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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, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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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, N.A.
NATIONSBANK PLAZA
901 MAIN STREET, SUITE 1700 75202
DALLAS, TEXAS (ZIP CODE)
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(214) 209-2400
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
------------------- ----------------
Units of Beneficial Interest NEW YORK STOCK EXCHANGE, INC.
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
At March 31, 1999, 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 $23,650,000. For this purpose San Juan Partners,
L.L.C. was considered an affiliate of the registrant.
DOCUMENTS INCORPORATED BY REFERENCE
None
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TABLE OF CONTENTS
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PART I .........................................................................................................1
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...............................................7
Liabilities of the Delaware Trustee and the Trustee....................................7
Termination and Liquidation of the Trust...............................................8
DESCRIPTION OF UNITS............................................................................9
Distributions and Income Computations..................................................9
Periodic Reports to Unitholders.......................................................10
Voting Rights of Unitholders..........................................................10
Liability of Unitholders..............................................................11
Transfer Agent........................................................................11
FEDERAL INCOME TAX CONSEQUENCES................................................................12
ERISA CONSIDERATIONS...........................................................................14
STATE TAX CONSIDERATIONS.......................................................................14
REGULATION AND PRICES..........................................................................15
Regulation of Natural Gas.............................................................15
Environmental Regulation..............................................................16
Competition, Markets and Prices.......................................................16
Item 2. Properties....................................................................................17
THE ROYALTY INTERESTS..........................................................................17
The Underlying Properties.............................................................17
The NPI .............................................................................19
Reserve Report........................................................................19
Historical Gas Sales Prices and Production............................................22
Gas Purchase Contract.................................................................22
Gas Gathering Contract................................................................23
Federal Lands.........................................................................24
The Infill NPI........................................................................24
Title to Properties...................................................................24
Item 3. Legal Proceedings.............................................................................25
Item 4. Submission of Matters to a Vote of Security Holders...........................................25
PART II ........................................................................................................26
Item 5. Market for Registrant's Common Equity and Related Unitholder Matters..........................26
Item 6. Selected Financial Data.......................................................................26
Item 7. Trustee's Discussion and Analysis of Financial Condition and Results of Operations............27
Year 2000.....................................................................................29
Forward-Looking Statements....................................................................29
Item 7A. Quantitative and Qualitative Disclosures About Market Risk....................................29
Item 8. Financial Statements and Supplementary Data...................................................30
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..........40
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PART III ........................................................................................................40
Item 10. Directors and Executive Officers of the Registrant...........................................40
Item 11. Executive Compensation.......................................................................40
Item 12. Security Ownership of Certain Beneficial Owners and Management...............................40
Item 13. Certain Relationships and Related Transactions...............................................41
Administrative Services Agreement............................................................41
PART IV ........................................................................................................42
Item 14. Exhibits, Financial Statement Schedules and Reports On Form 8-K..............................42
Financial Statement Schedules................................................................42
Exhibits.....................................................................................42
Reports on Form 8-K..........................................................................44
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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, 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--The Royalty Interests--Burlington Resources' Performance Assurances."
"BRTI" means Burlington Resources Trading Inc., a wholly owned subsidiary
of Burlington Resources.
"BRTI Payment Obligations" has the meaning assigned to such term under
"Item 2--The Royalty Interests--Burlington Resources' Performance Assurances."
"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.
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"Conveyance" means the Net Profits Interest Conveyance from BROG to the
Trust, a copy of which is filed as an exhibit to this Form 10-K.
"December 31, 1998 Reserve Report" means the Reserve Report, dated March
25, 1999, on the estimated BROG 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, 1998, 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, 1998 Section 29 Tax Credit Report" means the report, dated
March 26, 1999, on the estimated BROG reserves and estimated Section 29 tax
credits attributable to the Royalty Interests and the Underlying Properties as
of December 31, 1998, 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.
"Dominion" means Dominion Energy, Inc., a Delaware corporation and the
parent company of San Juan.
"Gas Gathering Contract" means the Gas Gathering, Dehydrating and Treating
Agreement, dated as of May 3, 1990, between BRGI and BRTI, 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 BROG and BRTI, 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 BRTI 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 San Juan
interest in any Infill Wells less (a) San Juan's working interest share of
property, production and related taxes (including severance taxes) in respect of
such Infill Wells; (b) San Juan's working interest share of lease operating
expenses in respect of such Infill Wells; (c) San Juan'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 San Juan) 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.
"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.
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"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.
"Liquidation" means the sale of the Royalty Interests to San Juan Partners,
L.L.C. pursuant to an Agreement of Sale and Purchase dated March 26, 1999.
"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.
"MMBtu" means million Btu.
"MMcf" means million cubic feet of natural gas.
"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."
"NPI Net Proceeds" consists generally of the aggregate proceeds
attributable to San Juan'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)
San Juan's working interest share of property, production and related taxes
(including severance taxes) on the Underlying Properties; (ii) San Juan's
working interest share of lease operating expenses on the Underlying Properties;
(iii) San Juan'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 BROG 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 San Juan) be deducted in calculating NPI Net Proceeds.
"Price Credit" means the credit received by BRTI from BROG (as predecessor
to San Juan) for each MMBtu of natural gas purchased by BRTI after December 31,
1993 and until the termination of the Gas Purchase Contract on December 31,
1998, when the Index Price was less than the Minimum Purchase Price, equal to
the difference between the Minimum Purchase Price and the Index Price.
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"Price Credit Account" means the account established by BRTI 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 Reserve Reports on the
estimated BROG 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, 1993, 1994, 1995, 1996 and 1997,
respectively, prepared by Netherland Sewell & Associates, Inc., petroleum
engineers, a copy of each of which is filed as an exhibit to this Form 10-K.
"Prior Tax Credit Reports" means, collectively, the reports on the
estimated BROG reserves and estimated Section 29 tax credits attributable to the
Royalty Interests and the Underlying Properties as of December 31, 1994, 1995,
1996 and 1997, respectively, prepared by Netherland, Sewell & Associates, Inc.,
independent petroleum engineers, a copy of each of which is filed as an exhibit
to this Form 10-K.
"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.
"San Juan" means San Juan Partners, L.L.C., a Texas limited liability
company.
"Sharing Price" means $2.04 per MMBtu.
"Termination Date" means December 28, 1998, the date a proposal to
terminate the Trust was approved by the requisite vote of Unitholders of the
Trust.
"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, BROG, as grantor, Mellon Bank (DE) National Association,
as the Delaware Trustee, and NationsBank, N.A. (as successor to 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, N.A. (as successor to 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.
"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.
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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"), Burlington Resources Oil & Gas
Company, a Delaware corporation ("BROG"), as grantor, Mellon Bank (DE) National
Association, a national banking association (the "Delaware Trustee"), and
NationsBank, N.A. (as successor to 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
BROG to the Trust. Effective January 1, 1996, Meridian Oil Production Inc., a
wholly owned subsidiary of Burlington Resources ("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 prior to
the date of such merger to BROG refer to MOPI, references to BRTI refer to MOTI
and references to BRGI refer to MOGI. 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.
As described in greater detail under "Termination and Liquidation of the
Trust" and elsewhere in this report, the Trust was terminated as of December 28,
1998 (the "Termination Date") pursuant to approval by Unitholders of a
Unitholder proposal to terminate the Trust. On December 31, 1998, effective as
of July 1, 1998, BROG sold its retained interest in the Underlying Properties
(as defined below) subject to and burdened by the Royalty Interests to San Juan
Partners, L.L.C., a Texas limited liability company ("San Juan") and a
subsidiary of Dominion Energy, Inc., a Delaware corporation ("Dominion"). In
addition, in the same transaction, San Juan assumed all of BROG's and Burlington
Resources rights and obligations under the Trust Agreement and other related
documents, including certain preferential rights to purchase the Royalty
Interests. Following the Termination Date, pursuant to the Trust Agreement the
Trustee used its best efforts to sell the remaining Royalty Interests and
liquidate the Trust assets. On March 26, 1999, the Trustee, on behalf of the
Trust, entered into an Agreement of Sale and Purchase with San Juan, pursuant to
which San Juan acquired on that date the remaining Royalty Interests as well as
all proceeds of production since the Termination Date attributable to such
interests for an all-cash purchase price of $73 million (such transaction, the
"Liquidation"). Pursuant to the terms of the Trust Agreement, Unitholders of
record as of April 12, 1999 (the "Special Distribution Record Date") will
receive no later than April 27, 1999, as a special distribution, the proceeds
from the Liquidation, net of fees, expenses, liabilities and other obligations
of the Trust, including fees and expenses incurred in connection with the
Liquidation and net of funds the Trustee estimates to be necessary to hold in
reserve to pay any other such 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 anticipates that a small final
distribution will be made at a later date to Unitholders as of the Special
Distribution Record Date of the balance, if any, of the amount of such reserve
not actually used.
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 OR TEMPORARY INVESTMENTS PENDING PAYMENT OF EXPENSES AND
LIABILITIES OF THE TRUST OR DISTRIBUTION TO UNITHOLDERS. UPON THE CLOSE OF
BUSINESS ON THE APRIL 12, 1999 SPECIAL DISTRIBUTION RECORD DATE, THE UNITS (AS
DEFINED BELOW) WERE DE-LISTED BY THE NEW YORK STOCK EXCHANGE. FOLLOWING PAYMENT
OF THE SPECIAL DISTRIBUTION, THE TRUSTEE INTENDS TO PROCEED WITH THE WINDING
DOWN AND DISSOLUTION OF THE TRUST AS SOON AS PRACTICABLE.
CREATION AND ORGANIZATION OF THE TRUST
All of the authorized units of beneficial interest in the Trust ("Units")
were issued to BROG on June 17, 1993. On that date, BROG transferred its Units
to its parent, Burlington Resources, by dividend. Burlington Resources, in turn,
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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 was formed under Delaware law pursuant to the terms of the Trust
Agreement to acquire and hold certain net profits interests (the "Royalty
Interests") in the Fruitland coal formation underlying the Northeast Blanco Unit
held by BROG at such time (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. After the conveyance of
the Royalty Interests, BROG retained the remainder of its interest in the
Underlying Properties, which interest is burdened by the Royalty Interests. On
December 31, 1998, effective as of July 1, 1998, BROG sold its retained interest
in the Underlying Properties subject to and burdened by the Royalty Interests to
San Juan. In addition, in the same transaction, San Juan assumed all of BROG's
and Burlington Resources rights and obligations under the Trust Agreement and
other related documents, including certain preferential rights to purchase the
Royalty Interests. As a result of the consummation of the Liquidation on March
26, 1999, San Juan has acquired title to the entire interest in the Underlying
Properties as was held by BROG prior to the formation of the Trust. For a
description of the Underlying Properties and other information relating to such
properties, see "Item 2--The Royalty Interests."
ASSETS OF THE TRUST
As a result of the Liquidation and the conveyance of the Royalty Interests
to San Juan, 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. Prior to the Liquidation, the only assets of the
Trust, other than cash and temporary investments were the Royalty Interests. The
Royalty Interests consist primarily of a net profits interest (the "NPI") in the
Underlying Properties, which generally entitled the Trust to receive 95 percent
of the NPI Net Proceeds until the Termination Date. Pursuant to the Trust
Agreement, the Royalty Interests were conveyed in the Liquidation to San Juan
effective as of the Termination Date, and San Juan was therefore entitled to the
proceeds of production attributable to the Royalty Interests since such date.
"NPI Net Proceeds" consists generally of the aggregate proceeds attributable to
San Juan'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) San Juan's working interest share of property, production
and related taxes (including severance taxes) on the Underlying Properties; (ii)
San Juan's working interest share of lease operating expenses on the Underlying
Properties; (iii) San Juan'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 BROG to the extent of its prior 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"), which entitled the Trust, prior to the Termination Date, 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 San
Juan's interest in any Infill Wells less San Juan'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 in connection with the final administration, winding
up and
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dissolution of the Trust. 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, including proceeds from the sale thereof, 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.
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 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
San Juan 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 San Juan. San Juan has also agreed to indemnify 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).
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TERMINATION AND LIQUIDATION OF THE TRUST
The Trust was terminated on December 28, 1998 by the affirmative vote of
the holders of more than 66 2/3% of the outstanding Units to terminate the
Trust. Following termination, the Trustee and the Delaware Trustee have
continued to act as trustees of the Trust during the sale of the remaining
Royalty Interests and will continue to act as Trustees until such time as the
net proceeds from the Liquidation and any other remaining available funds have
been distributed to Unitholders and the Trust has been dissolved.
Following the termination of the Trust, as required by the Trust Agreement,
the Trustee used its best efforts to sell the remaining Royalty Interests for
cash pursuant to the procedures described herein. The Trustee retained Albrecht
& Associates, Inc., a Houston based oil and gas divestment firm (the "Advisor"),
on behalf of the Trust to assist the Trustee in selling the remaining Royalty
Interests and to issue an opinion as to the fairness to the Trust and the
Unitholders of any such sale from a financial point of view. San Juan, as
successor to BROG, had the right, but not the obligation, to purchase all
remaining Royalty Interests following termination of the Trust as described in
the following paragraph.
San Juan had the right, which it did not exercise, to make a cash offer
within 60 days following the Termination Date to purchase all of the remaining
Royalty Interests. Since no such offer was made by San Juan, the Trustee used
best efforts (as defined in the Trust Agreement), assisted by the Advisor, to
locate potential buyers for the Royalty Interests. Had a bidder other than San
Juan submitted the highest offer for the Royalty Interests, at the end of a
120-day period following the Termination Date and prior to accepting any offer
from another bidder, the Trustee would have been required to notify San Juan 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"). San Juan
would have then had the right, but not the obligation, to purchase all remaining
Royalty Interests for a cash purchase price equal to 105 percent of the Highest
Offer Price (net of any commissions or other fees payable by the Trust in
connection with the sale). If no other acceptable offers had been received for
all remaining Royalty Interests, the Trustee could have requested San Juan
submit another offer for consideration by the Trustee and could have accepted or
rejected such offer.
Pursuant to the Trust Agreement, because the sale of the Royalty Interests
was made within a 150-day period following the Termination Date, San Juan, as
buyer of the Royalty Interests, and not the Trust or Unitholders, is entitled to
all proceeds of production attributable to the Royalty Interests following the
Termination Date.
In the event that San Juan had not purchased the Royalty Interests, the
Trustee could have accepted any offer for all or any part of the Royalty
Interests it deemed to be in the best interests of the Trust and Unitholders and
if necessary would have continued, for a period of up to one 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 had not been sold by the end of such year, the Trustee would
have been required to sell the remaining Royalty Interests at public auction,
which sale could have been to San Juan or any of its affiliates, and would not
have been contingent upon any determination of fairness.
The sale to San Juan followed several weeks of active marketing of the
Royalty Interests to potential purchasers by the Advisor. By letter dated March
22, 1999, San Juan submitted the highest offer received by the Trust and the
Trustee, on behalf of the Trust, accepted such offer on March 25, 1999. Prior to
the closing of the sale, the Advisor delivered its opinion that the sale of the
Royalty Interests to San Juan was fair to the Trust and the Unitholders from a
financial point of view.
San Juan's special purchase rights, as described above, were acquired from
BROG on December 31, 1998. 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.
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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
April 12, 1999, there were 8,800,000 Units outstanding. The Trust may not issue
additional Units.
DISTRIBUTIONS AND INCOME COMPUTATIONS
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 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 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 represented proceeds from the sale of gas produced during the
preceding calendar quarter. 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 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. Pursuant to the Trust Agreement, all proceeds of production
attributable to the Royalty Interests after the Termination Date were paid to
San Juan, as purchaser of the Royalty Interests. Cash receipts of the Trust
attributable to production in the fourth quarter of 1998 through the Termination
Date were distributed on March 16, 1999, to Unitholders of record on March 4,
1999, as an ordinary quarterly distribution.
Under the Trust Agreement, the Trustee was required to sell the Royalty
Interests following termination of the Trust. The net proceeds from the sale of
the Royalty Interests in the Liquidation, less liabilities and expenses of the
Trust and amounts used for cash reserves, will be distributed as a special
distribution to Unitholders of record on April 12, 1999, the special record date
established for such distribution. Pursuant to the Trust Agreement, a special
distribution is to be made of undistributed sales proceeds and other amounts
received by the Trust (collectively, a "Special Distribution Amount") when such
amounts, in the aggregate, exceed $10,000,000, and the record date for
determining the recipients of a Special Distribution Amount is to be the 15th
day following receipt by the Trust of amounts exceeding such threshold (unless
such day is not a business day in which case the record date will be the next
business day thereafter). Distribution to Unitholders of the Special
Distribution Amount resulting from the Liquidation will be made no later than
April 27, 1999, the date that is 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, although the cash proceeds from production after the Termination Date
will be paid to San Juan rather than the Trust or Unitholders, the Unitholders
will be required to report income, depreciation and Section 29 credits
attributable to the remaining Royalty Interests following the Termination Date
until the Liquidation on March 26, 1999. See "Federal Income Tax Consequences --
Allocations After Termination and Before Liquidation" below. In addition, 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
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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).
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 San Juan's interest in the Underlying Properties for such
quarter. Following the distribution of such report with respect to the first
quarter of 1999, the Trustee does not anticipate preparing and distributing any
additional periodic reports. 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 San Juan's interest in the Underlying
Properties. Following the distribution of this annual report, the Trustee does
not anticipate preparing and distributing any additional annual reports.
The Trustee files such returns for Federal income tax purposes as 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. Following the issuance
of this annual report, the Trustee intends to distribute the 1999 tax
information booklet to Unitholders of record in 1999 as soon as practicable.
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 more 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 San Juan. 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.
Pursuant to the above described procedures, on December 8, 1998, San Juan,
as a holder of not less 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
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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 the affirmative vote of the holders of not less than 66-2/3% of the total
outstanding Units as required by the Trust Agreement. Because San Juan
controlled more than 66-2/3% of the total outstanding Units on the record date
for such meeting, the approval of San Juan's proposal was assured. The proposal
is described in more detail in the Trust's Information Statement on Schedule 14C
for such Unitholder meeting, which is included as an exhibit to this Form 10-K
and incorporated herein by reference.
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. In
addition the consent of San Juan (as successor to BROG) and the approval of not
less than 66-2/3% of the outstanding Units is required for the amendment of
certain provisions of the Trust Agreement. The Trustee, the Delaware Trustee,
and San Juan (as successor to BROG) 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. 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").
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FEDERAL INCOME TAX CONSEQUENCES
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. Such sections of the Public Offering
Prospectus were summarized in exhibits to previous reports on Form 10-K filed by
the Trust. No assurance can be provided that the opinions of counsel to
Burlington Resources (which do not bind the Internal Revenue Service (the
"IRS")) set forth in the Public Offering Prospectus and summarized in previous
reports on Form 10-K filed by the Trust will not be challenged by the IRS or
will be sustained by a court if so challenged. 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.
Based on the Federal income tax consequences discussed in the Public
Offering Prospectus, the Trustee has provided Unitholders of record in 1998 with
a tax booklet containing certain tax information needed to compute the income,
deductions and credits attributable to the Units and to allow Unitholders of
record on one or more Quarterly Record Dates during such year to file their tax
returns. On or before June 30, 1999, the Trustee intends to provide Unitholders
with a tax booklet containing certain 1999 tax information needed to compute the
income, deductions and credits attributable to the Units and to allow
Unitholders of record on the March 4, 1999 Quarterly Record Date or the April
12, 1999 Special Distribution Record Date to file their 1999 tax returns. Each
Unitholder should consult the Unitholder's tax advisor regarding all tax filing
and compliance matters relating to his Units.
TERMINATION, LIQUIDATION AND SPECIAL DISTRIBUTION
As discussed under sections labeled "Termination and Liquidation of the
Trust" and "Distributions and Income Computations," the Trustee, on behalf of
the Trust, has sold the remaining Royalty Interests to San Juan on March 26,
1999. The Trust will not incur any federal income tax liability as a result of
the termination of the Trust, the Liquidation, or the payment of the Special
Distribution Amount.
No Unitholder will incur any Federal income tax liability as a result of
the Termination of the Trust on December 28, 1998. However, each Unitholder of
record on the Special Distribution Record Date will recognize gain or loss as a
result of the March 26, 1999 Liquidation. The amount of gain or loss is measured
by the difference between the Unitholder's share of the amount realized on the
Liquidation and his adjusted basis for such Units.
The amount realized from the Liquidation will be attributed to Unitholders
in the same manner as the Trustee allocates the income received by the Trust
(i.e., by allocating the $73 million all-cash proceeds from the Liquidation (net
of fees, expenses, liabilities, and other obligations of the Trust arising from
or incurred in connection with the Liquidation) among the 8,800,000 Units
outstanding at the time of such Liquidation, and apportioning such amount, on a
per Unit basis among the Unitholders of record on the Special Distribution
Record Date). For purposes of determining gain or loss from the Liquidation,
the amount realized allocated among the Unitholders will not be reduced by
amounts used by the Trustee (i) to pay liabilities of the Trust (incurred in
connection with the final administration of the Trust) or (ii) to increase the
Trust's cash reserve for anticipated expenses of the Trust incurred in
connection with the final administration, winding up and dissolution of the
Trust. However, the cash proceeds received by the Trust as a result of the
Liquidation will be reduced by such amounts in determining the Special
Distribution Amount.
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Prior to determining the gain or loss resulting from the Liquidation, each
Unitholder should reduce his tax basis (but not below zero) in the remaining
Royalty Interests (and, correspondingly, his Units) by (1) the amount of
depletion allowable with respect to the remaining Royalty Interests through the
date of the Liquidation, and (2) by the amount of any return of capital,
including returns of capital resulting from a reduction to the cash reserve
maintained by the Trust during a quarterly period. See the discussion regarding
"Allocations After Termination and Before Liquidation" below. On or before June
30, 1999, the Trustee intends to provide to Unitholders the 1999 tax information
necessary for Federal income tax purposes regarding their respective shares of
(a) income, depletion, and estimated Section 29 tax credits for the record
holders of Units on the March 4, 1999 Quarterly Record Date and the April 12,
1999 Special Distribution Record Date and (b) the amount realized from the
Liquidation.
Assuming a Unitholder holds his Units as a capital asset, gain or loss from
the Liquidation will be treated as a capital gain or loss. If a Unitholder has
held his Units for more than one year, the gain or loss will constitute a
long-term capital gain or loss; otherwise, the gain or loss will constitute a
short-term capital gain or loss. Notwithstanding the foregoing, a Unitholder
must, upon the Liquidation, treat as ordinary income his depletion recapture
amount, which is an amount equal to the lesser of (i) the gain on such sale
attributable to disposition of the remaining Royalty Interests or (ii) the sum
of the prior depletion deductions taken with respect to the remaining Royalty
Interests (but not in excess of the initial basis of such Units allocated to the
remaining Royalty Interests).
ALLOCATIONS AFTER TERMINATION AND BEFORE LIQUIDATION
Generally, a Unitholder is entitled to income, depletion, and Section 29
tax credits to the extent that he is an owner of the economic interest at the
time the qualifying gas is produced and sold. Since the inception of the Trust,
the Trustee has allocated the income associated with cash paid to the Trust
during a calendar quarter, and the Section 29 tax credits and depletion
allowable with regard to such income, to Unitholders of record on the Quarterly
Record Date for such quarter. With respect to each complete calendar quarter,
the Quarterly Record Date for such calendar quarter is 63 days following the end
of such quarter.
The Trust was terminated as of December 28, 1998, pursuant to approval by
the holders of more that 66-2/3% of the Units. Following such approval and in
accordance with the Trust Agreement, the Liquidation provides that San Juan, as
purchaser of the remaining Royalty Interests, is entitled to all proceeds of
production attributable to the remaining Royalty Interests after the Termination
Date. As a result, all cash proceeds from production attributable to the period
from September 30, 1998 to December 28, 1998 (as adjusted for normal Trust
administrative expenses and interest income), were allocated (based on a daily
proration of the proceeds for the entire calendar quarter) and distributed to
Unitholders of record on the Quarterly Record Date occurring on March 4, 1999.
None of the cash proceeds from production attributable to the remaining Royalty
Interests after the Termination Date will be allocated to the Trust (or,
ultimately, to the Unitholders thereof).
Unlike the cash proceeds from production after the Termination Date (such
proceeds to be paid to San Juan as purchaser of the remaining Royalty
Interests), Unitholders will be allocated income (and, correspondingly, the
Section 29 tax credits attributable to such income) and depletion attributable
to production from the remaining Royalty Interests for the entire calendar
quarter in which the Termination occurred (since they will continue to own the
"economic interest" in the qualifying gas until the Liquidation). Such income,
Section 29 tax credits, and depletion will be allocated to Unitholders of record
on the March 4, 1999, Quarterly Record Date following the end of such calendar
quarter. For the calendar quarter beginning on January 1, 1999 (during which the
Liquidation occurred), income (and, correspondingly, the Section 29 tax credits
attributable to such income) and depletion attributable to the remaining Royalty
Interests for the period beginning on the first day of such calendar quarter and
ending on the date of the Liquidation will be allocated to Unitholders of record
on the Special Distribution Record Date. In addition, unitholders of record
with regard to this period will be entitled to the cash proceeds (and required
to report the income) earned as interest on investments by the Trust.
ALLOCATIONS AFTER LIQUIDATION
Following the Liquidation, the Trust will maintain a cash reserve to pay
expenses of the Trust incurred in connection with the final administration,
winding up, and dissolution. During such period, the Trust anticipates that
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interest will be earned on the cash proceeds held by the Trust. All expenses
paid by the Trust and all interest income earned after Liquidation will be
allocated to Unitholders of record on the Special Distribution Record Date in
accordance with the Trust Agreement. Any interest income allocated to the
Unitholders during this period will be taxed, for Federal income tax purposes,
as ordinary income. During the period following the Liquidation and ending on
June 30, 1999, the Trust intends (a) to complete all of its obligations
regarding the final administration, winding up and dissolution, (b) to pay all
liabilities and expenses of the Trust, and, thereafter, (c) to distribute any
remaining cash amount to the Unitholders of record on the Special Distribution
Record Date.
POSSIBLE CHALLENGES BY THE IRS
It is possible that the IRS may challenge the Trust's use of (i) the
Special Distribution Record Date to determine the allocation of (a) the amount
realized from the Liquidation, and (b) the Trust's income and expenses for the
short period beginning on April 1, 1999 and ending on or before June 30, 1999
(during which period the Trust intends to complete all of its obligations, pay
all of its liabilities and expenses, and distribute all remaining cash
reserves), or (ii) the Quarterly Record Date allocations for any full or partial
quarter in which the Trust was in existence, or (iii) the allocation of income,
depletion and Section 29 tax credits attributable to the remaining Royalty
Interests for any period less than a complete calendar quarter. Any IRS
challenge is likely to have a material adverse effect only if successful and
only for certain Unitholders.
The information above is only a summary of some of the federal income tax
consequences generally affecting the Trust and its individual U.S. Unitholders
resulting from the Termination and Liquidation of, and the final distributions
from, the Trust. This summary does not address the particular federal income tax
consequences applicable to Unitholders other than U.S. individuals nor does it
address state or local tax consequences. The tax consequences of the Liquidation
may affect Unitholders differently depending upon their particular tax
situations, and, accordingly, this summary is not a substitute for careful tax
planning and reporting on an individual basis.
UNITHOLDERS SHOULD CONSULT THEIR TAX ADVISORS TO DETERMINE THE FEDERAL, STATE,
AND OTHER INCOME TAX CONSEQUENCES OF THE TERMINATION, THE LIQUIDATION, AND
DISSOLUTION OF THE TRUST WITH RESPECT TO THEIR PARTICULAR TAX CIRCUMSTANCES.
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
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requirements. 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 and pay for only the services they require, regardless
of whether the customer purchases natural gas from such pipelines or from other
suppliers. Because of the sale of the Royalty Interests, the impact of these
regulations, if any, will be immaterial to the Trust.
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. Because of the sale of
the Royalty Interests, the effect, if any, of such proposals will be immaterial
to 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. Because of the sale of the Royalty Interest, the
effect of such state regulation, if any, will be immaterial to the Trust.
15
<PAGE> 19
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. However, any costs or expenses incurred by
San Juan 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 San
Juan (as successor to BROG) and not the Trust (and San Juan (as successor to
BROG) 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 San
Juan'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 San Juan but will be deducted in
calculating NPI Net Proceeds or Infill Net Proceeds and prior to the Termination
Date, therefore, would have reduced amounts payable to the Trust. As a result of
the Liquidation and the forthcoming dissolution of the Trust, the Trust will no
longer be receiving additional revenues from the NPI Net Proceeds or Infill Net
Proceeds and consequently the effect of environmental regulation, environmental
remediation obligations or other environmental liabilities related to the
Underlying Properties is expected to be immaterial to the Trust and Unitholders.
COMPETITION, MARKETS AND PRICES
Prior to the Termination Date, the revenues of the Trust and the amount of
cash distributions to Unitholders depended 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. San Juan 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 San Juan. Competition may also be presented by alternative
fuel sources, including heating oil and other fossil fuels.
Demand for natural gas production has historically been seasonal in nature
and prices for gas fluctuate accordingly. Prior to the Liquidation, such price
fluctuations and the continuation of a variable market for natural gas directly
impacted Trust distributions, estimates of Trust reserves and estimated future
net revenue from Trust reserves. The impact of gas prices on the estimated
future net revenue from Trust reserves similarly impacted the valuation of the
Royalty Interests by the Trustee, the Advisor and potential purchasers of the
Royalty Interests in connection with the marketing and sale of the Royalty
Interests.
Prices for natural gas are subject to wide fluctuations in response to
relatively minor changes in supply, market uncertainty and a variety of
additional factors that are beyond the control of the Trust and San Juan. 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. Following the Liquidation, future gas prices and demand
will have no further effect on the Trust.
16
<PAGE> 20
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
17
<PAGE> 21
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.
<TABLE>
<CAPTION>
WORKING INTEREST
WORKING INTEREST OWNERS PERCENTAGE
----------------------- ----------
<S> <C>
Amoco Production Co..................................... 35.4
San Juan Partners, L.L.C. .............................. 19.8
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
</TABLE>
18
<PAGE> 22
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.
<TABLE>
<CAPTION>
DECEMBER 31, NUMBER OF WELLS ACRE
------------ -------------- ----
GROSS NET GROSS NET
----- --- ----- ---
<S> <C> <C> <C> <C> <C>
1996................................................. 102 20 32,595 6,404
1997................................................. 101 20 32,595 6,404
1998................................................. 101 20 32,595 6,404
</TABLE>
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.
19
<PAGE> 23
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.
20
<PAGE> 24
<TABLE>
<CAPTION>
ROYALTY
INTERESTS
---------
<S> <C>
Net Proved Gas Reserves (Bcf)(a)(b).................................... 50.9
Estimated Future Net Revenues (in millions)(c)......................... $49.6
Discounted Estimated Future Net Revenues (in millions)(c).............. $30.3
</TABLE>
- ----------------
(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.
21
<PAGE> 25
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:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------
1996 1997 1998
---- ---- ----
<S> <C> <C> <C>
Production from San Juan's interest in the Underlying
Properties (Bcf)............................................ 12.20 11.10 13.05
Weighted average production costs (dollars per Mcf)............ $ 0.12 $ 0.23 $ 0.24
Weighted average sales price of gas produced from BROG's
interest in the Underlying Properties (dollars per Mcf)..... $ 1.04 $ 0.99 $ 0.97
Average Blanco Hub Spot Price (dollars per MMBtu).............. $ 1.66 $ 2.32 $ 1.86
</TABLE>
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.
22
<PAGE> 26
(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
23
<PAGE> 27
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.
24
<PAGE> 28
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.
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.
25
<PAGE> 29
PART II
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.
<TABLE>
<CAPTION>
PRICE DISTRIBUTIONS
---------------------- -------------
HIGH LOW PER UNIT
---- --- -------------
<S> <C> <C> <C>
1998
First Quarter................................ $8-9/16 $5-1/16 $.143235
Second Quarter............................... $8-9/16 $8-7/16 $.210321
Third Quarter................................ $8-13/16 $7-3/4 $.210220
Fourth Quarter............................... $10 $7-1/4 $.201541
1997
First Quarter................................ $9-3/4 $7-5/8 $.147801
Second Quarter............................... $8-1/4 $6-3/4 $.160766
Third Quarter................................ $8 $7-1/16 $.205895
Fourth Quarter............................... $7-15/16 $5-3/8 $.125486
</TABLE>
At March 31, 1999, there were 8,800,000 Units outstanding and approximately 628
Unitholders of record.
ITEM 6. Selected Financial Data.
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
----------------- ----------------- ----------------- ----------------- ----------------
<S> <C> <C> <C> <C> <C>
Royalty Income................. $ 7,440,433 $ 6,270,303 $ 10,671,428 $ 14,076,780 $ 17,115,969
Distributable Income........... $ 6,656,771 $ 5,621,938 $ 10,040,541 $ 13,402,397 $ 16,423,579
Distributable Income per
Unit........................... $ .76 $ .64 $ 1.14 $ 1.52 $ 1.87
Distributions per Unit $ .76 $ .64 $ 1.14 $ 1.52 $ 1.88
Total Assets, December 31...... $ 73,313,847 $ 93,589,077 $ 107,530,131 $ 123,634,960 $ 147,565,760
Trust Corpus, December 31...... $ 73,144,463 $ 93,484,928 $ 107,328,165 $ 123,534,740 $ 147,459,837
</TABLE>
26
<PAGE> 30
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.
27
<PAGE> 31
<TABLE>
<CAPTION>
FOR THE TWELVE MONTHS ENDED
---------------------------------------------------------
Sept. 30, 1998 Sept. 30, 1997 Sept. 30, 1996
-------------- -------------- --------------
<S> <C> <C> <C>
Production (Bcf)(1) 12.829 10.936 12.761
Production 11.375 9.817 11.515
(Trillion Btu)(2)
Average Inside FERC Price $ 2.08 $ 2.28 $ 1.34
($/MMBtu)(3)
BROG Average Entitled Price Received $ 1.08 $ 1.11 $ 1.18
($/MMBtu)(4)
</TABLE>
(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.
28
<PAGE> 32
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. 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.
29
<PAGE> 33
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
30
<PAGE> 34
FINANCIAL STATEMENTS
BURLINGTON RESOURCES COAL SEAM GAS ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1998 1997
----------- -----------
<S> <C> <C>
ASSETS
Cash and cash equivalents ...................................................... $ 38,025 $ 50,819
Royalty interests in gas properties (less accumulated amortization and
impairment allowance of $107,124,178 and 86,861,742)(Note 10) .................. 73,275,822 93,538,258
----------- -----------
Total assets ............................................................. $73,313,847 $93,589,077
=========== ===========
LIABILITIES AND TRUST CORPUS
Trust expenses payable ......................................................... $ 169,384 $ 104,149
Trust corpus (8,800,000 units of beneficial interest authorized and outstanding) 73,144,463 93,484,928
----------- -----------
Total liabilities and trust corpus ............................................. $73,313,847 $93,589,077
=========== ===========
</TABLE>
STATEMENTS OF DISTRIBUTABLE INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1998 1997 1996
------------ ------------ ------------
<S> <C> <C> <C>
Royalty income ................................ $ 7,440,433 $ 6,270,303 $ 10,671,428
Interest income ............................... 21,108 16,190 28,339
------------ ------------ ------------
7,461,541 6,286,493 10,699,767
General and administrative expenses (Note 4) .. (804,770) (664,555) (659,226)
------------ ------------ ------------
Distributable income .......................... $ 6,656,771 $ 5,621,938 $ 10,040,541
============ ============ ============
Distributable income per unit (8,800,000 units) $ .76 $ .64 $ 1.14
============ ============ ============
Distributions per unit ........................ $ .76 $ .64 $ 1.14
============ ============ ============
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------
1998 1997 1996
------------- ------------- -------------
<S> <C> <C> <C>
Trust Corpus, beginning of period .... $ 93,484,928 $ 107,328,165 $ 123,534,740
Amortization and impairment of royalty
interests ............................ (20,262,436) (13,833,622) (16,231,820)
Distributable income ................. 6,656,771 5,621,938 10,040,541
Distributions to Unitholders ......... (6,734,800) (5,631,553) (10,015,296)
------------- ------------- -------------
Trust corpus, end of period .......... $ 73,144,463 $ 93,484,928 $ 107,328,165
============= ============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
31
<PAGE> 35
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
32
<PAGE> 36
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.
33
<PAGE> 37
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.
34
<PAGE> 38
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
35
<PAGE> 39
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:
<TABLE>
<CAPTION>
Quarterly Record Date Payment Date Distribution per Unit
- --------------------- ------------ ---------------------
<S> <C> <C>
March 4, 1999 March 16, 1999 $.144859
</TABLE>
<TABLE>
<CAPTION>
Special Distribution Record Date Payment Date Distribution per Unit (unaudited)
- -------------------------------- ------------ ---------------------------------
<S> <C> <C>
April 12, 1999 On or before April 27, $8.167045
1999
</TABLE>
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):
<TABLE>
<CAPTION>
DISTRIBUTABLE INCOME PER
CALENDAR QUARTER ROYALTY INCOME DISTRIBUTABLE INCOME UNIT
- ----------------- -------------- -------------------- ------------------------
1998
- ----
<S> <C> <C> <C>
First.......................... $1,424 $1,243 $.14
Second.......................... 2,029 1,812 .21
Third .......................... 2,026 1,909 .22
Fourth ......................... 1,961 1,693 .19
------ ----- ---
$7,440 $6,657 $.76
====== ====== ====
1997
First........................... $1,472 $1,279 $.15
Second.......................... 1,619 1,400 .16
Third .......................... 1,987 1,872 .21
Fourth.......................... 1,192 1,071 .12
------ ----- ---
Total $6,270 $5,622 $.64
====== ====== ====
</TABLE>
36
<PAGE> 40
Selected 1998 fourth quarter data are as follows (in thousands except per unit
amounts):
<TABLE>
<S> <C>
Royalty income $ 1,961
Interest income 5
General and administrative expenses (273)
---------------
Distributable income $ 1,693
===============
Distributable income per unit $ .19
===============
Distribution per unit $ .19
===============
</TABLE>
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.
37
<PAGE> 41
<TABLE>
<CAPTION>
NATURAL GAS
(MMcf)
------------
<S> <C>
Proved reserves at January 1, 1996.................................... 76,545
Revisions of previous estimates....................................... 6,671
Production ........................................................... (11,582)
--------
Proved reserves at December 31,1996................................... 71,634
Revisions of previous estimates....................................... (396)
Production............................................................ (10,541)
--------
Proved Reserves at December 31,1997 60,697
Revisions of previous estimates ...................................... 2,637
Production............................................................ (12,398)
--------
Proved reserves at December 31, 1998................................. 50,936
=======
</TABLE>
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):
<TABLE>
<CAPTION>
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
Future cash inflows $ 70,837 $ 92,338 $ 143,716
Future production taxes, operating costs
and capital expenditures (21,202) (22,858) (27,410)
--------- --------- ---------
Future net cash flows 49,635 69,480 116,306
10% discount factor (19,344) (27,067) (49,001)
--------- --------- ---------
Standardized measure of
discounted future net revenues $ 30,291 $ 42,413 $ 67,305
========= ========= =========
</TABLE>
38
<PAGE> 42
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)
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Balance at January 1 $ 42,413 $ 67,305 $ 47,570
Increase (decrease) due to:
Net sales of coal seam gas (7,348) (6,223) (9,042)
Net changes in prices and costs (10,888) (29,636) 18,444
Changes in estimated volumes 1,873 4,236 5,576
Accretion of discount 4,241 6,731 4,757
-------- -------- --------
Balance at December 31 $ 30,291 $ 42,413 $ 67,305
======== ======== ========
</TABLE>
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.
39
<PAGE> 43
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 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. 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.
40
<PAGE> 44
<TABLE>
<CAPTION>
AMOUNT AND
NATURE OF
BENEFICIAL PERCENT
NAME AND ADDRESS OF BENEFICIAL OWNER OWNERSHIP OF CLASS
------------------------------------ --------- --------
<S> <C> <C>
San Juan Partners, L.L.C.............................. 5,867,968(1) 66.68%
901 E. Byrd Street
Richmond, Virginia 23220
Dominion Energy, Inc.................................. 5,867,968(2) 66.68%
901 E. Byrd Street
Richmond, Virginia 23220
</TABLE>
- --------------
(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. 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.
41
<PAGE> 45
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this report:
1. Financial Statements (included in Item 8. of this report)
<TABLE>
<CAPTION>
PAGE IN THIS
REPORT
------
<S> <C>
Independent Auditors' Report....................................................... 30
Statements of Assets, Liabilities and Trust Corpus as of
December 31, 1998 and 1997...................................................... 31
Statements of Distributable Income for the years ended December 31,
1998, 1997 and 1996............................................................. 31
Statements of Changes in Trust Corpus for the years ended
December 31, 1998, 1997 and 1996................................................ 31
Notes to Financial Statements...................................................... 32-39
</TABLE>
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).
42
<PAGE> 46
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).
43
<PAGE> 47
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.
44
<PAGE> 48
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.)
45
<PAGE> 49
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER EXHIBIT
------ -------
<S> <C>
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).
</TABLE>
<PAGE> 50
<TABLE>
<S> <C>
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).
</TABLE>
<PAGE> 51
<TABLE>
<S> <C>
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.
</TABLE>
<PAGE> 1
EXHIBIT 23.1
[NSAI LETTERHEAD]
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 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 for the year ended December 31, 1998, to be filed by
the Burlington Resources Coal Seam Royalty Trust with the Securities and
Exchange Commission.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ FREDERIC D. SEWELL
---------------------------------------------
Frederic D. Sewell
Senior Vice President
Dallas, Texas
April 15, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 38,025
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 38,025
<PP&E> 180,000,000
<DEPRECIATION> 107,124,178
<TOTAL-ASSETS> 73,313,847
<CURRENT-LIABILITIES> 169,384
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 73,144,463
<TOTAL-LIABILITY-AND-EQUITY> 73,313,847
<SALES> 7,440,433
<TOTAL-REVENUES> 7,461,541
<CGS> 0
<TOTAL-COSTS> 804,770
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 6,656,771
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 6,656,771
<EPS-PRIMARY> .76
<EPS-DILUTED> .76
</TABLE>
<PAGE> 1
EXHIBIT 99.11
March 25, 1999
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 December 31,
1998, the (1) future net revenue to the Burlington Resources Coal Seam Gas
Royalty Trust (Trust) net profits interest and (2) proved reserves to the
Burlington Resources Oil & Gas Company (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 future net
revenue to the Trust net profits interest, as of December 31, 1998, to be:
<TABLE>
<CAPTION>
Burlington Net Reserves Trust Future Net Revenue
----------------------------------- -------------------------------------------
Condensate Gas Present Worth
Category (Barrels) (MCF) Total at 10%
- -------------------------- --------------- --------------- ------------------- -------------------
<S> <C> <C> <C> <C>
Proved Developed 0 64,535,184 $49,634,900 $30,291,100
</TABLE>
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
<PAGE> 2
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 share to the Trust after deducting the
Burlington working interest share of these taxes, future capital costs, 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 interest.
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 1998 price
received, adjusted for BTU content, the gathering fee, and shrinkage. This price
is also adjusted as specified in the gas purchase contract under provisions
related to the sharing price and price credit account and is held constant in
accordance with SEC guidelines.
Lease and well operating costs are based on operating expense records
provided by Burlington and the Trustee. 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 Burlington and 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.
<PAGE> 3
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 Company, the Trustee, 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
DDS:PJA
<PAGE> 1
EXHIBIT 99.12
March 26, 1999
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 December 31,
1998, 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 Company (Burlington) interest in the proved gas reserves as
estimated in our report dated March 25, 1999. 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 have been 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 December
31, 1998, to be:
<TABLE>
<CAPTION>
Trust Net Reserves Future Tax Credit
------------------------------------ ------------------------------------------
Condensate Gas Present Worth
Category (Barrels) (MCF) Total at 10%
- -------------------------- --------------- --------------- ------------------ ------------------
<S> <C> <C> <C> <C>
Proved Developed 0 23,488,676 $22,267,800 $18,787,200
</TABLE>
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
<PAGE> 2
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.
The estimated 1998 tax credit rate used in this report is $1.07 per
MMBTU. This rate is held constant in accordance with SEC guidelines. The gas
price used in this report is based on the December 1998 price received, adjusted
for BTU content, the gathering fee, and shrinkage. This price is also adjusted
as specified in the gas purchase contract under provisions related to the
sharing price and price credit account and is held constant in accordance with
SEC guidelines.
Lease and well operating costs are based on operating expense records
provided by Burlington and the Trustee. 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
<PAGE> 3
estimates were obtained from Burlington Resources Oil & Gas Company, the
Trustee, 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
DDS:PJA
