12, 1999, no later than April 27, 1999, of the net proceeds from the sale of the Royalty Interests. The record date for the special distribution is the 15th day following receipt of the purchase price by the Trust.
6. CONTINGENCIES
Under the terms of the gas purchase contract entered into between BROG and BRTI, an affiliate of BROG (the "Gas Purchase Contract"), which was terminated December 31, 1998, additional revenues were periodically 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 was accrued in a "Price Credit Account" and the amount of such account was subject to recoupment by BRTI from future revenues received from production, with respect to any month commencing after December 31, 1993, when the applicable index price in such month exceeded the Minimum Purchase Price. However, with the termination of the Gas Purchase Contract approved by Unitholders in connection with approval of the termination of the Trust, the balance of such unrecouped amounts was terminated and is no longer subject to recoupment.
The applicable index price was above the Minimum Purchase Price during all of 1998 except September resulting in a net reduction of the Price Credit Account of $2.0 million. The applicable index price was above the Minimum Purchase Price during 1997 except for March and April of 1997 resulting in a net reduction in the Price Credit Account of $3.3 million. The applicable index price was below the Minimum Purchase Price during 1996 except for the months of August, November and December. Pursuant to the terms of the Gas Purchase Contract, BRTI established the Price Credit Account. BRTI estimates that, as of December 29, 1998, BRTI had aggregate price credits in the Price Credit Account, which were terminated as of December 31, 1998, of approximately $3.6 million of which the Trust's 95 percent interest, which was subject to potential recoupment by BRTI against the revenues otherwise payable to the Trust, was approximately $3.4 million.
The Trustee has been advised by BROG 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. Because of the sale of the Royalty Interests, any change in the position of the MMS with respect to the treatment of Section 29 tax credits will be irrelevant to the Trust and Unitholders.
7. SUBSEQUENT EVENT
Subsequent to December 31, 1998, the Trust declared the following distributions:
The Trustee has estimated the Section 29 tax credit associated with the March 4, 1999 quarterly distribution to be $.19 per Unit (unaudited).
8. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data for the periods ended December 31, 1998 and 1997 are as follows (in thousands except per unit amounts):
Selected 1998 fourth quarter data are as follows (in thousands except per unit amounts):
As a result of the sale in March 1999, of the Trust's royalty interests in gas properties, an increase in the amortization and impairment provision of $1.4 million was recorded during the fourth quarter of 1998. 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, 1998, 1997 and 1996 and January 1, 1996 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, 1998, the price the Trust was entitled to receive under the Gas Purchase Contract prior to the termination of such contract was $1.90 per MMBtu subject to accrued and recouped price credits, which credits were cancelled as of such date (see Note 6). For purposes of preparation of the reserve report as of December 31, 1998, however, pricing was held constant at the minimum purchase price of $1.60 per MMBtu until the accrued price credits were recouped, after which $1.90 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. The net profits interest did 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 profits interest, to pay the future established 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, 1998 occur.
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, 1998, 1997 and 1996 relating to proved reserves (in thousands):
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, 1998, 1997 and 1996 (in thousands)
The above reserves do not include undiscounted Section 29 tax credits of approximately $22,268,000 at December 31, 1998 as estimated by an independent petroleum engineer. The present discounted (10%) value of these tax credits is approximately $18,787,000.
10. IMPAIRMENT OF ROYALTY INTERESTS
At December 31, 1998 the Trust's net carrying value of its investment in royalty interests in gas properties exceeded the aggregate of the net proceeds from the sale of the royalty interests and the March 1999 distribution to Unitholders. Accordingly, the Trust was required to record an impairment allowance during 1998 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 writedown required to be recorded in 1996 or 1997. An additional impairment allowance would have been required if the sale price of the Trust's Royalty Interests was not used to calculate this provision. Prior to the sale of the Royalty Interests, trust management routinely reviewed its long lived assets for impairment whenever events or circumstances indicated that the carrying amount of an asset may not be recoverable.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None. PART III
ITEM 10.
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.
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 1998 base amount of $39,206, 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 1998 of $39,206. 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 1998 was $5,167.
Administrative Services Fees. From the Trust's formation until December 31, 1998, Burlington Resources received 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". After December 31, 1998, San Juan, as successor to Burlington Resources, has performed such services and is paid the administrative services fee.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(a) Security Ownership of Certain Beneficial Owners. The following table sets forth as of April 8, 1999 information with respect to the only Unitholders known to the Trustee to be beneficial owners of more than 5 percent of the outstanding Units.
- -------------- (1) Directly owned.
(2) Represents Units directly owned by San Juan Partners, L.L.C., a limited liability company in which the named party holds a membership interest.
(b) Security Ownership of Management. The Trust has no directors or executive officers. As of April 12, 1999, NationsBank, N.A., the Trustee, did not beneficially own any Units. As of April 12, 1999, 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.
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.
From the Trust's formation until December 31, 1998, the Administrative Services Agreement obligated 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 1998, payable in equal quarterly installments, was $329,118. As of December 31, 1998, San Juan assumed all rights and obligations of Burlington Resources under the Administrative Services Agreement.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this report:
1. Financial Statements (included in Item 8. of this report)
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).
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).
10.5 -- Agreement of Sale and Purchase dated March 26, 1999, by and between Burlington Resources Coal Seam Gas Royalty Trust and San Juan Partners, L.L.C. (filed as Exhibit 10.1 to the Registrant's Form 8-K filed April 9, 1999 and incorporated herein by reference).
20.1 -- Information Statement of the Trust on Schedule 14C regarding special meeting of Unitholders held December 28, 1998 (filed December 7, 1998 and incorporated herein by reference).
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 BROG'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 BROG'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 BROG'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).
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 BROG's interest in the Underlying Properties as of December 31, 1996, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers (filed as Exhibit 99.7 to the Registrant's Form 10-K for the year ended December 31, 1996 and incorporated herein by reference).
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 (filed as Exhibit 99.8 to the Registrant's Form 10-K for the year ended December 31, 1996 and incorporated herein by reference).
99.9 -- Reserve Report, dated March 27, 1998, on the estimated reserves, estimated future net revenues and discounted estimated future net revenues attributable to the Royalty Interests and BROG's interest in the Underlying Properties as of December 31, 1997, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers (filed as Exhibit 99.9 to the Registrant's Form 10- K for the year ended December 31, 1997 and incorporated herein by reference).
99.10 -- Report, dated March 27, 1998, on the estimated Section 29 tax credits attributable to the Royalty Interests as of December 31, 1997, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers (filed as Exhibit 99.10 to the Registrant's Form 10-K for the year ended December 31, 1997 and incorporated herein by reference).
99.11 -- Reserve Report, dated March 25, 1999, on the estimated reserves, estimated future net revenues and discounted estimated future net revenues attributable to the Royalty Interests and San Juan's interest in the Underlying Properties as of December 31, 1998, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers.
99.12 -- Report, dated March 26, 1999, on the estimated Section 29 tax credits attributable to the Royalty Interests as of December 31, 1998, prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers.
(b) Reports on Form 8-K.
Current Report on Form 8-K filed December 30, 1998 regarding the approval by Unitholders of a proposal to terminate the Trust and certain other actions.
Current Report on Form 8-K filed January 12, 1998, regarding the engagement by the Trustee of Albrecht & Associates, Inc. as advisor in connection with the sale of the Royalty Interests.
Current Report on Form 8-K filed April 9, 1999 regarding the sale of the Royalty Interests to San Juan Partners, L.L.C.
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, N.A., Trustee
By: /S/ RON E. HOOPER ---------------------------------------- RON E. HOOPER VICE PRESIDENT AND TRUST ADMINISTRATOR
Date: April 15, 1999
(The Registrant has no directors or executive officers.)
INDEX TO EXHIBITS